0001571049-17-001533.txt : 20170222 0001571049-17-001533.hdr.sgml : 20170222 20170222115731 ACCESSION NUMBER: 0001571049-17-001533 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 172 CONFORMED PERIOD OF REPORT: 20161231 FILED AS OF DATE: 20170222 DATE AS OF CHANGE: 20170222 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Otter Tail Corp CENTRAL INDEX KEY: 0001466593 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 270383995 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-53713 FILM NUMBER: 17627566 BUSINESS ADDRESS: STREET 1: 215 S CASCADE ST STREET 2: PO BOX 496 CITY: FERGUS FALLS STATE: MN ZIP: 56538-0496 BUSINESS PHONE: 866-410-8780 MAIL ADDRESS: STREET 1: 215 S CASCADE ST STREET 2: PO BOX 496 CITY: FERGUS FALLS STATE: MN ZIP: 56538-0496 FORMER COMPANY: FORMER CONFORMED NAME: Otter Tail Holding Co DATE OF NAME CHANGE: 20090618 10-K 1 t1700069_10k.htm FORM 10-K

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

(Mark One) 

xAnnual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the fiscal year ended December 31, 2016

 

¨Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the transition period from _______to_______

 

Commission File Number 0-53713

 

OTTER TAIL CORPORATION
(Exact name of registrant as specified in its charter)

 

MINNESOTA 27-0383995
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)

 

215 SOUTH CASCADE STREET, BOX 496, FERGUS FALLS, MINNESOTA 56538-0496
(Address of principal executive offices) (Zip Code)

 

Registrant's telephone number, including area code: 866-410-8780

 

Securities registered pursuant to Section 12(b) of the Act:

 

  Title of each class Name of each exchange on which registered
  COMMON SHARES, par value $5.00 per share The NASDAQ Stock Market LLC

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the

Securities Act. (Yes x No__ )

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or

Section 15(d) of the Act. (Yes __ No x)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. (Yes x No__ )

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). (Yes x No__ )

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

  Large Accelerated Filer x Accelerated Filer ¨
  Non-Accelerated Filer ¨ Smaller Reporting Company ¨
  (Do not check if a smaller reporting company)  

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the

Exchange Act). (Yes __ No x )

 

The aggregate market value of common stock held by non-affiliates, computed by reference to the last sales price on June 30, 2016 was $1,260,418,253.

 

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of

the latest practicable date: 39,410,825 Common Shares ($5 par value) as of February 10, 2017.

 

Documents Incorporated by Reference:

 

Proxy Statement for the 2017 Annual Meeting-Portions incorporated by reference into Part III

 

 

   

 

 

OTTER TAIL CORPORATION

FORM 10-K TABLE OF CONTENTS

 

  Description Page
  Definitions 2
PART I    
     
ITEM 1. Business 4
ITEM 1A. Risk Factors 26
ITEM 1B. Unresolved Staff Comments 33
ITEM 2. Properties 33
ITEM 3. Legal Proceedings 33
ITEM 3A. Executive Officers of the Registrant (as of February 22, 2017) 34
ITEM 4. Mine Safety Disclosures 34
     
PART II    
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters And Issuer Purchases of Equity Securities 35
ITEM 6. Selected Financial Data 36
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 36
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk 58
ITEM 8. Financial Statements and Supplementary Data:  
  Report of Independent Registered Public Accounting Firm 59
  Consolidated Balance Sheets 60
  Consolidated Statements of Income 62
  Consolidated Statements of Comprehensive Income 63
  Consolidated Statements of Common Shareholders’ Equity 64
  Consolidated Statements of Cash Flows 65
  Consolidated Statements of Capitalization 66
  Notes to Consolidated Financial Statements 67
  Supplementary Financial Information - Quarterly Information 116
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 117
ITEM 9A. Controls and Procedures 117
ITEM 9B. Other Information 117
     
PART III    
ITEM 10. Directors, Executive Officers and Corporate Governance 118
ITEM 11. Executive Compensation 118
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 119
ITEM 13. Certain Relationships and Related Transactions and Director Independence 119
ITEM 14. Principal Accountant Fees and Services 119
     
PART IV    
ITEM 15. Exhibits and Financial Statement Schedules 120
ITEM 16. Form 10-K Summary 128
     
Signatures   129

 

1

 

 

Definitions

 

The following abbreviations or acronyms are used in the text. References in this report to “the Company”, “we”, “us” and “our” are to Otter Tail Corporation.

 

AEV, Inc. Aevenia, Inc.
AFUDC Allowance for Funds Used During Construction
ALJ Administrative Law Judge
AQCS Air Quality Control System
ARO Accumulated Asset Retirement Obligation
ASC Accounting Standards Codification
ASC 606 ASC Topic 606 – Revenue from Contracts with Customers
ASC 718 ASC Topic 718 – Compensation—Stock Compensation
ASC 815 ASC Topic 815 – Derivatives and Hedging
ASC 820 ASC Topic 820 – Fair Value Measurement
ASC 980 ASC Topic 980 – Regulated Operations  
ASM Ancillary Services Market
ASU Accounting Standards Update
BACT Best-Available Control Technology
BART Best-Available Retrofit Technology
Brookings Project Brookings-Southeast Twin Cities 345 kV Project
BTD BTD Manufacturing, Inc.
BTD – Illinois Miller Welding & Iron Works, Inc.
Btu British Thermal Unit
CAA Clean Air Act
CapX2020 Capacity Expansion 2020
CCMC Coyote Creek Mining Company, L.L.C.
CCR Coal Combustion Residuals
CIP Conservation Improvement Program
CO2 carbon dioxide
CON Certificate of Need
CPEC Central Power Electric Cooperative
CPP Clean Power Plan
CSAPR Cross-State Air Pollution Rule
CWIP Construction Work in Progress
D.C. Circuit United States Court of Appeals for the District of Columbia
DENR Department of Environment and Natural Resources
DRR Data Requirement Rule
ECR Environmental Cost Recovery
EEI Edison Electric Institute
EEP Energy Efficiency Plan
EPA Environmental Protection Agency
ESSRP Executive Survivor and Supplemental Retirement Plan
Exchange Act The Securities Exchange Act of 1934
Fargo Project Fargo-Monticello 345 kV Project
FASB Financial Accounting Standards Board
FCA Fuel Clause Adjustment
FERC Federal Energy Regulatory Commission
Foley Foley Company
GAAP Generally Accepted Accounting Principles in the United States
GHG Greenhouse Gas
Impulse Impulse Manufacturing, Inc.
IRP Integrated Resource Plan
JPMorgan JPMorgan Chase Bank, N.A.
JPMS J.P. Morgan Securities LLC
kV kiloVolt
kW kiloWatt
kwh kilowatt-hour
LSA Lignite Sales Agreement
MATS Mercury and Air Toxics Standards
MDU MDU Resources Group, Inc.

 

2

 

 

MISO Midcontinent Independent System Operator, Inc.
MISO Tariff MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff
MNCIP Minnesota Conservation Improvement Program
MNDOC Minnesota Department of Commerce
MPCA Minnesota Pollution Control Agency
MPU Act The Minnesota Public Utilities Act
MPUC Minnesota Public Utilities Commission
MRO Midwest Reliability Organization
MVP Multi-Value Project
MW megawatts
NAAQS National Ambient Air Quality Standards
NERC North American Electric Reliability Corporation
NAEMA North American Energy Marketers Association
NDPSC North Dakota Public Service Commission
NDRRA North Dakota Renewable Resource Adjustment
NPDES National Pollutant Discharge Elimination System
Northern Pipe Northern Pipe Products, Inc.
NOx Nitrogen Oxide
NSP MN Northern States Power - Minnesota
NSPS New Source Performance Standards
NYMEX New York Mercantile Exchange
OAG Minnesota Office of the Attorney General
OTP Otter Tail Power Company
PACE Partnership in Assisting Community Expansion
PCOR Plains CO2 Reduction Partnership
ppb parts per billion
PS Polystyrene
PSD Prevention of Significant Deterioration
PTCs Production Tax Credits
PVC Polyvinyl Chloride
RBOB Reformulated Blendstock for Oxygenate Blending
RCRA Resource Conservation and Recovery Act
ROE Return on Equity
RRA Renewable Resource Adjustment
RSG Revenue Sufficiency Guarantee
RTO Adder Incentive of additional 50-basis points for Regional Transmission Organization participation
SDPUC South Dakota Public Utilities Commission
SEC Securities and Exchange Commission
SF6 Sulfur Hexaflouride
SIP State Implementation Plan
SO2 Sulfur Dioxide
SPP Southwest Power Pool
Standex Standex International Corporation
T.O. Plastics T.O. Plastics, Inc.
TCR Transmission Cost Recovery
Varistar Varistar Corporation
VIC Voluntary Investigation and Cleanup
VIE Variable Interest Entity
Vinyltech Vinyltech Corporation
WIIN Water Infrastructure Improvements for the Nation

 

3

 

 

PART I

 

Item 1.BUSINESS

 

(a) General Development of Business

 

Otter Tail Power Company was incorporated in 1907 under the laws of the State of Minnesota. In 2001, the name was changed to “Otter Tail Corporation” to more accurately represent the broader scope of consolidated operations and the name Otter Tail Power Company (OTP) was retained for use by the electric utility. On July 1, 2009 Otter Tail Corporation completed a holding company reorganization whereby OTP, which had previously been operated as a division of Otter Tail Corporation, became a wholly owned subsidiary of the new parent holding company named Otter Tail Corporation (the Company). The new parent holding company was incorporated in June 2009 under the laws of the State of Minnesota in connection with the holding company reorganization. The Company’s executive offices are located at 215 South Cascade Street, P.O. Box 496, Fergus Falls, Minnesota 56538-0496 and 4334 18th Avenue SW, Suite 200, P.O. Box 9156, Fargo, North Dakota 58106-9156. The Company’s telephone number is (866) 410-8780.

 

The Company makes available free of charge at its website (www.ottertail.com) its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors and executive officers and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on the Company’s website is not deemed to be incorporated by reference into this Annual Report on Form 10-K.

 

Otter Tail Corporation and its subsidiaries conduct business primarily in the United States. The Company had approximately 2,054 full-time employees in its continuing operations at December 31, 2016. The Company’s businesses have been classified in three segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision maker. The three segments are Electric, Manufacturing and Plastics.

 

From 2011 through 2015 the Company sold several businesses in execution of an announced strategy to realign its business portfolio to reduce its risk profile and dedicate a greater portion of its resources toward electric utility operations. The following divestitures occurred in this timeframe:

 

·In 2011, the Company sold Idaho Pacific Holdings, Inc., its Food Ingredient Processing business, and E.W. Wylie Corporation, its flat-bed trucking company.
   
·In January 2012, the Company sold the assets of Aviva Sports, Inc., a recreational equipment manufacturer.
   
·In February 2012, the Company sold DMS Health Technologies, Inc., its former Health Services segment business.
   
·In November 2012, the Company completed the sale of the assets of its former wind tower company.
   
·On February 8, 2013 the Company sold substantially all the assets of its former dock and boatlift company.
   
·On February 28, 2015 the Company sold the assets of AEV, Inc., its former energy and electrical construction contractor, and on April 30, 2015 the Company sold Foley Company, its former water, wastewater, power and industrial construction contractor. With the sale of these two companies in 2015 the Company eliminated its Construction segment.

 

On September 1, 2015 the Company acquired the assets of Impulse Manufacturing Inc. (Impulse) of Dawsonville, Georgia, now operating under the name BTD-Georgia, for a final adjusted payment of $29.3 million in cash. BTD-Georgia offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers.

 

The chart below indicates the companies included in each of the Company’s reporting segments.

 

 

4

 

 

·Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.
   
·Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.
   
·Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States.

 

OTP is a wholly owned subsidiary of the Company. The Company’s manufacturing and plastic pipe businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance that are not allocated to its subsidiary companies. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

 

The Company has lowered its overall risk by investing in rate base growth opportunities in its Electric segment and divesting certain nonelectric operating companies that no longer fit the Company’s portfolio criteria. This strategy has provided a more predictable earnings stream, improved the Company’s credit quality and preserved its ability to fund the dividend. The Company’s goal is to deliver annual growth in earnings per share between four to seven percent over the next several years, using 2016 diluted earnings per share from continuing operations as the base for measurement. The growth is expected to come from the substantial increase in the Company’s regulated utility rate base and from planned increased earnings from existing capacity in place at the Company’s manufacturing and plastic pipe businesses, including the 2015 acquisition of BTD-Georgia and the facilities expansion and addition of paint services at BTD’s Minnesota facilities completed in 2016. The Company will continue to review its business portfolio to see where additional opportunities exist to improve its risk profile, improve credit metrics and generate additional sources of cash to support the growth opportunities in its electric utility. The Company will also evaluate opportunities to allocate capital to potential acquisitions in its Manufacturing and Plastics segments. Over time, the Company expects the electric utility business will provide approximately 75% to 85% of its overall earnings. The Company expects its manufacturing and plastic pipe businesses will provide 15% to 25% of its earnings, and will continue to be a fundamental part of its strategy. The actual mix of earnings from continuing operations in 2016 was 80% from the electric utility and 20% from the manufacturing and plastic pipe businesses, including unallocated corporate costs.

 

The Company maintains the following criteria in evaluating whether its operating companies are a strategic fit, the operating company:

 

·Maintains a threshold level of net earnings and a return on invested capital in excess of the Company’s weighted average cost of capital.
   
·Has a strategic differentiation from competitors and a sustainable cost advantage.
   
·Operates within a stable and growing industry and is able to quickly adapt to changing economic cycles.
   
·Has a strong management team committed to operational excellence.

 

For a discussion of the Company's results of operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations," on pages 36 through 58 of this Annual Report on Form 10-K.

 

(b) Financial Information about Industry Segments

 

The Company is engaged in businesses classified into three segments: Electric, Manufacturing and Plastics. Financial information about the Company's segments and geographic areas is included in note 2 of "Notes to Consolidated Financial Statements" on pages 75 through 78 of this Annual Report on Form 10-K.

 

5

 

 

(c) Narrative Description of Business

 

ELECTRIC

 

General

 

Electric includes OTP which is headquartered in Fergus Falls, Minnesota, and provides electricity to more than 130,000 customers in a service area encompassing 70,000 square miles of western Minnesota, eastern North Dakota and northeastern South Dakota. The Company derived 53%, 52% and 51% of its consolidated operating revenues and 81%, 80% and 76% of its consolidated operating income from its Electric segment for the years ended December 31, 2016, 2015 and 2014, respectively.

 

The breakdown of retail electric revenues by state is as follows:

 

State  2016   2015 
Minnesota   53.0%   50.4%
North Dakota   38.4    40.6 
South Dakota   8.6    9.0 
Total   100.0%   100.0%

 

The territory served by OTP is predominantly agricultural. The aggregate population of OTP’s retail electric service area is approximately 230,000. In this service area of 422 communities and adjacent rural areas and farms, approximately 126,000 people live in communities having a population of more than 1,000, according to the 2010 census. The only communities served which have a population in excess of 10,000 are Jamestown, North Dakota (15,427); Bemidji, Minnesota (13,431); and Fergus Falls, Minnesota (13,138). As of December 31, 2016 OTP served 131,546 customers. Although there are relatively few large customers, sales to commercial and industrial customers are significant.

 

The following table provides a breakdown of electric revenues by customer category. All other sources include gross wholesale sales from utility generation, net revenue from energy trading activity and sales to municipalities.

 

Customer Category  2016   2015 
Commercial   36.1%   35.4%
Residential   30.8    32.1 
Industrial   31.0    29.9 
All Other Sources   2.1    2.6 
Total   100.0%   100.0%

 

Capacity and Demand

 

As of December 31, 2016 OTP’s owned net-plant dependable kilowatt (kW) capacity was:

 

Baseload Plants    
Big Stone Plant   255,800 kW
Coyote Station   149,800 
Hoot Lake Plant   140,100 
Total Baseload Net Plant   545,700 kW
Combustion Turbine and Small Diesel Units   108,100 kW
Hydroelectric Facilities   2,500 kW
Owned Wind Facilities (rated at nameplate)     
Luverne Wind Farm (33 turbines)   49,500 kW
Ashtabula Wind Center (32 turbines)   48,000 
Langdon Wind Center (27 turbines)   40,500 
Total Owned Wind Facilities   138,000 kW

 

The baseload net plant capacity for Big Stone Plant and Coyote Station constitutes OTP’s ownership percentages of 53.9% and 35%, respectively. OTP owns 100% of the Hoot Lake Plant. During 2016, about 54% of OTP’s retail kwh sales were supplied from OTP generating plants with the balance supplied by purchased power.

 

6

 

 

In addition to the owned facilities described above, OTP had the following purchased power agreements in place on December 31, 2016:

 

Purchased Wind Power Agreements (rated at nameplate and greater than 2,000 kW)
Ashtabula Wind III   62,400 kW
Edgeley   21,000 
Langdon   19,500 
Total Purchased Wind   102,900 kW
Purchase of Capacity (in excess of 1 year and 500 kW)     
Great River Energy1   100,000 kW

1100,000 kiloWatt (kW) through May 2017, 25,000 kW June 2017 – May 2019, and 50,000 kW June 2019 – May 2021.

 

OTP has a direct control load management system which provides some flexibility to OTP to effect reductions of peak load. OTP also offers rates to customers which encourage off-peak usage.

 

OTP’s capacity requirement is based on MISO Module E requirements. OTP is required to have sufficient Zonal Resource Credits to meet its monthly weather normalized forecast demand, plus a reserve obligation. OTP met its MISO obligation for the 2016-2017 MISO planning year. OTP generating capacity combined with additional capacity under purchased power agreements (as described above) and load management control capabilities is expected to meet 2017 system demand and MISO reserve requirements.

 

Fuel Supply

 

Coal is the principal fuel burned at the Big Stone, Coyote and Hoot Lake generating plants. Coyote Station, a mine-mouth facility, burns North Dakota lignite coal. Hoot Lake Plant and Big Stone Plant burn western subbituminous coal.

 

The following table shows the sources of energy used to generate OTP’s net output of electricity for 2016 and 2015:

 

   2016   2015 
Sources  Net kwhs
Generated
(Thousands)		   % of Total
kwhs
Generated		   Net kwhs
Generated
(Thousands)		   % of Total
kwhs
Generated		 
Subbituminous Coal   1,419,901    50.3%   1,132,335    49.1%
Lignite Coal   844,225    29.9    662,450    28.7 
Wind and Hydro   517,396    18.4    493,276    21.4 
Natural Gas and Oil   40,257    1.4    17,907    0.8 
Total   2,821,779    100.0%   2,305,968    100.0%

 

OTP has the following primary coal supply agreements:

 

Plant Coal Supplier Type of Coal Expiration Date
Big Stone Plant Contura Coal Sales, LLC Wyoming subbituminous December 31, 2017
Big Stone Plant Peabody COALSALES, LLC Wyoming subbituminous December 31, 2017
Coyote Station Coyote Creek Mining Company, L.L.C. North Dakota lignite December 31, 2040
Hoot Lake Plant Cloud Peak Energy Resources LLC Montana subbituminous December 31, 2023

 

OTP’s anticipated coal needs for Big Stone Plant are secured under contract through December 2017.

 

In October 2012 the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton being paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. The LSA provides for the Coyote Station owners to purchase the membership interests in CCMC in the event of certain early termination events and also at the end of the term of the LSA.

 

OTP’s coal supply requirements for Hoot Lake Plant are secured under contract through December 2023.

 

7

 

 

Railroad transportation services to the Big Stone Plant and Hoot Lake Plant are provided under a common carrier rate by the BNSF Railway. The common carrier rate is subject to a mileage-based methodology to assess a fuel surcharge. The basis for the fuel surcharge is the U.S. average price of retail on-highway diesel fuel. No coal transportation agreement is needed for Coyote Station due to its location next to a coal mine.

 

The average cost of fuel consumed (including handling charges to the plant sites) per million British Thermal Units (Btu) for the years 2016, 2015, and 2014 was $2.146, $2.281 and $2.036, respectively.

 

General Regulation

 

OTP is subject to regulation of rates and other matters in each of the three states in which it operates and by the federal government for certain interstate operations.

 

A breakdown of electric rate regulation by each jurisdiction is as follows:

 

      2016     2015 
Rates  Regulation  % of
Electric
Revenues		   % of kwh
Sales		   % of
Electric
Revenues		   % of kwh
Sales		 
MN Retail Sales  MN Public Utilities Commission   47.5%   54.0%   47.2%   52.0%
ND Retail Sales  ND Public Service Commission   34.4    37.1    38.0    38.7 
SD Retail Sales  SD Public Utilities Commission   7.8    8.9    8.5    9.3 
Transmission & Wholesale  Federal Energy Regulatory Commission   10.3    —    6.3    — 
Total      100.0%   100.0%   100.0%   100.0%

 

OTP operates under approved retail electric tariffs in all three states it serves. OTP has an obligation to serve any customer requesting service within its assigned service territory. The pattern of electric usage can vary dramatically during a 24-hour period and from season to season. OTP’s tariffs are designed to recover the costs of providing electric service. To the extent peak usage can be reduced or shifted to periods of lower usage, the cost to serve all customers is reduced. In order to shift usage from peak times, OTP has approved tariffs in all three states for residential demand control, general service time of use and time of day, real-time pricing, and controlled and interruptible service. Each of these specialized rates is designed to improve efficient use of OTP resources, while giving customers more control over their electric bill. OTP also has approved tariffs in its three service territories which allow qualifying customers to release and sell energy back to OTP when wholesale energy prices make such transactions desirable.

 

With a few minor exceptions, OTP’s electric retail rate schedules provide for adjustments in rates based on the cost of fuel delivered to OTP’s generating plants, as well as for adjustments based on the cost of electric energy purchased by OTP. OTP also credits certain margins from wholesale sales to the fuel and purchased power adjustment. The adjustments for fuel and purchased power costs are presently based on a two month moving average in Minnesota and by the Federal Energy Regulatory Commission (FERC), a three month moving average in South Dakota and a four month moving average in North Dakota. These adjustments are applied to the next billing period after becoming applicable. These adjustments also include an over or under recovery mechanism, which is calculated on an annual basis in Minnesota and on a monthly basis in North Dakota and South Dakota.

 

Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of the material regulations of each jurisdiction applicable to OTP’s electric operations, as well as any specific electric rate proceedings during the last three years with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC. The Company’s manufacturing and plastic pipe businesses are not subject to direct regulation by any of these agencies.

 

Major Capital Expenditure Projects

 

The Big Stone South – Brookings MVP and CapX2020 Project—This 345 kiloVolt (kV) transmission line, currently under construction, will extend approximately 70 miles between a substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Northern States Power – MN (NSP MN), a subsidiary of Xcel Energy Inc., jointly developed this project, and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as a Multi-Value Project (MVP) under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly

 

8

 

 

assigned to those who benefit. Construction began on this line in the third quarter of 2015 and the line is expected to be in service in fall 2017. OTP’s total capital investment in this project is expected to be approximately $80 million, which includes certain assets that will be owned 100% by OTP.

 

The Big Stone South – Ellendale MVP—This is a 345 kV transmission line that will extend 163 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. (MDU), and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019. OTP’s total capital investment in this project is expected to be approximately $149 million, which includes certain assets that will be owned 100% by OTP.

 

Capacity Expansion 2020 (CapX2020) Transmission Line Projects—CapX2020 is a joint initiative of eleven investor-owned, cooperative, and municipal utilities in Minnesota and the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service.

 

Fargo–Monticello 345 kV CapX2020 Project (the Fargo Project)—OTP has invested approximately $81 million and has a 14.2% ownership interest in the jointly-owned assets of this 240-mile transmission line, and owns 100% of certain assets of the project. The final phase of this project was energized on April 2, 2015.

 

Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project)—OTP has invested approximately $26 million and has a 4.8% ownership interest in this 250-mile transmission line. The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011. The final segments of this line were energized on March 26, 2015.

 

Big Stone Plant Air Quality Control System (AQCS)— OTP completed construction and testing of the Big Stone Plant AQCS in the fourth quarter of 2015 and placed the AQCS into commercial operation on December 29, 2015. OTP’s capitalized cost of the project, excluding allowance for funds used during construction, was approximately $200 million.

 

Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.

 

Minnesota

 

Under the Minnesota Public Utilities Act, OTP is subject to the jurisdiction of the MPUC with respect to rates, issuance of securities, depreciation rates, public utility services, construction of major utility facilities, establishment of exclusive assigned service areas, contracts and arrangements with subsidiaries and other affiliated interests, and other matters. The MPUC has the authority to assess the need for large energy facilities and to issue or deny certificates of need, after public hearings, within one year of an application to construct such a facility.

 

Pursuant to the Minnesota Power Plant Siting Act, the MPUC has authority to select or designate sites in Minnesota for new electric power generating plants (50,000 kW or more) and routes for transmission lines (100 kV or more) in an orderly manner compatible with environmental preservation and the efficient use of resources, and to certify such sites and routes as to environmental compatibility after an environmental impact study has been conducted by the Minnesota Department of Commerce (MNDOC) and the Office of Administrative Hearings has conducted contested case hearings.

 

The Minnesota Division of Energy Resources, part of the MNDOC, is responsible for investigating all matters subject to the jurisdiction of the MNDOC or the MPUC, and for the enforcement of MPUC orders. Among other things, the MNDOC is authorized to collect and analyze data on energy including the consumption of energy, develop recommendations as to energy policies for the governor and the legislature of Minnesota and evaluate policies governing the establishment of rates and prices for energy as related to energy conservation. The MNDOC also has the power, in the event of energy shortage or for a long-term basis, to prepare and adopt regulations to conserve and allocate energy.

 

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2016 General Rate Case—On February 16, 2016 OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested an allowed rate of return on rate base of 8.07% and an allowed rate of return on equity of 10.4% based on an equity ratio of 52.5% of total capital. On April 14, 2016 the MPUC issued an order approving an interim rate increase of 9.56% to the base rate portion of customers’ bills effective April 16, 2016, as modified and subject to refund. The request and interim rate information is detailed in the table below:

 

($ in thousands)  Annualized or
Test Year		   Actual Through
December 31, 2016		 
Revenue Increase Requested  $19,296      
Increase Percentage Requested   9.80%     
Jurisdictional Rate Base  $483,000      
Interim Revenue Increase (subject to refund)  $16,816   $10,976 

 

The major components of the requested rate increase are summarized below:

 

Revenue Requirement Deficiency Cost Factors (in thousands)  2016 Test Year
Allocation		 
Increased Rate Base  $10,000 
Increased Expenses   7,700 
Other   1,596 
Total Requested Revenue Increase  $19,296 
Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset   (2,480)
Approved Interim Revenue Increase (subject to refund)  $16,816 

 

The deadline for submission of intervenor direct testimony was August 16, 2016. Direct testimony of the MNDOC included a recommendation for an 8.87% allowed rate of return on equity, and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. Hearings before the Administrative Law Judge (ALJ) occurred in October 2016. On January 5, 2017 the ALJ’s report was issued which included a recommendation for a 9.54% allowed rate of return on equity.

 

Based on OTP’s modifications to its original request and other expected outcomes in the aforementioned rate case, OTP has recorded an estimated interim rate refund of $3.6 million as of December 31, 2016. Oral arguments before the MPUC are expected to occur in late February 2017. The MPUC is expected to make its final decision in March 2017 and issue its written order in spring 2017.

 

2010 General Rate Case—OTP’s most recently completed general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%.

 

Integrated Resource Plan (IRP)—Minnesota law requires utilities to submit to the MPUC for approval a 15-year advance IRP. A resource plan is a set of resource options a utility could use to meet the service needs of its customers over a forecast period, including an explanation of the utility’s supply and demand circumstances, and the extent to which each resource option would be used to meet those service needs. The MPUC’s findings of fact and conclusions regarding resource plans shall be considered prima facie evidence, subject to rebuttal, in Certificate of Need (CON) hearings, rate reviews and other proceedings. Typically, the filings are submitted every two years.

 

On December 5, 2014 the MPUC issued an order approving OTP’s 2014-2028 IRP filing, which included the following items:

 

·Authorization to add up to 300 MW of wind between 2017 and 2021 if it is cost effective and does not negatively impact OTP’s electric system operation.
   
·Construction of solar generation sufficient to comply with the Minnesota Solar Energy Standard by 2020.
   
·Confirmation of a 1.5% energy savings goal, as filed in OTP’s triennial Minnesota Conservation Improvement Program (MNCIP) plan.
   
·Authorization to obtain 200 MW, subject to need, of intermediate natural gas generation in the 2019-2021 timeframe.

 

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On September 14, 2015 the MPUC granted OTP a six-month extension to June 1, 2016 to file its latest IRP. The extension allowed OTP time to model compliance with final rules on proposed standards of performance for carbon dioxide (CO2) emissions from fossil fuel-fired power plants published by the Environmental Protection Agency (EPA) on October 23, 2015 and to incorporate planned wind and natural gas-fired generation additions.

 

OTP filed its 2017-2031 IRP with the MPUC on June 1, 2016, which included the following items:

 

·Adding 200 megawatts (MW) of wind resources (100 MW in 2018 and 100 MW in 2020) and authorization to add up to 100 MW more at a later time. With three 100-MW additions to OTP’s wind energy resources, wind would serve approximately 34% of OTP’s customers' energy needs.
   
·Adding 30 MW of solar resources by 2020 to comply with Minnesota's Solar Energy Standard.
   
·Adding a 248 MW simple-cycle natural gas-fired plant in 2021 to replace Hoot Lake Plant’s two coal-fired steam turbines to be retired in 2021. The natural gas-fired plant will likely be located in close proximity to a high-voltage transmission line and a large natural gas pipeline within OTP’s service area.

 

OTP expects the MPUC hearing on the 2017-2031 IRP to occur in late February or early March 2017.

 

Renewable Energy Standards, Conservation, Renewable Resource Riders—Minnesota law favors conservation over the addition of new resources. In addition, Minnesota law requires the use of renewable resources where new supplies are needed, unless the utility proves that a renewable energy facility is not in the public interest. An existing environmental externality law requires the MPUC, to the extent practicable, to quantify the environmental costs associated with each method of electricity generation, and to use such monetized values in evaluating generation resources. The MPUC must disallow any nonrenewable rate base additions (whether within or outside of the state) or any related rate recovery, and may not approve any nonrenewable energy facility in an IRP, unless the utility proves that a renewable energy facility is not in the public interest. The state has prioritized the acceptability of new generation with wind and solar ranked first and coal and nuclear ranked fifth, the lowest ranking. The MPUC’s current estimate of the range of costs of future CO2 regulation to be used in modeling analyses for resource plans is $9 to $34/ton of CO2 commencing in 2022. The MPUC is required to annually update these estimates.

 

Minnesota has a renewable energy standard which requires OTP to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 17% by 2016; 20% by 2020 and 25% by 2025. In addition, Minnesota law requires 1.5% of total Minnesota electric sales by public utilities to be supplied by solar energy by 2020. At least 10% of the 1.5% requirement must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kWs or less. Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. OTP has acquired sufficient renewable resources to currently comply with Minnesota renewable energy standards. OTP is evaluating potential options for maintaining compliance and meeting the solar energy standard. OTP’s projected capital expenditures include $40 million for a solar project in 2019. OTP’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.

 

Under the Next Generation Energy Act of 2007, an automatic adjustment mechanism was established to allow Minnesota electric utilities to recover investments and costs incurred to satisfy the requirements of the renewable energy standard. The MPUC is authorized to approve a rate schedule rider to enable utilities to recover the costs of qualifying renewable energy projects that supply renewable energy to Minnesota customers. Cost recovery for qualifying renewable energy projects can be authorized outside of a rate case proceeding, provided that such renewable projects have received previous MPUC approval. Renewable resource costs eligible for recovery may include return on investment, depreciation, operation and maintenance costs, taxes, renewable energy delivery costs and other related expenses.

 

Minnesota Conservation Improvement Programs—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state's energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota.

 

The MNDOC may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC.

 

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On September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case.

 

OTP recognized a financial incentive for 2014 of $3.0 million due, in part, to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016. Additionally, OTP saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million along with an updated surcharge with an effective date of October 1, 2015.

 

Based on results from the 2015 MNCIP program year, OTP recognized a financial incentive of $4.2 million. The 2015 MNCIP program resulted in an approximate 39% increase in energy savings compared to 2014 program results. On April 1, 2016 OTP requested approval for recovery of its 2015 MNCIP program costs not included in base rates, a $4.3 million financial incentive and an update to the MNCIP surcharge from the MPUC. On July 19, 2016 the MPUC issued an order approving OTP’s request with an effective date of October 1, 2016.

 

Based on results from the 2016 MNCIP program year, OTP recognized a financial incentive of $5.1 million in 2016. The 2016 program resulted in an approximate 18% increase in energy savings compared to 2015 program results. OTP will request approval for recovery of its 2016 MNCIP program costs not included in base rates, a $5.1 million financial incentive and an update to the MNCIP surcharge from the MPUC by April 1, 2017.

 

On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes to the MNCIP financial incentive. The new model will provide utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism.

 

In 2016 the MNDOC opened an additional docket to investigate how investor-owned utilities calculate their avoided costs pertaining to generation capacity, energy, transmission and distribution. Avoided costs are the basis of MNCIP program benefits which, going forward, will establish OTP’s financial incentive. On May 23, 2016 the MNDOC accepted OTP’s 2017 avoided costs calculation, but is requiring Minnesota investor-owned utilities to undergo an analysis of transmission and distribution avoided costs for 2018 and 2019. OTP is participating in a stakeholder group with the MNDOC, Xcel Energy Inc., and Minnesota Power to determine the best method for calculating avoided costs. Results from this work should be submitted to the MNDOC in the second quarter of 2017.

 

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act (the MPU Act) provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a CON proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility's retail customers, or exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The MPU Act also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Finally, under certain circumstances, the MPU Act also authorizes TCR riders to recover the costs associated with distribution planning and investments in distribution facilities to modernize the utility grid. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers.

 

OTP filed an annual update to its Minnesota TCR rider on February 7, 2013 to include three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but found capitalized internal costs, costs in excess of CON estimates and a carrying charge ineligible for recovery through the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP is seeking recovery of the capitalized internal costs and costs in excess of CON estimates in its current general rate case filing in Minnesota. In response to the MPUC’s approval of OTP’s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. OTP filed an annual update to its Minnesota TCR rider on September 30, 2015 requesting revenue recovery of approximately $7.8 million. A supplemental filing to the update was made on December 21, 2015 to address an issue surrounding the proration of accumulated deferred

 

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income taxes and, in an unrelated adjustment, the TCR rider update revenue request was reduced to $7.2 million. On March 9, 2016 the MPUC issued an order approving OTP’s annual update to its TCR rider, with an effective date of April 1, 2016.

 

OTP filed an update to its TCR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The proposed rate changes went into effect on September 1, 2016. The MPUC granted extensions to the MNDOC to file initial comments in this docket until February 2, 2017.

 

In OTP’s 2016 general rate case, the MNDOC has argued that the MPUC should require OTP to include in the TCR rider retail rate base 100% of OTP’s investment in the Big Stone South – Brookings and Big Stone South – Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. OTP has opposed this treatment, arguing the projects are appropriately assigned to the FERC jurisdiction, and the FERC’s determination of the projects’ revenue requirements should not be altered by forcing the revenues into the retail revenue requirement calculations. In the general rate case proceeding, the ALJ recommended that the MPUC should affirm OTP’s treatment. If the MPUC finds that the MNDOC’s treatment should be followed, it would result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time.

 

Environmental Cost Recovery (ECR) Rider—On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements included a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. The MPUC approved OTP’s 2014 ECR rider annual update request on November 24, 2014 with an effective date of December 1, 2014. OTP filed its 2015 annual update on July 31, 2015, with a request to keep the 2014 annual update rate in place. On December 21, 2015 OTP filed a supplemental filing with updated financial information. The MPUC issued an order on March 9, 2016 approving OTP’s request to leave the 2014 annual update rate in place. OTP filed an update to its Minnesota ECR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request, with an effective date of September 1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis and has since granted extensions to the MNDOC to file initial comments in this docket until February 2, 2017. Reply comments were due from OTP on February 13, 2017.

 

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery of these costs. These costs are included in OTP’s 2016 general rate case in Minnesota and are being considered for recovery either through the FCA rider or general rates. These costs are currently being expensed as incurred.

 

Capital Structure Petition—Minnesota law requires an annual filing of a capital structure petition with the MPUC. In this filing the MPUC reviews and approves the capital structure for OTP. Once the petition is approved, OTP may issue securities without further petition or approval, provided the issuance is consistent with the purposes and amounts set forth in the approved capital structure petition. The MPUC approved OTP’s most recent capital structure petition on August 2, 2016, allowing for an equity to total capitalization ratio between 47.5% and 58.1%, with total capitalization not to exceed $1,123,168,000 until the MPUC issues a new capital structure order for 2017. OTP is required to file its 2017 capital structure petition no later than May 1, 2017.

 

North Dakota

 

OTP is subject to the jurisdiction of the NDPSC with respect to rates, services, certain issuances of securities, construction of major utility facilities and other matters. The NDPSC periodically performs audits of gas and electric utilities over which it has rate setting jurisdiction to determine the reasonableness of overall rate levels. In the past, these audits have occasionally resulted in settlement agreements adjusting rate levels for OTP.

 

The North Dakota Energy Conversion and Transmission Facility Siting Act grants the NDPSC the authority to approve sites in North Dakota for large electric generating facilities and high voltage transmission lines. This Act is similar to the Minnesota Power Plant Siting Act described above and applies to proposed wind energy electric power generating plants exceeding 500 kW of electricity, non-wind energy electric power generating plants exceeding 50,000 kW and transmission lines with a design in excess of 115 kV. OTP is required to submit a ten-year plan to the NDPSC biennially.

 

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The NDPSC reserves the right to review the issuance of stocks, bonds, notes and other evidence of indebtedness of a public utility. However, the issuance by a public utility of securities registered with the SEC is expressly exempted from review by the NDPSC under North Dakota state law.

 

General Rates—OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.

 

Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment (NDRRA) which enables OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment. The NDPSC approved OTP’s 2013 annual update to its NDRRA on March 12, 2014 with an effective date of April 1, 2014, which resulted in a 13.5% reduction in the NDRRA rate. The NDPSC approved OTP’s 2014 annual update to the NDRRA, including a change in rate design from an amount per kwh consumed to a percentage of a customer’s bill, on March 25, 2015 with an effective date of April 1, 2015. OTP submitted its 2015 annual update to the NDRRA rider rate on December 31, 2015 with a requested implementation date of April 1, 2016. On February 25, 2016 OTP made a supplemental filing to address the impact of bonus depreciation for income taxes and related deferred tax assets on the NDRRA, as well as an adjustment to the estimated amount of Federal Production Tax Credits used. The NDPSC approved the NDRRA 2015 annual update on June 22, 2016 with an effective date of July 1, 2016. The updated NDRRA reflects a reduction in the return on equity (ROE) component of the rate from 10.75%, approved in OTP’s most recent general rate case, to 10.50%. OTP submitted its 2016 annual update to the NDRRA rider rate on December 30, 2016, requesting a decrease to the NDRRA rate from 7.573% to 7.005%, with a requested implementation date of April 1, 2017.

 

Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case. The NDPSC approved OTP’s 2014 annual update to its TCR rider rate on December 17, 2014 with an effective date of January 1, 2015. On August 31, 2015 OTP filed its 2015 annual update to its North Dakota TCR rider rate requesting recovery of approximately $10.2 million for 2016 compared with $8.5 million for 2015, including costs assessed by the MISO as well as new costs from the Southwest Power Pool (SPP) that OTP began incurring January 1, 2016. These new costs are associated with OTP’s load connected to the transmission system of Central Power Electric Cooperative (CPEC). OTP’s load became subject to SPP transmission-related charges when CPEC transmission assets were added to the SPP. The NDPSC approved OTP’s 2015 annual update to its TCR rider rate on December 16, 2015, with an effective date of January 1, 2016. On September 1, 2016 OTP filed its annual update to the TCR rider requesting a revenue requirement of $5.7 million, which includes a reduction of $2.6 million for a projected over-collection for 2016. Primary drivers of the decrease from the 2015 updated rider rate include the impact of federal bonus depreciation and unresolved MISO ROE complaint proceedings. OTP filed a supplemental filing on September 14, 2016, requesting that the over-collection balance be spread over the next two years for purposes of reducing the volatility of the rates from year to year. The NDPSC approved the update on December 14, 2016. The new rates went into effect on January 1, 2017.

 

Environmental Cost Recovery Rider—On December 18, 2013 the NDPSC approved OTP’s request for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. The ECR provides for a current return on CWIP and a return on investment at the level approved in OTP’s most recent general rate case. On March 31, 2014 OTP filed an annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR. This update included a request to increase the ECR rider rate from 7.531% to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective date of July 1, 2015, along with the approval of recovery of OTP’s North Dakota jurisdictional share of Hoot Lake Plant Mercury and Air Toxics Standards (MATS) project costs.

 

On March 31, 2016 OTP filed its annual update to the ECR rider requesting a reduction in the rate from 9.193% to 7.904% of base rates, or a revenue requirement reduction from $12.2 million to $10.4 million, effective July 1, 2016. The rate reduction request was primarily due to the Company’s 2015 bonus depreciation election for income taxes, which reduces revenue requirements. The filing was approved on June 22, 2016.

 

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance costs. On February 25, 2015 the NDPSC approved recovery of these costs through modification of the ECR rider, instead of recovery through the FCA as OTP had proposed. The ECR rider reagent and emissions allowance charge became effective May 1, 2015.

 

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South Dakota

 

Under the South Dakota Public Utilities Act, OTP is subject to the jurisdiction of the SDPUC with respect to rates, public utility services, construction of major utility facilities, establishment of assigned service areas and other matters. Under the South Dakota Energy Facility Permit Act, the SDPUC has the authority to approve sites in South Dakota for large energy conversion facilities (100,000 kW or more) and transmission lines with a design of 115 kV or more.

 

2010 General Rate Case—OTP’s most recent general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued on April 21, 2011 and effective with bills rendered on and after June 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.50%.

 

Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. The SDPUC approved OTP’s 2013 annual update on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP’s 2014 annual update on February 13, 2015 with an effective date of March 1, 2015. OTP filed its 2015 annual update on October 30, 2015 with a proposed effective date of March 1, 2016. A supplemental filing was made on February 3, 2016 to true-up the filing to include the impact of bonus depreciation elected for 2015, the inclusion of a deferred tax asset relating to a net operating loss and the proration of accumulated deferred income taxes. This update included the recovery of new SPP transmission costs OTP began to incur on January 1, 2016. On February 12, 2016 the SDPUC approved OTP’s annual update to its TCR rider, with an effective date of March 1, 2016. On November 1, 2016 OTP filed the annual update to the South Dakota TCR rider. OTP made a supplemental filing on January 20, 2017 to include updated costs through December 2016 as well as updated forecast information. The proposed effective date of the new rates is March 1, 2017.

 

Environmental Cost Recovery Rider—On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover OTP’s South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014. On August 31, 2015 OTP filed its annual update to the South Dakota ECR requesting recovery of approximately $2.7 million in annual revenue. The SDPUC approved the request on October 15, 2015 with an effective date of November 1, 2015. On August 31, 2016 OTP filed its 2016 update to the ECR rider, requesting recovery of approximately $2.3 million in annual revenue. The SDPUC approved the request on October 26, 2016 with an effective date of November 1, 2016. The lower revenue requirement is a result of the implementation of federal bonus depreciation taken on the Big Stone Plant AQCS.

 

Reagent Costs and Emission Allowances—On August 1, 2014 OTP filed a request with the SDPUC to revise its FCA rider in South Dakota to include recovery of reagent and emission allowance costs. On September 16, 2014 the SDPUC approved OTP’s request to include recovery of these costs in its South Dakota FCA rider.

 

Energy Efficiency Plan (EEP)—The SDPUC has encouraged all investor-owned utilities in South Dakota to be part of an Energy Efficiency Partnership to significantly reduce energy use. The plan is being implemented with program costs, carrying costs and a financial incentive being recovered through an approved rider.

 

On May 1, 2014 OTP filed a request with the SDPUC for approval of updates to its EEP based on 2013 results. On August 26, 2014 the SDPUC issued a written order approving the maximum available incentive payment limited to 30% of the budget amount provided in the EEP, or $84,000. In addition to the incentive payment approval, the SDPUC approved OTP’s proposal to leave the South Dakota Energy Efficiency Adjustment Rider at $0.00103/kwh.

 

On May 1, 2015 OTP filed its 2014 South Dakota EEP Status Report, financial incentive and surcharge adjustment along with a request for approval of an incentive of $105,000 and EEP surcharge increase to $0.00152/kwh. On July 14, 2015 the SDPUC issued a written order approving OTP’s 2014 EEP Status Report, incentive and surcharge increases.

 

On April 29, 2016 OTP filed its 2015 South Dakota EEP Status Report, financial incentive and surcharge adjustment with the SDPUC. The filing requested approval of an incentive of $105,900 and a decrease in the EEP surcharge from $0.00152/kwh to $0.00114/kwh effective July 1, 2016. The SDPUC approved the request. On April 29, 2016 OTP also filed its 2017-2019 goals and budgets for its South Dakota EEP triennial plan. For the 2017, 2018 and 2019 EEP planning years, OTP has proposed energy savings goals and budgets of 3,804,094 kwh and $449,000 in 2017, 3,805,177 kwh and $449,000 in 2018 and 3,806,262 kwh and $449,000 in 2019. On November 22, 2016 the SDPUC approved OTP’s 2017-2019 EEP triennial plan with certain conditions.

 

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FERC

 

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935, as amended. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.

 

Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing.

 

Effective January 1, 2012 the FERC authorized OTP to recover 100% of prudently incurred CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission Expansion Plan: the Big Stone South–Brookings MVP and the Big Stone South–Ellendale MVP.

 

On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. On October 16, 2014 the FERC issued an order finding that the current MISO ROE may be unjust and unreasonable and setting the issue for hearing. Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the United States Court of Appeals for the District of Columbia (D.C. Circuit). A non-binding decision by the presiding ALJ was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%.

 

On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.

 

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the D.C. Circuit. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. The FERC is expected to issue its order not earlier than spring 2017.

 

Based on a potential reduction by the FERC in the ROE component of the MISO Tariff, OTP recorded reductions in revenue of $1.6 million in 2016 and $1.1 million in 2015 and has a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE.

 

Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with FERC to market participants, revisions to the RSG rate based on several FERC orders and FERC’s decision to resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. These consolidated cases are currently held in abeyance while the parties engage in mediation before the D.C. Circuit. OTP is an intervenor in these cases and a participant in mediation. The scope of the issues that will be subject to appeal at the D.C. Circuit have not yet been finalized. In addition, MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders. Although the Company cannot estimate OTP’s exposure at this time, a final order reversing the relevant FERC orders could have a material adverse effect on the Company’s results of operations.

 

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NAEMA

 

OTP is a member of the North American Energy Marketers Association (NAEMA) which is an independent, non-profit trade association representing entities involved in the marketing of energy or in providing services to the energy industry. NAEMA has over 150 members with operations in 48 states and Canada. Power pool sales are conducted continuously through NAEMA in accordance with schedules filed by NAEMA with the FERC.

North American Electric Reliability Corporation (NERC)

 

NERC is an international regulatory authority, subject to oversight by the FERC and governmental authorities in Canada, whose mission is to assure the reliability of the bulk power system in North America. As an owner and operator within the bulk power system, OTP is required to comply with NERC reliability standards, including standards on cybersecurity and protection of critical infrastructure. The FERC approved NERC’s critical infrastructure and protection standards in November 2014.

 

Midwest Reliability Organization (MRO)

 

OTP is a member of the MRO. The MRO is a non-profit organization dedicated to ensuring the reliability and security of the bulk power system in the north central region of North America, including parts of both the United States and Canada. MRO began operations in 2005 and is one of eight regional entities in North America operating under authority from regulators in the United States and Canada through a delegation agreement with the NERC. The MRO is responsible for: (1) developing and implementing reliability standards, (2) enforcing compliance with those standards, (3) providing seasonal and long-term assessments of the bulk power system’s ability to meet demand for electricity, and (4) providing an appeals and dispute resolution process.

 

The MRO region covers roughly one million square miles spanning the provinces of Saskatchewan and Manitoba, the states of North Dakota, Minnesota, Nebraska and the majority of the territory in the states of South Dakota, Iowa and Wisconsin. The region includes more than 130 organizations that are involved in the production and delivery of power to more than 20 million people. These organizations include municipal utilities, cooperatives, investor-owned utilities, a federal power marketing agency, Canadian Crown Corporations, independent power producers and others who have interests in the reliability of the bulk power system.

 

To ensure our compliance with NERC standards, the MRO periodically audits OTP. OTP’s most recent audit began with a notification in October 2015 and MRO audit staff conducted fieldwork in January 2016. On January 23, 2017 OTP received its draft audit report from the MRO audit team. Based on the results of their fieldwork and subsequent discussions with OTP, the MRO found no potential violations at OTP.

 

MISO

 

OTP is a member of the MISO. As the transmission provider and security coordinator for the region, the MISO seeks to optimize the efficiency of the interconnected system, provide regional solutions to regional planning needs and minimize risk to reliability through its security coordination, long-term regional planning, market monitoring, scheduling and tariff administration functions. The MISO covers a broad region containing all or parts of 15 states and the Canadian province of Manitoba. The MISO has operational control of OTP’s transmission facilities above 100 kV, but OTP continues to own and maintain its transmission assets.

 

Through the MISO Energy Markets, MISO seeks to develop options for energy supply, increase utilization of transmission assets, optimize the use of energy resources across a wider region and provide greater visibility of data. MISO aims to facilitate a more cost-effective and efficient use of the wholesale bulk electric system.

 

The MISO Ancillary Services Market (ASM) facilitates the provision of Regulation, Spinning Reserve and Supplemental Reserves. The ASM integrates the procurement and use of regulation and contingency reserves with the existing Energy Market. OTP has actively participated in the market since its commencement.

 

Other

 

OTP is subject to various federal laws, including the Public Utility Regulatory Policies Act of 1978 and the Energy Policy Act of 1992 (which are intended to promote the conservation of energy and the development and use of alternative energy sources) and the Energy Policy Act of 2005.

 

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Competition, Deregulation and Legislation

 

Electric sales are subject to competition in some areas from municipally owned systems, rural electric cooperatives and, in certain respects, from on-site generators and cogenerators. Electricity also competes with other forms of energy. The degree of competition may vary from time to time depending on relative costs and supplies of other forms of energy.

 

The Company believes OTP is well positioned to be successful in a competitive environment. A comparison of OTP’s electric retail rates to the rates of other investor-owned utilities, cooperatives and municipals in the states OTP serves indicates OTP’s rates are competitive.

 

Legislative and regulatory activity could affect operations in the future. OTP cannot predict the timing or substance of any future legislation or regulation. The Company does not expect retail competition to come to the states of Minnesota, North Dakota or South Dakota in the foreseeable future. There has been no legislative action regarding electric retail choice in any of the states where OTP operates. The Minnesota legislature has in the past considered legislation that, if passed, would have limited the Company’s ability to maintain and grow its nonelectric businesses.

 

OTP is unable to predict the impact on its operations resulting from future regulatory activities, from future legislation or from future taxes that may be imposed on the source or use of energy.

 

Environmental Regulation

 

Impact of Environmental Laws—OTP’s existing generating plants are subject to stringent federal and state standards and regulations regarding, among other things, air, water and solid waste pollution. In the five years ended December 31, 2016 OTP invested approximately $210 million in environmental control facilities. The 2017 and 2018 construction budgets include approximately $6 million and $5 million, respectively, for environmental equipment for existing facilities.

 

Air Quality - Criteria Pollutants—Pursuant to the Clean Air Act (CAA), the EPA has promulgated national primary and secondary standards for certain air pollutants.

 

The primary fuels burned by OTP’s steam generating plants are North Dakota lignite coal and western subbituminous coal. Electrostatic precipitators have been installed at the principal units at the Hoot Lake Plant. The Hoot Lake Plant is currently operating within all presently applicable federal and state air quality and emission standards.

 

The South Dakota Department of Environment and Natural Resources (DENR) issued a Title V Operating Permit to the Big Stone Plant on June 9, 2009, allowing for operation. The Big Stone Plant continues to operate under Title V permit provisions. The Big Stone Plant is currently operating within all presently applicable federal and state air quality and emission standards.

 

The Coyote Station is equipped with sulfur dioxide (SO2) removal equipment. The removal equipment—referred to as a dry scrubber—consists of a spray dryer, followed by a fabric filter, and is designed to desulfurize hot gases from the stack. The fabric filter collects spray dryer residue along with the fly ash. The Coyote Station is currently operating within all presently applicable federal and state air quality and emission standards.

 

The CAA, in addressing acid deposition, imposed requirements on power plants in an effort to reduce national emissions of SO2 and nitrogen oxides (NOx).

 

The national Acid Rain Program SO2 emission reduction goals are achieved through a market based system under which power plants are allocated "emissions allowances" that require plants to either reduce their SO2 emissions or acquire allowances from others to achieve compliance. Each allowance is an authorization to emit one ton of SO2. SO2 emission requirements are currently being met by all of OTP’s generating facilities without the need to acquire additional allowances for compliance with the acid deposition provisions of the CAA.

 

The national Acid Rain Program NOx emission reduction goals are achieved by imposing mandatory emissions standards on individual sources. All of OTP’s generating facilities met the NOx standards during 2016.

 

The Cross-State Air Pollution Rule (CSAPR) requires SO2 and NOx emission reductions in primarily eastern states in order to allow downwind states to achieve national ambient air quality standards (NAAQS). CSAPR's Phase 1 emission budgets began on January 1, 2015 for the annual SO2 and NOx programs, with stricter Phase 2 budgets beginning in 2017.

 

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The CSAPR rule applies to OTP’s Solway gas peaking plant and the Hoot Lake coal-fired plant in Minnesota. Hoot Lake Plant may be required to purchase SO2 allowances to continue operating at historical levels. Minnesota is considered a Group 2 state for SO2 compliance. Any SO2 allowances that need to be obtained for Hoot Lake Plant will need to be from an entity in a Group 2 state. However, due to reduced dispatch of Hoot Lake Plant in 2016 and early 2017 due to power market conditions, and a decline in Group 2 SO2 allowance prices throughout 2016, the impact of the CSAPR rule is anticipated to be minimal.

 

On September 7, 2016 the EPA finalized an update to the CSAPR to address interstate emission transport with respect to the more recent 2008 ozone NAAQS. The updated CSAPR does not apply to Minnesota, North Dakota and South Dakota.

 

On October 1, 2015 the EPA announced that it tightened the primary and secondary NAAQS for ozone from 75 parts per billion (ppb) to 70 ppb. This was at the upper end of the range of which the EPA had proposed, which was 65 to 70 ppb. As set forth in the rule, EPA requested that states submit their initial ozone designation recommendations no later than October 1, 2016. All of the states in which OTP operates recommended that they be designated as attainment. EPA will review these recommendations, along with 2014-2016 air quality data, to make final determinations of whether areas are in attainment with the new standard by October 1, 2017. Nonattainment areas are required to meet the standard in the 2020 to 2037 timeframe, with deadlines depending on the severity of an area's ozone problem. Several parties filed petitions for review in the D.C. Circuit challenging the rule and litigation is now pending.

 

In June 2010, the EPA established a new primary NAAQS for SO2 at a level of 75 ppb on a 1-hour average. Designations for this standard are proceeding under several different pathways. For certain large sources as defined by 2012 emissions, including Big Stone Plant and Coyote Station, the EPA entered into a consent decree with the Sierra Club/Natural Resources Defense Council that required the EPA to promulgate final designations near those sources by July 2, 2016. On June 30, 2016, the EPA signed a final rule that designated the areas around Big Stone Plant and Coyote Station as being in attainment/unclassifiable with the 1-hour SO2 NAAQS. Numerous other sources, including Hoot Lake Plant, are covered by the EPA's final Data Requirements Rule (DRR) that was finalized in August 2015. The DRR requires states to provide either modeling or monitoring data to adequately characterize SO2 emissions surrounding those sources. Based on modeling, in January 2017, the state of Minnesota recommended to the EPA that the area surrounding Hoot Lake Plant be designated as attainment. The EPA will evaluate the state submittals, and it is anticipated that the EPA will issue final designations for the DRR by the end of 2017.

 

Air Quality – Hazardous Air Pollutants—On December 16, 2011 the EPA signed a final rule to reduce mercury and other air toxics emissions from power plants known as the MATS rule. The final rule became effective on April 16, 2012, and plants had until April 16, 2015 to comply. However, the EPA encouraged state permitting authorities to broadly grant a one-year compliance extension to plants that need additional time to install controls. With the installation of new pollution control equipment in 2015, OTP's affected units are meeting current requirements. Emissions monitoring equipment and/or stack testing is being used to verify compliance with the standards. Litigation surrounding the MATS rule is ongoing despite the expiration of the compliance deadlines, and the rule remains in effect while the litigation continues. On April 15, 2016 the EPA issued a supplemental finding that the MATS rule continues to be “appropriate and necessary” when considering the costs of compliance. This finding is being challenged by several parties.

 

Air Quality – EPA New Source Review Enforcement Initiative—In 1998 the EPA announced its New Source Review Enforcement Initiative targeting coal-fired power plants, petroleum refineries, pulp and paper mills and other industries for alleged violations of the EPA’s New Source Review rules. These rules require owners or operators that construct new major sources or make major modifications to existing sources to obtain permits and install air pollution control equipment at affected facilities. Pursuant to the Initiative, the EPA has attempted to determine if emission sources violated certain provisions of the CAA by making major modifications to their facilities without installing state-of-the-art pollution controls. OTP has not received any recent requests from the EPA, pursuant to Section 114(a) of the CAA, to provide information relative to past operation and capital construction projects at its coal-fired plants.

 

Air Quality – Regional Haze Program—The EPA promulgated the Regional Haze Rule in 1999, and on June 15, 2005 the EPA provided final guidelines for conducting Best-Available Retrofit Technology (BART) determinations under the rule. The Regional Haze Rule requires emissions reductions from BART-eligible sources that are deemed to contribute to visibility impairment in Class I air quality areas. Big Stone Plant is BART eligible, and the South Dakota DENR determined that the plant is subject to emission reduction requirements based on the modeled contribution of the plant emissions to visibility impairment in downwind Class I air quality areas. Based on the South Dakota DENR's BART determination and the final South Dakota Regional Haze State Implementation Plan (SIP) approved by the EPA on March 29, 2012, Big Stone Plant was required to install Selective Catalytic Reduction and separated over-fire air to reduce NOx emissions, dry flue gas desulfurization to reduce SO2 emissions, and a new baghouse for particulate matter control. The Big Stone Plant BART compliant AQCS equipment was placed into commercial operation on December 29, 2015.

 

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The North Dakota Regional Haze SIP requires that Coyote Station reduce its NOx emissions to 0.5 pounds per million Btu as calculated on a 30-day rolling average basis beginning on July 1, 2018. The control equipment was installed during a spring 2016 outage, and tuning of the equipment is ongoing.

 

Air Quality – Greenhouse Gas (GHG) Regulation—Combustion of fossil fuels for the generation of electricity is a considerable stationary source of CO2 emissions in the United States and globally. OTP is an owner or part-owner of three baseload, coal-fired electricity generating plants and three fuel-oil or natural gas-fired combustion turbine peaking plants with a combined net dependable capacity of 650 MW. In 2016 these plants emitted approximately 2.7 million tons of CO2.

 

In April 2007, the U.S. Supreme Court issued a decision that determined that the EPA has authority to regulate CO2 and other GHGs from automobiles as “air pollutants” under the CAA. The EPA thereafter conducted a rulemaking to determine whether GHG emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” While this case addressed a provision of the CAA related to emissions from motor vehicles, a parallel provision of the CAA applies to stationary sources such as electric generators. The EPA determined that parallel provision would be automatically triggered once the EPA began regulating motor vehicle GHG emissions. The first step in the EPA rulemaking process was the publication of an endangerment finding in the December 15, 2009 Federal Register where the EPA found that CO2 and five other GHGs – methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride – threaten public health and the environment.

 

The EPA’s endangerment finding for GHGs did not in and of itself impose any emission reduction requirements but rather authorized the EPA to finalize the GHG standards for new light-duty vehicles as part of the joint rulemaking with the Department of Transportation. These standards applied to motor vehicles as of January 2011, which the EPA determined made GHGs “subject to regulation” under the CAA. According to the EPA, this triggered the Prevention of Significant Deterioration (PSD) and Title V operating permits programs for stationary sources of GHGs.

 

On June 6, 2010 the EPA published a final “tailoring rule” that phased in application of its PSD and Title V programs to GHG emission sources, including power plants. The PSD program applies to existing sources if there is a physical change or change in the method of operation of the facility that results in a significant net emissions increase of any pollutant. As a result, PSD does not apply on a set timeline as is the case with other regulatory programs, but is triggered when certain activities take place at a major source. If triggered, the owner or operator of an affected facility must undergo a review which requires, among other things, the identification and implementation of best-available control technology (BACT) for the regulated air pollutants for which there is a significant net emissions increase, and an analysis of the ambient air quality impacts of the facility.

 

In June 2012 the United States Court of Appeals for the D.C. Circuit upheld most of the EPA’s rules regarding the regulation of GHGs under the CAA, including the tailoring rule. However, in October 2013 the U.S. Supreme Court granted a petition for a writ of certiorari to review the question of whether the regulation of new motor vehicle GHG emissions does in fact automatically trigger PSD and Title V regulation of GHGs for stationary sources. On June 23, 2014 the U.S. Supreme Court issued its decision that, in summary, held the EPA exceeded its statutory authority and may not require a PSD or Title V permit based solely on GHG emissions. However, the U.S. Supreme Court also said the EPA could continue to require that PSD permits for sources otherwise subject to PSD based on emissions of conventional pollutants contain limitations on GHG emissions based on the application of BACT. The EPA revised its regulations to implement this ruling and in 2016 proposed a de minimis level of GHG emissions below which PSD would not apply. OTP does not anticipate making modifications that would trigger PSD requirements at any of its facilities or undertaking construction of a new unit that might trigger PSD.

 

The EPA has developed New Source Performance Standards (NSPS) for GHGs from new and existing fossil fuel-fired electric generating units. On October 23, 2015 the EPA published the final NSPS under section 111(b) of the CAA that requires certain new units (as well as modified and reconstructed units) to meet CO2 emission standards. New natural gas combustion turbines are required to meet a standard of 1,000 lbs. of CO2 per gross megawatt hour averaged over a 12-month period if they meet the definition of a baseload unit. New natural gas combined cycle units are anticipated to fit into this category. Simple cycle combustion turbines are regulated in a non-baseload category that is required to meet a heat input based standard that can be met by burning clean fuels such as natural gas. This rule was challenged by a number of parties and litigation is pending.

 

The EPA also published GHG performance standards for existing sources under CAA Section 111(d) (111(d) Standard). A 111(d) Standard, unlike those set under CAA Section 111(b), applies to existing sources of a pollutant. Under Section 111(d), the EPA promulgates emission guidelines and the states are then given a period of time to develop plans to implement the standard. The EPA reviews each state-developed standard and then approves it if the state’s plan comports with the federal emission guidelines. If the state does not submit a plan or the EPA finds that the plan is inadequate, the EPA will prescribe a plan for that state.

 

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For both new and existing sources, the EPA must develop a “standard of performance,” which is defined as:

 

…a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the [EPA] Administrator determines has been adequately demonstrated.

 

For existing sources, Section 111(d) also requires the EPA to consider, “among other factors, remaining useful lives of the sources in the category of sources to which such standard applies.”

 

On June 18, 2014 the EPA published proposed Section 111(d) emission guidelines for existing fossil fuel-fired power plants, termed the Clean Power Plan (CPP). The CPP proposed state-specific rate-based goals for CO2 emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve the goals. An interim goal was proposed to be achieved on average over the ten year period of 2020-2029, and a final goal in 2030 and each year thereafter. The EPA used a formula that relies on four building blocks to determine the state-specific goal: (1) a six percent heat rate improvement at each coal plant, (2) increased reliance on natural gas combined cycle units, (3) a renewable energy target, and (4) demand side energy efficiency savings. Specific to OTP, EPA's proposed formula created substantially different targets for North Dakota, South Dakota, and Minnesota, primarily due to the EPA's second building block that envisioned redispatching natural gas combined cycle units to a 70% capacity factor.

 

On October 23, 2015 the EPA published the final CPP. The final rule delayed the start of the interim goal period to 2022 and used a different formula to calculate state goals that resulted in a narrower range of state-specific targets. The EPA formula relied on only three building blocks in the final rule: (1) a heat rate improvement at each coal plant, (2) increased reliance on natural gas combined cycle units, and (3) increased deployment of renewable energy. These building blocks were applied to each grid interconnection that resulted in final national uniform emission rate standards of 1,305 pounds of CO2 per net megawatt hour for coal plants and 771 pounds of CO2 per net megawatt hour for natural gas combined cycle plants. These uniform rates were applied on a weighted average basis to the affected units of each state, resulting in a much narrower range of goals in the final rule as compared to the proposed rule. The EPA then translated the rate goals into mass-based goals that can be applied to existing sources or, if a state chooses, a mass-based goal that applies to both existing sources and new sources.

 

A number of states, utilities, and trade groups filed petitions for review with the D.C. Circuit seeking to overturn the rule, and also moved to stay the rule. On January 14, 2016 the D.C. Circuit denied the stay motions. Numerous petitioners then sought an emergency stay in the U.S. Supreme Court. On February 9, 2016 the U.S. Supreme Court granted a stay of the rule pending disposition of petitions for review in the D.C. Circuit and, if a petition for a writ of certiorari seeking review by the U.S. Supreme Court were granted, any final Supreme Court determination. The D.C. Circuit heard oral argument on challenges to the CO2 emission guidelines on September 27, 2016 before the full court, and a decision is likely to be rendered in the first half of 2017. In addition, members of Congress and the new administration have been very critical of the CPP and may take actions that could impact the rule or the litigation. Therefore, while the CPP remains stayed, there is uncertainty regarding the future of the rule.

 

Also on October 23, 2015 the EPA proposed model trading rules along with the proposed federal plan for states that do not have a fully approved state plan. The EPA proposed both a rate-based trading plan and a mass-based trading plan for the federal plan. On December 19, 2016 the EPA withdrew the model trading rules and federal plan from the interagency review process and instead released the model trading rules as a working draft. The draft does not reflect final agency action or official statement of policy, and does not create any legal obligations. The docket for these items will remain open so that the EPA can potentially finalize the work in the future should the CPP, or a similar rule, be implemented.

 

Several states and regional organizations have or will develop state-specific or regional legislative initiatives to reduce GHG emissions through mandatory programs. In 2007 the state of Minnesota passed legislation regarding renewable energy portfolio standards that requires retail electricity providers to obtain 25% of the electric energy sold to Minnesota customers from renewable sources by the year 2025. Additionally, in 2013 the state of Minnesota passed a provision that requires public utilities to generate or procure sufficient electricity generated by solar energy to serve its retail electricity customers in Minnesota so that by the end of 2020, at least 1.5% of the utility's total retail electric sales to retail customers in Minnesota is generated by solar energy. The Minnesota legislature set a January 1, 2008 deadline for the MPUC to establish an estimate of the likely range of costs of future CO2 regulation on electricity generation. The legislation also set state targets for reducing fossil fuel use, included goals for reducing the state's output of GHGs, and restricted importing electricity that would contribute to statewide power sector CO2 emission. The MPUC, in its order dated December 21, 2007, established an estimate of future CO2 regulation costs at between $4/ton and $30/ton emitted in 2012 and after. Annual updates of the range are required. For 2016 the range is $9-$34/ton, and the applicable effective date to begin using CO2 costs in resource planning decisions is 2022. Minnesota opened a new docket to investigate the environmental and socioeconomic costs of externalities associated with electricity generation. A final ruling in that case is not expected until the second quarter of 2017.

 

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The states of North Dakota and South Dakota currently have no proposed or pending legislation related to the regulation of GHG emissions, but North Dakota and South Dakota have 10% renewable energy objectives. OTP currently has sufficient renewable generation to meet the renewable energy objectives in both North Dakota and South Dakota.

 

While the eventual outcome of GHG regulation is unknown, OTP is taking steps to reduce its carbon footprint and mitigate levels of CO2 emitted in the process of generating electricity for its customers through the following initiatives:

 

·Supply efficiency and reliability: Since 2005, SO2 and NOx emitted from OTP’s fossil fuel-fired plants have decreased 50% and 62%, respectively. OTP’s efforts to increase plant efficiency and add renewable energy to its resource mix have reduced its CO2 intensity. Between 2005 and 2015 OTP decreased its overall system average CO2 emissions intensity by approximately 30%. With recent installations of pollution control equipment, OTP expects to achieve reductions of mercury emissions of more than 70% between 2005 and 2016. Further reductions are expected with the anticipated replacement of Hoot Lake Plant generation with natural gas-fired generation in the 2021 timeframe.
   
·Conservation: Since 1992 OTP has helped its customers conserve more than 3.1 million cumulative megawatt-hours of electricity, which is roughly equivalent to the amount of electricity that 258,000 average homes would use in a year and represents approximately 250% of the annual energy sales of OTP’s entire residential customer base. Additionally, OTP’s conservation programs contribute 71 MW of load reduction to its system.
   
·Renewable energy: Since 2002, OTP’s customers have been able to purchase 100% of their electricity from wind generation through OTP’s Tail Winds program. OTP has access to 102.9 MW of wind powered generation under power purchase agreements and owns 138 MW of wind powered generation. OTP is exploring options for meeting a Minnesota legislative mandate requiring Minnesota’s investor-owned utilities to serve 1.5% of their Minnesota retail electric sales with solar power by 2020.
   
·Other: OTP is a participating member of the EPA’s sulfur hexafluoride (SF6) Emission Reduction Partnership for Electric Power Systems program, which proactively is targeting a reduction in emissions of SF6, a potent GHG. SF6 has a global-warming potential 23,900 times that of CO2. OTP participates in carbon sequestration research through the Plains CO2 Reduction (PCOR) Partnership through the University of North Dakota’s Energy and Environmental Research Center. The PCOR Partnership is a collaborative effort of approximately 100 public and private sector stakeholders working toward a better understanding of the technical and economic feasibility of capturing and storing anthropogenic CO2 emissions from stationary sources in central North America.

 

While the future financial impact of any proposed or pending litigation or regulation of GHG emissions is unknown at this time, any capital and operating costs incurred for additional pollution control equipment or CO2 emission reduction measures, such as the cost of sequestration or purchasing allowances, or offset credits, or the imposition of a carbon tax or cap and trade program at the state or federal level could materially adversely affect the Company’s future results of operations, cash flows, and possibly financial condition, unless such costs could be recovered through regulated rates and/or future market prices for energy.

 

Water Quality—The Federal Water Pollution Control Act Amendments of 1972 and amendments thereto, provide for, among other things, the imposition of effluent limitations to regulate discharges of pollutants, including thermal discharges, into the waters of the United States, and the EPA has established effluent guidelines for the steam electric power generating industry. Discharges must also comply with state water quality standards.

 

Effluent limits specific to Hoot Lake Plant and Coyote Station are incorporated into their National Pollutant Discharge Elimination System (NPDES) permits. Big Stone Plant is a zero discharge facility and therefore does not have a NPDES permit. On November 3, 2015 the EPA published the final rule that sets technology-based effluent limitations on certain types of discharges. Generally, the final rule establishes new requirements for wastewater streams from wet flue gas desulfurization, fly ash transport, and bottom ash transport. This includes zero discharge requirements for fly ash and bottom ash transport water. OTP’s facilities either utilize dry ash handling or use transport water in a closed loop manner. Therefore, OTP anticipates minimal impact from the rule.

 

On May 9, 2014 the EPA Administrator signed a final rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures for certain existing facilities. The final rule includes seven compliance options, plus a potential "de minimis" option that is not well defined. Although the impact of the Hoot Lake Plant intake structure has been extensively evaluated in two separate studies both of which showed minimal impact, OTP will need to have state agency discussions during the renewal of the Hoot Lake Plant NPDES permit to determine the appropriate path forward. Coyote Station will also need to provide various studies with their next NPDES permit renewal application, but minimal impact is anticipated since Coyote Station already uses closed-cycle cooling. Litigation over the final rule remains pending.

 

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OTP has all federal and state water permits presently necessary for the operation of the Coyote Station, the Big Stone Plant and the Hoot Lake Plant.

 

OTP owns five small dams on the Otter Tail River, which are subject to FERC licensing requirements. A license for all five dams was issued on December 5, 1991. In June 2015 OTP notified the FERC of its intent to relicense these dams. The current FERC license expires in 2021 and the licensing process takes approximately 5 years. The FERC completed the scoping meeting in the fall of 2016. OTP is currently in the process of finalizing the study plan. The studies will be completed in 2017 and 2018. These studies will be followed by the filing of the license application in 2019. OTP expects FERC to issue an order on the license application in 2021. Total nameplate rating (manufacturer’s expected output) of the five dams is 3,450 kW.

 

Solid Waste—Permits for disposal of ash and other solid wastes have been issued for the Coyote Station, the Big Stone Plant and the Hoot Lake Plant.

 

On December 19, 2014 the EPA announced a final rule regulating coal combustion residuals (CCR) under the Resource Conservation and Recovery Act (RCRA) regulating the disposal of coal ash generated from the combustion of coal by electric utilities under Subtitle D’s nonhazardous provisions. The final rule was published on April 17, 2015. The rule requires OTP to complete certain actions, such as installing additional groundwater monitoring wells and investigating whether existing surface impoundments meet defined location restrictions, in order to determine whether existing surface impoundments should be retired or retrofitted with liners. OTP is still in the process of completing its actions. Therefore, the cost impact of this rule will not be known until those actions are completed. Existing landfill cells can continue to operate as designed, but future expansions will require composite liner and leachate collection systems. On December 20, 2016 the Water Infrastructure Improvements for the Nation (WIIN) Act was signed into law. The WIIN Act allows states to regulate CCR if the state standards are at least as protective as the EPA CCR Rule.

 

At the request of the Minnesota Pollution Control Agency (MPCA), OTP has an ongoing investigation at its former, closed Hoot Lake Plant ash disposal sites. The MPCA continues to monitor site activities under its Voluntary Investigation and Cleanup (VIC) Program. OTP completed projects in 2014 and 2015 that removed the ash from two entire VIC areas and placed it in OTP’s permitted disposal area. Efforts to remove ash from the remaining two VIC areas began in 2016 and will continue through 2017.

 

In 1980 the United States enacted the Comprehensive Environmental Response, Compensation and Liability Act, commonly known as CERCLA or the Federal Superfund law, which was reauthorized and amended in 1986. In 1983 Minnesota adopted the Minnesota Environmental Response and Liability Act, commonly known as the Minnesota Superfund law. In 1988 South Dakota enacted the Regulated Substance Discharges Act, commonly known as the South Dakota Superfund law. In 1989, North Dakota enacted the Environmental Emergency Cost Recovery Act. Among other requirements, the federal and state acts establish environmental response funds to pay for remedial actions associated with the release or threatened release of certain regulated substances into the environment. These federal and state Superfund laws also establish liability for cleanup costs and damage to the environment resulting from such release or threatened release of regulated substances. The Minnesota Superfund law also creates liability for personal injury and economic loss under certain circumstances. OTP has not incurred any significant costs to date related to these laws. OTP is not presently named as a potentially responsible party under the federal or state Superfund laws.

 

Capital Expenditures

 

OTP is continually expanding, replacing and improving its electric facilities. During 2016 approximately $150 million in cash was invested for additions and replacements to its electric utility properties. During the five years ended December 31, 2016 gross electric property additions, including construction work in progress, were approximately $677 million and gross retirements were approximately $89 million. OTP estimates that during the five-year period 2017-2021 it will invest approximately $862 million for electric construction, which includes $315 million for renewable wind and solar energy generation projects, $147 million for natural gas-fired generation to replace Hoot Lake Plant capacity and $116 million for MVP transmission projects. The remainder of the 2017-2021 anticipated capital expenditures is for asset replacements, additions and improvements across OTP’s generation, transmission, distribution and general plant. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Requirements” section for further discussion.

 

The $315 million planned investment for renewable wind and solar energy generation projects includes the Merricourt Wind Project. In November 2016 OTP signed agreements to purchase this 150-MW wind farm in southeastern North Dakota that EDF Renewable Energy will design and build in 2019.

 

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Franchises

 

At December 31, 2016 OTP had franchises to operate as an electric utility in substantially all of the incorporated municipalities it serves. All franchises are nonexclusive and generally were obtained for 20-year terms, with varying expiration dates. No franchises are required to serve unincorporated communities in any of the three states that OTP serves. OTP believes that its franchises will be renewed prior to expiration.

 

Employees

 

At December 31, 2016 OTP had 682 equivalent full-time employees. A total of 397 OTP employees are represented by local unions of the International Brotherhood of Electrical Workers under two separate contracts expiring on August 21, 2017 and October 31, 2017. OTP has not experienced any strike, work stoppage or strike vote, and considers its present relations with employees to be good.

 

MANUFACTURING

 

General

 

Manufacturing consists of businesses engaged in the following activities: contract machining, metal parts stamping, fabrication and painting, and production of material handling trays and horticultural containers.

 

The Company derived 28%, 28% and 27% of its consolidated operating revenues and 11%, 9% and 17% of its consolidated operating income from the Manufacturing segment for the years ended December 31, 2016, 2015 and 2014, respectively. Following is a brief description of each of these businesses:

 

BTD Manufacturing, Inc. (BTD), with headquarters located in Detroit Lakes, Minnesota, is a metal stamping and tool and die manufacturer that provides its services mainly to customers in the Midwest. BTD stamps, fabricates, welds, paints and laser cuts metal components according to manufacturers’ specifications primarily for the recreational vehicle, agricultural, oil and gas, lawn and garden, industrial equipment, health and fitness and enclosure industries in its facilities in Detroit Lakes and Lakeville, Minnesota, Washington, Illinois and Dawsonville, Georgia. BTD’s Illinois facility also manufactures and fabricates parts for off-road equipment, mining machinery, oil fields and offshore oil rigs, wind industry components, broadcast antennae and farm equipment.

 

On September 1, 2015 Miller Welding and Iron Works, Inc., a wholly owned subsidiary of BTD, acquired the assets of Impulse for $30.8 million in cash. A post-closing reduction in the purchase price of $1.5 million was agreed to in June 2016 resulting in an adjusted purchase price of $29.3 million. Impulse now operates under the name BTD-Georgia. BTD-Georgia offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers.

 

T.O. Plastics, Inc. (T.O. Plastics), located in Otsego and Clearwater, Minnesota, manufactures and sells thermoformed products for the horticulture industry throughout the United States. T.O. Plastics also designs and manufactures quality thermoformed products and packaging solutions for the medical and life sciences, industrial, recreation and electronics industries. Examples of products produced for these industries are clamshell packing, blister packs, returnable pallets and handling trays for shipping and storing odd-shaped or difficult-to-handle parts. T.O. Plastics’ Otsego thermoforming facility has an AIB International compliance rating for producing food-contact packaging materials in its operations.

 

Product Distribution

 

The principal method for distribution of the manufacturing companies’ products is by direct shipment to the customer by common carrier ground transportation. No single customer or product of the Company’s manufacturing companies account for over 10% of the Company’s consolidated revenue.

 

Competition

 

The various markets in which the Manufacturing segment entities compete are characterized by intense competition from both foreign and domestic manufacturers. These markets have many established manufacturers with broader product lines, greater distribution capabilities, greater capital resources, excess capacity, labor advantages and larger marketing, research and development staffs and facilities than the Company’s manufacturing entities.

 

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The Company believes the principal competitive factors in its Manufacturing segment are product performance, quality, price, technical innovation, cost effectiveness, customer service and breadth of product line. The Company’s manufacturing entities intend to continue to compete on the basis of high-performance products, innovative production technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings.

 

Raw Materials Supply

 

The companies in the Manufacturing segment use raw materials in the products they manufacture, including steel, aluminum and polystyrene and other plastics resins. Both pricing increases and availability of these raw materials are concerns of companies in the Manufacturing segment. The companies in the Manufacturing segment attempt to pass increases in the costs of these raw materials on to their customers. Increases in the costs of raw materials that cannot be passed on to customers could have a negative effect on profit margins in the Manufacturing segment. Additionally, a certain amount of residual material (scrap) is a by-product of many of the manufacturing and production processes used by the Company’s manufacturing companies. Declines in commodity prices for these scrap materials due to weakened demand or excess supply can negatively impact the profitability of the Company’s manufacturing companies as it reduces their ability to mitigate the cost associated with excess material.

 

Backlog

 

The Manufacturing segment has backlog in place to support 2017 revenues of approximately $118 million compared with $134 million one year ago.

 

Capital Expenditures

 

Capital expenditures in the Manufacturing segment typically include additional investments in new manufacturing equipment or expenditures to replace worn-out manufacturing equipment. Capital expenditures may also be made for the purchase of land and buildings for plant expansion and for investments in management information systems. During 2016, cash expenditures for capital additions in the Manufacturing segment were approximately $8 million. Total capital expenditures for the Manufacturing segment during the five-year period 2017-2021 are estimated to be approximately $54 million.

 

Employees

 

At December 31, 2016 the Manufacturing segment had 1,175 full-time employees. There were 1,037 full-time employees at BTD and its subsidiaries and 138 full-time employees at T.O. Plastics as of December 31, 2016.

 

PLASTICS

 

General

 

Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The Company derived 19%, 20% and 22% of its consolidated operating revenues and 16%, 19% and 20% of its consolidated operating income from the Plastics segment for the years ended December 31, 2016, 2015 and 2014, respectively. Following is a brief description of these businesses:

 

Northern Pipe Products, Inc. (Northern Pipe), located in Fargo, North Dakota, manufactures and sells PVC pipe for municipal water, rural water, wastewater, storm drainage systems and other uses in the northern, midwestern, south-central and western regions of the United States as well as central and western Canada.

 

Vinyltech Corporation (Vinyltech), located in Phoenix, Arizona, manufactures and sells PVC pipe for municipal water, wastewater, water reclamation systems and other uses in the western, northwestern and south-central regions of the United States.

 

Together these companies have the current capacity to produce approximately 300 million pounds of PVC pipe annually.

 

Customers

 

PVC pipe products are marketed through a combination of independent sales representatives, company salespersons and customer service representatives. Customers for the PVC pipe products consist primarily of wholesalers and distributors throughout the northern, midwestern, south-central, western and northwest United States. The principal method for distribution of the PVC pipe companies’ products is by common carrier ground transportation. No single customer of the PVC pipe companies accounts for over 10% of the Company’s consolidated revenue.

 

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Competition

 

The plastic pipe industry is fragmented and competitive, due to the number of producers, the small number of raw material suppliers and the fungible nature of the product. Due to shipping costs, competition is usually regional, instead of national, in scope. The principal factors of competition are price, service, warranty, and product performance. Northern Pipe and Vinyltech compete not only against other plastic pipe manufacturers, but also ductile iron, steel and concrete pipe producers. Pricing pressure will continue to affect our Plastics segment operating margins in the future.

 

Northern Pipe and Vinyltech intend to continue to compete on the basis of their high quality products, cost-effective production techniques and close customer relations and support.

 

Manufacturing and Resin Supply

 

PVC pipe is manufactured through a process known as extrusion. During the production process, PVC compound (a dry powder-like substance) is introduced into an extrusion machine, where it is heated to a molten state and then forced through a sizing apparatus to produce the pipe. The newly extruded pipe is then pulled through a series of water cooling tanks, marked to identify the type of pipe and cut to finished lengths. Warehouse and outdoor storage facilities are used to store the finished product. Inventory is shipped from storage to distributors and customers by common carrier.

 

The PVC resins are acquired in bulk and shipped to point of use by rail car. There are four vendors that Northern Pipe and Vinyltech can source to supply their PVC resin requirements. Two vendors provided 100% and 96% of total resin purchases in 2016 and 2015, respectively. The supply of PVC resin may also be limited primarily due to manufacturing capacity and the limited availability of raw material components. A majority of U.S. resin production plants are located in the Gulf Coast region, which is subject to risk of damage to the plants and potential shutdown of resin production because of exposure to hurricanes that occur in that part of the United States. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could disrupt the ability of the Plastics segment to manufacture products, cause customers to cancel orders or require incurrence of additional expenses to obtain PVC resin from alternative sources, if such sources were available. Both Northern Pipe and Vinyltech believe they have good relationships with their key raw material vendors.

 

Due to the commodity nature of PVC resin and PVC pipe and the dynamic supply and demand factors worldwide, historically the markets for both PVC resin and PVC pipe have been very cyclical with significant fluctuations in prices and gross margins.

 

Capital Expenditures

 

Capital expenditures in the Plastics segment typically include investments in extrusion machines and support equipment. During 2016, cash expenditures for capital additions in the Plastics segment were approximately $3 million. Total capital expenditures for the five-year period 2017-2021 are estimated to be approximately $20 million to replace existing equipment.

 

Employees

 

At December 31, 2016 the Plastics segment had 156 full-time employees. Northern Pipe had 90 full-time employees and Vinyltech had 66 full-time employees as of December 31, 2016.

 

Item 1A.  RISK FACTORS

 

RISK FACTORS AND CAUTIONARY STATEMENTS

 

Our businesses are subject to various risks and uncertainties. Any of the risks described below or elsewhere in this Annual Report on Form 10-K or in our other SEC filings could materially adversely affect our business, financial condition and results of operations.

 

GENERAL

 

Federal and state environmental regulation could require us to incur substantial capital expenditures and increased operating costs.

 

We are subject to federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health safety. These laws and regulations regulate the modification and operation of existing facilities, the construction and operation of new facilities and the proper storage, handling, cleanup and disposal of

 

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hazardous waste and toxic substances. Compliance with these legal requirements requires us to commit significant resources and funds toward environmental monitoring, installation and operation of pollution control equipment, payment of emission fees and securing environmental permits. Obtaining environmental permits can entail significant expense and cause substantial construction delays. Failure to comply with environmental laws and regulations, even if caused by factors beyond our control, may result in civil or criminal liabilities, penalties and fines.

 

Existing environmental laws or regulations may be revised and new laws or regulations may be adopted or become applicable to us. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material effect on our results of operations.

 

Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and increase borrowing costs and pension plan and postretirement health care expenses.

 

We rely on access to both short- and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations. If we are unable to access capital at competitive rates, our ability to implement our business plans may be adversely affected. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to access one or more financial markets.

 

Disruptions, uncertainty or volatility in the financial markets can also adversely impact our results of operations, the ability of customers to finance purchases of goods and services, and our financial condition, as well as exert downward pressure on stock prices and/or limit our ability to sustain our current common stock dividend level.

 

Changes in the U.S. capital markets could also have significant effects on our pension plan. Our pension income or expense is affected by factors including the market performance of the assets in the master pension trust maintained for the pension plan for some of our employees, the weighted average asset allocation and long-term rate of return of our pension plan assets, the discount rate used to determine the service and interest cost components of our net periodic pension cost and assumed rates of increase in our employees’ future compensation. If our pension plan assets do not achieve positive rates of return, or if our estimates and assumed rates are not accurate, our earnings may decrease because net periodic pension costs would rise and we could be required to provide additional funds to cover our obligations to employees under the pension plan.

 

We could be required to contribute additional capital to the pension plan in the future if the market value of pension plan assets significantly declines, plan assets do not earn in line with our long-term rate of return assumptions or relief under the Pension Protection Act is no longer granted.

 

Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating income.

 

We had approximately $37.6 million of goodwill recorded on our consolidated balance sheet as of December 31, 2016. We have recorded goodwill for businesses in our Manufacturing and Plastics business segments. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of these businesses, we may be forced to record an impairment charge, which would lead to decreased assets and a reduction in net operating performance. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying amount of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including changes in economic, industry or market conditions, changes in business operations, future business operating performance, changes in competition or changes in technologies. Any changes in key assumptions or actual performance compared with key assumptions about our business and its future prospects or other assumptions could affect the fair value of one or more business segments, which may result in an impairment charge. Declines in projected operating cash flows at BTD or the Plastics segment may result in goodwill impairments that could adversely affect our results of operations and financial position, as well as financing agreement covenants.

 

The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on the Company.

 

Otter Tail Corporation is a holding company with no significant operations of its own. The primary source of funds for payment of our financial obligations and dividends to our shareholders is from cash provided by our subsidiary companies. Our ability to meet our financial obligations and pay dividends on our common stock principally depends on the actual and projected earnings, cash flows, capital requirements and general financial position of our subsidiary companies, as well as regulatory factors, financial covenants, general business conditions and other matters.

 

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Under our $130 million revolving credit agreement we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00. OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 under its $170 million revolving credit agreement. Both credit agreements contain restrictions on the payment of cash dividends on a default or event of default. As of December 31, 2016 we were in compliance with the debt covenants.

 

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. The MPUC indirectly limits the amount of dividends OTP can pay to us by requiring an equity-to-total-capitalization ratio between 47.5% and 58.1% based on OTP’s 2016 capital structure petition. OTP’s equity-to-total-capitalization ratio, including short-term debt, was 52.9% as of December 31, 2016.

 

While these restrictions are not expected to affect our ability to pay dividends at the current level in the foreseeable future, there is no assurance that adverse financial results would not reduce or eliminate our ability to pay dividends.

 

We rely on our information systems to conduct our business, and failure to protect these systems against security breaches or cyber-attacks could adversely affect our business and results of operations. Additionally, if these systems fail or become unavailable for any significant period of time, our business could be harmed.

 

All of our businesses require us to collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss. We also use third-party vendors to electronically process certain of our business transactions. The efficient operation of our business is dependent on computer hardware and software systems. Information systems, both ours and those of third-party information processors, are vulnerable to security breach by computer hackers and cyber terrorists.

 

The breach of certain business systems could affect our ability to correctly record, process and report financial information and transactions. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. We have cybersecurity insurance related to a breach event covering expenses for notification, credit monitoring, investigation, crisis management, public relations and legal advice. The policy also provides coverage for regulatory action defense including fines and penalties, potential payment card industry fines and penalties and costs related to cyber extortion. We also maintain property and casualty insurance that may cover restoration of data, certain physical damage or third party injuries caused by potential cybersecurity incidents. However, damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available.

 

We rely on industry accepted security measures and technology to securely maintain confidential and proprietary information maintained on our information systems. In an effort to reduce the likelihood and severity of cyber intrusions, we have cybersecurity processes and controls designed to protect and preserve the confidentiality, integrity and availability of data and systems. However, all these measures and technology may not adequately prevent security breaches or cyber-attacks. In addition, the unavailability of the information systems or failure of these systems to perform as anticipated for any reason could disrupt our business and could result in decreased performance and increased overhead costs, causing our business and results of operations to suffer. Any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches could adversely affect our business and results of operations.

 

Economic conditions could negatively impact our businesses.

 

Our businesses are affected by local, national and worldwide economic conditions. Tightening of credit in financial markets could adversely affect the ability of customers to finance purchases of our goods and services, resulting in decreased orders, cancelled or deferred orders, slower payment cycles, and increased bad debt and customer bankruptcies. Our businesses may also be adversely affected by decreases in the general level of economic activity, such as decreases in business and consumer spending. A decline in the level of economic activity and uncertainty regarding energy and commodity prices could adversely affect our results of operations and our future growth.

 

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If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.

 

We expect much of our growth in the next few years will come from major capital investment at existing companies. To achieve the organic growth we expect, we must have access to the capital markets, be successful with capital expansion programs related to organic growth, develop new products and services, expand our markets and increase efficiencies in our businesses. Competitive and economic factors could adversely affect our ability to do this. If we are unable to achieve and sustain consistent organic growth, we will be less likely to meet our revenue growth targets, which, together with any resulting impact on our net income growth, may adversely affect the market price of our common shares.

 

Our plans to grow and realign our business mix through capital projects, acquisitions and dispositions may not be successful, which could result in poor financial performance.

 

As part of our business strategy, we intend to increase capital expenditures in our existing businesses and to continually assess our mix of businesses and potential strategic acquisitions or dispositions. There are risks associated with capital expenditures including not being granted timely or full recovery of rate base additions in our regulated utility business and the inability to recover the cost of capital additions due to an economic downturn, lack of markets for new products, competition from producers of lower cost or alternative products, product defects, loss of customers or other factors. We may not be able to identify appropriate acquisition candidates or successfully negotiate, finance or integrate acquisitions. Future acquisitions could involve numerous risks including: difficulties in integrating the operations, services, products and personnel of the acquired business; and the potential loss of key employees, customers and suppliers of the acquired business. If we are unable to successfully manage these risks, we could face reductions in net income in future periods.

 

We may, from time to time, sell assets to provide capital to fund investments in our electric utility business or for other corporate purposes, which could result in the recognition of a loss on the sale of any assets sold and other potential liabilities. The sale of any of our businesses also exposes us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

 

As part of our business strategy, we continually assess our business portfolio to determine if our operating companies continue to meet our portfolio criteria. A loss on the sale of a business would be recognized if a company is sold for less than its book value.

 

In certain transactions we retain obligations that have arisen, or subsequently arise, out of our conduct of the business prior to the sale. These obligations are sometimes direct or, in other cases, take the form of an indemnification obligation to the buyer. These obligations include such things as warranty, environmental, and the collection of certain receivables. Unforeseen costs related to these obligations could result in future losses related to the business sold.

 

Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition.

 

Depending on the specific product or service, we may provide certain warranty terms against manufacturing defects and certain materials. We reserve for warranty claims based on industry experience and estimates made by management. For some of our products we have limited history on which to base our warranty estimate. Our assumptions could be materially different from any actual claim and could exceed reserve balances.

 

Expenses associated with the remediation of warranty claims for our manufacturing businesses, including our former wind tower manufacturer, could be substantial. The potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. If we are required to cover remediation expenses in addition to our regular warranty coverage, we could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect our consolidated net income and financial condition.

 

We are subject to risks associated with energy markets.

 

Our businesses are subject to the risks associated with energy markets, including market supply and increasing energy prices. If we are faced with shortages in market supply, we may be unable to fulfill our contractual obligations to our retail, wholesale and other customers at previously anticipated costs. This could force us to obtain alternative energy or fuel supplies at higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher than expected energy or fuel costs would negatively affect our financial performance.

 

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Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could materially adversely affect our business, financial condition, results of operations and prospects.

 

Our provision for income taxes and reporting of tax-related assets and liabilities require significant judgments and the use of estimates. Amounts of tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions and tax credits, including, but not limited to, estimates for potential adverse outcomes regarding tax positions that have been taken and the ability to utilize tax benefit carryforwards, such as net operating loss and tax credit carryforwards. Actual income taxes could vary significantly from estimated amounts due to the future impacts of, among other things, changes in tax laws, regulations and interpretations, the financial condition and results of operations of Otter Tail Corporation, and the resolution of audit issues raised by taxing authorities. Ultimate resolution of income tax matters may result in material adjustments to tax-related assets and liabilities, which could materially adversely affect our business, financial condition, results of operations and prospects.

 

ELECTRIC

 

We may experience fluctuations in revenues and expenses related to our electric operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to shareholders or scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.

 

A number of factors, many of which are beyond our control, may contribute to fluctuations in our revenues and expenses from electric operations, causing our net income to fluctuate from period to period. These risks include fluctuations in the volume and price of sales of electricity to customers or other utilities, which may be affected by factors such as mergers and acquisitions of other utilities, geographic location of other utilities, transmission costs (including increased costs related to operations of regional transmission organizations), changes in the manner in which wholesale power is sold and purchased, unplanned interruptions at OTP’s generating plants, the effects of regulation and legislation, demographic changes in OTP’s customer base and changes in OTP’s customer demand or load growth. Electric wholesale margins have been significantly and adversely affected by increased efficiencies in the MISO market. Other risks include weather conditions or changes in weather patterns (including severe weather that could result in damage to OTP’s assets), fuel and purchased power costs and the rate of economic growth or decline in OTP’s service areas. A decrease in revenues or an increase in expenses related to our electric operations may reduce the amount of funds available for our existing and future businesses, which could result in increased financing requirements, impair our ability to make expected distributions to shareholders or impair our ability to make scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.

 

Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

 

We are subject to federal and state legislation, government regulations and regulatory actions that may have a negative impact on our business and results of operations. The electric rates that OTP is allowed to charge for its electric services are one of the most important items influencing our financial position, results of operations and liquidity. The rates that OTP charges its electric customers are subject to review and determination by state public utility commissions in Minnesota, North Dakota and South Dakota. OTP is also regulated by the FERC. Our ability to obtain rate adjustments to maintain reasonable rates of return depends on regulatory action under applicable statutes and regulations and we cannot provide assurance that rate adjustments will be obtained or reasonable authorized rates of return on capital will be earned. OTP will file rate cases with, or seek cost recovery authorization from, federal and state regulatory authorities. An adverse decision by one or more regulatory commissions concerning the level or method of determining electric utility rates, the authorized returns on equity, implementation of enforceable federal reliability standards or other regulatory matters, permitted business activities (such as ownership or operation of nonelectric businesses) or any prolonged delay in rendering a decision in a rate or other proceeding (including with respect to the recovery of capital expenditures in rates) could result in lower revenues and net income.

 

OTP’s operations are subject to an extensive legal and regulatory framework under federal and state laws as well as regulations imposed by other organizations that may have a negative impact on our business and results of operations.

 

We are subject to an extensive legal and regulatory framework imposed under federal and state law and regulatory agencies, including FERC and NERC. We could be subject to potential financial penalties for compliance violations. In addition, energy policy initiatives at the state or federal level could increase incentives for distributed generation or municipal utility ownership, or local initiatives could introduce generation or distribution requirements, that could change the current integrated utility model. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. If a serious reliability incident did occur, it could have a material effect on our operations or financial results. Some states have the authority to impose substantial penalties in the event of non-compliance. We attempt to mitigate the risk of regulatory penalties through formal training. However, there is no guarantee our compliance program will be sufficient to ensure against violations.

 

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These laws and regulations significantly influence our operations and may affect our ability to recover costs from our customers. We are required to have numerous permits, licenses, approvals and certificates from the agencies and other organizations that regulate our business. We believe we have obtained the necessary approvals for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies and other organizations. Changes in regulations or the imposition of additional regulations could have a material adverse impact on our results of operations.

 

OTP’s electric transmission and generation facilities could be vulnerable to cyber and physical attack that could impair our ability to provide electrical service to our customers or disrupt the U.S. bulk power system.

 

OTP owns electric transmission and generation facilities subject to mandatory and enforceable standards advanced by the NERC. These bulk electric system facilities provide the framework for the electrical infrastructure of OTP’s service territory and interconnected systems, the operation of which is dependent on information technology systems. Further, the information systems that operate OTP’s electric system are interconnected to external networks. Parties that wish to disrupt the U.S. bulk power system or OTP’s operations could view OTP’s computer systems, software or networks as attractive targets for cyber-attack.

 

In addition, OTP’s generation and transmission facilities are spread throughout a large service territory. These facilities could be subject to physical attack or vandalism that could disrupt OTP’s operations or conceivably the regional or U.S. bulk power system.

 

OTP is subject to mandatory cybersecurity and physical security regulatory requirements. OTP implements the NERC standards for operating its transmission and generation assets and stays abreast of best practices within business and the utility industry to protect its computers and computer controlled systems from outside attack. We rely on industry accepted security measures and technology to securely maintain confidential and proprietary information necessary for the operation of our systems. In an effort to reduce the likelihood and severity of cyber intrusions, we have cybersecurity processes and controls designed to protect and preserve the confidentiality, integrity and availability of data and systems. We also take prudent and reasonable steps to protect the physical security of our generation and transmission facilities. However, all these measures and technology may not adequately prevent security breaches or cyber-attacks. Any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches or physical attack of our generation or transmission facilities could adversely affect our business and results of operations.

 

OTP’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

 

Operation of electric generating facilities involves risks which can adversely affect energy output and efficiency levels. Most of OTP’s generating capacity is coal-fired. OTP relies on a limited number of suppliers of coal, making it vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. OTP is a captive rail shipper of the BNSF Railway for shipments of coal to its Big Stone and Hoot Lake plants, making it vulnerable to increased prices for coal transportation from a sole supplier and disruptions in coal deliveries due to rail line congestion and constraints on the rail lines between the coal source mines and the plants. Higher fuel prices result in higher electric rates for OTP’s retail customers through fuel clause adjustments and could make it less competitive in wholesale electric markets. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting OTP’s electric generating facilities. The loss of a major generating facility would require OTP to find other sources of supply, if available, and expose it to higher purchased power costs.

 

Changes to regulation of generating plant emissions, including but not limited to CO2 emissions, could affect our operating costs and the costs of supplying electricity to our customers.

 

Existing or new laws or regulations passed or issued by federal or state authorities addressing climate change or reductions of GHG emissions, such as mandated levels of renewable generation, mandatory reductions in CO2 emission levels, taxes on CO2 emissions or cap and trade regimes, could require us to incur significant new costs, which could negatively impact our net income, financial position and operating cash flows if such costs cannot be recovered through rates granted by ratemaking authorities in the states where OTP provides service or through increased market prices for electricity. Debate continues in Congress and in the new administration on the direction and scope of U.S. and international policy on climate change and regulation of GHGs. Congress has considered but has not adopted GHG legislation which would require a reduction in GHG emissions and there is no legislation under active consideration at this time. The likelihood of any federal mandatory CO2 emissions reduction program being adopted by Congress in the near future, and the specific requirements of any such program, are uncertain, as are the future of additional regulatory actions.

 

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In 2014, the EPA published proposed standards of performance for CO2 emissions from new fossil fuel-fired power plants, proposed CO2 emission guidelines for existing fossil fuel-fired power plants and proposed CO2 standards of performance for CO2 emissions from reconstructed and modified fossil fuel-fired power plants, essentially requiring that such plants install updated control technology when constructing, modifying or reconstructing to reduce their emissions. The EPA published final rules for each of these proposals on October 23, 2015. On February 9, 2016 the U.S. Supreme Court granted a stay of the CO2 emission guidelines for existing fossil fuel-fired power plants pending disposition of petitions for review in the D.C. Circuit and, if a petition for a writ of certiorari seeking review by the U.S. Supreme Court were granted, any final Supreme Court determination. The D.C. Circuit heard oral argument on challenges to the CO2 emission guidelines on September 27, 2016 before the full court, and a decision will likely be rendered in early 2017. In addition, members of Congress and the new administration have been very critical of the emissions guidelines and may take actions that could impact the guidelines or related litigation. Consequently, uncertainty regarding the status of the rules may continue for a period of time. OTP is assessing the potential impact of the EPA’s final rules on existing affected sources of CO2 emissions at OTP. The final outcome of this rulemaking process could have a material adverse impact on our business and financial results.

 

MANUFACTURING

 

Competition from foreign and domestic manufacturers, the price and availability of raw materials, prices and supply of scrap or recyclable material and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

 

Our manufacturing businesses are subject to intense risks associated with competition from foreign and domestic manufacturers, many of whom have broader product lines, greater distribution capabilities, greater capital resources, larger marketing, research and development staffs and facilities and other capabilities that may place downward pressure on margins and profitability. The companies in our Manufacturing segment use a variety of raw materials in the products they manufacture, including steel, aluminum and polystyrene and other plastics resins. Costs for these items can fluctuate significantly. If our manufacturing businesses are not able to pass on cost increases to their customers, it could have a negative effect on profit margins in our Manufacturing segment. Additionally, a certain amount of residual material (scrap) is a by-product of many of the manufacturing and production processes used by our manufacturing companies. Declines in commodity prices for these scrap materials due to weakened demand or excess supply, can negatively impact the profitability of our manufacturing companies as it reduces their ability to mitigate the cost associated with excess material. Changes in macroeconomic conditions can negatively impact demand in the end-use markets for products and parts that we manufacture, resulting in reduced sales and profits.

 

Each of our manufacturing companies has significant customers and concentrated sales to such customers. If our relationships with significant customers should change materially, it would be difficult to immediately and profitably replace lost sales.

 

PLASTICS

 

Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of PVC resin. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for our plastics business.

 

We rely on a limited number of vendors to supply the PVC resin used in our plastics business. Two vendors accounted for 100% of our total purchases of PVC resin in 2016 and 96% of our total purchases of PVC resin in 2015. In addition, the supply of PVC resin may be limited primarily due to manufacturing capacity and the limited availability of raw material components. A majority of U.S. resin production plants are located in the Gulf Coast region, which may increase the risk of a shortage of resin in the event of a hurricane or other natural disaster in that region. The loss of a key vendor or any interruption or delay in the availability or supply of PVC resin could disrupt our ability to deliver our plastic products, cause customers to cancel orders or require us to incur additional expenses to obtain PVC resin from alternative sources, if such sources are available.

 

We compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish our products from those of our competitors.

 

The plastic pipe industry is fragmented and competitive due to the number of producers and the fungible nature of the product. We compete not only against other plastic pipe manufacturers, but also against ductile iron, steel and concrete pipe manufacturers. Due to shipping costs, competition is usually regional instead of national in scope, and the principal areas of competition are a combination of price, service, warranty, and product performance. Our inability to compete effectively in each of these areas and to distinguish our plastic pipe products from competing products may adversely affect the financial performance of our plastics business.

 

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Changes in PVC resin prices can negatively affect our plastics business.

 

The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been lower. Changes in PVC resin prices can negatively affect PVC pipe prices, profit margins on PVC pipe sales and the value of our finished goods inventory.

 

By the end of 2016, certain PVC resin producers in the United States had completed approximately 900 million pounds of resin production capacity additions to support the global market for PVC resin. Should this capacity not be used to support the resin export market, vendors may take steps to have it absorbed in the U.S. resin market. If this occurs, our Plastics segment financial results could be adversely impacted by PVC resin pricing strategies implemented by U.S. producers to get this capacity absorbed in the U.S. PVC resin market.

 

Item 1B.  UNRESOLVED STAFF COMMENTS

 

None.

 

Item 2.     PROPERTIES

 

The Coyote Station, which commenced operation in 1981, is a 414,000 kW (nameplate rating) mine-mouth plant located in the lignite coal fields near Beulah, North Dakota and is jointly owned by OTP, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Public Service Company. OTP is the operating agent of the Coyote Station and owns 35% of the plant.

 

OTP, jointly with Northwestern Public Service Company and Montana-Dakota Utilities Co., owns the 414,000 kW (nameplate rating) Big Stone Plant in northeastern South Dakota which commenced operation in 1975. OTP is the operating agent of Big Stone Plant and owns 53.9% of the plant.

 

Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of two separate generating units: a unit built in 1959 (53,500 kW nameplate rating) and a unit added in 1964 (75,000 kW nameplate rating) and modified in 1988 to provide cycling capability, allowing this unit to be more efficiently brought online from a standby mode. These two generating units have a combined nameplate rating of 128,500 kW. Current plans are for both units to be removed from service in 2021.

 

OTP owns 27 wind turbines at the Langdon, North Dakota Wind Energy Center with a nameplate rating of 40,500 kW, 32 wind turbines at the Ashtabula Wind Energy Center located in Barnes County, North Dakota with a nameplate rating of 48,000 kW and 33 wind turbines at the Luverne Wind Farm located in Steele County, North Dakota with a nameplate rating of 49,500 kW.

 

As of December 31, 2016 OTP’s transmission facilities, which are interconnected with lines of other public utilities, consisted of 535 miles of 345 kV lines; 479 miles of 230 kV lines; 878 pole miles of 115 kV lines; and 3,973 miles of lower voltage lines, principally 41.6 kV. OTP owns the uprated portion of 48 pole miles of the 345 kV lines, with Minnkota Power Cooperative retaining title to the original 230 kV construction, and OTP owns an undivided interest in the remaining 345 kV line miles. OTP is a joint owner, with other regional utilities, in transmission lines with the following ownership interests: 14.8% in the 70 mile Bemidji-Grand Rapids 230 kV line, approximately 14.2% of 242 pole miles of energized line in the Fargo-Monticello 345 kV project and approximately 4.8% of 255 pole miles of energized line in the Brookings to Southeast Twin Cities 345 kV project.

 

In addition to the properties mentioned above, all of which are utilized by the Electric segment, the Company owns and has investments in offices and service buildings utilized by each of its manufacturing and plastic pipe companies. The Company’s subsidiaries own facilities and equipment used in: the manufacture of PVC pipe, thermoformed products, heavy metal fabricated products, metal parts stamping, fabricating, painting and contract machining.

 

Management of the Company believes the facilities and equipment described above are adequate for the Company's present businesses.

 

Item 3.LEGAL PROCEEDINGS

 

The Company is the subject of various pending or threatened legal actions and proceedings in the ordinary course of its business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. The Company records a liability in its consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where the Company has assessed that a loss is probable and an amount can be reasonably

 

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estimated. The Company believes the final resolution of currently pending or threatened legal actions and proceedings, either individually or in the aggregate, will not have a material adverse effect on its consolidated financial position, results of operations or cash flows, excluding any liability for RSG charges described in Note 9 to the Company’s consolidated financial statements for which an estimate cannot be made at this time.

 

Item 3A.  EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF FEBRUARY 22, 2017)

 

Set forth below is a summary of the principal occupations and business experience during the past five years of the executive officers as defined by rules of the SEC. Each of the executive officers, excluding John Abbott, has been employed by the Company for more than five years in an executive or management position either with the Company or its wholly owned subsidiary, Otter Tail Power Company.

 

NAME AND AGE   DATE ELECTED
TO OFFICE		   PRESENT POSITION AND BUSINESS EXPERIENCE
Charles S. MacFarlane (52)   4/13/15   Present: President and Chief Executive Officer
George A. Koeck (64)   4/10/00   Present: Senior Vice President, General Counsel and Corporate Secretary
Kevin G. Moug (57)   4/9/01   Present: Chief Financial Officer and Senior Vice President
Timothy J. Rogelstad (50)   4/14/14   Present: Senior Vice President, Electric Platform
John Abbott (58)   2/11/15   Present: Senior Vice President, Manufacturing Platform

 

On April 13, 2015 Mr. MacFarlane was elected as the Company’s President and Chief Executive Officer and as member of the Company’s board of directors effective with the retirement of Edward J. McIntyre as Chief Executive Officer of the Company and as a member of the Company’s board of directors. On February 5, 2014 the Company’s board of directors appointed Mr. MacFarlane, then President and Chief Executive Officer of OTP and Senior Vice President, Electric Platform of the Company, to the role of President and Chief Operating Officer of the Company, effective April 14, 2014. Mr. MacFarlane joined OTP in 2001 and had served as its President from 2003 to 2014 and its Chief Executive Officer from 2007 to 2014. He served as Senior Vice President, Electric platform of the Company from 2012 to 2014. Prior to joining OTP, Mr. MacFarlane served as Director of Electric Distribution Planning and Engineering for Xcel Energy Inc.’s multi-state service territory. He was also Director of Delivery Construction and Field Operations for Northern States Power Company prior to its merger with New Centuries Energy and becoming Xcel Energy.

 

On April 14, 2014 Timothy J. Rogelstad was appointed to succeed Mr. MacFarlane as President of OTP and Senior Vice President, Electric Platform of the Company. Mr. Rogelstad joined OTP in June 1989 as an engineer in the System Engineering Department and served as Supervisor, Transmission Planning, and Manager, Delivery Planning, before being named Vice President, Asset Management, in 2012. In the role of Vice President, Asset Management at OTP, he was in charge of OTP’s Delivery Planning, Delivery Maintenance, Delivery Engineering, System Operations, and Project Management Departments. Mr. Rogelstad is a registered professional engineer in the three states where OTP serves, Minnesota, North Dakota, and South Dakota.

 

On February 5, 2015 John Abbott was selected to serve as Senior Vice President, Manufacturing Platform, and President of Varistar. Prior to coming to the Company, Mr. Abbott served as an officer and group vice president for eight years at Standex International Corporation (Standex), a group of restaurant equipment companies,. During his last five years at Standex, Mr. Abbott served as Group Vice President, Food Service Equipment Group. In this role, Mr. Abbott was responsible for all strategic and operational aspects of the Food Service Equipment business. Prior to working at Standex, Mr. Abbott was with Pentair for 20 years, rising from product manager to president and global business unit leader of its water filtration division.

 

George A. Koeck and Kevin G. Moug have each held their present positions with the Company for more than five years.

 

The term of office for each of the executive officers is one year and any executive officer elected may be removed by the vote of the board of directors at any time during the term. There are no family relationships between any of the executive officers or directors.

 

Item 4.Mine Safety Disclosures

 

Not Applicable.

 

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PART II

 

Item 5.MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

The Company’s common stock is traded on the NASDAQ Global Select Market under the NASDAQ symbol “OTTR”. The information required by this Item can be found on Page 36 of this Annual Report on Form 10-K under the heading “Selected Financial Data,” on Page 95 under the heading “Retained Earnings and Dividend Restriction” and on Page 116 under the heading “Supplementary Financial Information.” The Company does not have a publicly announced stock repurchase program. The Company did not repurchase any equity securities during the three months ended December 31, 2016. 

 

PERFORMANCE GRAPH

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN

 

This graph compares the cumulative total shareholder return on the Company’s common shares for the last five fiscal years with the cumulative return of The NASDAQ Stock Market Index and the Edison Electric Institute (EEI) Index over the same period (assuming the investment of $100 in each vehicle on December 31, 2011, and reinvestment of all dividends).

 

 

   2011   2012   2013   2014   2015   2016 
OTC  $100.00   $119.53   $145.91   $160.79   $144.62   $230.05 
EEI  $100.00   $102.09   $115.37   $148.72   $142.92   $167.84 
NASDAQ  $100.00   $116.43   $155.41   $174.78   $175.62   $198.47 

 

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Item 6.SELECTED FINANCIAL DATA

 

(thousands, except number of shareholders and per-share data)  2016   2015   2014   2013   2012 
Revenues                         
Electric  $427,383   $407,131   $407,743   $373,540   $350,765 
Manufacturing   221,289    215,011    219,583    204,997    208,965 
Plastics   154,901    157,758    172,050    164,957    150,517 
Intersegment Eliminations   (34)   (96)   (114)   (80)   (82)
Total Operating Revenues  $803,539   $779,804   $799,262   $743,414   $710,165 
Net Income from Continuing Operations  $62,037   $58,589   $56,883   $48,595   $46,034 
Net Income (Loss) from Discontinued Operations   284    756    840    2,270    (51,307)
Net Income (Loss)  $62,321   $59,345   $57,723   $50,865   $(5,273)
Operating Cash Flow from Continuing Operations  $163,541   $131,540   $125,769   $142,408   $155,026 
Operating Cash Flow - Continuing and Discontinued Operations   163,386    117,540    112,474    147,781    233,547 
Capital Expenditures - Continuing Operations   161,259    160,084    163,582    159,833    114,186 
Total Assets (1)   1,912,385    1,818,683    1,738,116    1,558,190    1,567,523 
Long-Term Debt (1)   505,341    443,846    495,906    387,212    417,830 
Basic Earnings Per Share - Continuing Operations (2)   1.61    1.56    1.56    1.33    1.25 
Basic Earnings (Loss) Per Share - Total (2)   1.62    1.58    1.58    1.39    (0.17)
Diluted Earnings Per Share - Continuing Operations (2)   1.60    1.56    1.55    1.33    1.25 
Diluted Earnings (Loss) Per Share - Total (2)   1.61    1.58    1.57    1.39    (0.17)
Return on Average Common Equity (3)   9.8%   10.1%   10.4%   9.5%   (1.1)%
Dividends Declared Per Common Share   1.25    1.23    1.21    1.19    1.19 
Dividend Payout Ratio   78%   78%   77%   86%   — 
Common Shares Outstanding - Year End   39,348    37,857    37,218    36,272    36,168 
Number of Common Shareholders (4)   13,805    14,062    14,134    14,252    14,584 
(1)2012 through 2015 adjusted in 2016 to reflect the netting of unamortized debt expense against related debt on the liability side of the balance sheet.
(2)Based on average number of shares outstanding.
(3)Earnings available for common shares divided by the 13-month average of month-end common equity balances.
(4)Holders of record at year end.

 

Item 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Overview

 

Otter Tail Corporation and its subsidiaries form a diverse group of businesses with operations classified into three segments: Electric, Manufacturing and Plastics. Our primary financial goals are to maximize earnings and cash flows and to allocate capital profitably toward growth opportunities that will increase shareholder value. Meeting these objectives enables us to preserve and enhance our financial capability by maintaining desired capitalization ratios and a strong interest coverage position and preserving investment grade credit ratings on outstanding securities, which, in the form of lower interest rates, benefits both our customers and shareholders.

 

Our strategy is to continue to grow our largest business, the regulated electric utility, which will lower our overall risk, create a more predictable earnings stream, improve our credit quality and preserve our ability to fund the dividend. Over time, we expect the electric utility business will provide approximately 75% to 85% of our overall earnings. We expect our manufacturing and plastic pipe businesses will provide 15% to 25% of our earnings, and will continue to be a fundamental part of our strategy. The actual mix of earnings from continuing operations in 2016, 2015 and 2014 was 80%, 83% and 77%, respectively, from our electric utility business and 20%, 17% and 23%, respectively, from our manufacturing and plastic pipe businesses, including unallocated corporate costs.

 

Reliable utility performance along with rate base investment opportunities over the next five years will provide us with a strong base of revenues, earnings and cash flows. We also look to our manufacturing and plastic pipe companies to provide organic growth as well. Organic, internal growth comes from new products and services, market expansion and increased efficiencies. We expect much of our growth in these businesses in the next few years will come from utilizing expanded plant capacity from capital investments made in previous years. We will also evaluate opportunities to allocate capital to potential acquisitions in our Manufacturing and Plastics segments. We are a committed long-term owner and therefore we do not acquire companies in pursuit of short-term gains. However, we will divest operating companies that no longer fit into our

 

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strategy and risk profile over the long term. In the period 2011 through 2015 we sold several businesses in execution of our announced strategy to realign our portfolio of businesses and refocus our capital investment in the electric utility.

 

On September 1, 2015 Miller Welding & Iron Works, Inc., a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing, Inc. of Dawsonville, Georgia for $30.8 million in cash. A post-closing reduction in the purchase price of $1.5 million was agreed to in June 2016 resulting in an adjusted purchase price of $29.3 million. The acquired business, now operating under the name BTD-Georgia, is a full-service, high-tech metal fabricator located 30 miles north of Atlanta, Georgia. BTD-Georgia offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers.

 

Major growth strategies and initiatives in our future include:

 

·Planned capital budget expenditures of up to $936 million for the years 2017 through 2021, of which $862 million are for capital projects at Otter Tail Power Company (OTP), including $315 million for renewable wind and solar energy generation projects, $147 million for natural gas-fired generation to replace Hoot Lake Plant capacity and $116 million for transmission projects designated by the Midcontinent Independent System Operator, Inc. (MISO) as Multi-Value Projects (MVPs). The remainder of OTP’s 2017-2021 anticipated capital expenditures is for asset replacements, additions and improvements across OTP’s generation, transmission, distribution and general plant. See “Capital Requirements” section for further discussion.
   
·The $315 million planned investment for renewable wind and solar energy generation projects includes the Merricourt Wind Project. In November 2016 OTP signed agreements to purchase this 150-megawatt (MW) wind farm in southeastern North Dakota that EDF Renewable Energy will design and build in 2019.
   
·Continued investigation and evaluation of organic growth opportunities and evaluation of opportunities to allocate capital to potential acquisitions in our Manufacturing and Plastics segments.

 

In 2016:

 

·Our Electric segment net income increased 3.0% to $49.8 million from $48.4 million in 2015.
   
·Our Manufacturing segment net income increased 34.1% to $5.7 million from $4.2 million in 2015.
   
·Our Plastics segment net income decreased 12.2% to $10.6 million from $12.1 million in 2015.
   
·Our net cash from continuing operations was $163.5 million.
   
·Capital Expenditures at OTP totaled $149.6 million as work continued on two major MISO-designated MVPs.
   
·We raised net proceeds of $43.9 million from the sale of 1,014,115 shares of common stock through our At-the-Market offering program and the issuance of 356,339 shares of common stock through our stock plans.
   
·We issued $130.0 million of long-term debt, paid $87.5 million to retire and redeem long-term debt, including the retirement of $52.3 million of our 9.000% notes due in December 2016, and reduced our short-term borrowings by $37.8 million.

 

The following table summarizes our consolidated results of operations for the years ended December 31:

 

(in thousands)  2016   2015 
Operating Revenues:          
Electric  $427,349   $407,039 
Manufacturing   221,289    215,011 
Plastics   154,901    157,754 
Total Operating Revenues  $803,539   $779,804 
Net Income (Loss) From Continuing Operations:          
Electric  $49,829   $48,370 
Manufacturing   5,694    4,247 
Plastics   10,628    12,108 
Corporate   (4,114)   (6,136)
Total Net Income From Continuing Operations:  $62,037   $58,589 

 

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Revenues in our Electric and Manufacturing business segments increased in 2016 compared with 2015. Major factors contributing to a $20.3 million (5.0%) increase in Electric segment revenues between the years were increased kilowatt-hour (kwh) sales to pipeline customers, increased revenue billed under an interim rate increase in Minnesota net of an estimated potential refund, an increase in transmission tariff revenues and a net increase in rider revenues related to increased rider rates, offset by a decrease in revenues from the recovery of fuel and purchased power costs due to a net reduction in those costs in 2016. Manufacturing segment revenues increased $6.3 million (2.9%). Revenues at BTD showed a net increase of $9.8 million, with revenues from BTD-Georgia, acquired in September 2015, increasing by $15.4 million. Revenues from BTD’s other locations decreased $5.6 million, despite a $9.6 million increase in revenue from sales of wind tower components from BTD’s Illinois plant, due to reduced sales to manufacturers of recreational, agricultural and industrial equipment as demand for these products remained soft in 2016. Revenues at T.O. Plastics, Inc. (T.O. Plastics) decreased $3.5 million, mainly due to the loss of product sales to a major customer who began producing the product in-house in 2015. Plastics segment revenues were down $2.9 million (1.8%), despite a 10.5% increase in pounds of polyvinyl chloride (PVC) pipe sold, mainly due to lower PVC sales prices driven by lower raw material costs.

 

The $3.4 million increase in net income from continuing operations in 2016 compared with 2015 reflects the following:

 

·A $1.5 million increase in Electric segment net income due to increased net interim rates in Minnesota and increased retail rider revenues which were almost entirely offset by increased operating and income tax expenses.
   
·A $1.4 million increase in Manufacturing segment net income is mainly due to sales of wind tower components from BTD’s Illinois plant and improved productivity and profits at BTD’s Minnesota facilities.
   
·A $2.0 million net-of-tax decrease in Corporate net losses as a result of receiving nontaxable benefit proceeds from corporate-owned life insurance and lower operating expenses due to lower benefit and insurance costs.

 

offset by:

 

·A $1.5 million decrease in Plastics segment net income mainly due to reduced margins on pipe sales resulting from sales prices that declined more than the decline in raw material costs.

 

Following is a more detailed analysis of our operating results by business segment for the years ended December 31, 2016, 2015 and 2014, followed by a discussion of our financial position at the end of 2016 and our outlook for 2017.

 

Results of Operations

 

This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes. See note 2 to consolidated financial statements for a complete description of our lines of business, locations of operations and principal products and services.

 

Intersegment Eliminations—Amounts presented in the following segment tables for 2016, 2015 and 2014 operating revenues, cost of goods sold and other nonelectric operating expenses will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

 

Intersegment Eliminations (in thousands)  2016   2015   2014 
Operating Revenues:               
Electric  $34   $92   $114 
Product Sales   —    4    — 
Cost of Products Sold   6    9    45 
Other Nonelectric Expenses   28    87    69 

 

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Electric

 

The following table summarizes the results of operations for our Electric segment for the years ended December 31:

 

(in thousands)  2016   %
change		   2015   %
change		   2014 
Retail Sales Revenues  $376,610    3   $364,614    1   $361,100 
Wholesale Revenues – Company Generation   4,584    83    2,499    (78)   11,160 
Net Revenue – Energy Trading Activity   —    (100)   186    (82)   1,031 
Other Revenues   46,189    16    39,832    16    34,452 
Total Operating Revenues  $427,383    5   $407,131    —   $407,743 
Production Fuel   54,792    28    42,744    (36)   67,216 
Purchased Power – System Use   63,226    (19)   78,150    19    65,848 
Other Operation and Maintenance Expenses   151,225    7    140,768    (1)   141,936 
Depreciation and Amortization   53,743    20    44,786    2    44,076 
Property Taxes   14,266    6    13,512    7    12,607 
Operating Income  $90,131    3   $87,171    15   $76,060 
Electric kilowatt-hour (kwh) Sales (in thousands)                         
Retail kwh Sales   4,750,421    3    4,593,604    (2)   4,695,062 
Wholesale kwh Sales – Company Generation   190,288    77    107,510    (61)   273,454 
Wholesale kwh Sales – Purchased Power Resold   —    (100)   5,547    (68)   17,303 
Heating Degree Days   5,314    (6)   5,633    (22)   7,205 
Cooling Degree Days   451    (7)   483    32    367 

 

2016 Compared with 2015

The following table shows heating and cooling degree days as a percent of normal:

 

   2016   2015 
Heating Degree Days   84.1%   88.2%
Cooling Degree Days   97.4%   103.4%

 

The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in 2016 and 2015 and between the years:

 

   2016 vs Normal   2015 vs Normal   2016 vs 2015 
Effect on Diluted Earnings Per Share  $(0.067)  $(0.044)  $(0.023)

 

The $12.0 million increase in retail revenue includes:

 

·An $11.0 million increase in retail revenue related to a 9.56% interim rate increase implemented in April 2016 in conjunction with OTP's 2016 general rate increase request in Minnesota.
   
·A $4.4 million increase in Environmental Cost Recovery (ECR) rider revenue due to the recovery of additional investment and costs related to the operation of the air quality control system (AQCS) at Big Stone Plant that was placed in service in December 2015.
   
·A $4.3 million increase in revenue related to an increase in retail kwh sales, mainly to pipeline customers.
   
·A $2.2 million increase in Transmission Cost Recovery (TCR) rider revenues related to increased investment in transmission plant.
   
·A $1.7 million increase in Conservation Improvement Program (CIP) cost recovery revenues directly related to additional CIP activities.

 

offset by:

 

·A $5.7 million decrease in fuel and purchased power cost recovery revenues mainly due to an 11.4% decrease in kwhs purchased partially offset by a 19.7% kwh increase in generation.
   
·A $3.6 million reduction in interim rate revenues recorded to provide for an estimated refund related to a modification in OTP’s original request and other expected outcomes in the pending Minnesota general rate case.
   
·A $1.6 million decrease in revenues related to decreased consumption due to milder weather in 2016, evidenced by a 5.7% reduction in heating-degree days and 6.6% reduction in cooling-degree days between the years.
   
·A $0.6 million decrease in Renewable Resource Adjustment (RRA) rider revenues in North Dakota, which were down as a result of earning more federal Production Tax Credits (PTCs) to pass back to customers due to a 3.6% increase in kwhs generated from wind turbines eligible for PTCs.

 

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A $2.1 million increase in revenue from wholesale electric sales from company-owned generation was partially offset by a $1.5 million increase in fuel costs for wholesale generation, resulting in a $0.6 million increase in wholesale revenue net of fuel costs as increased plant availability in 2016 provided greater opportunity for OTP to respond to market demand.

 

Other electric revenues increased $6.4 million as a result of:

 

·A $4.8 million increase in MISO transmission tariff revenues, mainly driven by increased investment in regional transmission lines and related returns on and recovery of Capacity Expansion 2020 (CapX2020) and MISO-designated MVP investment costs and operating expenses.
   
·A $3.0 million increase in MISO network integration transmission service revenues due to a regional transmission cooperative terminating its integrated transmission agreement with OTP and joining the Southwest Power Pool (SPP) in 2016.

 

offset by:

 

·A $1.3 million decrease in revenue related to a reduction in integrated transmission agreement revenues from two regional transmission providers related to the curtailment of services under one agreement and the discontinuance of another agreement.

 

Production fuel costs increased $12.0 million as a result of a 27.1% increase in kwhs generated from our steam-powered and combustion turbine generators related to Big Stone Plant being fully operational in 2016 after the tie in of the AQCS in 2015, as well as Coyote Station being available to run at full load in 2016 after being restricted to half load in 2015 because of boiler feed water pump problems.

 

The cost of purchased power to serve retail customers decreased $14.9 million due to an 11.4% decrease in kwhs purchased in combination with an 8.7% decrease in the cost per kwh purchased. Greater availability of company-owned generation in 2016 reduced the need to purchase electricity to serve retail load. The decreased cost per kwh purchased was driven by lower market demand mainly resulting from milder weather in 2016 compared with 2015.

 

Electric operating and maintenance expenses increased $10.5 million as a result of:

 

·$3.7 million in transmission expenses from the SPP as a result of a regional transmission cooperative terminating its integrated transmission agreement with OTP and joining the SPP in 2016.
   
·A $1.9 million increase in pollution control reagent costs at Big Stone Plant and Coyote Station related to compliance with the Environmental Protection Agency (EPA) power plant emission regulations.
   
·A $1.7 million increase in CIP program expenditures related to additional CIP activities.
   
·A $1.3 million increase in MISO transmission service charges due to increased transmission investment by other MISO members.
   
·A $1.1 million increase in storm repair expenses associated with excessive storm damage in OTP's Minnesota service area in July 2016 and in its North Dakota and South Dakota service areas in December 2016.
   
·$0.8 million related to increases in other expense categories.

 

Depreciation and amortization expense increased $9.0 million mainly due to the AQCS at Big Stone Plant being placed in service in December 2015 along with increased investment in transmission assets with the final phases of the Fargo-Monticello and Brookings-Southeast Twin Cities 345-kV transmission lines placed in service near the end of the first quarter of 2015.

 

The $0.8 million increase in property tax expense is related to property additions in Minnesota and North Dakota in 2015.

 

2015 Compared with 2014

Retail sales revenue increased $3.5 million mainly as a result of:

 

·An $8.7 million increase in ECR rider revenues related to earning a return in North Dakota and Minnesota on increasing amounts invested in the AQCS at Big Stone Plant, earning a return on the Hoot Lake Plant Mercury and Air Toxics Standards (MATS) project in North Dakota beginning in 2015, and the initiation of an ECR rider in South Dakota in December 2014 to recover costs and earn a return on amounts invested in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects.
   
·A $3.1 million increase in revenues recoverable under CIP riders related to an increase in CIP incentives awarded for 2014 program results as well as increases in CIP accruals for 2015 program incentives and recoverable expenditures.
   
·A $3.1 million increase in revenue from higher sales to pipeline customers.

 

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·A $0.9 million increase in North Dakota RRA rider revenues.

 

offset by:

 

·A $4.8 million decrease in revenues related to a 2.2% decrease in retail kwh sales mainly resulting from milder weather in 2015, evidenced by heating-degree days that were 21.8% lower than in 2014 and 88.2% of normal. Weather impacted diluted earnings per share negatively by approximately $0.08 per share in 2015 compared with 2014 and approximately $0.05 per share compared with weather normalized sales for 2015.
   
·A $4.0 million decrease in revenues from the recovery of fuel and purchased power costs due to the 2.2% decrease in retail kwh sales and a 3.0% decrease in the combined cost of fuel and purchased power per kwh purchased and generated.
   
·A $3.0 million decrease in revenues due to lower sales to residential customers in North Dakota and Minnesota and lower sales to commercial customers in North Dakota.
   
·A $0.4 million reduction in Big Stone II cost recovery rider revenues in North Dakota as the North Dakota share of costs were fully recovered by March 31, 2014.

 

Wholesale electric revenues from company-owned generation decreased $8.7 million as a result of a 60.7% reduction in wholesale kwh sales combined with a 43.0% decrease in revenue per wholesale kwh sold. The decreases in wholesale kwh sales and prices were driven by decreased wholesale market demand resulting from milder weather in 2015. Also, OTP had fewer resources available for selling into the wholesale market. Big Stone Plant was off line from March through July 2015 for an extended maintenance outage. Coyote Station operated at reduced load in 2015 due to ongoing repairs related to a December 2014 boiler feed pump failure and fire. Hoot Lake Plant was curtailed in 2015 due to low market prices for electricity, which was a factor contributing to a strategic decision to shut down Hoot Lake Plant’s Unit 3 for preventative maintenance in September 2015. Generation from company-owned wind turbines was down 6.0% from 2014, primarily due to lower average wind speeds in the first half of 2015. The decrease in wholesale prices for electricity was due, in part, to lower prices for natural gas used in the generation of electricity in 2015 compared with 2014.

 

Net revenue from energy trading activities decreased $0.8 million as a result of OTP discontinuing its trading activities not directly associated with serving retail customers in December 2014 due to a lack of market activity and profitable trading opportunities.

 

Other electric revenues increased $5.4 million, primarily as a result of an increase in MISO transmission tariff revenues related to increased investment in regional transmission projects including returns on and recovery of CapX2020 and MISO-designated MVP investment costs and operating expenses.

 

Production fuel costs decreased $24.5 million as a result of a 39.3% decrease in kwhs generated from OTP’s steam-powered and combustion turbine generators primarily due to the factors discussed above. The cost of purchased power to serve retail customers increased $12.3 million due to a 55.7% increase in kwhs purchased, partially offset by a 23.8% decrease in the cost per kwh purchased. The increase in power purchases for retail sales was necessitated by the reduced availability of company-owned generating capacity discussed above. The decreased cost per kwh purchased was driven by lower market demand due to milder weather in 2015 in combination with lower prices for natural gas used in the generation of electricity.

 

Electric operating and maintenance expenses decreased $1.2 million reflecting:

 

·A $3.0 million net reduction in generation plant operating and maintenance costs between the years as costs incurred in 2014 at Hoot Lake Plant and Coyote Station were more than the maintenance costs incurred at Big Stone Plant in 2015. Although kwh generation decreased for all three plants in 2015, work done on the plants in 2014 was more operating and maintenance in nature while more capitalized projects were completed in 2015. Also, with the plants generating fewer kwhs in 2015, operating costs were lower in 2015.
   
·A $1.4 million reduction in travel related expenses as a result of increased vehicle usage on capital projects and lower fuel prices.
   
·A $0.7 million increase in capitalized administrative and general expenses due to more time being spent on capital projects.
   
·A $0.4 million reduction in the North Dakota share of Big Stone II costs being amortized as the North Dakota share of costs were fully recovered by March 31, 2014.
   
·An expense of $0.3 million recorded in June 2014 related to OTP not earning a return on the deferred recovery of the Minnesota share of Big Stone II abandoned transmission plant costs.

 

offset by:

 

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·A $3.8 million increase in MISO transmission tariff charges related to increasing investments by other transmission owners in regional CapX2020 and MISO-designated MVP transmission projects.
   
·A $0.9 million increase in Minnesota CIP expenditures and new program implementation costs.

 

Depreciation expense increased $0.7 million as a result of increased investment in transmission, distribution and general plant placed in service in 2014 and 2015.

 

The $0.9 million increase in property tax expense primarily is due to increased property valuations and transmission plant additions in Minnesota.

 

Manufacturing

 

The following table summarizes the results of operations for our Manufacturing segment for the years ended December 31:

 

(in thousands)  2016   %
change		   2015   %
change		   2014 
Operating Revenues  $221,289    3   $215,011    (2)  $219,583 
Cost of Products Sold   171,732    —    171,956    2    169,033 
Lease Exit Costs   —    —    —    —    2,843 
Other Operating Expenses   21,994    4    21,116    3    20,497 
Depreciation and Amortization   15,794    33    11,853    13    10,518 
Operating Income  $11,769    17   $10,086    (40)  $16,692 

 

2016 Compared with 2015

The increase in revenues in our Manufacturing segment in 2016 compared with 2015 relates to the following:

 

·Revenues at BTD increased $9.8 million, including:

 

oA $15.4 million increase in revenues at BTD-Georgia as a result of BTD owning and operating this plant for the entire year of 2016 compared to four months in 2015.

 

oA $9.6 million increase in revenues mainly related to the production of wind tower components.

 

offset by:

 

oA $15.2 million decrease in revenues related to lower sales to manufacturers of recreational and agricultural equipment due to softness in end markets served by those manufacturers.

 

·Revenues at T.O. Plastics decreased $3.5 million, including:

 

oA $3.0 million decrease in revenue related to a continued decline in sales to a customer insourcing product into its own manufacturing facilities.

 

oA $0.6 million decrease in sales of horticultural products due to sales execution challenges, including lower sales to a major distributor.

 

offset by:

 

oA net $0.1 million increase in sales of other products in the industrial and life sciences markets.

 

The decrease in cost of products sold in our Manufacturing segment includes the following:

 

·Cost of products sold at BTD increased $1.7 million. This includes a $15.5 million increase in cost of products sold at BTD-Georgia, offset by a $13.8 million net decrease in cost of products sold at BTD’s other facilities. The $13.8 million decrease is related to the decrease in sales, partially offset by an increase in costs of products sold at BTD’s Illinois plant as a result of the increase in the production of wind tower components.

 

·Cost of products sold at T.O. Plastics decreased $1.9 million related to the decrease in sales.

 

Gross margins at BTD were positively impacted in 2016 by changes in customer product mix between periods.

 

The $0.9 million increase in operating expenses in our Manufacturing segment includes the following:

 

·Operating expenses at BTD increased $1.4 million, of which $1.2 million was due to a full year of operations at BTD-Georgia in 2016.

 

·Operating expenses at T.O. Plastics decreased $0.4 million, primarily as a result of a $0.5 million decrease in selling expenses.

 

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The $3.9 million increase in depreciation and amortization expenses in our Manufacturing segment includes a $2.3 million increase at BTD-Georgia and a $1.8 million increase at BTD’s other plants mainly as a result of placing new assets in service in Minnesota in 2015 and 2016. Depreciation expense at T.O. Plastics decreased $0.2 million between the years.

 

2015 Compared with 2014

The decrease in revenues in our Manufacturing segment in 2015 compared with 2014 relates to the following:

 

·Revenues at BTD decreased $6.6 million (3.5%) due to the following:

 

oAn $8.6 million decrease in sales, mainly to manufacturers of oil and gas exploration and extraction equipment as a result of a reduction in drilling activity related to low oil prices.
   
oA $3.2 million decrease in sales of scrap metal due to a reduction in scrap metal prices and a reduction in scrap volume related to lower production and sales volumes between years.
   
oA $2.1 million decrease in sales to manufacturers of agricultural equipment related to continued softness in the agricultural industry.
   
oA $1.5 million reduction in tooling revenues.
   
oOffset by $8.8 million in sales at BTD-Georgia, acquired on September 1, 2015.

 

·Revenues at T.O. Plastics increased $2.0 million (6.1%) reflecting:
   
oA $1.4 million increase in sales of horticultural containers.
   
oA $0.5 million increase in sales of custom products.
   
oA $0.1 million increase in sales of various other products to industrial customers.

 

The increase in cost of products sold in our Manufacturing segment relates to the following:

 

·Cost of products sold at BTD decreased $0.4 million, reflecting an $8.7 million decrease in costs related to decreased sales, offset by $8.3 million in costs incurred at BTD-Georgia from September through December 2015.
   
·Cost of products sold at T.O. Plastics increased $3.3 million due to increases in material, labor and freight costs related to the increase in sales at T.O. Plastics.

 

The $2.8 million reduction in Manufacturing segment operating expenses related to the lease exit costs incurred in 2014, was partially offset by $0.6 million in operating expenses incurred at BTD-Georgia from September through December 2015. Labor and benefit expense increases of $1.0 million at BTD were mostly offset by a $0.9 million reduction in labor and benefit expenses at T.O. Plastics between the years.

 

Depreciation and amortization expense at BTD-Georgia from September through December 2015 was approximately $1.0 million. A $0.6 million increase in depreciation expense at BTD related to recent asset additions under its Minnesota facilities expansion plan was partially offset by a $0.3 million decrease in depreciation expense at T.O. Plastics as a result of certain assets reaching the end of their depreciable lives.

 

Plastics

 

The following table summarizes the results of operations for our Plastics segment for the years ended December 31:

 

(in thousands)  2016   %  
change		   2015   %  
change		   2014 
Operating Revenues  $154,901    (2)  $157,758    (8)  $172,050 
Cost of Products Sold   123,496    —    123,085    (12)   139,081 
Other Operating Expenses   9,402    (5)   9,849    6    9,292 
Depreciation and Amortization   3,861    9    3,552    6    3,364 
Operating Income  $18,142    (15)  $21,272    5   $20,313 

 

2016 Compared with 2015

The $2.9 million decrease in Plastics segment revenues is the result of an 11.2% decrease in the price per pound of pipe sold, partially offset by a 10.5% increase in pounds of pipe sold. The decline in sales price per pound is related to lower raw material prices between the periods. Increased pipe sales in the Colorado, Utah, and the South Central and Northwest regions of the United States were partially offset by decreased sales volumes in Montana, South Dakota and Minnesota. Cost of products sold increased $0.4 million due to the increase in sales volume, partly offset by a 9.2% decrease in the cost per pound of PVC pipe sold, as sales prices declined more than raw material prices. Lower margins have resulted in reduced incentive compensation, which is the primary factor contributing to the $0.4 million decrease in Plastics segment operating expenses.

 

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The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been lower.

 

2015 Compared with 2014

The $14.3 million decrease in Plastics segment revenues is the result of a 7.0% decrease in the price per pound of pipe sold in combination with a 1.4% decrease in pounds of PVC pipe sold. The decrease in sales are due in part to delayed purchases related to falling resin prices and in part to reduced demand in the region of the United States between the Mississippi River and the Rocky Mountain states, especially in Texas where soft markets were exacerbated by severe spring flooding. The $16.0 million decrease in costs of products sold is mainly due to a 10.2% decrease in the cost per pound of pipe sold as a result of lower resin prices. The $0.6 million increase in operating expenses was mainly related to increased wage and benefit costs.

 

Corporate

 

Corporate includes items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on our consolidated statements of income.

 

(in thousands)  2016   %
change		   2015   %
change		   2014 
Airplane Rent and Lease Exit Costs  $—    —   $—    —   $3,012 
Other Operating Expenses   8,896    (3)   9,143    (12)   10,406 
Depreciation and Amortization   47    (73)   172    48    116 

 

Corporate operating expenses decreased $0.2 million in 2016 as compared to 2015 as a result of decreased expenditures for contracted services and a decrease in claims at our captive insurance company, partially offset by a decrease in expenses allocated to OTP.

 

Corporate operating expenses decreased $4.3 million in 2015 compared with 2014 primarily due to:

 

·A $3.0 million reduction in airplane operating lease expense related to the early termination of an airplane lease in the second quarter of 2014, as divestitures had reduced the need for the airplane. The cost to terminate the lease early was approximately $2.5 million or a net-of-tax impact on diluted earnings per share of ($0.04).
   
·A $0.8 million reduction in insurance costs at our captive insurance company related to lower claims activity in 2015.
   
·A $0.5 million decrease in labor expense due to a reduction in employees in 2015.

 

CONSOLIDATED INTEREST CHARGES

 

(in thousands)  2016   %
change		   2015   %
change		   2014 
Interest Charges  $31,886    2   $31,160    5   $29,648 

 

The $0.7 million increase in interest charges in 2016 compared with 2015 is due to an increase in interest expense on short-term debt at OTP as a result of a $24.7 million increase in OTP’s daily average balance of short-term debt outstanding between the years and a $0.2 million decrease in capitalized interest expense. The increase in OTP’s use of short-term borrowing is related to its increasing investment in two major MVP transmission line projects under construction.

 

The $1.5 million increase in interest charges in 2015 compared with 2014 is mainly due to:

 

·A $1.3 million increase in interest expense incurred in January and February of 2015 at OTP related to the February 27, 2014 issuance of $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044.
   
·A $19.6 million increase in the daily average balance of short-term debt outstanding in 2015 compared with 2014.

 

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Consolidated OTHER INCOME

 

(in thousands)  2016   %
change		   2015   %
change		   2014 
Other Income  $2,905    33   $2,177    (39)  $3,557 

 

The $0.7 million increase in other income in 2016 compared with 2015 is mainly due to benefit proceeds from corporate-owned life insurance received in 2016.

 

The $1.4 million decrease in other income in 2015 compared with 2014, includes:

 

·A $0.8 million gain on the sale of an investment in tax-credit-qualified low income housing rental property in 2014 that was not duplicated in 2015.

 

·A $0.3 million reduction in other income at OTP related to reductions in allowance for equity funds used in construction (AFUDC) and carrying charges earned on funds invested in Minnesota CIP prior to recovery, in alignment with a decrease in short-term borrowing rates.

 

·A $0.2 million reduction in corporate-owned life insurance cash surrender value increases.

 

Consolidated Income Taxes

 

Income tax expense - continuing operations was $20.1 million in 2016 compared with $21.6 million in 2015 and $16.6 million in 2014. The following table provides a reconciliation of income tax expense – continuing operations calculated at the federal statutory rate on income from continuing operations before income taxes reported on our consolidated statements of income:

 

   For the Year Ended December 31, 
(in thousands)  2016   2015   2014 
Tax Computed at Federal Statutory Rate – Continuing Operations  $28,741   $28,081   $25,704 
Increases (Decreases) in Tax from:               
Federal PTCs   (7,175)   (6,962)   (7,517)
State Income Taxes Net of Federal Income Tax Expense   2,848    4,945    1,993 
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes   (850)   (850)   (849)
Corporate-owned Life Insurance   (680)   (167)   (354)
Dividend Received/Paid Deduction   (537)   (560)   (622)
Section 199 Domestic Production Activities Deduction   (482)   —    (1,026)
Investment Tax Credit Amortization   (350)   (571)   (597)
AFUDC - Equity   (280)   (426)   (505)
Differences Reversing in Excess of Federal Rates   77    (1,143)   (106)
Permanent and Other Differences   (1,231)   (705)   436 
Total Income Tax Expense – Continuing Operations  $20,081   $21,642   $16,557 
Effective Income Tax Rate – Continuing Operations   24.5%   27.0%   22.5%

 

Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs increased 3.6% in 2016 compared with 2015. OTP’s kwh generation from its wind turbines eligible for PTCs decreased 7.4% in 2015 primarily due to lower average wind speed in 2015 compared with 2014. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

 

DISCONTINUED OPERATIONS

 

On April 30, 2015 we sold Foley Company (Foley) for $12.0 million in cash, plus $6.3 million in adjustments for working capital and other related items received in October 2015, less $1.0 million in selling expenses. On February 28, 2015 we sold the assets of AEV, Inc. for $22.3 million in cash, plus $0.6 million in adjustments for working capital and fixed assets received in October 2015, less $0.8 million in selling expenses. Foley and AEV, Inc were formerly included in our Construction segment.

 

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On February 8, 2013 we completed the sale of substantially all the assets of our dock and boatlift company, formerly included in our Manufacturing segment. On November 30, 2012 we completed the sale of the assets of our wind tower manufacturing business. This business was the only remaining entity in our former Wind Energy segment.

 

Our Wind Energy and Construction segments were eliminated as a result of the sales of our wind tower manufacturing business, Foley and AEV, Inc. The financial position, results of operations and cash flows of Foley, AEV, Inc., our wind tower manufacturing business and our dock and boatlift company are reported as discontinued operations in our consolidated financial statements. Following are the results of discontinued operations by entity for the years ended December 31, 2016, 2015 and 2014:

 

(in thousands)  Foley   AEV, Inc.   Wind
Tower
Business		   Dock and
Boatlift
Business		   Intercompany
Transactions
Adjustment		   Total 
2016 Net (Loss) Income  $(114)  $(5)  $454   $(51)  $—   $284 
2015 Net (Loss) Income  $(5,489)  $6,216   $344   $(580)  $265   $756 
2014 Net (Loss) Income  $(3,034)  $2,621   $(11)  $274   $990   $840 

 

Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts were recognized on a percentage-of-completion basis. The method used to determine the progress of completion was based on the ratio of costs incurred to total estimated costs on construction projects. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in pretax charges of $4.4 million in 2015.

 

Impact of Inflation

 

OTP operates under regulatory provisions that allow price changes in fuel and certain purchased power costs to be passed to most retail customers through automatic adjustments to its rate schedules under fuel clause adjustments. Other increases in the cost of electric service must be recovered through timely filings for electric rate increases with the appropriate regulatory agency.

 

Our Manufacturing and Plastics segments consist entirely of businesses whose revenues are not subject to regulation by ratemaking authorities. Increased operating costs are reflected in product or services pricing with any limitations on price increases determined by the marketplace. Raw material costs, labor costs, fuel and energy costs and interest rates are important components of costs for companies in these segments. Any or all of these components could be impacted by inflation or other pricing pressures, with a possible adverse effect on our profitability, especially where increases in these costs exceed price increases on finished products. In recent years, our operating companies have faced strong inflationary and other pricing pressures with respect to steel, fuel, resin, and health care costs, which have been partially mitigated by pricing adjustments.

 

Liquidity

 

The following table presents the status of our lines of credit as of December 31, 2016 and December 31, 2015:

 

(in thousands)  Line Limit   In Use on
December 31,
2016		   Restricted due to
Outstanding
Letters of Credit		   Available on
December 31,
2016		   Available on
December 31,
2015		 
Otter Tail Corporation Credit Agreement  $130,000   $—   $—   $130,000   $90,334 
OTP Credit Agreement   170,000    42,883    50    127,067    148,694 
Total  $300,000   $42,883   $50   $257,067   $239,028 

 

We believe we have the necessary liquidity to effectively conduct business operations for an extended period if needed. Our balance sheet is strong and we are in compliance with our debt covenants. Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing.

 

We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets and borrowing ability because of investment-grade credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. On May 11, 2015 we filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 11, 2018. On

 

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May 11, 2015, we entered into a Distribution Agreement with J.P. Morgan Securities LLC (JPMS) under which we may offer and sell our common shares from time to time through JPMS, as our distribution agent, up to an aggregate sales price of $75 million through an At-the-Market offering program. We sold 36,403 shares at the end of the third quarter of 2016 under this program that were settled in October 2016 and received proceeds of $1,256,000 net of $16,000 in commissions paid to JPMS.

 

Equity or debt financing will be required in the period 2017 through 2021 given the expansion plans related to our Electric segment to fund construction of new rate base investments. Also, such financing will be required should we decide to reduce borrowings under our lines of credit or refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes. Our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside our control. In addition, our borrowing costs can be impacted by changing interest rates on short-term and long-term debt and ratings assigned to us by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios.

 

The determination of the amount of future cash dividends to be declared and paid will depend on, among other things, our financial condition, improvement in earnings per share, cash flows from operations, the level of our capital expenditures and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by our subsidiaries. See note 8 to consolidated financial statements for more information. The decision to declare a dividend is reviewed quarterly by the board of directors. On February 2, 2017 our board of directors increased the quarterly dividend from $0.3125 to $0.32 per common share.

 

2016 Cash Flows Compared with 2015 Cash Flows

Cash provided by operating activities of continuing operations was $163.5 million in 2016 compared with $131.5 million in 2015. The $32.0 million increase in cash provided by continuing operations between the years includes a $32.8 million reduction in cash used for working capital items due to:

 

·An $18.2 million decrease in cash used for accounts payable and other current liabilities at OTP, reflecting higher levels of payables in December 2016 for coal deliveries and transmission services related to the colder temperatures in December 2016 and the payment, in January 2015, of large billings for coal transportation, coal and power purchased in December 2014.

 

·A $10.7 million decrease in cash used for accounts payable and other current liabilities at the plastic pipe companies related to an increase in year-end resin purchases in 2016 compared to 2015.

 

·A $7.3 million decrease in cash used for interest payable and income taxes receivable between the years, mainly related to having made a $4.0 million estimated tax payment in December 2015 that was refunded in the first quarter of 2016, as a five-year extension of bonus depreciation for income taxes, approved on December 18, 2015, resulted in a lower federal income tax liability for the Company in 2015.

 

offset by:

 

·A $2.3 million increase in unbilled revenues at OTP between the years resulting from the 2016 increase in interim rates in Minnesota and increased kwh sales due to colder weather in December 2016 compared with December 2015.

 

In continuing operations, net cash used in investing activities was $159.3 million in 2016 compared with $193.6 million in 2015. The $34.3 million decrease in cash used for investing activities includes a $32.3 million decrease in cash used in acquisitions as we paid $30.8 million to acquire the assets of BTD-Georgia in September 2015 and received a purchase price adjustment of $1.5 million in June 2016.

 

Net cash used in financing activities of continuing operations was $4.1 million in 2016 compared with net cash provided by financing activities of $38.1 million in 2015. Financing activities in 2016 included:

 

·$80.0 million in proceeds from the issuance of our 3.55% Guaranteed Senior Notes due December 15, 2026 in December 2016.

 

·$50.0 million borrowed under our term loan agreement in February 2016.

 

·$32.8 million in net proceeds from the issuance of 1,014,115 shares of common stock under the Company’s At-the-Market offering program.

 

·$11.1 million in net proceeds from the issuance of 356,399 shares of common stock under the Company’s automatic dividend reinvestment and share purchase plans.

 

offset by:

 

·The repayment of the $52.3 million balance of our 9.000% notes due in December 2016.

 

·A $41.2 million reduction of short-term borrowings and checks written in excess of cash.

 

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·The repayment of $35.0 million of funds borrowed in February 2016 under our term loan agreement.

 

·$48.2 million in common stock dividend payments.

 

The outstanding short-term borrowings that were paid down were, in part, used to fund the expansion of BTD’s Minnesota facilities in 2015 and the September 1, 2015 acquisition of BTD-Georgia. See note 6 to the Company’s consolidated financial statements for further information on stock issuances and retirements in 2016.

 

2015 Cash Flows Compared with 2014 Cash Flows

Cash provided by operating activities from continuing operations was $131.5 million in 2015 compared with $125.8 million in 2014. Contributing to the $5.7 million increase in cash provided by continuing operations between the periods were:

 

·A $10.0 million decrease in discretionary contributions to the Company’s pension plan.

 

·A $2.3 million increase in depreciation expense.

 

·A $1.6 million increase in net income from continuing operations.

 

offset by:

 

·$7.2 million in cash used to decrease accounts payable at OTP in 2015 partly related to power purchases and repair services incurred in connection with the boiler pump failure and fire at Coyote Station in December 2014.

 

In continuing operations, net cash used in investing activities was $193.6 million in 2015 compared with $163.9 million in 2014. The purchase of the assets of BTD-Georgia for $30.8 million on September 1, 2015 was the main factor contributing to the $29.7 million increase in cash used in investing activities of continuing operations between the periods. A $3.4 million decrease in cash used for capital expenditures includes a $13.1 million reduction in capital expenditures at OTP as several major projects were completed and placed in service in 2015, including two CapX2020 transmission line projects and the new AQCS at Big Stone Plant, partially offset by a $9.0 million increase in cash used for capital expenditures in our Manufacturing segment, mainly at BTD as it moved forward with its project to expand and realign its Minnesota production and warehouse facilities.

 

Investing activities of discontinued operations in 2015 includes cash proceeds, net of selling expenses, of $22.1 million from the sale of AEV, Inc. and $17.3 million from the sale of Foley, partially offset by $1.8 million in cash used in investing activities of discontinued operations, mainly related to the purchase by AEV, Inc. of assets being leased under operating leases prior to the assets being sold.

 

Net cash provided by financing activities of continuing operations was $38.1 million in 2015 compared with $49.7 million in 2014. Net cash provided by financing activities in 2015 includes $69.8 million in short-term borrowings used to fund a portion of our capital expenditures and the acquisition of BTD-Georgia. Net cash proceeds of $13.8 million from the issuance of common stock under our At-the-Market offering program and various stock purchase and dividend reinvestment plans were also used to fund a portion of our capital expenditures. See note 6 to the Company’s consolidated financial statements for further information on stock issuances and retirements in 2015. Cash used for common stock dividend payments totaled $46.2 million in 2015.

 

 

 

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Capital Requirements

 

We have a capital expenditure program for expanding, upgrading and improving our plants and operating equipment. Typical uses of cash for capital expenditures are investments in electric generation facilities and environmental upgrades, transmission and distribution lines, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems. The capital expenditure program is subject to review and is revised in light of changes in demands for energy, technology, environmental laws, regulatory changes, business expansion opportunities, the costs of labor, materials and equipment and our consolidated financial condition.

 

Cash used for consolidated capital expenditures was $161.3 million in 2016, $160 million in 2015 and $164 million in 2014. Estimated capital expenditures for 2017 are $149 million. Total capital expenditures for the five-year period 2017 through 2021 are estimated to be approximately $936 million, which includes $315 million for renewable wind and solar energy generation projects, $147 million for natural gas-fired generation to replace Hoot Lake Plant capacity and $116 million for OTP transmission projects designated by the MISO as MVPs.

 

The breakdown of 2014, 2015 and 2016 actual cash used for capital expenditures and 2017 through 2021 estimated capital expenditures by segment is as follows:

 

(in millions)  2014   2015   2016   2017   2018   2019   2020   2021  
2017-2021		 
Electric  $149   $136   $150   $135   $173   $346   $130   $78   $862 
Manufacturing   11    20    8    10    13    11    10    10    54 
Plastics   4    4    3    4    4    4    4    4    20 
Total  $164   $160   $161   $149   $190   $361   $144   $92   $936 

 

The following table summarizes our contractual obligations at December 31, 2016 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.

 

(in millions)  Total   Less than
1 Year		   1-3
Years		   3-5
Years		   More than
5 Years		 
Coal Contracts (required minimums)  $671   $31   $44   $45   $551 
Debt Obligations   584    76    15    141    352 
Interest on Debt Obligations   337    27    50    50    210 
Capacity and Energy Requirements   277    24    49    38    166 
Postretirement Benefit Obligations   100    5    11    11    73 
Other Purchase Obligations   85    74    11    —    — 
Operating Lease Obligations   40    7    9    7    17 
Total Contractual Cash Obligations  $2,094   $244   $189    292   $1,369 

 

Postretirement Benefit Obligations include estimated cash expenditures for the payment of retiree medical and life insurance benefits and supplemental pension benefits under our unfunded Executive Survivor and Supplemental Retirement Plan, but do not include amounts to fund our noncontributory funded pension plan, as we are not currently required to make a contribution to that plan.

 

CAPITAL RESOURCES

 

Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings, and alternative financing arrangements such as leasing. Equity or debt financing will be required in the period 2017 through 2021 given the expansion plans related to our Electric segment to fund construction of new rate base and transmission investments, in the event we decide to reduce borrowings under our lines of credit, to refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or otherwise, or that if such financing is available, it will be available on terms acceptable to us. If adequate funds are not available on acceptable terms, our businesses, results of operations and financial condition could be adversely affected.

 

Under our shelf registration statement filed with the SEC we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, until May 11, 2018.

 

Under our At-the-Market offering program, we may offer and sell our common shares from time to time through JPMS, as our distribution agent, up to an aggregate sales price of $75 million, of which $39.2 million remained available at December 31, 2016. Under the Distribution Agreement with JPMS, we will designate the minimum price and maximum

 

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number of shares to be sold through JPMS on any given trading day or over a specified period of trading days, and JPMS will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. We are not obligated to sell and JPMS is not obligated to buy or sell any of the shares under the Agreement.

 

Short-Term Debt

 

The following table presents the status of our lines of credit as of December 31, 2016 and December 31, 2015:

 

(in thousands)  Line Limit   In Use on
December 31,
2016		   Restricted due to
Outstanding
Letters of Credit		   Available on
December 31,
2016		   Available on
December 31,
2015		 
Otter Tail Corporation Credit Agreement  $130,000   $—   $—   $130,000   $90,334 
OTP Credit Agreement   170,000    42,883    50    127,067    148,694 
Total  $300,000   $42,883   $50   $257,067   $239,028 

 

Under the Otter Tail Corporation Credit Agreement (as defined below), the maximum amount of debt outstanding in 2016 was $63,757,000 on January 4, 2016 and the average daily balance of debt outstanding during 2016 was $16,200,000. The weighted average interest rate paid on debt outstanding under the Otter Tail Corporation Credit Agreement during 2016 was 2.3% compared with 2.0% in 2015. Under the OTP Credit Agreement (as defined below), the maximum amount of debt outstanding in 2016 was $51,885,000 on December 16, 2016 and the average daily balance of debt outstanding during 2016 was $32,576,000. The weighted average interest rate paid on debt outstanding under the OTP Credit Agreement during 2016 was 1.8% compared with 1.5% in 2015. The maximum amount of consolidated short-term debt outstanding in 2016 was $87,211,000 on January 25, 2016 and the average daily balance of consolidated short-term debt outstanding during 2016 was $48,776,000. The weighted average interest rate on consolidated short-term debt outstanding on December 31, 2016 was 1.9%.

 

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $130 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On October 31, 2016 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021 and the unsecured revolving credit facility was reduced from $150 million to $130 million. We can draw on this credit facility to refinance certain indebtedness and support our operations and the operations of certain of our subsidiaries. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 1.75%, subject to adjustment based on our senior unsecured credit ratings. We are required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The Otter Tail Corporation Credit Agreement contains a number of restrictions on us and the businesses of our wholly owned subsidiary, Varistar Corporation (Varistar) and its subsidiaries, including restrictions on our and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of our subsidiaries. Outstanding letters of credit issued by us under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million.

 

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 31, 2016 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

 

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Long-Term Debt

 

2016 Note Purchase Agreement

On September 23, 2016 we entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which we agreed to issue to the purchasers, in a private placement transaction, $80 million aggregate principal amount of our 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes). The 2026 Notes were issued on December 13, 2016. Our obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by our Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). The proceeds from the issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our 9.000% Senior Notes due December 15, 2016, and to pay down a portion of the $50 million in funds borrowed in February 2016 under our term loan agreement.

 

We may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by us of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. We are required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if we and our Material Subsidiaries sell a “substantial part” of our or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes.

 

The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and our Material Subsidiaries. These include restrictions on our and our Material Subsidiaries’ abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or pay dividends on our and our Material Subsidiaries’ shares of capital stock, and make investments. The 2016 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2016 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our or our Material Subsidiaries’ credit ratings.

 

Term Loan Agreement

On February 5, 2016 we entered into a Term Loan Agreement (the Term Loan Agreement) with the Banks named therein, JPMorgan Chase Bank, N.A. (JPMorgan), as administrative agent, and JPMS, as Lead Arranger and Book Runner. The Term Loan Agreement provides for an unsecured term loan with an aggregate commitment of $50 million that we may use for purposes of funding working capital, capital expenditures and other corporate purposes of the Company and certain of our subsidiaries. Under the Term Loan Agreement, we may, on up to two occasions, enter into additional tranches of term loans in minimum increments of $10 million, subject to the consent of the lenders and so long as the aggregate amount of outstanding term loans does not exceed $100 million at any time. Borrowings under the Term Loan Agreement will bear interest at either (1) LIBOR plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve Bank of New York Rate plus 0.50% and (c) LIBOR multiplied by the Statutory Reserve Rate plus 1%. The applicable interest rate will depend on our election of whether to make the advance a LIBOR advance. The Term Loan Agreement terminates on February 5, 2018.

 

On February 5, 2016 we borrowed $50 million under the Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points and used the proceeds to pay down borrowings under the Otter Tail Corporation Credit Agreement that were used to fund the expansion of BTD’s Minnesota facilities in 2015 and to fund the September 1, 2015 acquisition of BTD-Georgia. We repaid $35.0 million under the Term Loan Agreement in the fourth quarter of 2016.

 

The Term Loan Agreement contains a number of restrictions on us, Varistar and certain subsidiaries of Varistar, including restrictions on our and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The Term Loan Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The Term Loan Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the Term Loan Agreement are guaranteed by Varistar and certain of its subsidiaries.

 

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2013 Note Purchase Agreement

On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) with the Purchasers named therein, pursuant to which OTP agreed to issue to the Purchasers, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). On February 27, 2014 OTP issued all $150 million aggregate principal amount of the Notes.

 

The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states OTP must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP.

 

The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement, provided that no default or event of default has occurred and is continuing.

 

2007 and 2011 Note Purchase Agreements

On December 1, 2011, OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011 (2011 Note Purchase Agreement). OTP also has outstanding its $155 million senior unsecured notes issued in four series consisting of $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, due 2017; $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement).

 

The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.”

 

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Financial Covenants

We were in compliance with the financial covenants in our debt agreements as of December 31, 2016.

 

No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

 

Our borrowing agreements are subject to certain financial covenants. Specifically:

 

·Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis). As of December 31, 2016 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement was 3.68 to 1.00.

 

·Under the 2016 Note Purchase Agreement, we may not permit our Priority Indebtedness to exceed 10% of our Total Capitalization.

 

·Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.

 

·Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of December 31, 2016 OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, was 3.64 to 1.00.

 

·Under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement.

 

As of December 31, 2016 our ratio of Interest-bearing Debt to Total Capitalization was 0.46 to 1.00 on a consolidated basis and 0.47 to 1.00 for OTP. Neither Otter Tail Corporation or OTP had any Priority Indebtedness outstanding as of December 31, 2016.

 

Our ratio of earnings to fixed charges from continuing operations reported in Exhibit 12.1 to this Annual Report on Form 10-K, which includes imputed finance costs on operating leases, was 3.4x for 2016 and 2015. During 2017, we expect this coverage ratio to increase, assuming 2017 net income meets our expectations.

 

 

OFf-Balance-Sheet Arrangements

 

We and our subsidiary companies have outstanding letters of credit totaling $4.6 million, but our line of credit borrowing limits are only restricted by $50,000 in outstanding letters of credit. We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

 

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2017 BUSINESS OUTLOOK

 

We anticipate 2017 diluted earnings per share to be in the range of $1.60 to $1.75. This guidance reflects the current mix of businesses we own, considers the cyclical nature of some of our businesses, and reflects current regulatory factors and economic challenges facing our Electric, Manufacturing and Plastics segments and strategies for improving future operating results. We expect capital expenditures for 2017 to be $149 million compared with actual cash used for capital expenditures of $161 million in 2016. Major projects in our planned expenditures for 2017 include investments in two large transmission line projects for the Electric segment, which positively impact earnings by providing an immediate return on invested funds through rider recovery mechanisms.

 

Segment components of our 2017 earnings per share guidance range compared with 2016 actual earnings are as follows:

 

   2016 EPS   2017 EPS Guidance 
   by Segment   Low   High 
Electric  $1.29   $1.31   $1.34 
Manufacturing  $0.15   $0.17   $0.21 
Plastics  $0.27   $0.26   $0.30 
Corporate  $(0.11)  $(0.14)  $(0.10)  
Total – Continuing Operations  $1.60   $1.60   $1.75 

 

Contributing to our earnings guidance for 2017 are the following items:

 

·We expect 2017 Electric segment net income to be higher than 2016 segment net income based on:

 

oNormal weather for 2017. Milder than normal weather in 2016 negatively impacted diluted earnings per share by $0.07 compared to normal.

 

oConstructive outcome of a rate case filed in Minnesota on February 16, 2016 with a full year of increased rates compared with 8.5 months in 2016. The Minnesota Public Utilities Commission determines our rates. Our ability to obtain final rates similar to interim rates and reasonable rates of return depends on regulatory action under applicable statutes and regulations. We cannot provide assurance our interim rates will become final and that our modifications to our original request will ultimately be approved.

 

oRider recovery increases, including transmission riders related to the Electric segment’s continuing investments in its share of the MVPs in South Dakota.

 

oExpected increases in sales to pipeline and commercial customers.

 

offset by: 

 

oIncreased operating and maintenance expenses of $0.06 per share due to inflationary increases and increasing costs of medical, workers compensation and retiree medical. Included is an increase in pension costs as a result of a decrease in the discount rate from 4.76% to 4.60% and a decrease in the assumed long-term rate of return on plan assets from 7.75% to 7.50%.

 

oHigher depreciation and property tax expense due to large capital projects being put into service.

 

oLower CIP incentives of $0.04 per share in Minnesota as a result of program changes made by the state. OTP estimates the implementation of the new CIP financial incentive model will reduce these incentives by approximately 50% compared to the previous incentive mechanism.

 

oIncreased costs related to contractual price increases in certain capacity agreements.

 

·We expect 2017 net income from our Manufacturing segment to increase over 2016 due to:

 

oIncreased sales of 4.5% coming primarily from the lawn and garden end markets. We continue to see soft end markets in agriculture, oil and gas.

 

oImproved margins on parts and tooling sales given improved productivity across all of BTD’s locations and lower interest costs as a result of the refinancing of long-term debt completed in the fourth quarter of 2016.

 

oAn increase in earnings from T.O. Plastics mainly driven by year over year sales growth in our horticulture and custom markets and lower interest costs as a result of the refinancing of long-term debt completed in the fourth quarter of 2016.

 

oBacklog for the manufacturing companies of approximately $118 million for 2017 compared with $134 million one year ago.
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·We expect 2017 net income from the Plastics segment to be similar to 2016. Sales volumes in 2017 are expected to be down compared with 2016 due to lower sales in the Southern California and Texas markets offset by strengthening sales prices resulting in improved operating margins year over year. The Plastics segment also benefits from lower interest costs as a result of the refinancing of long term debt completed in the fourth quarter of 2016.

 

·Corporate costs in 2017 are expected to be in line with 2016 costs.

 

The following table shows our 2016 capital expenditures and 2017 through 2021 anticipated capital expenditures and electric utility average rate base:

 

(in millions)  2015   2016   2017   2018   2019   2020   2021   Total 
Capital Expenditures:                                        
Electric Segment:                                        
Renewables and Natural Gas Generation            $3   $80   $288   $71   $20   $462 
Transmission             88    49    11    11    7    166 
Other             44    44    47    48    51    234 
Total Electric Segment       $150   $135   $173   $346   $130   $78   $862 
Manufacturing and Plastics Segments        11    14    17    15    14    14    74 
Total Capital Expenditures       $161   $149   $190   $361   $144   $92   $936 
Total Electric Utility Average Rate Base  $919   $1,001*  $1,063   $1,118   $1,267   $1,396   $1,419      

*Estimated

 

The consolidated capital expenditure plan for the 2017-2021 time period calls for $936 million based on the need for additional wind and solar in rate base and capital spending for a natural gas-fired plant that is expected to replace Hoot Lake Plant when it is retired in 2021. Taking into account the increased capital expenditure plan, our compounded annual growth rate in rate base is projected to be 7.5% over the 2015 to 2021 timeframe.

 

Execution on the currently anticipated electric utility capital expenditure plan is expected to grow rate base and be a key driver in increasing utility earnings over the 2017 through 2021 timeframe.

 

Our outlook for 2017 is dependent on a variety of factors and is subject to the risks and uncertainties discussed in Item 1A. Risk Factors, and elsewhere in this Annual Report on Form 10-K.

 

Critical Accounting Policies Involving Significant Estimates

 

Our significant accounting policies are described in note 1 to our consolidated financial statements. The discussion and analysis of the financial statements and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

 

We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, interim rate refunds, warranty reserves and actuarially determined benefits costs and liabilities. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the board of directors. The following critical accounting policies affect the more significant judgments and estimates used in the preparation of our consolidated financial statements.

 

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Pension and Other Postretirement Benefits Obligations and Costs

Pension and postretirement benefit liabilities and expenses for our electric utility and corporate employees are determined by actuaries using assumptions about the discount rate, expected return on plan assets, rate of compensation increase and healthcare cost-trend rates. Further discussion of our pension and postretirement benefit plans and related assumptions is included in note 11 to our consolidated financial statements.

 

These benefits, for any individual employee, can be earned and related expenses can be recognized and a liability accrued over periods of up to 35 or more years. These benefits can be paid out for up to 40 or more years after an employee retires. Estimates of liabilities and expenses related to these benefits are among our most critical accounting estimates. Although deferral and amortization of fluctuations in actuarially determined benefit obligations and expenses are provided for when actual results on a year-to-year basis deviate from long-range assumptions, compensation increases and healthcare cost increases or a reduction in the discount rate applied from one year to the next can significantly increase our benefit expenses in the year of the change. Also, a reduction in the expected rate of return on pension plan assets in our funded pension plan or realized rates of return on plan assets that are well below assumed rates of return or an increase in the anticipated life expectancy of plan participants could result in significant increases in recognized pension benefit expenses in the year of the change or for many years thereafter because actuarial losses can be amortized over the average remaining service lives of active employees.

 

The pension benefit cost for 2017 for our noncontributory funded pension plan is expected to be $5.9 million compared to $5.7 million in 2016, reflecting a decrease in the assumed rate of return on pension plan assets from 7.75% in 2016 to 7.50% in 2017, and a decrease in the estimated discount rate used to determine annual benefit cost accruals from 4.76% in 2016 to 4.60% in 2017. In selecting the discount rate, we consider the yields of fixed income debt securities, which have ratings of “Aa” published by recognized rating agencies, along with bond matching models specific to our plan’s cash flows as a basis to determine the rate.

 

Subsequent increases or decreases in actual rates of return on plan assets over assumed rates or increases or decreases in the discount rate or rate of increase in future compensation levels could significantly change projected costs. For 2016, all other factors being held constant: a 0.25 increase in the discount rate would have decreased our 2016 pension benefit cost by $892,000; a 0.25 decrease in the discount rate would have increased our 2016 pension benefit cost by $937,000; a 0.25 increase in the assumed rate of increase in future compensation levels would have increased our 2016 pension benefit cost by $521,000; a 0.25 decrease in the assumed rate of increase in future compensation levels would have decreased our 2016 pension benefit cost by $509,000; and a 0.25 increase (or decrease) in the expected long-term rate of return on plan assets would have decreased (or increased) our 2016 pension benefit cost by $628,000.

 

Increases or decreases in the discount rate or in retiree healthcare cost inflation rates could significantly change our projected postretirement healthcare benefit costs. A 0.25 increase in the discount rate would have decreased our 2016 postretirement medical benefit costs by $197,000. A 0.25 decrease in the discount rate would have increased our 2016 postretirement medical benefit costs by $206,000. See note 11 to consolidated financial statements for the cost impact of a change in medical cost inflation rates.

 

We believe the estimates made for our pension and other postretirement benefits are reasonable based on the information that is known at the point in time the estimates are made. These estimates and assumptions are subject to a number of variables and are subject to change.

 

Taxation

We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income, real estate and use taxes. These judgments could result in the recognition of a liability for potential adverse outcomes regarding uncertain tax positions that we have taken. While we believe our liability for uncertain tax positions as of December 31, 2016 reflects the most likely probable expected outcome of these tax matters in accordance with the requirements of ASC Topic 740, Income Taxes, the ultimate outcome of such matters could result in additional adjustments to our consolidated financial statements. However, we do not believe such adjustments would be material.

 

Deferred income taxes are provided for revenue and expenses which are recognized in different periods for income tax and financial reporting purposes. We assess our deferred tax assets for recoverability taking into consideration our historical and anticipated earnings levels, the reversal of other existing temporary differences, available net operating loss carryforwards and available tax planning strategies that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, a valuation allowance against our deferred tax assets. As facts and circumstances change, adjustments to the valuation allowance may be required.

 

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Asset Impairment

We are required to test for asset impairment relating to property and equipment whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset may exceed its fair value and not be recoverable. We apply the accounting guidance under ASC 360-10-35, Property, Plant, and Equipment – Subsequent Measurement, in order to determine whether or not an asset is impaired. This standard requires an impairment analysis when indicators of impairment are present. If such indicators are present, the standard requires that if the sum of the future expected cash flows from a company’s asset, undiscounted and without interest charges, is less than the carrying amount, an asset impairment must be recognized in the financial statements. The amount of the impairment is the difference between the fair value of the asset and the carrying amount of the asset.

 

We believe the accounting estimates related to an asset impairment are critical because: (1) they are highly susceptible to change from period to period, reflecting changing business cycles, (2) they require management to make assumptions about future cash flows over future years, and (3) the impact of recognizing an impairment could have a significant effect on operations. Management’s assumptions about future cash flows require significant judgment because actual operating levels have fluctuated in the past and are expected to continue to do so in the future.

 

As of December 31, 2016 an assessment of the carrying amounts of our long-lived assets and other intangibles indicated these assets were not impaired.

 

Goodwill Impairment

Goodwill is required to be evaluated annually for impairment, according to ASC 350-20-35, Goodwill – Subsequent Measurement. We perform quantitative goodwill impairment testing annually in the fourth quarter. In addition, the test is performed on an interim basis whenever events or circumstances indicate that the carrying amount of goodwill may not be recoverable. Examples of such events or circumstances may include a significant adverse change in business climate, weakness in an industry in which our reporting units operate or recent significant cash or operating losses with expectations that those losses will continue.

 

The quantitative goodwill impairment test is a two-step process performed at the reporting unit level. We have determined the reporting units for our goodwill impairment test are our operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which our chief operating decision makers regularly review the operating results. For more information on our operating segments, see note 2 to consolidated financial statements. The first step of the quantitative impairment test involves comparing the fair value of each reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying value, the test is complete and no impairment is recorded. If the fair value of a reporting unit is less than its carrying value, step two of the test is performed to determine the amount of impairment loss, if any. The impairment is computed by comparing the implied fair value of the reporting unit’s goodwill to the carrying value of that goodwill. If the carrying value is greater than the implied fair value, an impairment loss must be recorded. At December 31, 2016, the fair value substantially exceeded the carrying value at all our reporting units reported under continuing operations.

 

Determining the fair value of a reporting unit requires judgment and the use of significant estimates which include assumptions about the reporting unit’s future revenue, profitability and cash flows, amount and timing of estimated capital expenditures, inflation rates, weighted average cost of capital, operational plans, and current and future economic conditions, among others. The fair value of each reporting unit is determined using a weighted combination of income and market approaches. We use a discounted cash flow methodology for our income approach. Under this approach, the discounted cash flow model determines fair value based on the present value of projected cash flows over a specified period and a residual value related to future cash flows beyond the projection period. Both values are discounted using a rate which reflects the best estimate of the weighted average cost of capital at each reporting unit. Under the market approach, we estimate fair value using multiples derived from comparable enterprise value to EBITDA multiples, comparable price earnings ratios, comparable enterprise value to sales multiples and if available, comparable sales transactions for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. We believe the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not impairment is indicated.

 

acquisition METHOD OF accounting

We account for acquisitions under the requirements of ASC Topic 805, Business Combinations. Under ASC 805 the term “purchase method of accounting” is replaced with “acquisition method of accounting” and requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions.

 

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Acquired assets and liabilities assumed that are subject to critical estimates include property, plant and equipment, intangible assets and inventory. The fair value of property, plant and equipment is based on valuations performed by qualified internal personnel and/or with the assistance of outside appraisers. Fair values assigned to plant and equipment are based on several factors including the age and condition of the equipment, maintenance records of the equipment and auction values for equipment with similar characteristics at the time of purchase. Intangible assets are identified and valued using the guidelines of ASC 805. The fair value of intangible assets is based on estimates including royalty rates, customer attrition rates and estimated cash flows.

 

While the allocation of purchase price is subject to a high degree of judgment and uncertainty, we do not expect the estimates to vary significantly once an acquisition is complete. We believe our estimates have been reasonable in the past as there have been no significant valuation adjustments to the allocation of purchase price.

 

Forward-Looking Information – Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

 

This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 (the Act). When used in this Form 10-K and in future filings by the Company with the SEC, in the Company’s press releases and in oral statements, words such as “may,” “will,” “expect,” “anticipate,” “continue,” “estimate,” “project,” “believes” or similar expressions are intended to identify forward-looking statements within the meaning of the Act. Such statements are based on current expectations and assumptions, and entail various risks and uncertainties that could cause actual results to differ materially from those expressed in such forward-looking statements. Such risks and uncertainties include the various factors set forth in Item 1A. Risk Factors of this Annual Report on Form 10-K and in our other SEC filings.

 

Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

At December 31, 2016 we had exposure to market risk associated with interest rates because we had $15 million outstanding subject to a variable interest rate that is indexed to 30 day LIBOR plus 90 basis points under the Term Loan Agreement that terminates on February 5, 2018. OTP had $42.9 million in short-term debt outstanding subject to variable interest rates indexed to LIBOR plus 1.25% under the OTP Credit Agreement.

 

All of our remaining consolidated long-term debt outstanding on December 31, 2016 has fixed interest rates. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.

 

We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

 

The companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, aluminum and polystyrene (PS) and other plastics resins. The price and availability of these raw materials could affect the revenues and earnings of our Manufacturing segment.

 

The plastics companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, sales volume has been higher and when resin prices are falling, sales volume has been lower. Operating income may decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

 

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Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Shareholders of

Otter Tail Corporation

 

We have audited the accompanying consolidated balance sheets and statements of capitalization of Otter Tail Corporation and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report Regarding Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

 

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Otter Tail Corporation and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

 

/s/ Deloitte & Touche LLP  
   
Minneapolis, Minnesota  
February 22, 2017  

 

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Otter Tail Corporation
Consolidated Balance Sheets, December 31
(in thousands)  2016   2015 
         
Assets          
           
Current Assets          
Cash and Cash Equivalents  $—   $— 
Accounts Receivable:          
Trade (less allowance for doubtful accounts of $1,246 for 2016 and $1,262 for 2015)   68,242    62,974 
Other   5,850    9,073 
Inventories   83,740    85,416 
Unbilled Revenues   20,080    17,869 
Income Taxes Receivable   662    4,000 
Regulatory Assets   21,297    18,904 
Other   8,144    8,453 
Total Current Assets   208,015    206,689 
           
Investments   8,417    8,284 
Other Assets   34,104    32,784 
Goodwill   37,572    39,732 
Other Intangibles–Net   14,958    15,673 
Regulatory Assets   132,094    127,707 
           
Plant          
Electric Plant in Service   1,860,357    1,820,763 
Nonelectric Operations   211,826    201,343 
Construction Work in Progress   153,261    79,612 
Total Gross Plant   2,225,444    2,101,718 
Less Accumulated Depreciation and Amortization   748,219    713,904 
Net Plant   1,477,225    1,387,814 
           
Total Assets  $1,912,385   $1,818,683 

 

See accompanying notes to consolidated financial statements.

 

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Otter Tail Corporation
Consolidated Balance Sheets, December 31
(in thousands, except share data)  2016   2015 
         
Liabilities and Equity          
           
Current Liabilities          
Short-Term Debt  $42,883   $80,672 
Current Maturities of Long-Term Debt   33,201    52,422 
Accounts Payable   89,350    89,499 
Accrued Salaries and Wages   17,497    16,182 
Accrued Taxes   16,000    14,827 
Other Accrued Liabilities   15,377    15,416 
Liabilities of Discontinued Operations   1,363    2,098 
Total Current Liabilities   215,671    271,116 
           
Pensions Benefit Liability   97,627    104,912 
Other Postretirement Benefits Liability   62,571    48,730 
Other Noncurrent Liabilities   21,706    23,854 
           
Commitments and Contingencies (note 9)          
           
Deferred Credits          
Deferred Income Taxes   226,591    207,669 
Deferred Tax Credits   22,849    24,506 
Regulatory Liabilities   82,433    77,432 
Other   7,492    11,595 
Total Deferred Credits   339,365    321,202 
           
Capitalization (page 66)          
Long-Term Debt—Net   505,341    443,846 
           
Cumulative Preferred Shares – Authorized 1,500,000 Shares Without Par Value; Outstanding – None   —    — 
           
Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value; Outstanding – None   —    — 
           
Common Shares, Par Value $5 Per Share–Authorized, 50,000,000 Shares; Outstanding, 2016—39,348,136 Shares; 2015—37,857,186 Shares   196,741    189,286 
Premium on Common Shares   337,684    293,610 
Retained Earnings   139,479    126,025 
Accumulated Other Comprehensive Loss   (3,800)   (3,898)
Total Common Equity   670,104    605,023 
           
Total Capitalization   1,175,445    1,048,869 
           
Total Liabilities and Equity  $1,912,385   $1,818,683 

 

See accompanying notes to consolidated financial statements.

 

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Otter Tail Corporation
Consolidated Statements of Income–For the Years Ended December 31
(in thousands, except per-share amounts)  2016   2015   2014 
             
Operating Revenues               
Electric  $427,349   $407,039   $407,629 
Product Sales   376,190    372,765    391,633 
Total Operating Revenues   803,539    779,804    799,262 
                
Operating Expenses               
Production Fuel – Electric   54,792    42,744    67,216 
Purchased Power – Electric System Use   63,226    78,150    65,848 
Electric Operation and Maintenance Expenses   151,225    140,768    141,936 
Cost of Products Sold (depreciation included below)   295,222    295,032    308,069 
Other Nonelectric Expenses   40,264    40,021    45,981 
Depreciation and Amortization   73,445    60,363    58,074 
Property Taxes – Electric   14,266    13,512    12,607 
Total Operating Expenses   692,440    670,590    699,731 
                
Operating Income   111,099    109,214    99,531 
                
Interest Charges   31,886    31,160    29,648 
Other Income   2,905    2,177    3,557 
Income Before Income Taxes – Continuing Operations   82,118    80,231    73,440 
Income Tax Expense – Continuing Operations   20,081    21,642    16,557 
Net Income from Continuing Operations   62,037    58,589    56,883 
Discontinued Operations               
Income (Loss) – net of Income Tax Expense (Benefit) of $138 in 2016, ($1,539) in 2015 and $3,952 in 2014   284    (5,404)   6,445 
Impairment Loss – net of Income Tax (Benefit) of $0 in 2015 and 2014   —    (1,000)   (5,605)
Gain on Disposition – net of Income Tax Expense of $4,530 in 2015   —    7,160    — 
Net Income from Discontinued Operations   284    756    840 
Total Net Income  $62,321   $59,345   $57,723 
                
Average Number of Common Shares Outstanding–Basic   38,546    37,495    36,514 
Average Number of Common Shares Outstanding–Diluted   38,731    37,668    36,753 
                
Basic Earnings Per Common Share:               
Continuing Operations  $1.61   $1.56   $1.56 
Discontinued Operations  $0.01   $0.02   $0.02 
   $1.62   $1.58   $1.58 
Diluted Earnings Per Common Share:               
Continuing Operations  $1.60   $1.56   $1.55 
Discontinued Operations  $0.01   $0.02   $0.02 
   $1.61   $1.58   $1.57 
Dividends Declared Per Common Share  $1.25   $1.23   $1.21 

 

See accompanying notes to consolidated financial statements.

 

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Otter Tail Corporation
Consolidated Statements of Comprehensive Income–For the Years Ended December 31
(in thousands)  2016   2015   2014 
Net Income  $62,321   $59,345   $57,723 
Other Comprehensive Income (Loss):               
Unrealized Loss on Available-for-Sale Securities:               
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period   (3)   (3)   (19)
Losses Arising During Period   (14)   (49)   (14)
Income Tax Benefit   6    18    12 
Change in Unrealized Losses on Available-for-Sale Securities – net-of-tax   (11)   (34)   (21)
Pension and Postretirement Benefit Plans:               
Actuarial (Losses) Gains Net of Regulatory Allocation Adjustment   (445)   510    (5,048)
Amortization of Unrecognized Postretirement Benefit Costs (note 11)   628    821    192 
Income Tax (Expense) Benefit   (74)   (532)   1,942 
Pension and Postretirement Benefit Plans – net-of-tax   109    799    (2,914)
Total Other Comprehensive Income (Loss)   98    765    (2,935)
Total Comprehensive Income  $62,419   $60,110   $54,788 

 

See accompanying notes to consolidated financial statements.

 

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Otter Tail Corporation
Consolidated Statements of Common Shareholders’ Equity
(in thousands, except common shares outstanding)  Common
Shares
Outstanding		   Par Value,
Common
Shares		   Premium
on
Common
Shares		   Retained
Earnings		   Accumulated
Other
Comprehensive
Income/(Loss)		   Total
Common
Equity		 
Balance, December 31, 2013   36,271,696   $181,358   $255,759   $99,441   $(1,728)(a)  $534,830 
Common Stock Issuances, Net of Expenses   971,286    4,857    21,057              25,914 
Common Stock Retirements   (24,929)   (125)   (465)             (590)
Net Income                  57,723         57,723 
Other Comprehensive Loss                       (2,935)   (2,935)
Tax Benefit – Stock Compensation             302              302 
Employee Stock Incentive Plan Expense             1,783              1,783 
Common Dividends ($1.21 per share)                  (44,261)        (44,261)
Balance, December 31, 2014   37,218,053   $186,090   $278,436   $112,903   $(4,663)(a)  $572,766 
Common Stock Issuances, Net of Expenses   690,485    3,453    14,715              18,168 
Common Stock Retirements   (51,352)   (257)   (1,339)             (1,596)
Net Income                  59,345         59,345 
Other Comprehensive Income                       765    765 
Tax Benefit – Stock Compensation             82              82 
Employee Stock Incentive Plan Expense             1,716              1,716 
Common Dividends ($1.23 per share)                  (46,223)        (46,223)
Balance, December 31, 2015   37,857,186   $189,286   $293,610   $126,025   $(3,898)(a)  $605,023 
Common Stock Issuances, Net of Expenses   1,494,618    7,473    38,490              45,963 
Common Stock Retirements   (3,668)   (18)   (86)             (104)
Net Income                  62,321         62,321 
Other Comprehensive Income                       98    98 
Employee Stock Incentive Plan Expense             3,178              3,178 
ASU 2016-09 Adoption             2,492    (623)        1,869 
Common Dividends ($1.25 per share)                  (48,244)        (48,244)
Balance, December 31, 2016   39,348,136   $196,741   $337,684   $139,479   $(3,800)(a)  $670,104 

 

(a) Accumulated Other Comprehensive Loss on December 31 is comprised of the following:
(in thousands)  2016   2015   2014 
Unrealized (Loss) Gain on Marketable Equity Securities:               
Before Tax  $(29)  $(12)  $40 
Tax Effect   10    4    (14)
Unrealized (Loss) Gain on Marketable Equity Securities – net-of-tax   (19)   (8)   26 
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits:               
Before Tax   (6,300)   (6,484)   (7,815)
Tax Effect   2,519    2,594    3,126 
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits – net-of-tax   (3,781)   (3,890)   (4,689)
Accumulated Other Comprehensive Loss:               
Before Tax   (6,329)   (6,496)   (7,775)
Tax Effect   2,529    2,598    3,112 
Net Accumulated Other Comprehensive Loss  $(3,800)  $(3,898)  $(4,663)

 

See accompanying notes to consolidated financial statements.

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Otter Tail Corporation
Consolidated Statements of Cash Flows—For the Years Ended December 31
(in thousands)  2016   2015   2014 
Cash Flows from Operating Activities               
Net Income  $62,321   $59,345   $57,723 
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:               
Net Gain from Sale of Discontinued Operations   —    (7,160)   — 
Net (Income) Loss from Discontinued Operations   (284)   6,404    (840)
Depreciation and Amortization   73,445    60,363    58,074 
Deferred Tax Credits   (1,657)   (1,878)   (1,904)
Deferred Income Taxes   19,124    26,027    28,204 
Change in Deferred Debits and Other Assets   (10,090)   11,407    (50,361)
Discretionary Contribution to Pension Fund   (10,000)   (10,000)   (20,000)
Change in Noncurrent Liabilities and Deferred Credits   14,685    20,524    58,442 
Allowance for Equity/Other Funds Used During Construction   (857)   (1,303)   (1,543)
Change in Derivatives Net of Regulatory Deferral   —    (14,736)   519 
Stock Compensation Expense – Equity Awards   3,178    1,716    1,783 
Other—Net   7    (80)   601 
Cash (Used for) Provided by Current Assets and Current Liabilities:               
Change in Receivables   (944)   (1,746)   (4,647)
Change in Inventories   1,874    1,960    (12,577)
Change in Other Current Assets   (2,541)   (210)   (579)
Change in Payables and Other Current Liabilities   11,941    (15,150)   10,296 
Change in Interest Payable and Income Taxes Receivable/Payable   3,339    (3,943)   2,578 
Net Cash Provided by Continuing Operations   163,541    131,540    125,769 
Net Cash Used in Discontinued Operations   (155)   (14,000)   (13,295)
Net Cash Provided by Operating Activities   163,386    117,540    112,474 
Cash Flows from Investing Activities               
Capital Expenditures   (161,259)   (160,084)   (163,582)
Proceeds from Disposal of Noncurrent Assets   4,837    3,590    2,467 
Acquisition Purchase Price Cash Received (Paid)   1,500    (30,806)   — 
Cash Used for Investments and Other Assets   (4,402)   (6,302)   (2,785)
Net Cash Used in Investing Activities – Continuing Operations   (159,324)   (193,602)   (163,900)
Net Proceeds from Sale of Discontinued Operations   —    39,401    — 
Net Cash Used in Investing Activities – Discontinued Operations   —    (1,769)   (596)
Net Cash Used in Investing Activities   (159,324)   (155,970)   (164,496)
Cash Flows from Financing Activities               
Change in Checks Written in Excess of Cash   (3,363)   2,857    1,236 
Net Short-Term (Repayments) Borrowings   (37,789)   69,818    (40,341)
Proceeds from Issuance of Common Stock   44,435    14,233    26,259 
Common Stock Issuance Expenses   (562)   (451)   (673)
Payments for Retirement of Capital Stock   (104)   (1,596)   (590)
Proceeds from Issuance of Long-Term Debt   130,000    —    150,000 
Short-Term and Long-Term Debt Issuance Expenses   (888)   (312)   (856)
Payments for Retirement of Long-Term Debt   (87,547)   (212)   (41,088)
Dividends Paid and Other Distributions   (48,244)   (46,223)   (44,261)
Net Cash (Used in) Provided by Financing Activities – Continuing Operations   (4,062)   38,114    49,686 
Net Cash Provided by Financing Activities – Discontinued Operations   —    316    1,178 
Net Cash (Used in) Provided by Financing Activities   (4,062)   38,430    50,864 
Net Change in Cash and Cash Equivalents – Discontinued Operations   —    —    (849)
Net Change in Cash and Cash Equivalents   —    —    (2,007)
Cash and Cash Equivalents at Beginning of Period   —    —    2,007 
Cash and Cash Equivalents at End of Period  $—   $—   $— 

 

See accompanying notes to consolidated financial statements.

 

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Otter Tail Corporation
Consolidated Statements of Capitalization, December 31
(in thousands, except share data)  2016   2015 
Short-Term Debt          
Otter Tail Corporation Credit Agreement  $—   $59,666 
Otter Tail Power Company Credit Agreement   42,883    21,006 
Total Short-Term Debt  $42,883   $80,672 
           
Long-Term Debt          
Obligations of Otter Tail Corporation          
9.000% Notes, due December 15, 2016  $—   $52,330 
Term Loan, LIBOR plus 0.90%, due February 5, 2018   15,000    — 
3.55% Guaranteed Senior Notes, due December 15, 2026   80,000    — 
North Dakota Development Note, 3.95%, due April 1, 2018   106    182 
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021   836    977 
Total – Otter Tail Corporation   95,942    53,489 
Less: Current Maturities—net of Unamortized Debt Issuance Costs   231    52,422 
       Unamortized Long-Term Debt Issuance Costs   539    122 
Total Otter Tail Corporation Long-Term Debt net of Unamortized Debt Issuance Costs   95,172    945 
           
Obligations of Otter Tail Power Company          
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017   33,000    33,000 
Senior Unsecured Notes 4.63%, due December 1, 2021   140,000    140,000 
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022   30,000    30,000 
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027   42,000    42,000 
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029   60,000    60,000 
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037   50,000    50,000 
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044   90,000    90,000 
Total – Otter Tail Power Company   445,000    445,000 
Less: Current Maturities—net of Unamortized Debt Issuance Costs   32,970    — 
Unamortized Long-Term Debt Issuance Costs   1,861    2,099 
Total Otter Tail Power Company Long-Term Debt net of Unamortized Debt Issuance Costs   410,169    442,901 
           
Total Consolidated Long-Term Debt   540,942    498,489 
Less: Current Maturities—net of Unamortized Debt Issuance Costs   33,201    52,422 
Unamortized Long-Term Debt Issuance Costs   2,400    2,221 
Total Consolidated Long-Term Debt net of Unamortized Debt Issuance Costs   505,341    443,846 
Cumulative Preferred Shares—Without Par Value, Authorized 1,500,000 Shares; Outstanding: None          
Cumulative Preference Shares–Without Par Value, Authorized 1,000,000 Shares; Outstanding: None          
Total Common Shareholders’ Equity   670,104    605,023 
Total Capitalization  $1,175,445   $1,048,869 

 

See accompanying notes to consolidated financial statements.

 

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Otter Tail Corporation

Notes to Consolidated Financial Statements

For the years ended December 31, 2016, 2015 and 2014

 

1. Summary of Significant Accounting Policies

 

Principles of Consolidation

The consolidated financial statements of Otter Tail Corporation and its wholly owned subsidiaries (the Company) include the accounts of the following segments: Electric, Manufacturing and Plastics. See note 2 to consolidated financial statements for further descriptions of the Company’s business segments. All intercompany balances and transactions have been eliminated in consolidation except profits on sales to the regulated electric utility company from nonregulated affiliates, which is in accordance with the requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, Regulated Operations (ASC 980).

 

Regulation and ASC 980

The Company’s regulated electric utility company, Otter Tail Power Company (OTP), accounts for the financial effects of regulation in accordance with ASC 980. This standard allows for the recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. See note 4 to consolidated financial statements for further discussion.

 

OTP is subject to various state and federal agency regulations. The accounting policies followed by this business are subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company’s nonelectric businesses.

 

Plant, Retirements and Depreciation

Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction. The amount of interest capitalized on electric utility plant was $495,000 in 2016, $723,000 in 2015 and $689,000 in 2014. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are charged against the accumulated reserve for estimated removal costs, a regulatory liability. Maintenance, repairs and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated remaining service lives of the properties (5 to 82 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.88% in 2016, 2.61% in 2015 and 2.89% in 2014. Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates.

 

Property and equipment of nonelectric operations are carried at historical cost or at the then-current replacement cost if acquired in a business combination, and are depreciated on a straight-line basis over the assets’ estimated useful lives (3 to 40 years). The cost of additions includes contracted work, direct labor and materials, allocable overheads and capitalized interest. No interest was capitalized on nonelectric plant in 2016, 2015 or 2014. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.

 

Recoverability of Long-Lived Assets

The Company reviews its long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. The Company determines potential impairment by comparing the carrying amount of the assets with net cash flows expected to be provided by operating activities of the business or related assets. If the sum of the expected future net cash flows is less than the carrying amount of the assets, the Company would recognize an impairment loss. Such an impairment loss would be measured as the amount by which the carrying amount exceeds the fair value of the asset, where fair value is based on the discounted cash flows expected to be generated by the asset.

 

Jointly Owned Facilities

OTP is a joint owner in two coal-fired steam-powered electric generation plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station near Beulah, North Dakota. OTP is also a joint owner, with other regional utilities, in three major in-service transmission lines and two additional major transmission lines under construction. The following table provides OTP’s ownership percentages and amounts included in the Company’s December 31, 2016 and 2015 consolidated balance sheets for OTP’s share of jointly owned assets in each of these jointly owned facilities:

 

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Jointly Owned Facilities (dollars in thousands)  OTP
Ownership
Percentage		   Electric Plant
in Service		   Construction
Work in
Progress		   Accumulated
Depreciation		   Net Plant 
December 31, 2016                         
Big Stone Plant   53.9%  $328,809   $23   $(65,665)  $263,167 
Coyote Station   35.0%   176,315    113    (101,499)   74,929 
Fargo-Monticello 345 kV line   14.2%   78,298    —    (3,511)   74,787 
Brookings-Southeast Twin Cities 345 kV line1   4.8%   26,406    —    (924)   25,482 
Bemidji-Grand Rapids 230 kV line   14.8%   16,331    —    (1,573)   14,758 
Big Stone South to Brookings 345 kV line1   50.0%   —    45,050    —    45,050 
Big Stone South to Ellendale 345 kV line1   50.0%   —    49,160    —    49,160 
December 31, 2015                         
Big Stone Plant   53.9%  $327,474   $(305)  $(57,641)  $269,528 
Coyote Station   35.0%   165,497    7,405    (103,822)   69,080 
Fargo-Monticello 345 kV line   14.2%   78,272    —    (2,213)   76,059 
Brookings-Southeast Twin Cities 345 kV line1   4.8%   26,189    —    (486)   25,703 
Bemidji-Grand Rapids 230 kV line   14.8%   16,331    —    (1,233)   15,098 
Big Stone South to Brookings 345 kV line1   50.0%   —    14,210    —    14,210 
Big Stone South to Ellendale 345 kV line1   50.0%   —    8,335    —    8,335 
1Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).

 

The Company’s share of direct revenue and expenses of the jointly owned facilities is included in operating revenue and expenses in the consolidated statements of income.

 

Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.

 

If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. Coyote Station started taking delivery of coal and paying for coal and accumulated development fees and capital charges under the LSA in May 2016. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of December 31, 2016 could be as high as $60.6 million, OTP’s 35% share of unrecovered costs.

 

Income Taxes

Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect in the periods when the temporary differences reverse. The Company amortizes investment tax credits over the estimated lives of related property. The Company records income taxes in accordance with ASC Topic 740, Income Taxes, and has recognized in its consolidated financial statements the tax effects of all tax positions that are “more-likely-than-not” to be sustained on audit based solely on the technical merits of those positions as of the balance sheet date. The term “more-likely-than-not” means a likelihood of more than 50%. The Company

 

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classifies interest and penalties on tax uncertainties as components of the provision for income taxes. See note 14 to consolidated financial statements regarding the Company’s accounting for uncertain tax positions.

 

The Company also is required to assess the realizability of its deferred tax assets, taking into consideration the Company’s forecast of future taxable income, the reversal of other existing temporary differences, available net operating loss carryforwards and available tax planning strategies that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, valuation allowances against the Company’s deferred tax assets. To the extent facts and circumstances change in the future, adjustments to the valuation allowance may be required.

 

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, the price is fixed or determinable and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as OTP’s 2015 forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with ASC Topic 815, Derivatives and Hedging (ASC 815). Gains and losses on forward energy contracts subject to regulatory treatment, if any, have been deferred and recognized on a net basis in revenue in the period realized.

 

For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

 

Customer electricity use is metered and bills are rendered monthly. Revenue is accrued for electricity consumed but not yet billed. Rate schedules applicable to substantially all customers include a fuel clause adjustment, under which the rates are adjusted to reflect changes in average cost of fuels and purchased power, and a surcharge for recovery of conservation-related expenses. Revenue is recognized for fuel and purchased power costs incurred in excess of amounts recovered in base rates but not yet billed through the fuel clause adjustment, for conservation program incentives and bonuses earned but not yet billed and for renewable resource, transmission-related and environmental incurred costs and investment returns approved for recovery through riders.

 

Revenues on wholesale electricity sales from Company-owned generating units are recognized when energy is delivered. For shared use of transmission facilities with certain regional transmission cooperatives, revenues are estimated. Bills are rendered based on anticipated usage and settlements are made later based on actual usage. Estimated revenues may be adjusted prior to settlement, or at the time of settlement, to reflect actual usage.

 

Under ASC 815, OTP accounts for forward energy contracts as derivatives subject to mark-to-market accounting unless those contracts meet the definition of a capacity contract or are not subject to unplanned netting, then OTP accounts for the contracts under the normal purchases and sales exception to mark-to-market accounting.

 

Manufacturing and Plastics operating revenues are recorded when products are shipped.

 

Warranty Reserves

Certain products sold by the Company’s manufacturing and plastics companies carry product warranties for one year after the shipment date. These companies’ standard product warranty terms generally include post-sales support and repairs or replacement of a product at no additional charge for a specified period of time. While these companies engage in extensive product quality programs and processes, including actively monitoring and evaluating the quality of their component suppliers, they base their estimated warranty obligations on warranty terms, ongoing product failure rates, repair costs, product call rates, average cost per call, and current period product shipments. The Company’s manufacturing and plastics companies have not incurred any significant warranty costs over the last three fiscal years in continuing operations.

 

Shipping and Handling Costs

The Company includes revenues received for shipping and handling in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of goods sold.

 

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Use of Estimates

The Company uses estimates based on the best information available in recording transactions and balances resulting from business operations. As better information becomes available (or actual amounts are known), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

 

Cash Equivalents

The Company considers all highly liquid debt instruments purchased with maturity of 90 days or less to be cash equivalents.

 

Investments

The following table provides a breakdown of the Company’s investments at December 31:

 

(in thousands)  2016   2015 
Cost Method:          
Economic Development Loan Pools  $54   $81 
Other   115    2,088 
Equity Method Partnerships   23    22 
Marketable Securities Classified as Available-for-Sale   8,225    8,093 
Total Investments  $8,417   $10,284 
Less: Aevenia, Inc. (AEV, Inc.) Escrow Funds Reported Under Other Current Assets   —    (1,500)
Foley Company (Foley) Escrow Funds Reported Under Other Current Assets   —    (500)
Investments  $8,417   $8,284 

 

The Company’s marketable securities classified as available-for-sale are held for insurance purposes and are reflected at their fair values on December 31, 2016. See further discussion below.

 

Agreements Subject to Legally Enforceable Netting Arrangements

The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.

 

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:

 

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).

 

Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

 

Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.

 

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The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2016 and December 31, 2015:

 

December 31, 2016 (in thousands)  Level 1   Level 2   Level 3 
Assets:               
Investments:               
Corporate Debt Securities – Held by Captive Insurance Company       $5,280      
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company        2,945      
Other Assets:               
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan  $849           
Total Assets  $849   $8,225      

 

December 31, 2015 (in thousands)  Level 1   Level 2   Level 3 
Assets:               
Current Assets – Other:               
Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions  $2,000           
Investments:               
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company       $4,235      
Corporate Debt Securities – Held by Captive Insurance Company        3,858      
Other Assets:               
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan   196           
Total Assets  $2,196   $8,093      
Liabilities:               
Other Accrued Liabilities:               
Derivative Liabilities – Forward Gasoline Purchase Contracts       $199      
Total Liabilities       $199      

 

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

 

Forward Gasoline Purchase Contracts –These contracts were priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods. As of December 31, 2016 OTP held, and currently holds, no RBOB contracts.

 

Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

 

Inventories

Electric segment inventories are reported at average cost. The Manufacturing and Plastics segments’ inventories are stated at the lower of average cost or market. Inventories consist of the following at December 31:

 

(in thousands)  2016   2015 
Finished Goods  $27,755   $25,971 
Work in Process   11,754    12,821 
Raw Material, Fuel and Supplies   44,231    46,624 
Total Inventories  $83,740   $85,416 

 

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Goodwill and Other Intangible Assets

The Company accounts for goodwill and other intangible assets in accordance with the requirements of ASC Topic 350, Intangibles—Goodwill and Other, measuring its goodwill for impairment annually in the fourth quarter, and more often when events indicate the assets may be impaired. The Company does qualitative assessments of its reporting units with recorded goodwill to determine if it is more likely than not that the fair value of the reporting unit exceeds its book value. The Company also does quantitative assessments of its reporting units with recorded goodwill to determine the fair value of the reporting unit.

 

In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued operations. See note 16 to consolidated financial statements.

 

On September 1, 2015 Miller Welding & Iron Works, Inc. (BTD-Illinois), a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing, Inc. (Impulse) of Dawsonville, Georgia. The acquired business operates under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference in the fair value of assets acquired and the price paid for Impulse resulted in an initial estimate of acquired goodwill of $8.2 million. A final determination of the purchase price was agreed to in June 2016 resulting in a $2.2 million reduction in acquired goodwill in June 2016. See note 2 to the Company’s consolidated financial statements for more information.

 

The following tables summarize changes to goodwill by business segment during 2016 and 2015:

 

(in thousands)  Gross Balance
December 31, 2015		   Accumulated
Impairments		   Balance (net of
impairments)
December 31, 2015		   Adjustments to
Goodwill in
2016		   Balance (net of
impairments)
December 31, 2016		 
Manufacturing  $20,430   $—   $20,430   $(2,160)  $18,270 
Plastics   19,302    —    19,302    —    19,302 
Total  $39,732   $—   $39,732   $(2,160)  $37,572 
                          
(in thousands)  Gross Balance
December 31, 2014		   Accumulated
Impairments		   Balance
(net of impairments)
December 31, 2014		   Adjustments
and Additions
to Goodwill
in 2015		   Balance
(net of impairments)
December 31, 2015		 
Manufacturing  $12,186   $—   $12,186   $8,244   $20,430 
Plastics   19,302    —    19,302    —    19,302 
Total  $31,488   $—   $31,488   $8,244   $39,732 

 

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. With the purchase of BTD-Georgia on September 1, 2015, the Company acquired customer relationships valued at $4,870,000 to be amortized over 20 years and the seller entered into a covenant not to compete valued at $620,000 to be amortized over three years. The final purchase price adjustment agreed to in June 2016 resulted in an $810,000 increase in the fair value of acquired customer relationships and a $30,000 reduction in the fair value of the covenant not to compete. The changes in the value of these intangibles had an insignificant impact on the Company’s consolidated net income in 2016 related to a change in amortization expense that would have been recorded in 2015 had the adjusted asset values been established on acquisition in 2015. See note 2 to the Company’s consolidated financial statements for more information.

 

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The following table summarizes the components of the Company’s intangible assets at December 31, 2016 and December 31, 2015:

 

December 31, 2016 (in thousands)  Gross Carrying
Amount		   Accumulated
Amortization		   Net Carrying
Amount		   Remaining
Amortization
Periods
Amortizable Intangible Assets:                  
Customer Relationships  $22,491   $7,861   $14,630   36-224 months
Covenant not to Compete   590    262    328   20 months
Total  $23,081   $8,123   $14,958    
                   
December 31, 2015 (in thousands)                  
Amortizable Intangible Assets:                  
Customer Relationships  $21,681   $6,714   $14,967   48-236 months
Covenant not to Compete   620    69    551   32 months
Other Intangible Assets   639    543    96   9 months
Emission Allowances   59    NA    59   Expensed as used
Total  $22,999   $7,326   $15,673    

 

The amortization expense for these intangible assets was:

 

(in thousands)  2016   2015   2014 
Amortization Expense – Intangible Assets  $1,436   $1,127   $977 

 

The estimated annual amortization expense for these intangible assets for the next five years is:

 

(in thousands)  2017   2018   2019   2020   2021 
Estimated Amortization Expense – Intangible Assets  $1,330   $1,264   $1,133   $1,099   $1,099 

 

Supplemental Disclosures of Cash Flow Information

 

   As of December 31, 
(in thousands)  2016   2015 
Noncash Investing Activities:          
Transactions Related to Capital Additions not Settled in Cash  $13,533   $20,371 

 

(in thousands)  2016   2015   2014 
Cash Paid (Received) During the Year for:               
Interest (net of amount capitalized)  $31,269   $30,512   $26,364 
Income Taxes  $(1,291)  $7,322   $145 

 

New Accounting Standards

 

Accounting Standards Update (ASU) 2014-09—In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

 

Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. As of December 31, 2016 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is evaluating transition options. Based on review of the Company’s revenue streams, the Company does not anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU 2014-09, with the exception of the treatment of contributions in aid of construction in the Electric segment on which consensus treatment has not been determined and guidance has not been provided. Currently, the Company reduces its investment in fixed assets for the amount of these contributions. Should the Company be required to recognize these contributions as revenue under ASU 2014-09, it could result in a significant increase in reported revenues and expenses. Adoption of ASU

 

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2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard. The Company does not plan to adopt the updated guidance prior to January 1, 2018.

 

ASU 2015-03—In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03), which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015 and must be applied retrospectively to balance sheets presented for periods prior to adoption. The Company adopted the updated standards in ASU 2015-03 in the first quarter of 2016. In conjunction with implementing this update, the Company is reclassifying the remaining balance of unamortized line of credit issuance costs from the deferred debit section of its consolidated balance sheet to other assets, eliminating the deferred debits section of its consolidated balance sheet and displaying long-term regulatory assets as a separate line item on its consolidated balance sheet. The effects of applying the guidance in ASU 2015-03 retrospectively to the Company’s December 31, 2015 consolidated balance sheet and statement of capitalization and of the associated reclassification of unamortized line of credit issuance costs are shown in the following table:

 

(in thousands)  December 31, 2015
Previously Stated		   Adjustments   December 31, 2015
Adjusted		 
Other Assets  $31,108   $1,676   $32,784 
Unamortized Debt Expense   3,897    (3,897)   — 
Total Assets   1,820,904    (2,221)   1,818,683 
                
Current Liabilities               
Current Maturities of Long-Term Debt   52,544    (122)   52,422 
Total Current Liabilities   271,238    (122)   271,116 
Capitalization               
Long-Term Debt—Net   445,945    (2,099)   443,846 
Total Capitalization   1,050,968    (2,099)   1,048,869 
Total Liabilities and Equity   1,820,904    (2,221)   1,818,683 

 

ASU 2015-11—In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires that inventories be measured at the lower of cost or net realizable value instead of the lower of cost or market value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The standards update is effective prospectively for fiscal years and interim periods beginning after December 15, 2016, with early adoption permitted. The Company does not expect the adoption of the updated standard to have a material impact on its consolidated financial statements.

 

ASU 2015-16—In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16), which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in ASU 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in ASU 2015-16 are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date, with earlier application permitted for financial statements that have not been issued. The Company elected to adopt the updated standard in the fourth quarter of 2015 in order to apply the updates to its recent acquisition of BTD-Georgia. Adoption of the updated standard did not have a material impact on the Company’s consolidated financial statements. The early adoption of the standard alleviated the need for prior period adjustments of income related to the BTD-Georgia acquisition purchase price adjustment recorded in June 2016. See note 2 to the Company’s consolidated financial statements for more information.

 

ASU 2016-02—In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 is a comprehensive amendment of the ASC, creating Topic 842, which will supersede the current requirements under ASC Topic 840 on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic 842 affects any entity that enters into a lease, with some specified scope exemptions. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria

 

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for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. The Company is currently reviewing ASU 2016-02, identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and evaluating transition options. The Company does not currently plan to apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019.

 

ASU 2016-09— In March 2016, the FASB issued ASU No. 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which is intended to improve and simplify accounting and reporting requirements related to stock-based compensation programs. The amendments in ASU 2016-09 change how companies account for certain aspects of share-based payments to employees, including: (1) changing award classifications from liability to equity as a result of an increase in the permitted level of share withholding to cover income taxes to satisfy statutory income tax withholding requirements on the awards, (2) recognizing excess tax benefits as an adjustment to income tax expense when the awards vest rather than directly adjusting stockholders' equity, and (3) introducing an accounting policy election that permits reporting entities to elect to account for forfeitures as they occur. The amendments in ASU 2016-09 are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted.

 

In the fourth quarter of 2016, the Company elected to early adopt the updates in ASU 2016-09. The withholding provisions in the award agreements applicable to the Company’s outstanding performance awards granted to executive officers in 2014, 2015 and 2016 allow for withholding up to the maximum statutory tax rates in the applicable jurisdictions. The updates in ASU 2016-09 result in these awards being classified as equity awards rather than liability awards, requiring the amount of expense recognized for these awards to be based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards. The reporting-date fair values of the 2014 and 2015 awards outstanding on December 31, 2015 were less than the grant-date fair values of the awards. On adoption of the updates in ASU 2016-09 in the fourth quarter of 2016, the difference in expense that would have been recognized related to the outstanding 2014 and 2015 awards in 2014 and 2015 had the awards been classified as equity awards instead of liability awards results in a cumulative-effect net-of-tax adjustment to retained earnings of $623,000, with related adjustments to unvested restricted stock liability, deferred tax and miscellaneous paid-in capital accounts, effective as of January 1, 2016, as illustrated below:

 

Balance Sheet Account Affected, Effective January 1, 2016  Debit   Credit 
Adjustment to Retained Earnings  $623,000      
Long-Term Incentive Payable  $1,453,000      
Deferred Taxes  $416,000      
Miscellaneous Paid-In Capital       $2,492,000 

 

The impact of adopting the updates in ASU 2016-09 effective January 1, 2016 on 2016 interim reporting periods was not material.

 

2. Business Combinations, Dispositions and Segment Information

 

Business Combinations

On September 1, 2015 BTD-Illinois, a wholly owned subsidiary of BTD, acquired the assets of Impulse of Dawsonville, Georgia for $30.8 million in cash. A post-closing reduction in the purchase price of $1.5 million was agreed to in June 2016 resulting in an adjusted purchase price of $29.3 million. The acquired business, operating under the name BTD-Georgia, is a full-service metal fabricator located 30 miles north of Atlanta, Georgia, which offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers. In addition to serving some of BTD’s existing customers from a location closer to the customers’ manufacturing facilities, this acquisition provides opportunities for growth in new and existing markets for BTD with complementing production capabilities that expand the capacity of services offered by BTD. Pro forma results of operations have not been presented for this acquisition because the effect of the acquisition was not material to the Company.

 

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Below is condensed balance sheet information disclosing the final allocation of the purchase price assigned to each major asset and liability category of BTD-Georgia:

 

(in thousands)    
Assets:     
Current Assets  $4,906 
Goodwill   6,083 
Other Intangible Assets   6,270 
Other Amortizable Assets   1,380 
Fixed Assets   13,649 
Total Assets  $32,288 
Liabilities:     
Current Liabilities  $2,971 
Lease Obligation   11 
Total Liabilities  $2,982 
Cash Paid  $29,306 

 

In the fourth quarter of 2015, the Company elected to early adopt ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which requires that an acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The purchase price adjustment agreed to in June 2016 resulted in a $2.2 million reduction to the value of acquired goodwill, a $0.8 million increase in the fair value of acquired customer relationships and a $0.1 million increase in acquired liabilities. The changes in the value of customer relationships had an immaterial impact on the Company’s consolidated net income in 2016 related to a change in amortization expense that would have been recorded in 2015 had the adjusted asset values been established on acquisition in 2015.

 

The Company acquired no new businesses in 2016 or 2014.

 

In execution of the Company’s announced strategy of realigning its business portfolio to reduce its risk profile and dedicate a greater portion of its resources toward electric utility operations, the Company sold several of its holdings in recent years. On December 31, 2014 the Company was in the process of negotiating the sales of Foley, its mechanical and prime contractor on industrial projects, and AEV, Inc., its electrical design and construction services company, which resulted in the removal of its Construction segment from continuing operations. The sale of Foley closed on April 30, 2015 and the sale of the assets of AEV, Inc. closed on February 28, 2015.

 

The results of operations of the Company’s recently disposed businesses are reported as discontinued operations in the Company’s consolidated financial statements as of and for the years ended December 31, 2016, 2015 and 2014, and are summarized in note 16 to consolidated financial statements.

 

Segment Information

The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company’s business structure currently includes the following three segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.

 

 

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.

 

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Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.

 

Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States.

 

OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

 

No single customer accounted for over 10% of the Company’s consolidated revenues in 2016, 2015 and 2014. All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.6% of sales in 2016, 97.1% of sales in 2015 and 95.9% of sales in 2014.

 

The Company evaluates the performance of its business segments and allocates resources to them based on segment net income contribution and return on total invested capital. Information on continuing operations for the business segments for 2016, 2015 and 2014 is presented in the following table:

 

(in thousands)  2016   2015   2014 
Operating Revenue               
Electric  $427,383   $407,131   $407,743 
Manufacturing   221,289    215,011    219,583 
Plastics   154,901    157,758    172,050 
Intersegment Eliminations   (34)   (96)   (114)
Total  $803,539   $779,804   $799,262 
Cost of Products Sold               
Manufacturing  $171,732   $171,956   $169,033 
Plastics   123,496    123,085    139,081 
Intersegment Eliminations   (6)   (9)   (45)
Total  $295,222   $295,032   $308,069 
Other Nonelectric Expenses               
Manufacturing  $21,994   $21,115   $23,340 
Plastics   9,402    9,850    9,292 
Corporate   8,896    9,143    13,418 
Intersegment Eliminations   (28)   (87)   (69)
Total  $40,264   $40,021   $45,981 
Depreciation and Amortization               
Electric  $53,743   $44,786   $44,076 
Manufacturing   15,794    11,853    10,518 
Plastics   3,861    3,552    3,364 
Corporate   47    172    116 
Total  $73,445   $60,363   $58,074 
Operating Income (Loss)               
Electric  $90,131   $87,171   $76,060 
Manufacturing   11,769    10,086    16,692 
Plastics   18,142    21,272    20,313 
Corporate   (8,943)   (9,315)   (13,534)
Total  $111,099   $109,214   $99,531 

 

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(in thousands)  2016   2015   2014 
Interest Charges               
Electric  $25,069   $24,371   $23,322 
Manufacturing   3,859    3,560    3,243 
Plastics   1,034    1,026    1,043 
Corporate and Intersegment Eliminations   1,924    2,203    2,040 
Total  $31,886   $31,160   $29,648 
Income Tax Expense (Benefit) – Continuing Operations               
Electric  $16,366   $16,067   $11,029 
Manufacturing   2,276    2,299    4,117 
Plastics   6,538    8,187    7,301 
Corporate   (5,099)   (4,911)   (5,890)
Total  $20,081   $21,642   $16,557 
Net Income (Loss)               
Electric  $49,829   $48,370   $43,684 
Manufacturing   5,694    4,247    9,361 
Plastics   10,628    12,108    12,085 
Corporate   (4,114)   (6,136)   (8,247)
Discontinued Operations   284    756    840 
Total  $62,321   $59,345   $57,723 
Capital Expenditures               
Electric  $149,648   $135,572   $148,719 
Manufacturing   8,429    20,295    11,252 
Plastics   3,085    4,206    3,567 
Corporate   97    11    44 
Total  $161,259   $160,084   $163,582 
Identifiable Assets               
Electric  $1,622,231   $1,520,887   $1,438,791 
Manufacturing   166,525    173,860    128,608 
Plastics   84,592    81,624    86,650 
Corporate   39,037    42,312    36,508 
Assets of Discontinued Operations   —    —    47,559 
Total  $1,912,385   $1,818,683   $1,738,116 

 

3. Rate and Regulatory Matters

 

Below are descriptions of OTP’s major capital expenditure projects and use of reagents and emission allowances that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2016, 2015 and 2014.

 

Major Capital Expenditure Projects

 

The Big Stone South – Brookings MVP and CapX2020 Project—This 345 kiloVolt (kV) transmission line, currently under construction, will extend approximately 70 miles between a substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Northern States Power – MN (NSP MN), a subsidiary of Xcel Energy Inc., jointly developed this project and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. Construction began on this line in the third quarter of 2015 and the line is expected to be in service in fall 2017.

 

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The Big Stone South – Ellendale MVP—This is a 345 kV transmission line that will extend 163 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. (MDU), and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019.

 

Capacity Expansion 2020 (CapX2020) Transmission Line Projects—CapX2020 is a joint initiative of eleven investor-owned, cooperative, and municipal utilities in Minnesota and the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service.

 

Fargo–Monticello 345 kV CapX2020 Project (the Fargo Project)—OTP has invested approximately $81 million and has a 14.2% ownership interest in the jointly-owned assets of this 240-mile transmission line, and owns 100% of certain assets of the project. The final phase of this project was energized on April 2, 2015.

 

Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project)—OTP has invested approximately $26 million and has a 4.8% ownership interest in this 250-mile transmission line. The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011. The final segments of this line were energized on March 26, 2015.

 

Big Stone Plant Air Quality Control System (AQCS)— OTP completed construction and testing of the Big Stone Plant AQCS in the fourth quarter of 2015 and placed the AQCS into commercial operation on December 29, 2015. OTP’s capitalized cost of the project, excluding allowance for funds used during construction, was approximately $200 million.

 

Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.

 

Reagent Costs

 

OTP’s systemwide costs for reagents are expected to increase to approximately $2.2 million annually through May 2021 when Hoot Lake Plant is expected to be retired. The Minnesota, North Dakota and South Dakota share of costs are approximately 50%, 40% and 10%, respectively. Reagent costs for the Big Stone Plant AQCS and Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) were initially incurred in 2015 when projects went into service.

 

Minnesota

 

2016 General Rate Case—On February 16, 2016 OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested an allowed rate of return on rate base of 8.07% and an allowed rate of return on equity of 10.4% based on an equity ratio of 52.5% of total capital. On April 14, 2016 the MPUC issued an order approving an interim rate increase of 9.56% to the base rate portion of customers’ bills effective April 16, 2016, as modified and subject to refund. The request and interim rate information is detailed in the table below:

 

($ in thousands)  Annualized or
Test Year		   Actual Through
December 31, 2016		 
Revenue Increase Requested  $19,296      
Increase Percentage Requested   9.80%     
Jurisdictional Rate Base  $483,000      
Interim Revenue Increase (subject to refund)  $16,816   $10,976 

 

The major components of the requested rate increase are summarized below:

 

Revenue Requirement Deficiency Cost Factors (in thousands)  2016 Test Year
Allocation		 
Increased Rate Base  $10,000 
Increased Expenses   7,700 
Other   1,596 
Total Requested Revenue Increase  $19,296 
Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset   (2,480)
Approved Interim Revenue Increase (subject to refund)  $16,816 

 

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The deadline for submission of intervenor direct testimony was August 16, 2016. Direct testimony of the Minnesota Department of Commerce (MNDOC) included a recommendation for an 8.87% allowed rate of return on equity, and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. Hearings before the Administrative Law Judge (ALJ) occurred in October 2016. On January 5, 2017 the ALJ issued his report which included a recommendation for a 9.54% allowed rate of return on equity.

 

Based on OTP’s modifications to its original request and other expected outcomes in the aforementioned rate case, OTP has recorded an estimated interim rate refund of $3.6 million as of December 31, 2016. Oral arguments before the MPUC are expected to occur in late February 2017. The MPUC is expected to make its final decision in March 2017 and issue its written order in spring 2017.

 

2010 General Rate Case—OTP’s most recently completed general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%.

 

Minnesota Conservation Improvement Programs—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state's energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota.

 

The MNDOC may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the Minnesota Conservation Improvement Program (MNCIP) through the use of an annual recovery mechanism approved by the MPUC.

 

On September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case.

 

OTP recognized a financial incentive for 2014 of $3.0 million due, in part, to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016. Additionally, OTP saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million along with an updated surcharge with an effective date of October 1, 2015.

 

Based on results from the 2015 MNCIP program year, OTP recognized a financial incentive of $4.2 million. The 2015 MNCIP program resulted in an approximate 39% increase in energy savings compared to 2014 program results. On April 1, 2016 OTP requested approval for recovery of its 2015 MNCIP program costs not included in base rates, a $4.3 million financial incentive and an update to the MNCIP surcharge from the MPUC. On July 19, 2016 the MPUC issued an order approving OTP’s request with an effective date of October 1, 2016.

 

Based on results from the 2016 MNCIP program year, OTP recognized a financial incentive of $5.1 million in 2016. The 2016 program resulted in an approximate 18% increase in energy savings compared to 2015 program results. OTP will request approval for recovery of its 2016 MNCIP program costs not included in base rates, a $5.1 million financial incentive and an update to the MNCIP surcharge from the MPUC by April 1, 2017.

 

On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes to the MNCIP financial incentive. The new model will provide utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism.

 

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act (the MPU Act) provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority

 

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transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility's retail customers, or exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The MPU Act also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Finally, under certain circumstances, the MPU Act also authorizes TCR riders to recover the costs associated with distribution planning and investments in distribution facilities to modernize the utility grid. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule.

 

MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers.

 

OTP filed an annual update to its Minnesota TCR rider on February 7, 2013 to include three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but found capitalized internal costs, costs in excess of CON estimates and a carrying charge ineligible for recovery through the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP is seeking recovery of the capitalized internal costs and costs in excess of CON estimates in its current general rate case filing in Minnesota. In response to the MPUC’s approval of OTP’s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. OTP filed an annual update to its Minnesota TCR rider on September 30, 2015 requesting revenue recovery of approximately $7.8 million. A supplemental filing to the update was made on December 21, 2015 to address an issue surrounding the proration of accumulated deferred income taxes and, in an unrelated adjustment, the TCR rider update revenue request was reduced to $7.2 million. On March 9, 2016 the MPUC issued an order approving OTP’s annual update to its TCR rider, with an effective date of April 1, 2016.

 

OTP filed an update to its TCR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The proposed rate changes went into effect on September 1, 2016. The MPUC has granted extensions to the MNDOC to file initial comments in this docket until February 2, 2017.

 

In OTP’s 2016 general rate case, the MNDOC has argued that the MPUC should require OTP to include in the TCR rider retail rate base 100% of OTP’s investment in the Big Stone South – Brookings and Big Stone South – Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. OTP has opposed this treatment, arguing that the projects are appropriately assigned to the FERC jurisdiction, and the FERC’s determination of the projects’ revenue requirements should not be altered by forcing the revenues into the retail revenue requirement calculations. In the general rate case proceeding, the ALJ has recommended that the MPUC should affirm OTP’s treatment. If the MPUC finds that the MNDOC’s treatment should be followed, it would result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time.

 

Environmental Cost Recovery (ECR) Rider—On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements included a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. The MPUC approved OTP’s 2014 ECR rider annual update request on November 24, 2014 with an effective date of December 1, 2014. OTP filed its 2015 annual update on July 31, 2015, with a request to keep the 2014 annual update rate in place. On December 21, 2015 OTP filed a supplemental filing with updated financial information. The MPUC issued an order on March 9, 2016 approving OTP’s request to leave the 2014 annual update rate in place. OTP filed an update to its Minnesota ECR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request, with an effective date of September 1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis and has since granted extensions to the MNDOC to file initial comments in this docket until February 2, 2017. Reply comments were due from OTP on February 13, 2017.

 

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Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery of these costs. These costs are included in OTP’s 2016 general rate case in Minnesota and are being considered for recovery either through the FCA rider or general rates. These costs are currently being expensed as incurred.

 

North Dakota

 

General Rates—OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.

 

Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment (NDRRA) which enables OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment. The NDPSC approved OTP’s 2013 annual update to its NDRRA on March 12, 2014 with an effective date of April 1, 2014, which resulted in a 13.5% reduction in the NDRRA rate. The NDPSC approved OTP’s 2014 annual update to the NDRRA, including a change in rate design from an amount per kwh consumed to a percentage of a customer’s bill, on March 25, 2015 with an effective date of April 1, 2015. OTP submitted its 2015 annual update to the NDRRA rider rate on December 31, 2015 with a requested implementation date of April 1, 2016. On February 25, 2016 OTP made a supplemental filing to address the impact of bonus depreciation for income taxes and related deferred tax assets on the NDRRA, as well as an adjustment to the estimated amount of Federal Production Tax Credits used. The NDPSC approved the NDRRA 2015 annual update on June 22, 2016 with an effective date of July 1, 2016. The updated NDRRA reflects a reduction in the return on equity (ROE) component of the rate from 10.75%, approved in OTP’s most recent general rate case, to 10.50%. OTP submitted its 2016 annual update to the NDRRA rider rate on December 30, 2016, requesting a decrease to the NDRRA rate from 7.573% to 7.005%, with a requested implementation date of April 1, 2017.

 

Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case. The NDPSC approved OTP’s 2014 annual update to its TCR rider rate on December 17, 2014 with an effective date of January 1, 2015. On August 31, 2015 OTP filed its 2015 annual update to its North Dakota TCR rider rate requesting recovery of approximately $10.2 million for 2016 compared with $8.5 million for 2015, including costs assessed by the MISO as well as new costs from the Southwest Power Pool (SPP) that OTP began incurring January 1, 2016. These new costs are associated with OTP’s load connected to the transmission system of Central Power Electric Cooperative (CPEC). OTP’s load became subject to SPP transmission-related charges when CPEC transmission assets were added to the SPP. The NDPSC approved OTP’s 2015 annual update to its TCR rider rate on December 16, 2015, with an effective date of January 1, 2016. On September 1, 2016 OTP filed its annual update to the TCR rider requesting a revenue requirement of $5.7 million, which includes a reduction of $2.6 million for a projected over-collection for 2016. Primary drivers of the decrease from the 2015 updated rider rate include the impact of federal bonus depreciation and unresolved MISO ROE complaint proceedings. OTP filed a supplemental filing on September 14, 2016, requesting that the over-collection balance be spread over the next two years for purposes of reducing the volatility of the rates from year to year. The NDPSC approved the update on December 14, 2016. The new rates went into effect on January 1, 2017.

 

Environmental Cost Recovery Rider—On December 18, 2013 the NDPSC approved OTP’s request for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. The ECR provides for a current return on CWIP and a return on investment at the level approved in OTP’s most recent general rate case. On March 31, 2014 OTP filed an annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR. This update included a request to increase the ECR rider rate from 7.531% to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective date of July 1, 2015, along with the approval of recovery of OTP’s North Dakota jurisdictional share of Hoot Lake Plant MATS project costs.

 

On March 31, 2016 OTP filed its annual update to the ECR rider requesting a reduction in the rate from 9.193% to 7.904% of base rates, or a revenue requirement reduction from $12.2 million to $10.4 million, effective July 1, 2016. The rate reduction request was primarily due to the Company’s 2015 bonus depreciation election for income taxes, which reduces revenue requirements. The filing was approved on June 22, 2016.

 

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Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance costs. On February 25, 2015 the NDPSC approved recovery of these costs through modification of the ECR rider, instead of recovery through the FCA as OTP had proposed. The ECR rider reagent and emissions allowance charge became effective May 1, 2015.

 

South Dakota

 

2010 General Rate Case—OTP’s most recent general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued on April 21, 2011 and effective with bills rendered on and after June 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.50%.

 

Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. The SDPUC approved OTP’s 2013 annual update on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP’s 2014 annual update on February 13, 2015 with an effective date of March 1, 2015. OTP filed its 2015 annual update on October 30, 2015 with a proposed effective date of March 1, 2016. A supplemental filing was made on February 3, 2016 to true-up the filing to include the impact of bonus depreciation elected for 2015, the inclusion of a deferred tax asset relating to a net operating loss and the proration of accumulated deferred income taxes. This update included the recovery of new SPP transmission costs OTP began to incur on January 1, 2016. On February 12, 2016 the SDPUC approved OTP’s annual update to its TCR rider, with an effective date of March 1, 2016. On November 1, 2016 OTP filed the annual update to the South Dakota TCR rider. OTP made a supplemental filing on January 20, 2017 to include updated costs through December 2016 as well as updated forecast information. The proposed effective date of the new rates is March 1, 2017.

 

Environmental Cost Recovery Rider—On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover OTP’s South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014. On August 31, 2015 OTP filed its annual update to the South Dakota ECR requesting recovery of approximately $2.7 million in annual revenue. The SDPUC approved the request on October 15, 2015 with an effective date of November 1, 2015. On August 31, 2016 OTP filed its 2016 update to the ECR rider, requesting recovery of approximately $2.3 million in annual revenue. The SDPUC approved the request on October 26, 2016 with an effective date of November 1, 2016. The lower revenue requirement is a result of the implementation of federal bonus depreciation taken on the Big Stone Plant AQCS.

 

Reagent Costs and Emission Allowances—On August 1, 2014 OTP filed a request with the SDPUC to revise its FCA rider in South Dakota to include recovery of reagent and emission allowance costs. On September 16, 2014 the SDPUC approved OTP’s request to include recovery of these costs in its South Dakota FCA rider.

 

Revenues Recorded under Rate Riders

 

The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the years ended December 31:

 

Rate Rider (in thousands)  2016   2015   2014 
Minnesota               
Conservation Improvement Program Costs and Incentives1  $12,920   $10,724   $7,757 
Environmental Cost Recovery   12,443    10,238    6,891 
Transmission Cost Recovery   5,795    5,202    6,275 
North Dakota               
Environmental Cost Recovery   11,089    9,502    5,872 
Renewable Resource Adjustment   7,800    8,409    7,484 
Transmission Cost Recovery   7,694    6,609    5,794 
South Dakota               
Environmental Cost Recovery   2,538    1,967    234 
Transmission Cost Recovery   1,820    1,290    1,207 
Conservation Improvement Program Costs and Incentives   468    583    435 

1Includes MNCIP costs recovered in base rates.

 

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FERC

 

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935, as amended. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.

 

Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing.

 

Effective January 1, 2012 the FERC authorized OTP to recover 100% of prudently incurred CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission Expansion Plan: the Big Stone South–Brookings MVP and the Big Stone South–Ellendale MVP.

 

On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. On October 16, 2014 the FERC issued an order finding that the current MISO ROE may be unjust and unreasonable and setting the issue for hearing. Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the United States Court of Appeals for the District of Columbia (D.C. Circuit). A non-binding decision by the presiding ALJ was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%.

 

On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.

 

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the D.C. Circuit. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. The FERC is expected to issue its order not earlier than spring 2017.

 

Based on a potential reduction by the FERC in the ROE component of the MISO Tariff, OTP recorded reductions in revenue of $1.6 million in 2016 and $1.1 million in 2015 and has a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE.

 

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4. Regulatory Assets and Liabilities

 

As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC 980. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

 

   December 31, 2016   Remaining
Recovery/
(in thousands)  Current   Long-Term   Total   Refund Period
Regulatory Assets:                  
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1  $6,443   $108,267   $114,710   see below
Deferred Marked-to-Market Losses1   4,063    6,467    10,530   48 months
Conservation Improvement Program Costs and Incentives2   4,836    5,158    9,994   21 months
Accumulated ARO Accretion/Depreciation Adjustment1   —    6,153    6,153   asset lives
Big Stone II Unrecovered Project Costs – Minnesota1   778    2,087    2,865   52 months
North Dakota Renewable Resource Rider Accrued Revenues2   1,319    482    1,801   15 months
Recoverable Fuel and Purchased Power Costs1   1,798    —    1,798   12 months
Debt Reacquisition Premiums1   325    1,214    1,539   189 months
Minnesota Deferred Rate Case Expenses Subject to Recovery1   1,082    —    1,082   12 months
Deferred Income Taxes1   —    1,014    1,014   asset lives
Big Stone II Unrecovered Project Costs – South Dakota2   100    543    643   77 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2   —    568    568   24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2   333    —    333   12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2   73    141    214   14 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2   113    —    113   12 months
Minnesota Renewable Resource Rider Accrued Revenues2   34    —    34   9 months
Total Regulatory Assets  $21,297   $132,094   $153,391    
Regulatory Liabilities:                  
Accumulated Reserve for Estimated Removal Costs – Net of Salvage  $—   $80,404   $80,404   asset lives
North Dakota Transmission Cost Recovery Rider Accrued Refund   1,381    782    2,163   24 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota   711    208    919   16 months
Deferred Income Taxes   —    818    818   asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund   757    —    757   12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund   285    —    285   12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund   139    —    139   12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up   —    132    132   24 months
Other   21    89    110   204 months
Total Regulatory Liabilities  $3,294   $82,433   $85,727    
Net Regulatory Asset Position  $18,003    49,661   $67,664    

1Costs subject to recovery without a rate of return.

2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

 

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   December 31, 2015   Remaining
Recovery/
(in thousands)  Current   Long-Term   Total   Refund Period
Regulatory Assets:                  
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1  $7,439   $99,293   $106,732   see below
Deferred Marked-to-Market Losses1   4,063    10,530    14,593   60 months
Conservation Improvement Program Costs and Incentives2   4,411    4,266    8,677   18 months
Accumulated ARO Accretion/Depreciation Adjustment1   —    5,672    5,672   asset lives
Big Stone II Unrecovered Project Costs – Minnesota1   942    2,620    3,562   84 months
North Dakota Renewable Resource Rider Accrued Revenues2   —    1,266    1,266   15 months
Debt Reacquisition Premiums1   351    1,539    1,890   201 months
Minnesota Deferred Rate Case Expenses Subject to Recovery1   291    —    291   12 months
Deferred Income Taxes1   —    1,455    1,455   asset lives
Big Stone II Unrecovered Project Costs – South Dakota2   100    643    743   89 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2   698    355    1,053   24 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues2   576    —    576   12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2   33    —    33   12 months
Minnesota Renewable Resource Rider Accrued Revenues2   —    68    68   see below
Total Regulatory Assets  $18,904   $127,707   $146,611    
Regulatory Liabilities:                  
Accumulated Reserve for Estimated Removal Costs – Net of Salvage  $—   $74,948   $74,948   asset lives
Refundable Fuel Clause Adjustment Revenues   1,834    —    1,834   12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund   132    —    132   12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota   —    1,279    1,279   see below
Deferred Income Taxes   —    1,110    1,110   asset lives
South Dakota Environmental Cost Recovery Rider Accrued Refund   185    —    185   12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund   777    —    777   12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion   5    95    100   216 months
North Dakota Environmental Cost Recovery Rider Accrued Refund   321    —    321   12 months
North Dakota Renewable Resource Rider Accrued Refund   68    —    68   12 months
Total Regulatory Liabilities  $3,322   $77,432   $80,754    
Net Regulatory Asset Position  $15,582   $50,275   $65,857    

1Costs subject to recovery without a rate of return.

2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

 

The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

 

All Deferred Marked-to-Market Losses recorded as of December 31, 2016 relate to forward purchases of energy scheduled for delivery through December 2020.

 

Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.

 

The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.

 

Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project.

 

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of December 31, 2016.

 

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Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 189 months.

 

Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota currently being recovered over a 24-month period beginning with the establishment of interim rates in April 2016.

 

The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes.

 

Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project.

 

The North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of December 31, 2016.

 

MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.

 

The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to South Dakota customers as of December 31, 2016.

 

The North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that have not been billed to North Dakota customers as of December 31, 2016.

 

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP’s request to set the rider rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered over an 18-month period beginning with the establishment of interim rates in April 2016.

 

The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.

 

The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of December 31, 2016.

 

Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund over a 24-month period beginning with the establishment of interim rates in April 2016.

 

The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of December 31, 2016.

 

The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of December 31, 2016.

 

The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of December 31, 2016.

 

If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of guidance under ASC 980 ceases.

 

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5. Open Contract Positions Subject to Legally Enforceable Netting Arrangements

 

OTP has certain derivative contracts that are designated as normal purchases and carried at historical cost in the accompanying balance sheet. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The following table shows the current fair value of these forward contract positions subject to legally enforceable netting arrangements as of December 31:

 

(in thousands)  2016   2015 
Derivatives in Gain Positions Subject to Legally Enforceable Netting Arrangements  $—   $— 
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements   (17,382)   (16,070)
 Net Balance Subject to Legally Enforceable Netting Arrangements  $(17,382)  $(16,070)

 

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of December 31:

 

(in thousands)  2016   2015 
Loss Contracts Covered by Deposited Funds or Letters of Credit  $—   $199 
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1   17,382    15,871 
Total Loss Contracts based on Current Market Values  $17,382   $16,070 
1Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.          
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade  $17,382   $15,871 
Offsetting Gains with Counterparties under Master Netting Agreements   —    — 
Reporting Date Deposit Requirement if Credit Risk Feature Triggered  $17,382   $15,871 

 

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6. Common Shares and Earnings per Share

 

Shelf Registration

The Company’s shelf registration statement filed with the Securities and Exchange Commission on May 11, 2015, under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on May 11, 2018.

 

Common Share Distribution Agreement

On May 11, 2015, the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it may offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of $75 million.

 

Under the Distribution Agreement, the Company will designate the minimum price and maximum number of shares to be sold through JPMS on any given trading day or over a specified period of trading days, and JPMS will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. Sales of the shares, if any, will be made by means of ordinary brokers’ transactions on the NASDAQ Global Select Market at market prices or as otherwise agreed with JPMS. The Company may also agree to sell shares to JPMS, as principal for its own account, on terms agreed by the Company and JPMS in a separate agreement at the time of sale. The Company is not obligated to sell and JPMS is not obligated to buy or sell any of the shares under the Distribution Agreement. The shares, if issued, will be issued pursuant to the Company’s existing shelf registration statement.

 

2016 Common Stock Activity

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2015 through December 31, 2016:

 

Common Shares Outstanding, December 31, 2015   37,857,186 
Issuances:     
At-the-Market Offering   1,014,115 
Automatic Dividend Reinvestment and Share Purchase Plan:     
Dividends Reinvested   163,010 
Cash Invested   115,801 
Vesting of Executive Stock Performance Awards   54,700 
Employee Stock Purchase Plan:     
Cash Invested   53,875 
Dividends Reinvested   23,713 
Employee Stock Ownership Plan   23,837 
Restricted Stock Issued to Directors   23,200 
Vesting of Restricted Stock Units   21,825 
Directors Deferred Compensation   542 
Retirements:     
Shares Withheld for Individual Income Tax Requirements   (3,668)
Common Shares Outstanding, December 31, 2016   39,348,136 

 

2014 Stock Incentive Plan

The 2014 Stock Incentive Plan (2014 Incentive Plan), which was approved by the Company’s shareholders in April 2014, provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, and other stock and stock-based awards. A total of 1,900,000 common shares were authorized for granting stock awards under the 2014 Incentive Plan, of which 1,356,811 were available for issuance as of December 31, 2016. The 2014 Incentive Plan terminates on December 13, 2023.

 

Employee Stock Purchase Plan

The 1999 Employee Stock Purchase Plan (Purchase Plan) allows eligible employees to purchase the Company’s common shares at 85% of the market price at the end of each six-month purchase period. For purchase periods beginning after January 1, 2017, the purchase price will be 100% of the market price at the end of each six-month purchase period. On April 16, 2012, the Company’s shareholders approved an amendment to the Purchase Plan, increasing the number of shares available under the Purchase Plan from 900,000 common shares to 1,400,000 common shares and making certain other changes to the terms of the Purchase Plan. Of the 1,400,000 common shares authorized to be issued under the Purchase Plan, 384,159 were available for purchase as of December 31, 2016. At the discretion of the Company, shares purchased under the Purchase Plan can be either new issue shares or shares purchased in the open market. To provide shares for purchases for the Purchase Plan, 53,875 common shares were issued in 2016, 42,253 common shares were issued in 2015 and 39,222 common shares were

 

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issued in 2014. The shares to be purchased by employees participating in the Purchase Plan were not material to the calculation of diluted earnings per share during the investment period.

 

Dividend Reinvestment and Share Purchase Plan

The Company’s shelf registration statement filed with the SEC on May 11, 2015, as amended on October 13, 2015, provides for the issuance of up to 1,500,000 common shares under the Company's Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. New common shares issued under the Plan totaled 278,811 in 2016 and 302,519 in 2015, leaving 918,670 common shares available for issuance under the Plan as of December 31, 2016.

 

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income with no adjustments in 2016, 2015 and 2014. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation:

 

   2016   2015   2014 
Weighted Average Common Shares Outstanding – Basic   38,546,459    37,494,986    36,514,397 
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:               
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance   118,644    100,194    135,480 
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees   45,712    36,180    27,540 
Nonvested Restricted Shares   16,778    22,848    49,998 
Shares Expected to be Issued Under the Deferred Compensation Program for Directors   3,417    13,488    24,048 
Potentially Dilutive Stock Options   —    330    1,096 
Total Dilutive Shares   184,551    173,040    238,162 
Weighted Average Common Shares Outstanding – Diluted   38,731,010    37,668,026    36,752,559 

 

The effect of dilutive shares on earnings per share for the years ended December 31, 2016, 2015 and 2014, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in any period.

 

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7. Share-Based Payments

 

Purchase Plan

Through December 31, 2016, the Purchase Plan allowed employees through payroll withholding to purchase shares of the Company’s common stock at a 15% discount from the average market price on the last day of a six month investment period. Under ASC Topic 718, Compensation—Stock Compensation (ASC 718), the Company is required to record compensation expense related to the 15% discount. The 15% discount resulted in compensation expense of $173,000 in 2016, $184,000 in 2015 and $175,000 in 2014. For purchase periods beginning after January 1, 2017, the purchase price will be 100% of the market price at the end of each six-month purchase period.

 

Stock Options Granted Under the 1999 Incentive Plan

The Company granted 2,041,500 options for the purchase of the Company’s common stock under the 1999 Stock Incentive Plan (1999 Incentive Plan). The exercise price of the options granted was the average market price of the Company’s common stock on the grant date. Under ASC 718 accounting requirements, compensation expense is recorded based on the estimated fair value of the options on their grant date using a fair-value option pricing model. Under ASC 718 accounting requirements, the fair value of the options granted has been recorded as compensation expense over the requisite service period (the vesting period of the options). The estimated fair value of all options granted under the 1999 Incentive Plan was based on the Black-Scholes option pricing model. There were no options outstanding as of December 31, 2016 or December 31, 2015.

 

Presented below is a summary of the stock options activity:

 

Stock Option Activity  2016   2015   2014 
   Options   Average
Exercise
Price		   Options   Average
Exercise
Price		   Options   Average
Exercise
Price		 
Outstanding, Beginning of Year   —         12,750   $24.93    34,700   $25.69 
Exercised   —         10,250    24.93    20,800    26.11 
Forfeited or Expired   —         2,500    24.93    1,150    26.495 
Outstanding, End of Year   —         —         12,750    24.93 
Exercisable, End of Year   —         —         12,750    24.93 
Cash Received for Options Exercised                 $256,000        $543,000 
Intrinsic Value of Options Exercised                 $75,000        $89,000 

 

Restricted Stock Granted to Directors

Under the 1999 Incentive Plan and the 2014 Incentive Plan, restricted shares of the Company’s common stock have been granted to members of the Company’s board of directors as a form of compensation. Under ASC 718 accounting requirements, compensation expense related to restricted shares is based on the fair value of the restricted shares on their grant dates. On April 11, 2016, 23,200 shares of restricted stock were granted to the Company’s nonemployee directors. The grant-date fair value of each share of restricted stock granted on April 11, 2016 was $28.66 per share, the average of the high and low market price on the date of grant. The restricted shares granted in 2016 vest 25% per year on April 8 of each year in the period 2017 through 2020 and are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreement.

 

Presented below is a summary of the status of directors’ restricted stock awards for the years ended December 31:

 

Directors’ Restricted Stock Awards  2016   2015   2014 
   Shares   Weighted
Average
Grant-Date
Fair Value		   Shares   Weighted
Average
Grant-Date
Fair Value		   Shares   Weighted
Average
Grant-Date
Fair Value		 
Nonvested, Beginning of Year   38,217   $29.78    38,050   $27.47    42,483   $25.03 
Granted   23,200    28.66    15,200    31.775    16,800    29.41 
Vested   15,083    28.28    15,033    25.96    21,233    24.11 
Forfeited   —         —         —      
Nonvested, End of Year   46,334    29.71    38,217    29.78    38,050    27.47 
Compensation Expense Recognized       $491,000        $417,000        $416,000 
Fair Value of Shares Vested in Year       $427,000        $390,000        $512,000 

 

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Restricted Stock Granted to Employees

Under the 1999 Incentive Plan and 2014 Incentive Plan, restricted shares of the Company’s common stock have been granted to employees as a form of compensation. Under ASC 718 accounting requirements, compensation expense related to restricted shares is based on the fair value of the restricted shares on their grant dates. No shares of restricted stock were granted to employees in 2016 or 2015.

 

Presented below is a summary of the status of employees’ restricted stock awards for the years ended December 31:

 

Employees’ Restricted Stock Awards  2016   2015   2014 
   Shares   Weighted
Average
Grant-Date
Fair Value		   Shares   Weighted
Average
Grant-Date
Fair Value		   Shares   Weighted
Average
Grant-Date
Fair Value		 
Nonvested, Beginning of Year   13,581   $28.56    45,280   $27.46    48,315   $25.04 
Granted   —         —         26,700    29.41 
Vested   6,401    27.25    31,699    27.09    25,360    24.80 
Forfeited   —         —         4,375    28.03 
Nonvested, End of Year   7,180    29.72    13,581    28.56    45,280    27.46 
Compensation Expense Recognized       $96,000        $359,000        $998,000 
Fair Value of Awards Vested       $174,000        $859,000        $629,000 

 

Restricted Stock Units Granted to Executive Officers

On February 4, 2016, 22,000 restricted stock units under the 2014 Incentive Plan were granted to the Company’s executive officers. The grant-date fair value of each restricted stock unit was $28.915 per share, the average of the high and low market price on the date of grant. The restricted stock units granted to executive officers in 2016 vest 25% per year on February 6 of each year in the period 2017 through 2020 and are eligible to receive dividend equivalent payments on all unvested awards over the awards’ respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases.

 

Presented below is a summary of the status of restricted stock unit awards granted to executive officers for the years ended December 31:

 

Executives’ Restricted Stock Unit Awards  2016   2015 
   Restricted
Stock
Units		   Weighted
Average
Grant-Date
Fair Value		   Restricted
Stock
Units		   Weighted
Average
Grant-Date
Fair Value		 
Nonvested, Beginning of Year   24,300   $31.682    —      
Granted   22,000    28.915    29,100   $31.681 
Vested   4,475    31.69    4,800    31.675 
Forfeited   —         —     
Nonvested, End of Year   41,825    30.23    24,300    31.682 
Compensation Expense Recognized       $446,000        $452,000 
Fair Value of Awards Vested       $142,000        $152,000 

 

Restricted Stock Units Granted to Employees

In 2016 the following restricted stock unit awards under the 2014 Incentive Plan were granted to key employees of the Company who are not executive officers:

 

   Grant Date  Units
Granted		   Grant-Date
Fair Value
per Award		 
Restricted Stock Units Vesting 100% on April 8, 2020  April 11, 2016   15,800   $24.00 
Restricted Stock Units Vesting 100% on April 8, 2020  September 21, 2016   1,420   $30.59 

 

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The grant-date fair value of each restricted stock unit was based on the average of the high and low market price of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion over the four-year vesting period. Under the terms of the restricted stock unit award agreements, all outstanding (unvested) restricted stock units held by a retiring grantee vest immediately on normal retirement.

 

Presented below is a summary of the status of employees’ restricted stock unit awards for the years ended December 31:

 

Employees’ Restricted Stock Unit Awards  2016   2015   2014 
   Restricted
Stock
Units		   Weighted
Average
Grant-Date
Fair Value		   Restricted
Stock
Units		   Weighted
Average
Grant-Date
Fair Value		   Restricted
Stock
Units		   Weighted
Average
Grant-Date
Fair Value		 
Nonvested, Beginning of Year   46,600   $23.75    45,900   $21.82    56,180   $19.79 
Granted   17,220    24.54    15,650    25.89    11,800    24.95 
Reinstated   —         —         75    30.81 
Vested   12,250    19.03    12,250    19.46    14,305    18.05 
Forfeited   4,200    24.51    2,700    22.84    7,850    18.90 
Nonvested, End of Year   47,370    25.19    46,600    23.75    45,900    21.82 
Compensation Expense Recognized       $307,000        $304,000        $194,000 
Fair Value of Awards Vested       $233,000        $238,000        $258,000 

 

Stock Performance Awards granted to Executive Officers

Stock performance award agreements have been granted under the 1999 Incentive Plan and the 2014 Incentive Plan for the Company’s executive officers. Under these agreements, the officers could be awarded shares of the Company’s common stock based on the Company’s total shareholder return relative to that of its peer group of companies in the Edison Electric Institute (EEI) Index over a three-year period beginning on January 1 of the year the awards are granted. Awards granted in 2016 and 2015 also included a performance incentive based on the Company’s average 3-year adjusted return on equity relative to a targeted average 3-year adjusted return on equity. The number of shares earned, if any, will be awarded and issued at the end of each three-year performance measurement period. The participants have no voting or dividend rights under these award agreements until the shares are issued at the end of the performance measurement period.

 

On February 4, 2016 performance share awards were granted to the Company’s executive officers under the 2014 Incentive Plan for the 2016-2018 performance measurement period. Under the 2016 performance share award agreements the aggregate award for performance at target is 81,500 shares. For target performance the Company’s executive officers would earn an aggregate of 54,333 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2016 through December 31, 2018. The Company’s executive officers would also earn an aggregate of 27,167 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 122,250 common shares.

 

Under the 2016 performance award agreements, payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to executive employment agreements with the Company is to be made at the target amount at the date of any such event. The vesting of these performance award agreements is accelerated and paid at target in the event of a change in control, disability or death (and upon retirement at or after age 62 for certain officers who are parties to executive employment agreements with the Company).

 

Through December 31, 2015, the income tax withholding terms applicable to outstanding performance awards dictated that the awards be classified and accounted for as liability awards, in accordance with the requirements of ASC 718, with compensation measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date. In the fourth quarter of 2016, the Company elected to early adopt the updates in ASU 2016-09, resulting in the outstanding 2015 and 2016 performance awards being now classified as equity awards. See note 1 for additional information on the impact of the adoption of ASU 2016-09.

 

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The table below provides a summary of stock performance awards granted and amounts expensed related to the stock performance awards:

 

Performance
Period		  Maximum
Shares Subject
 To Award		   Target
Shares		   Expense Recognized
in the Year Ended December 31,1		   Earned
Shares		 
           2016   2015   2014     
2016-2018   122,250    81,500   $798,000                
2015-2017   126,450    84,300    535,000   $943,000           
2014-2016   159,450    106,300    332,000    (64,000)  $1,422,000    121,491 
2013-2015   90,600    45,300    —    (445,000)   458,000    22,500 
2012-2014   148,400    74,200    —    —    142,000    89,991 
Total            $1,665,000   $434,000   $2,022,000    233,982 

1Expenses prior to 2016 are not restated to reflect what would have been expensed had the performance-to-date value of the outstanding awards been based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards.

 

Stock-based payment expense recognized in 2016 and 2015 for the 2016-2018 and 2015-2017 performance awards reflects the accelerated recognition of expense for outstanding and unvested awards of executives who are eligible for retirement and whose awards vest on normal retirement, as defined in the performance award agreements, prior to the vesting dates of the awards.

 

The earned shares shown in the table above for the 2014-2016 performance period include shares received in 2017 by participants in the plan, based on the Company achieving a total shareholder return ranking of 19 out of 43 companies in the EEI Index and a resulting payout at 114.29% of target. The earned shares also include shares for a portion of the award that vested on normal retirement of the Company’s former CEO on July 1, 2015 that were issued in 2016 following the 180 day deferral period required under the Internal Revenue Code at a value of $26.35 per share or $848,000.

 

The earned shares shown in the table above for the 2013-2015 performance period reflect shares that vested on normal retirement of the Company’s former CEO on July 1, 2015 that were issued in 2016 following the 180 day deferral period required under the Internal Revenue Code at a value of $26.35 per share or $593,000.

 

The earned shares shown in the table above for the 2012-2014 performance period reflect shares received in 2015 by active participants in the plan on December 31, 2014, based on the Company achieving a total shareholder return ranking of 21 out of 48 companies in the EEI Index and a resulting payout at 121.28% of target.

 

In connection with the resignation of executive officers in May 2014 and March 2012, the following unvested stock performance awards were forfeited: 8,900 granted in 2014, 4,900 granted in 2013, and 6,600 granted in 2012.

 

As of December 31, 2016 the total remaining unrecognized amount of compensation expense related to stock-based compensation for all of the Company’s stock-based payment programs was approximately $4.0 million (before income taxes), which will be amortized over a weighted average period of 2.2 years.

 

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8. Retained Earnings and Dividend Restriction

 

The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

 

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of December 31, 2016 the Company was in compliance with these financial covenants. See note 10 to consolidated financial statements for further information on the covenants.

 

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.

 

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.5% and 58.1% based on OTP’s 2016 capital structure petition approved by order of the MPUC on August 2, 2016. As of December 31, 2016 OTP’s equity-to-total-capitalization ratio including short-term debt was 52.9% and its net assets restricted from distribution totaled approximately $440,000,000. Total capitalization for OTP cannot currently exceed $1,123,168,000.

 

9. Commitments and Contingencies of Continuing Operations

 

Construction and Other Purchase Commitments

At December 31, 2016 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $84.8 million.

 

Electric Utility Capacity and Energy Requirements and Coal Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2040. OTP has commitments under contracts providing for the purchase of a significant portion of its current coal requirements. Current coal purchase agreements for Big Stone Plant and Coyote Station expire in 2017 and 2040, respectively. In January 2016, OTP entered into an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant for the period of January 1, 2016 through December 31, 2023. OTP has no fixed minimum purchase requirements under the agreement but all of Hoot Lake Plant’s coal requirements for the period covered must be purchased under this agreement. The dollar amounts of OTP’s estimated purchase requirements under this agreement are excluded from the table below because OTP has not committed to any minimum level of purchases under the agreement. Fuel clause adjustment mechanisms lessen the risk of loss from market price changes because they provide for recovery of most fuel costs. See table below for schedule of commitments.

 

Operating Leases

OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. Rent expense from continuing operations was $7,565,000, $6,447,000 and $10,165,000 for 2016, 2015 and 2014, respectively.

 

The amounts of the Company’s construction program and other commitments and commitments under capacity and energy agreements, coal and coal delivery contracts and operating leases for continuing operations as of December 31, 2016, are as follows:

 

   Construction
Program and Other		   Capacity and
Energy		   Coal
Purchase		   Operating Leases 
(in thousands)  Commitments   Requirements   Commitments   OTP   Nonelectric   Total 
2017  $74,328   $23,711   $30,699   $2,374   $4,760   $7,134 
2018   7,139    24,356    21,563    1,513    4,129    5,642 
2019   3,331    24,925    22,102    1,237    2,598    3,835 
2020   —    24,844    22,331    1,251    2,259    3,510 
2021   —    12,988    22,840    1,103    1,996    3,099 
Beyond 2021   —    166,137    550,719    9,396    7,320    16,716 
Total  $84,798   $276,961   $670,254   $16,874   $23,062   $39,936 

 

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Contingencies

Based on the reduction by the FERC in the ROE component of the MISO Tariff, OTP has a $2.7 million liability on its balance sheet as of December 31, 2016 representing OTP’s best estimate of its current refund obligation related to amounts collected under the MISO Tariff, net of amounts that would be subject to recovery under state jurisdictional TCR riders.

 

Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders and the FERC’s decision to resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. These consolidated cases are currently held in abeyance while the parties engage in mediation before the D.C. Circuit. OTP is an intervenor in these cases and a participant in mediation. The scope of the issues that will be subject to appeal at the D.C. Circuit have not yet been finalized. In addition, MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders. Although the Company cannot estimate OTP’s exposure at this time, a final order reversing the relevant FERC orders could have a material adverse effect on the Company’s results of operations.

 

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $1.0 million, excluding any liability for RSG charges for which an estimate cannot be made at this time.

 

In 2014 the Environmental Protection Agency (EPA) published proposed standards of performance for carbon dioxide (CO2) emissions from new fossil fuel-fired power plants, proposed CO2 emission guidelines for existing fossil fuel-fired power plants and proposed CO2 standards of performance for CO2 emissions from reconstructed and modified fossil fuel-fired power plants under section 111 of the Clean Air Act. The EPA published final rules for each of these proposals on October 23, 2015. All of these rules have been challenged on legal grounds and are currently pending before the D.C. Circuit. On February 9, 2016 the U.S. Supreme Court granted a stay of the CO2 emission guidelines for existing fossil fuel-fired power plants, pending disposition of petitions for review in the D.C. Circuit and, if a petition for a writ of certiorari seeking review by the U.S. Supreme Court were granted, any final Supreme Court determination. The D.C. Circuit heard oral argument on challenges to the CO2 emission guidelines on September 27, 2016 before the full court, and a decision will likely be rendered in the first half of 2017. In addition, members of Congress and the new administration have been very critical of the Clean Power Plan (CPP) and may take actions that could impact the rule or the litigation. Therefore, while the CPP remains stayed, there is uncertainty regarding the future of the rule. The final outcome of this rulemaking process could have an adverse impact on the Company’s business and results of operations.

 

Other

The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of December 31, 2016 will not be material.

 

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10. Short-Term and Long-Term Borrowings

 

Short-Term Debt

 

The following table presents the status of the Company’s lines of credit as of December 31, 2016 and December 31, 2015:

 

(in thousands)  Line Limit   In Use on
December 31,
2016		   Restricted due to
Outstanding
Letters of Credit		   Available on
December 31,
2016		   Available on
December 31,
2015		 
Otter Tail Corporation Credit Agreement  $130,000   $—   $—   $130,000   $90,334 
OTP Credit Agreement   170,000    42,883    50    127,067    148,694 
Total  $300,000   $42,883   $50   $257,067   $239,028 

 

Under the Otter Tail Corporation Credit Agreement (as defined below), the maximum amount of debt outstanding in 2016 was $63,757,000 on January 4, 2016 and the average daily balance of debt outstanding during 2016 was $16,200,000. The weighted average interest rate paid on debt outstanding under the Otter Tail Corporation Credit Agreement during 2016 was 2.3% compared with 2.0% in 2015. Under the OTP Credit Agreement (as defined below), the maximum amount of debt outstanding in 2016 was $51,885,000 on December 16, 2016 and the average daily balance of debt outstanding during 2016 was $32,576,000. The weighted average interest rate paid on debt outstanding under the OTP Credit Agreement during 2016 was 1.8% compared with 1.5% in 2015. The maximum amount of consolidated short-term debt outstanding in 2016 was $87,211,000 on January 25, 2016 and the average daily balance of consolidated short-term debt outstanding during 2016 was $48,776,000. The weighted average interest rate on consolidated short-term debt outstanding on December 31, 2016 was 1.9%.

 

On October 29, 2012 the Company entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $130 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On October 31, 2016 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021 and the unsecured revolving credit facility was reduced from $150 million to $130 million. The Company can draw on this credit facility to refinance certain indebtedness and support its operations and the operations of its subsidiaries. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 1.75%, subject to adjustment based on the Company’s senior unsecured credit ratings. The Company is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The Otter Tail Corporation Credit Agreement contains a number of restrictions on the Company and the businesses of its wholly owned subsidiary, Varistar Corporation (Varistar) and its subsidiaries, including restrictions on the Company’s and Varistar’s ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s credit ratings. The Company’s obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of the Company’s subsidiaries. Outstanding letters of credit issued by the Company under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million.

 

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 31, 2016 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

 

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Long-Term Debt Issuances and Retirements

 

2016 Note Purchase Agreement

On September 23, 2016 the Company entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which the Company agreed to issue to the purchasers, in a private placement transaction, $80 million aggregate principal amount of our 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes). The 2026 Notes were issued on December 13, 2016. The Company’s obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by its Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). The proceeds from the issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our 9.000% Senior Notes due December 15, 2016, and to pay down a portion of the $50 million in funds borrowed in February 2016 under the Company’s term loan agreement.

 

The Company may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. The Company is required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if the Company and its Material Subsidiaries sell a “substantial part” of its or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes.

 

The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and the Material Subsidiaries that became effective on execution of the 2016 Note Purchase Agreement. These include restrictions on the Company’s and the Material Subsidiaries’ abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or pay dividends on the Company’s and the Material Subsidiaries’ shares of capital stock, and make investments. The 2016 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2016 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s or the Material Subsidiaries’ credit ratings.

 

Term Loan Agreement

On February 5, 2016 the Company entered into a Term Loan Agreement (the Term Loan Agreement) with the Banks named therein, JPMorgan Chase Bank, N.A., as administrative agent, and JPMS, as Lead Arranger and Book Runner. The Term Loan Agreement provides for an unsecured term loan with an aggregate commitment of $50 million that the Company may use for purposes of funding working capital, capital expenditures and other corporate purposes of the Company and certain of our subsidiaries. Under the Term Loan Agreement, the Company may, on up to two occasions, enter into additional tranches of term loans in minimum increments of $10 million, subject to the consent of the lenders and so long as the aggregate amount of outstanding term loans does not exceed $100 million at any time. Borrowings under the Term Loan Agreement will bear interest at either (1) LIBOR plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve Bank of New York Rate plus 0.50% and (c) LIBOR multiplied by the Statutory Reserve Rate plus 1%. The applicable interest rate will depend on the Company’s election of whether to make the advance a LIBOR advance. The Term Loan Agreement terminates on February 5, 2018.

 

On February 5, 2016 the Company borrowed $50 million under the Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points and used the proceeds to pay down borrowings under the Otter Tail Corporation Credit Agreement that were used to fund the expansion of BTD’s Minnesota facilities in 2015 and to fund the September 1, 2015 acquisition of BTD-Georgia.

 

The Term Loan Agreement contains a number of restrictions on the Company, Varistar and certain subsidiaries of Varistar, including restrictions on its and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The Term Loan Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The Term Loan Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s credit ratings. The Company’s obligations under the Term Loan Agreement are guaranteed by Varistar and certain of its subsidiaries.

 

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2013 Note Purchase Agreement

On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) pursuant to which OTP has agreed to issue to the purchasers named therein, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). The Notes were issued on February 27, 2014. OTP used a portion of the proceeds of the Notes to retire early a $40.9 million term loan then outstanding and to repay OTP’s short-term debt outstanding on February 27, 2014. The remaining proceeds of the Notes were used to pay fees and expenses related to the issuance of the Notes and for other general purposes, including construction program expenditures.

 

The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states OTP must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP.

 

The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement, provided that no default or event of default has occurred and is continuing.

 

2007 and 2011 Note Purchase Agreements

On December 1, 2011, OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011 (the 2011 Note Purchase Agreement). OTP also has outstanding its $155 million senior unsecured notes issued in four series consisting of $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, due 2017; $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement).

 

The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.”

 

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Shelf Registration

On May 11, 2015 the Company filed a shelf registration statement with the SEC under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 11, 2018.

 

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of December 31, 2016 and December 31, 2015:

 

December 31, 2016 (in thousands)  OTP   Otter Tail
Corporation		   Otter Tail
Corporation
Consolidated		 
Short-Term Debt  $42,883   $—   $42,883 
Long-Term Debt:               
Term Loan, LIBOR plus 0.90%, due February 5, 2018       $15,000   $15,000 
3.55% Guaranteed Senior Notes, due December 15, 2026        80,000    80,000 
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017  $33,000         33,000 
Senior Unsecured Notes 4.63%, due December 1, 2021   140,000         140,000 
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022   30,000         30,000 
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027   42,000         42,000 
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029   60,000         60,000 
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037   50,000         50,000 
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044   90,000         90,000 
North Dakota Development Note, 3.95%, due April 1, 2018        106    106 
PACE Note, 2.54%, due March 18, 2021        836    836 
Total  $445,000   $95,942   $540,942 
Less:   Current Maturities net of Unamortized Debt Issuance Costs   32,970    231    33,201 
Unamortized Long-Term Debt Issuance Costs   1,861    539    2,400 
Total Long-Term Debt net of Unamortized Debt Issuance Costs  $410,169   $95,172   $505,341 
Total Short-Term and Long-Term Debt (with current maturities)  $486,022   $95,403   $581,425 

 

December 31, 2015 (in thousands)  OTP  Otter Tail
Corporation		  Otter Tail
Corporation
Consolidated
Short-Term Debt  $21,006   $59,666   $80,672 
Long-Term Debt:               
9.000% Notes, due December 15, 2016       $52,330   $52,330 
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017  $33,000         33,000 
Senior Unsecured Notes 4.63%, due December 1, 2021   140,000         140,000 
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022   30,000         30,000 
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027   42,000         42,000 
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029   60,000         60,000 
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037   50,000         50,000 
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044   90,000         90,000 
North Dakota Development Note, 3.95%, due April 1, 2018        182    182 
PACE Note, 2.54%, due March 18, 2021        977    977 
Total  $445,000   $53,489   $498,489 
Less:   Current Maturities net of Unamortized Debt Issuance Costs        52,422    52,422 
 Unamortized Long-Term Debt Issuance Costs   2,099    122    2,221 
Total Long-Term Debt net of Unamortized Debt Issuance Costs  $442,901   $945   $443,846 
Total Short-Term and Long-Term Debt (with current maturities)  $463,907   $113,033   $576,940 

 

The aggregate amounts of maturities on bonds outstanding and other long-term obligations at December 31, 2016 for each of the next five years are:

 

(in thousands)  2017   2018   2019   2020   2021 
Aggregate Amounts of Debt Maturities  $33,231   $15,187   $172   $185   $140,171 

 

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Financial Covenants

The Company and OTP were in compliance with the financial covenants in these debt agreements as of December 31, 2016.

 

No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

 

The Company’s and OTP’s borrowing agreements are subject to certain financial covenants. Specifically:

 

·Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, the Company may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis) as provided in the agreements.
   
·Under the 2016 Note Purchase Agreement, the Company may not permit its Priority Indebtedness to exceed 10% of its Total Capitalization. The Company had no Priority Indebtedness outstanding as of December 31, 2016.
   
·Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.
   
·Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement.
   
·Under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement. OTP had no Priority Indebtedness outstanding as of December 31, 2016.

 

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11. Pension Plan and Other Postretirement Benefits

 

For valuation of the Company’s pension and other postretirement benefit plans’ projected benefit obligations as of December 31, 2016, the Company adopted updated and modified mortality tables and an updated and modified mortality improvement scale that projects lower mortality improvements in the future for plan participants. The adoption of the updated and modified mortality tables and mortality improvement scale in 2016 decreased the Company’s pension and other postretirement benefit obligations from projected benefit obligations that would have been rendered using the mortality tables the Company had been using since 2014. Although the adoption of the updated and modified tables and improvement scale will have the effect of decreasing the estimated and recognized cost of future benefit payments in the near term, the ultimate cost recognized will be determined by the actual level and duration of future benefit payments.

 

Pension Plan

The Company's noncontributory funded pension plan covers substantially all corporate employees and OTP nonunion employees hired prior to September 1, 2006, and all union employees of OTP hired prior to November 1, 2013, excluding Coyote Station employees. Coyote Station employees hired before January 1, 2009 are covered under the plan. The plan provides 100% vesting after five vesting years of service and for retirement compensation at age 65, with reduced compensation in cases of retirement prior to age 62. The Company reserves the right to discontinue the plan but no change or discontinuance may affect the pensions theretofore vested.

 

The pension plan has a trustee who is responsible for pension payments to retirees and a separate pension fund manager responsible for managing the plan's assets. An independent actuary assists the Company in performing the necessary actuarial valuations for the plan.

 

The plan assets consist of common stock and bonds of public companies, U.S. government securities, cash and cash equivalents and alternative investments. None of the plan assets are invested in common stock or debt securities of the Company.

 

The following table lists components of net periodic pension benefit cost for the year ended December 31:

 

(in thousands)  2016   2015   2014 
Service Cost–Benefit Earned During the Period  $5,518   $6,059   $4,666 
Interest Cost on Projected Benefit Obligation   14,195    13,344    13,111 
Expected Return on Assets   (19,454)   (18,383)   (16,743)
Amortization of Prior Service Cost:               
From Regulatory Asset   189    188    257 
From Other Comprehensive Income1   5    5    7 
Amortization of Net Actuarial Loss:               
From Regulatory Asset   5,153    6,676    3,400 
From Other Comprehensive Income1   127    171    83 
Net Periodic Pension Cost  $5,733   $8,060   $4,781 
1Corporate cost included in Other Nonelectric Expenses.               

 

Weighted average assumptions used to determine net periodic pension cost for the year ended December 31:

 

   2016   2015   2014 
Discount Rate   4.76%   4.35%   5.30%
Long-Term Rate of Return on Plan Assets   7.75%   7.75%   7.75%
Rate of Increase in Future Compensation Level   3.13%   3.13%   3.13%

 

The following table presents amounts recognized in the consolidated balance sheets as of December 31:

 

(in thousands)  2016   2015 
Regulatory Assets:          
Unrecognized Prior Service Cost  $141   $329 
Unrecognized Actuarial Loss   98,039    101,974 
Total Regulatory Assets  $98,180   $102,303 
Accumulated Other Comprehensive Loss:          
Unrecognized Prior Service Cost  $12   $16 
Unrecognized Actuarial Loss   406    820 
Total Accumulated Other Comprehensive Loss  $418   $836 
Noncurrent Liability  $60,292   $69,101 

 

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Funded status as of December 31:

 

(in thousands)  2016   2015 
Accumulated Benefit Obligation  $(281,414)  $(268,387)
Projected Benefit Obligation  $(314,637)  $(302,740)
Fair Value of Plan Assets   254,345    233,639 
  Funded Status  $(60,292)  $(69,101)

 

The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s benefit obligations over the two-year period ended December 31, 2016:

 

(in thousands)  2016   2015 
Reconciliation of Fair Value of Plan Assets:          
Fair Value of Plan Assets at January 1  $233,639   $244,589 
Actual Return on Plan Assets   23,794    (9,160)
Discretionary Company Contributions   10,000    10,000 
Benefit Payments   (13,088)   (11,790)
Fair Value of Plan Assets at December 31  $254,345   $233,639 
Estimated Asset Return   10.1%   (3.7)%
Reconciliation of Projected Benefit Obligation:          
Projected Benefit Obligation at January 1  $302,740   $311,650 
Service Cost   5,518    6,059 
Interest Cost   14,195    13,344 
Benefit Payments   (13,088)   (11,790)
Actuarial Loss (Gain)   5,272    (16,523)
Projected Benefit Obligation at December 31  $314,637   $302,740 

 

Weighted average assumptions used to determine benefit obligations at December 31:

 

   2016   2015 
Discount Rate   4.60%   4.76%
Rate of Increase in Future Compensation Level   3.00%   3.13%

 

The assumed rate of return on pension fund assets used for the determination of 2017 net periodic pension cost is 7.50%. The assumed long-term rate of return on plan assets is based primarily on asset category studies using historical market return and volatility data with forward looking estimates based on existing financial market conditions and forecasts of capital markets. Modest excess return expectations versus some market indices are incorporated into the return projections based on the actively managed structure of the investment programs and their records of achieving such returns historically. The Company reviews its rate of return on plan asset assumptions annually. The assumptions are largely based on the asset category rate-of-return assumptions developed annually with the Company’s pension plan investment advisors, as well as input from actuaries who work with the pension plan.

 

Market-related value of plan assets—The Company’s expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets.

 

The Company bases actuarial determination of pension plan expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a five-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

 

Measurement Dates: 2016 2015
Net Periodic Pension Cost January 1, 2016 January 1, 2015
End of Year Benefit Obligations January 1, 2016 projected to
December 31, 2016		 January 1, 2015 projected to
December 31, 2015
Market Value of Assets December 31, 2016 December 31, 2015

 

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The estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic pension cost in 2017 are:

 

(in thousands)  2017 
Decrease in Regulatory Assets:     
Amortization of Unrecognized Prior Service Cost  $120 
Amortization of Unrecognized Actuarial Loss   5,090 
Decrease in Accumulated Other Comprehensive Loss:     
Amortization of Unrecognized Prior Service Cost   3 
Amortization of Unrecognized Actuarial Loss   125 
Total Estimated Amortization  $5,338 

 

Cash flows—The Company had no minimum funding requirement as of December 31, 2016 and will continue to evaluate if discretionary plan contributions will be made in 2017.

 

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid out from plan assets:

 

(in thousands)  2017   2018   2019   2020   2021   Years
2022-2026		 
   $13,413   $14,140   $14,806   $15,564   $16,335   $92,083 

 

The following objectives guide the investment strategy of the Company’s pension plan (the Plan):

 

·The assets of the Plan will be invested in accordance with all applicable laws in a manner consistent with fiduciary standards including Employee Retirement Income Security Act standards (if applicable). Specifically:
oThe safeguards and diversity that a prudent investor would adhere to must be present in the investment program.
oAll transactions undertaken on behalf of the Plan must be in the best interest of plan participants and their beneficiaries.
·The primary objective of the Plan is to provide a source of retirement income for its participants and beneficiaries.
·The near-term primary financial objective of the Plan is to improve the funded status of the Plan.
·A secondary financial objective is to minimize pension funding and expense volatility where possible.

 

The asset allocation strategy developed by the Company’s Retirement Plans Administration Committee (the Committee) is based on the current needs of the Plan and the objectives listed above. An asset/liability review is conducted annually or as often as necessary to assess the impact of various asset allocations on funded status and other financial variables. The current needs of the Plan, the overall investment objectives above, the investment preferences and risk tolerance of the Committee and the desired degree of diversification suggest the need for an investment allocation including multiple asset classes.

 

The asset allocation in the table below contains guideline percentages, at market value, of the total Plan invested in various asset classes. The Permitted Range is a guide and will at times not reflect the actual asset allocation as this will be dictated by market conditions, the independent actions of the Committee and/or Investment Managers and required cash flows to and from the Plan. The Permitted Range anticipates this fluctuation and provides flexibility for the Investment Managers’ portfolios to vary around the target without the need for immediate rebalancing. The Investment Manager will proactively monitor the asset allocation and will direct the purchases and sales to remain within the stated ranges.

 

The policy of the Plan is to invest assets in accordance with the allocations shown below:

 

   Permitted Range
Asset Class / PBO Funded Status  < 100% PBO  100% PBO  105% PBO  >=110% PBO
Equity  30% - 65%  25% - 60%  20% - 55%  15% - 50%
Investment Grade Fixed Income  35% - 75%  40% - 80%  45% - 85%  50% - 90%
Below Investment Grade Fixed Income*    0% - 15%   0% - 15%   0% - 15%   0% - 15%
Other**    0% - 20%   0% - 20%   0% - 20%   0% - 20%
* Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds.
** Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund.

 

104

 

 

The Company’s pension plan asset allocations at December 31, 2016 and 2015, by asset category are as follows:

 

Asset Allocation  2016   2015 
Large Capitalization Equity Securities   21.4%   21.2%
International Equity Securities   22.0%   21.6%
Small and Mid-Capitalization Equity Securities   9.0%   8.1%
SEI Dynamic Asset Allocation Fund   5.4%   5.6%
Equity Securities   57.8%   56.5%
Fixed-Income Securities and Cash   34.3%   35.8%
Other – SEI Energy Debt Collective Fund   4.1%   3.6%
Other – SEI Special Situation Collective Investment Trust   3.8%   4.1%
    100.0%   100.0%

 

The following table presents the Company’s pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy and assets measured using the NAV practical expedient to fair valuation as of December 31:

 

(in thousands)  2016   2015 
Assets in Level 1 of the Fair Value Hierarchy  $234,303   $215,676 
SEI Energy Debt Collective Fund at NAV   10,441    8,342 
SEI Special Situation Collective Investment Trust Fund at NAV (1)   9,601    9,621 
Total Assets  $254,345   $233,639 

(1)On December 30, 2016 the Company instructed the pension fund manager to sell the pension fund investment in the SEI Special Situation Collective Investment Trust Fund. The cash value of the investment on settlement of the sale in January 2017 was $9,679,000.

 

Fair Value Measurements of Pension Fund Assets

ASC 715, Compensation – Retirement Benefits, requires disclosures about pension plan assets identified by the three levels of the fair value hierarchy established by ASC 820-10-35.

 

The following table presents, the Company’s pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy as of December 31:

 

(in thousands)  2016   2015 
Large Capitalization Equity Securities Mutual Fund  $54,483   $49,513 
International Equity Securities Mutual Funds   55,916    50,504 
Small and Mid-Capitalization Equity Securities Mutual Fund   23,011    18,823 
SEI Dynamic Asset Allocation Mutual Fund   13,622    13,004 
Fixed Income Securities Mutual Funds   87,268    83,830 
Cash Management – Money Market Fund   3    2 
Total Assets  $234,303   $215,676 

 

The investments held by the SEI Special Situation Collective Investment Trust on December 31, 2016 and 2015 consisted of investments primarily in hedge funds that pursue alternative strategies, private equity funds and hybrid funds, as well as investments directly in other securities and financial instruments, with the objective of achieving high returns balanced against an appropriate level of volatility and market exposure over a full market cycle. The NAV of the SEI Special Situations Collective Investment Trust is determined by using the fair value of the portfolio as of the close of business at the end of the year. The fair value of the fund is calculated independently by the fund’s administrator and is reviewed by the Company.

 

The investments held by the SEI Energy Debt Collective Fund on December 31, 2016 and 2015 consist mainly of below investment grade high yielding bonds and loans of U.S. energy companies which trade at a discount to fair value. Redemptions are allowed semi-annually with a 95-day notice period, subject to fund director consent and certain gate, holdback and suspension restrictions. Subscriptions are allowed monthly with a three-year lock up on subscriptions. The Company invested $10.0 million in the SEI Energy Debt Fund in July 2015. The fund’s assets are valued in accordance with valuations reported by the fund’s sub-advisor or the fund’s underlying investments or other independent third party sources, although SEI in its discretion may use other valuation methods, subject to compliance with ERISA (as applicable). The fund’s assets are valued as of the close of business on the last business day of each calendar month and are available 30 days after the end of a calendar quarter. On an annual basis, as determined by the investment manager in its sole discretion, an independent valuation agent is retained to provide a valuation of the illiquid assets of the fund and of any other asset of the fund, as determined by the investment manager in its sole discretion. The Company reviews and verifies the reasonableness of the year-end valuations.

 

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Executive Survivor and Supplemental Retirement Plan (ESSRP)

The ESSRP is an unfunded, nonqualified benefit plan for executive officers and certain key management employees. The ESSRP provides defined benefit payments to these employees on their retirements for life or to their beneficiaries on their deaths for a 15-year postretirement period. Life insurance carried on certain plan participants is payable to the Company on the employee's death. There are no plan assets in this nonqualified benefit plan due to the nature of the plan.

 

The following table lists components of net periodic pension benefit cost for the year ended December 31:

 

(in thousands)  2016      2015      2014  
Service Cost–Benefit Earned During the Period  $252   $189   $51 
Interest Cost on Projected Benefit Obligation   1,667    1,523    1,520 
Amortization of Prior Service Cost:               
From Regulatory Asset   16    16    22 
From Other Comprehensive Income1   38    38    51 
Amortization of Net Actuarial Loss:               
From Regulatory Asset   293    334    142 
From Other Comprehensive Income2   446    602    46 
Net Periodic Pension Cost  $2,712   $2,702   $1,832 
1  Amortization of Prior Service Costs from Other Comprehensive Income Charged to:               
Electric Operation and Maintenance Expenses  $15   $15   $20 
Other Nonelectric Expenses   23    23    31 
                
2  Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:               
Electric Operation and Maintenance Expenses  $272   $310   $132 
Other Nonelectric Expenses   174    292    (86)

 

Weighted average assumptions used to determine net periodic pension cost for the year ended December 31:

 

   2016   2015   2014 
Discount Rate   4.76%   4.35%   5.30%
Rate of Increase in Future Compensation Level   3.13%   3.15%   3.18%

 

The following table presents amounts recognized in the consolidated balance sheets as of December 31:

 

(in thousands)  2016   2015 
Regulatory Assets:          
Unrecognized Prior Service Cost  $58   $75 
Unrecognized Actuarial Loss   2,890    2,936 
Total Regulatory Assets  $2,948   $3,011 
Projected Benefit Obligation Liability – Net Amount Recognized  $(37,335)  $(35,811)
Accumulated Other Comprehensive Loss:          
Unrecognized Prior Service Cost  $134   $172 
Unrecognized Actuarial Loss   5,915    5,815 
Total Accumulated Other Comprehensive Loss  $6,049   $5,987 

 

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The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations over the two-year period ended December 31, 2016 and a statement of the funded status as of December 31 of both years:

 

(in thousands)  2016    2015  
Reconciliation of Fair Value of Plan Assets:          
Fair Value of Plan Assets at January 1  $—   $— 
Actual Return on Plan Assets   —    — 
Employer Contributions   1,188    1,119 
Benefit Payments   (1,188)   (1,119)
Fair Value of Plan Assets at December 31  $—   $— 
Reconciliation of Projected Benefit Obligation:          
Projected Benefit Obligation at January 1  $35,811   $35,650 
Service Cost   252    189 
Interest Cost   1,667    1,523 
Benefit Payments   (1,188)   (1,119)
Plan Amendments   —    — 
Actuarial Loss (Gain)   793    (432)
Projected Benefit Obligation at December 31  $37,335   $35,811 

 

Weighted average assumptions used to determine benefit obligations at December 31:

 

   2016   2015 
Discount Rate   4.60%   4.76%
Rate of Increase in Future Compensation Level   3.00%   3.13%

 

The estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic pension cost for the ESSRP in 2017 are:

 

(in thousands)  2017  
Decrease in Regulatory Assets:     
Amortization of Unrecognized Prior Service Cost  $16 
Amortization of Unrecognized Actuarial Loss   285 
Decrease in Accumulated Other Comprehensive Loss:     
Amortization of Unrecognized Prior Service Cost   38 
Amortization of Unrecognized Actuarial Loss   440 
Total Estimated Amortization  $779 

 

Cash flows—The ESSRP is unfunded and has no assets; contributions are equal to the benefits paid to plan participants. The following benefit payments, which reflect future service, as appropriate, are expected to be paid:

 

   Years 
(in thousands)  2017   2018   2019   2020   2021   2022-2026 
   $1,253   $1,487   $1,562   $1,544   $1,754   $12,700 

 

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Other Postretirement Benefits

The Company provides a portion of health insurance and life insurance benefits for retired OTP and corporate employees. Substantially all of the Company's electric utility and corporate employees may become eligible for health insurance benefits if they reach age 55 and have 10 years of service. There are no plan assets. The following table lists components of net periodic postretirement benefit cost for the year ended December 31:

 

(in thousands)  2016   2015   2014 
Service Cost–Benefit Earned During the Period  $1,301   $1,297   $1,055 
Interest Cost on Projected Benefit Obligation   2,503    2,097    2,200 
Amortization of Prior Service Cost               
From Regulatory Asset   134    205    205 
From Other Comprehensive Income1   3    5    5 
Amortization of Net Actuarial Loss               
From Regulatory Asset   379    —    — 
From Other Comprehensive Income1   9    —    — 
  Net Periodic Postretirement Benefit Cost  $4,329   $3,604   $3,465 
Effect of Medicare Part D Subsidy  $(923)  $(1,487)  $(948)
1 Corporate cost included in Other Nonelectric Expenses.               

 

Weighted average assumptions used to determine net periodic postretirement benefit cost for the year ended December 31:

 

   2016   2015   2014 
Discount Rate   4.57%   4.20%   5.10%

 

The following table presents amounts recognized in the consolidated balance sheets as of December 31:

 

(in thousands)  2016   2015 
Regulatory Asset:          
Unrecognized Prior Service Cost  $(4)  $129 
Unrecognized Net Actuarial Loss   13,586    1,289 
Net Regulatory Asset  $13,582   $1,418 
Projected Benefit Obligation Liability – Net Amount Recognized  $(62,571)  $(48,730)
Accumulated Other Comprehensive (Income) Loss:          
Unrecognized Prior Service Cost  $4   $8 
Unrecognized Net Actuarial Gain   (171)   (347)
Accumulated Other Comprehensive Income  $(167)  $(339)

 

The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations and accrued postretirement benefit cost over the two-year period ended December 31, 2016:

 

(in thousands)  2016   2015 
Reconciliation of Fair Value of Plan Assets:          
Fair Value of Plan Assets at January 1  $—   $— 
Actual Return on Plan Assets   —    — 
Company Contributions   2,825    2,365 
Benefit Payments (Net of Medicare Part D Subsidy)   (5,908)   (5,324)
Participant Premium Payments   3,083    2,959 
Fair Value of Plan Assets at December 31  $—   $— 
Reconciliation of Projected Benefit Obligation:          
Projected Benefit Obligation at January 1  $48,730   $53,638 
Service Cost (Net of Medicare Part D Subsidy)   1,301    1,297 
Interest Cost (Net of Medicare Part D Subsidy)   2,503    2,097 
Benefit Payments (Net of Medicare Part D Subsidy)   (5,908)   (5,324)
Participant Premium Payments   3,083    2,959 
Actuarial Loss (Gain)   12,862    (5,937)
Projected Benefit Obligation at December 31  $62,571   $48,730 
Reconciliation of Accrued Postretirement Cost:          
Accrued Postretirement Cost at January 1  $(47,652)  $(46,413)
Expense   (4,329)   (3,604)
Net Company Contribution   2,825    2,365 
Accrued Postretirement Cost at December 31  $(49,156)  $(47,652)

 

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Weighted average assumptions used to determine benefit obligations at December 31:

 

   2016   2015 
Discount Rate   4.46%   4.57%

 

Assumed healthcare cost-trend rates as of December 31:

   2016   2015 
Healthcare Cost-Trend Rate Assumed for Next Year Pre-65   6.01%   6.16%
Healthcare Cost-Trend Rate Assumed for Next Year Post-65   6.23%   6.43%
Rate to Which the Cost-Trend Rate is Assumed to Decline   4.50%   4.50%
Year the Rate Reaches the Ultimate Trend Rate   2038    2038 

 

Assumed healthcare cost-trend rates have a significant effect on the amounts reported for healthcare plans. A one-percentage-point change in assumed healthcare cost-trend rates for 2016 would have the following effects:

(in thousands)  1 Point
Increase		   1 Point
Decrease		 
Effect on the Postretirement Benefit Obligation  $7,151   $(7,492)
Effect on Total of Service and Interest Cost  $653   $(519)
Effect on Expense  $1,454   $(907)

  

Measurement Dates: 2016 2015
Net Periodic Postretirement Benefit Cost January 1, 2016 January 1, 2015
     
End of Year Benefit Obligations January 1, 2016 projected to
December 31, 2016		 January 1, 2015 projected to
December 31, 2015

 

The estimated net amounts of unrecognized prior service cost to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic postretirement benefit cost in 2017 are:

 

(in thousands)  2017 
Decrease in Regulatory Assets:     
Amortization of Unrecognized Prior Service Cost  $— 
Amortization of Unrecognized Actuarial Loss   932 
Decrease in Accumulated Other Comprehensive Loss:     
Amortization of Unrecognized Prior Service Cost   — 
Amortization of Unrecognized Actuarial Loss   23 
Total Estimated Amortization  $955 

 

Cash flows—The Company expects to contribute $3.5 million net of expected employee contributions for the payment of retiree medical benefits and Medicare Part D subsidy receipts in 2017. The Company expects to receive a Medicare Part D subsidy from the Federal government of approximately $416,000 in 2017. The following benefit payments, which reflect expected future service, as appropriate, net of expected Medicare Part D subsidy receipts and participant premium payments, are expected to be paid:

 

   Years 
(in thousands)  2017   2018   2019   2020   2021   2022-2026 
    $3,512   $3,669   $3,828   $3,912   $4,046   $20,377 

 

401K Plan

The Company sponsors a 401K plan for the benefit of all corporate and subsidiary company employees. Contributions made to these plans by the Company and its subsidiary companies included in continuing operations totaled $3,877,000 for 2016, $3,602,000 for 2015 and $3,171,000 for 2014.

 

Employee Stock Ownership Plan

The Company has a stock ownership plan for the benefit of all its electric utility employees. Contributions made by the Company were $647,000 for 2016, $674,000 for 2015 and $696,000 for 2014.

 

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12. Fair Value of Financial Instruments

 

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

 

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of December 31, 2016 and December 31, 2015 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, for the respective entities, which approximate market rates.

 

Long-Term Debt including Current Maturities—The fair value of the Company's and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.

 

   December 31, 2016   December 31, 2015 
(in thousands)  Carrying
Amount		   Fair Value   Carrying
Amount		   Fair Value 
Cash and Cash Equivalents  $—   $—   $—   $— 
Short-Term Debt   (42,883)   (42,883)   (80,672)   (80,672)
Long-Term Debt including Current Maturities   (538,542)   (583,835)   (496,268)   (561,245)

 

13. Property, Plant and Equipment

 

(in thousands)  December 31,
2016		   December 31,
2015		 
Electric Plant in Service          
Production  $891,330   $879,121 
Transmission   410,679    391,941 
Distribution   466,285    451,820 
General   92,063    97,881 
Electric Plant in Service   1,860,357    1,820,763 
Construction Work in Progress   149,997    64,117 
Total Gross Electric Plant   2,010,354    1,884,880 
Less Accumulated Depreciation and Amortization   622,657    592,001 
Net Electric Plant  $1,387,697   $1,292,879 
Nonelectric Operations Plant          
Equipment  $155,809   $155,715 
Buildings and Leasehold Improvements   51,323    41,149 
Land   4,694    4,479 
Nonelectric Operations Plant   211,826    201,343 
Construction Work in Progress   3,264    15,495 
Total Gross Nonelectric Plant   215,090    216,838 
Less Accumulated Depreciation and Amortization   125,562    121,903 
Net Nonelectric Operations Plant  $89,528   $94,935 
Net Plant  $1,477,225   $1,387,814 

 

The estimated service lives for rate-regulated properties is 5 to 82 years. For nonelectric property the estimated useful lives are from 3 to 40 years.

 

   Service Life Range 
(years)  Low   High 
Electric Fixed Assets:          
Production Plant   9    82 
Transmission Plant   42    70 
Distribution Plant   5    68 
General Plant   5    50 
Nonelectric Fixed Assets:          
Equipment   3    12 
Buildings and Leasehold Improvements   7    40 

 

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14. Income Taxes

 

The total income tax expense differs from the amount computed by applying the federal income tax rate (35% in 2016, 2015 and 2014) to net income before total income tax expense for the following reasons:

 

(in thousands)  2016   2015   2014 
Tax Computed at Federal Statutory Rate – Continuing Operations  $28,741   $28,081   $25,704 
Increases (Decreases) in Tax from:               
Federal PTCs   (7,175)   (6,962)   (7,517)
State Income Taxes Net of Federal Income Tax Expense   2,848    4,945    1,993 
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes   (850)   (850)   (849)
Corporate-owned Life Insurance   (680)   (167)   (354)
Dividend Received/Paid Deduction   (537)   (560)   (622)
Section 199 Domestic Production Activities Deduction   (482)   —    (1,026)
Investment Tax Credit Amortization   (350)   (571)   (597)
Allowance for Funds Used During Construction – Equity   (280)   (426)   (505)
Differences Reversing in Excess of Federal Rates   77    (1,143)   (106)
Permanent and Other Differences   (1,231)   (705)   436 
Total Income Tax Expense – Continuing Operations  $20,081   $21,642   $16,557 
Income Tax Expense – Discontinued Operations – U.S.   138    2,991    3,952 
Income Tax Expense – Continuing and Discontinued Operations  $20,219   $24,633   $20,509 
Overall Effective Federal, State and Foreign Income Tax Rate   24.5%   29.3%   26.2%
Income Tax Expense From Continuing Operations Includes the Following:               
Current Federal Income Taxes  $1,070   $211   $124 
Current State Income Taxes   1,211    1    5 
Deferred Federal Income Taxes   23,586    23,050    21,044 
Deferred State Income Taxes   2,589    6,763    4,347 
Federal PTCs   (7,175)   (6,962)   (7,517)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes   (850)   (850)   (849)
Investment Tax Credit Amortization   (350)   (571)   (597)
Total  $20,081   $21,642   $16,557 
Total Income Before Income Taxes – Continuing and Discontinued Operations  $82,540   $83,978   $78,232 

 

 

The Company's deferred tax assets and liabilities were composed of the following on December 31:

 

(in thousands)  2016   2015 
Deferred Tax Assets          
Benefit Liabilities  $44,381   $41,788 
Federal PTCs   43,433    39,505 
Retirement Benefits Liabilities   38,390    41,958 
North Dakota Wind Tax Credits   32,962    32,962 
Cost of Removal   31,636    29,463 
Differences Related to Property   9,876    10,177 
Net Operating Loss Carryforward   3,865    22,824 
Vacation Accrual   2,725    2,500 
Investment Tax Credits   818    1,109 
Other   7,793    7,617 
Total Deferred Tax Assets  $215,879   $229,903 
Deferred Tax Liabilities          
Differences Related to Property  $(371,761)  $(366,234)
Retirement Benefits Regulatory Asset   (38,390)   (41,958)
Excess Tax over Book Pension   (15,509)   (13,775)
North Dakota Wind Tax Credits   (3,654)   (3,179)
Impact of State Net Operating Losses on Federal Taxes   (1,352)   (1,596)
Other   (11,804)   (10,830)
 Total Deferred Tax Liabilities  $(442,470)  $(437,572)
 Deferred Income Taxes  $(226,591)  $(207,669)

 

111

 

 

Federal PTCs are earned as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs increased 3.6% in 2016 compared with 2015. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

 

Schedule of expiration of tax credits and tax net operating losses available as of December 31, 2016:

 

(in thousands)  Amount   2017   2027-36 
United States               
Federal Net Operating Losses  $—   $—   $— 
Federal Tax Credits   46,435    —    46,435 
State Net Operating Losses   3,865    —    3,865 
State Tax Credits   33,993    389    33,604 

 

The carryforward period on a portion of the North Dakota wind tax credits from the Langdon wind project is five years. OTP has adjusted its deferred tax assets and deferred tax credits by $0.4 million for potential unused North Dakota wind tax credits related to the Langdon wind project.

 

The following table summarizes the activity related to our unrecognized tax benefits:

 

(in thousands)  2016   2015   2014 
Balance on January 1  $468   $222   $4,239 
Increases Related to Tax Positions for Prior Years   406    236    120 
Decreases Related to Tax Positions for Prior Years   —    —    (4,142)
Increases Related to Tax Positions for Current Year   114    10    5 
Uncertain Positions Resolved During Year   (97)   —    — 
Balance on December 31  $891   $468   $222 

 

The balance of unrecognized tax benefits as of December 31, 2016 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of December 31, 2016 is not expected to change significantly within the next 12 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in our consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of December 31, 2016.

 

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of December 31, 2016, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2013 for federal and Minnesota and North Dakota state income taxes.

 

15. Asset Retirement Obligations (AROs)

 

The Company’s AROs are related to OTP’s coal-fired generation plants and its 92 wind turbines located in North Dakota. The AROs include items such as site restoration, closure of ash pits, and removal of certain structures, generators, asbestos and storage tanks. The Company has legal obligations associated with the retirement of a variety of other long-lived tangible assets used in electric operations where the estimated settlement costs are individually and collectively immaterial. The Company has no assets legally restricted for the settlement of any of its AROs.

 

On December 19, 2014 the EPA’s rule regulating coal combustion residuals (CCR) went into effect. The final rule regulates CCR as a non-hazardous solid waste under Subtitle D of the Resource Conservation and Recovery Act. In the second quarter of 2015, subsequent to publication of the CCR rule, OTP completed an assessment of its ash handling and storage facilities at Hoot Lake Plant, Coyote Station and Big Stone Plant and determined that it had no immediate obligation under the rules to close or modify any existing ash handling facilities or storage sites but has discontinued the use of one pit at Coyote Station to avoid the potential for future obligations related to this site under the CCR rule. Additionally, OTP identified a slag sluice pond and slag stockpile area at Big Stone Plant that will need to be reclaimed at a future date to comply with the CCR rule. OTP established an ARO liability of approximately $0.5 million for its share of the estimated future costs to reclaim this site. Although identified as a new ARO resulting from the issuance of the CCR rule, the slag sluice pond and slag stockpile are currently in use, so the cost of the new ARO was capitalized. Therefore, the establishment of the ARO will have no impact on current year consolidated operating expenses but will result in an offsetting charge to the removal cost component of the accumulated provision for depreciation on the Company’s consolidated balance sheet. Future reclamation costs, when incurred, will be charged against, and reduce, the accumulated ARO liability.

 

112

 

 

OTP recorded no new AROs in 2016.

 

Reconciliations of carrying amounts of the present value of the Company’s legal AROs, capitalized asset retirement costs and related accumulated depreciation and a summary of settlement activity for the years ended December 31, 2016 and 2015 are presented in the following table:

 

(in thousands)  2016   2015 
Asset Retirement Obligations          
Beginning Balance  $8,084   $7,721 
New Obligations Recognized   —    451 
Adjustments Due to Revisions in Cash Flow Estimates   (103)   (424)
Accrued Accretion   360    336 
Settlements   —    — 
Ending Balance  $8,341   $8,084 
Asset Retirement Costs Capitalized          
Beginning Balance  $3,086   $3,059 
New Obligations Recognized   —    451 
Adjustments Due to Revisions in Cash Flow Estimates   (103)   (424)
Settlements   —    — 
Ending Balance  $2,983   $3,086 
Accumulated Depreciation – Asset Retirement Costs Capitalized          
Beginning Balance  $673   $527 
New Obligations Recognized   —    — 
Adjustments Due to Revisions in Cash Flow Estimates   —    — 
Depreciation Expense   122    146 
Settlements   —    — 
Ending Balance  $795   $673 
Settlements   None    None 
Original Capitalized Asset Retirement Cost – Retired  $—   $— 
Accumulated Depreciation   —    — 
           
Asset Retirement Obligation  $—   $— 
Settlement Cost   —    — 
Gain on Settlement – Deferred Under Regulatory Accounting  $—   $— 

 

16. Discontinued Operations

 

On April 30, 2015 the Company sold Foley for $12.0 million in cash, plus $6.3 million in adjustments for working capital and other related items received in October 2015, less $1.0 million in selling expenses. On February 28, 2015 the Company sold the assets of AEV, Inc. for $22.3 million in cash, plus $0.6 million in adjustments for working capital and fixed assets received in October 2015, less $0.8 million in selling expenses. Foley and AEV, Inc. were formerly included in the Company’s Construction segment.

 

On February 8, 2013 the Company completed the sale of substantially all the assets of its dock and boatlift company, formerly included in our Manufacturing segment. On November 30, 2012 the Company completed the sale of the assets of our wind tower manufacturing business. This business was the only remaining entity in the Company’s former Wind Energy segment.

 

The Company’s Wind Energy and Construction segments were eliminated as a result of the sales of its wind tower manufacturing business, Foley and AEV, Inc. The financial position, results of operations and cash flows of Foley, AEV, Inc., the Company’s wind tower manufacturing business and its dock and boatlift company are reported as discontinued operations in the Company’s consolidated financial statements.

 

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Following are summary presentations of the results of discontinued operations for the years ended December 31, 2016, 2015 and 2014:

 

   For the Year Ended December 31, 2016 
(in thousands)  Foley   AEV, Inc.   Wind
Tower
Business		   Dock and
Boatlift
Business		   Intercompany
Transactions
Adjustment		   Total 
Operating Expenses  $250   $—   $(757)  $85   $—   $(422)
Income Tax (Benefit) Expense   (136)   5    303    (34)   —    138 
Net (Loss) Income  $(114)  $(5)  $454   $(51)  $—   $284 

 

   For the Year Ended December 31, 2015 
(in thousands)  Foley   AEV, Inc.   Wind
Tower
Business		   Dock and
Boatlift
Business		   Intercompany
Transactions
Adjustment		   Total 
Operating Revenues  $21,625   $2,998   $—   $—   $—   $24,623 
Operating Expenses   26,839    4,532    (462)   966    (240)   31,635 
Asset Impairment Charge   1,000    —    —    —    —    1,000 
Interest Expense   177    27    —    —    (204)   — 
Other Income (Deductions)   (42)   2    111    —    (2)   69 
Income Tax (Benefit) Expense   (921)   (638)   229    (386)   177    (1,539)
Net (Loss) Income from Operations   (5,512)   (921)   344    (580)   265    (6,404)
(Loss) Gain on Disposition Before Taxes   (204)   11,894    —    —    —    11,690 
Income Tax (Benefit) Expense on Disposition   (227)   4,757    —    —    —    4,530 
Net Gain on Disposition   23    7,137    —    —    —    7,160 
Net (Loss) Income  $(5,489)  $6,216   $344   $(580)  $265   $756 

 

   For the Year Ended December 31, 2014 
(in thousands)  Foley   AEV, Inc.   Wind
Tower
Business		   Dock and
Boatlift
Business		   Intercompany
Transactions
Adjustment		   Total 
Operating Revenues  $105,333   $44,527   $—   $—   $—   $149,860 
Operating Expenses   100,826    40,297    19    (180)   (960)   140,002 
Asset Impairment Charge   5,605    —    —    —    —    5,605 
Interest Expense   510    184    —    —    (694)   — 
Other (Deductions) Income   (38)   304    —    277    (4)   539 
Income Tax Expense (Benefit)   1,388    1,729    (8)   183    660    3,952 
Net (Loss) Income  $(3,034)  $2,621   $(11)  $274   $990   $840 

 

Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts were recognized on a percentage-of-completion basis. The method used to determine the progress of completion was based on the ratio of costs incurred to total estimated costs on construction projects. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in pretax charges of $4.4 million in 2015.

 

In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued operations.

 

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Following are summary presentations of the major components of assets and liabilities of discontinued operations as of December 31, 2016 and December 31, 2015:

 

   December 31, 2016 
(in thousands)  Foley   AEV, Inc.   Wind
Tower
Business		   Dock and
Boatlift
Business		   Total 
Current Liabilities  $—   $—   $589   $774   $1,363 
Liabilities of Discontinued Operations  $—   $—   $589   $774   $1,363 

 

   December 31, 2015 
(in thousands)  Foley   AEV, Inc.   Wind
Tower
Business		   Dock and
Boatlift
Business		   Total 
Current Liabilities  $—   $—   $1,299   $799   $2,098 
Liabilities of Discontinued Operations  $—   $—   $1,299   $799   $2,098 

 

Included in current liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow:

 

(in thousands)  2016   2015 
Warranty Reserve Balance, January 1  $2,103   $2,527 
Additional Provision for Warranties Made During the Year   —    — 
Settlements Made During the Year   (24)   (124)
Decrease in Warranty Estimates for Prior Years   (710)   (300)
Warranty Reserve Balance, December 31  $1,369   $2,103 

 

The warranty reserve balances as of December 31, 2016 relate entirely to products produced by the Company’s former wind tower and dock and boatlift manufacturing companies. Certain products sold by the companies carried one to fifteen year warranties. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies.

 

Expenses associated with remediation activities of these companies could be substantial. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated net income and financial condition.

 

17. Subsequent Events

 

Stock Incentive Awards

On February 2, 2017 the following stock incentive awards were granted to officers under the 2014 Incentive Plan:

 

Award  Shares/Units
Granted		   Weighted
Average
Grant-Date
Fair Value
per Award		   Vesting 
Restricted Stock Units Granted   15,900   $37.65    25% per year through February 6, 2021 
Stock Performance Awards Granted   59,500   $31.00    December 31, 2019 

 

The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant.

 

115

 

 

Under the performance share awards the aggregate award for performance at target is 59,500 shares. For target performance the participants would earn an aggregate of 39,667 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2017 through December 31, 2019, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2017 and the average closing price for the 20 trading days immediately preceding January 1, 2020. The participants would also earn an aggregate of 19,833 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 89,250 common shares. There are no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance measurement period. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718, and will be measured over the performance period based on the grant-date fair value of the award.

 

Under the 2017 Performance Award Agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to Executive Employment Agreements with the Company is to be made at target at the date of any such event.

 

The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.

 

Supplementary Financial Information

 

Quarterly Information (not audited)

 

Because of changes in the number of common shares outstanding and the impact of diluted shares, the sum of the quarterly earnings (loss) per common share may not equal total earnings (loss) per common share.

 

Three Months Ended  March 31   June 30   September 30   December 31 
(in thousands, except per share data)  2016   20151   2016   2015   2016   2015   2016   2015 
Operating Revenues–Continuing Operations  $206,242   $202,841   $203,482   $188,153   $197,175   $200,023   $196,640   $188,787 
Operating Income–Continuing Operations  $27,576   $25,025   $27,083   $24,800   $27,284   $29,626   $29,156   $29,763 
Net Income (Loss):                                        
Continuing Operations  $14,490   $13,781   $15,556   $13,657   $14,594   $15,709   $17,397   $15,442 
Discontinued Operations  $30   $4,154   $119   $(2,221)  $22   $(317)  $113   $(860)
Total Net Income  $14,520   $17,935   $15,675   $11,436   $14,616   $15,392   $17,510   $14,582 
Basic Earnings (Loss) Per Share:                                        
Continuing Operations  $.38   $.37   $.41   $.37   $.38   $.42   $.45   $.41 
Discontinued Operations  $—   $.11   $—   $(.06)  $—   $(.01)  $—   $(.02)
Total Basic Earnings Per Share  $.38   $.48   $.41   $.31   $.38   $.41   $.45   $.39 
Diluted Earnings (Loss) Per Share:                                        
Continuing Operations  $.38   $.37   $.41   $.36   $.37   $.42   $.44   $.41 
Discontinued Operations  $—   $.11   $—   $(.06)  $—   $(.01)  $—   $(.02)
Total Diluted Earnings Per Share  $.38   $.48   $.41   $.30   $.37   $.41   $.44   $.39 
Dividends Declared Per Common Share  $.3125   $.3075   $.3125   $.3075   $.3125   $.3075   $.3125   $.3075 
Price Range:                                        
High   29.73    33.44    33.50    32.76    36.42    28.34    42.55    28.76 
Low   25.80    30.60    27.77    26.14    32.89    24.82    33.08    25.20 
Average Number of Common Shares Outstanding—Basic   37,937    37,243    38,179    37,433    38,833    37,575    39,236    37,728 
Average Number of Common Shares Outstanding—Diluted   38,045    37,498    38,321    37,653    39,006    37,795    39,552    37,868 

1 Results include pre-tax goodwill impairment charges of $1.0 million at Foley in discontinued operations.

 

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

None.

 

Item 9A. CONTROLS AND PROCEDURES

 

Evaluation of Disclosures Controls and Procedures. Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act)) as of December 31, 2016, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2016.

 

Changes in Internal Control over Financial Reporting. There were no changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) under the Exchange Act) during the fourth quarter ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Management’s Report Regarding Internal Control Over Financial Reporting. Management is responsible for the preparation and integrity of the consolidated financial statements and representations in this Annual Report on Form 10-K. The consolidated financial statements of the Company have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and include some amounts that are based on informed judgments and best estimates and assumptions of management.

 

In order to assure the consolidated financial statements are prepared in conformance with generally accepted accounting principles, management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). These internal controls are designed only to provide reasonable assurance, on a cost-effective basis, that transactions are carried out in accordance with management’s authorizations and assets are safeguarded against loss from unauthorized use or disposition.

 

Management has completed its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013) to conduct the required assessment of the effectiveness of the Company’s internal control over financial reporting. Based on this assessment, management concluded that, as of December 31, 2016, the Company’s internal control over financial reporting was effective based on those criteria. The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has audited the Company’s consolidated financial statements included in this Annual Report on Form 10-K and issued an attestation report on the Company’s internal control over financial reporting.

 

Attestation Report of Independent Registered Public Accounting Firm. The attestation report of Deloitte & Touche LLP, the Company’s independent registered public accounting firm, regarding the Company’s internal control over financial reporting is provided on page 59.

 

Item 9B. OTHER INFORMATION

 

None.

 

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PART III

 

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

The information required by this Item regarding Directors is incorporated by reference to the information under “Election of Directors” in the Company's definitive Proxy Statement for the 2017 Annual Meeting. The information regarding executive officers and family relationships is set forth in Item 3A hereto. The information regarding Section 16 reporting is incorporated by reference to the information under “Security Ownership of Directors and Officers - Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive Proxy Statement for the 2017 Annual Meeting. The information required by this Item regarding the Company’s procedures for recommending nominees to the board of directors is incorporated by reference to the information under “Meetings and Committees of the Board of Directors – Corporate Governance Committee” in the Company’s definitive Proxy Statement for the 2017 Annual Meeting. The information required by this Item in regard to the Audit Committee and the Company’s Audit Committee financial experts is incorporated by reference to the information under “Meetings and Committees of the Board of Directors – Audit Committee” in the Company’s definitive Proxy Statement for the 2017 Annual Meeting.

 

The Company has adopted a code of conduct that applies to all of its directors, officers (including its principal executive officer, principal financial officer, and its principal accounting officer or controller or person performing similar functions) and employees. The Company’s code of conduct is available on its website at www.ottertail.com. The Company intends to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of its code of conduct by posting such information on its website at the address specified above. Information on the Company’s website is not deemed to be incorporated by reference into this Annual Report on Form 10-K.

 

Item 11. EXECUTIVE COMPENSATION

 

The information required by this Item is incorporated by reference to the information under “Compensation Discussion and Analysis,” “Report of Compensation Committee,” “Executive Compensation” and “Director Compensation” in the Company's definitive Proxy Statement for the 2017 Annual Meeting.

 

118

 

 

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

The information required by this Item regarding security ownership is incorporated by reference to the information under “Security Ownership of Certain Beneficial Owners” and “Security Ownership of Directors and Officers” in the Company’s definitive Proxy Statement for the 2017 Annual Meeting.

 

EQUITY COMPENSATION PLAN INFORMATION

 

The following table sets forth information as of December 31, 2016 about the Company’s common stock that may be issued under all of its equity compensation plans:

 

Plan Category  Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
(a)		   Weighted average
exercise price of
outstanding
options, warrants
and rights
(b)		   Number of securities remaining
available for future issuance under
equity compensation plans
(excluding securities reflected in
column (a))
(c)		 
Equity compensation plans approved by security holders:               
2014 Stock Incentive Plan   417,193(1)  $0.00    1,356,811(2)
1999 Stock Incentive Plan   14,135(3)  $0.00    —(4)
1999 Employee Stock Purchase Plan   —    N/A    384,159(5)
Equity compensation plans not approved by security holders   —    —    — 
Total   431,328   $0.00    1,740,970 

 

(1)Includes 122,250, 126,450 and 89,291 performance based share awards granted in 2016, 2015 and 2014, respectively, 78,745 restricted stock units outstanding as of December 31, 2016, and 457 stock units as part of the director deferred compensation program, and excludes 48,789 shares of restricted stock issued under the 2014 Stock Incentive Plan.

 

(2)The 2014 Stock Incentive Plan provides for the issuance of any shares available under the plan in the form of restricted stock, restricted stock units, performance awards and other types of stock-based awards, in addition to the granting of options, warrants or stock appreciation rights.

 

(3)Includes 11,250 restricted stock units outstanding as of December 31, 2016, and 2,885 stock units as part of the director deferred compensation program, and excludes 4,725 shares of restricted stock issued under the 1999 Stock Incentive Plan.

 

(4)The 1999 Stock Incentive Plan provided for the issuance of any shares available under the plan in the form of restricted stock, restricted stock units, performance awards and other types of stock-based awards, in addition to the granting of options, warrants or stock appreciation rights. The 1999 Stock Incentive Plan expired by its terms on December 13, 2013 and no more awards may be granted thereunder.

 

(5)Shares are issued based on employee’s election to participate in the plan.

 

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

The information required by this Item is incorporated by reference to the information under “Policy and Procedures Regarding Transactions with Related Persons,” “Election of Directors” and “Meetings and Committees of the Board of Directors” in the Company’s definitive Proxy Statement for the 2017 Annual Meeting.

 

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

The information required by this Item is incorporated by reference to the information under “Ratification of Independent Registered Public Accounting Firm – Fees” and “Ratification of Independent Registered Public Accounting Firm – Pre-Approval of Audit/Non-Audit Services Policy” in the Company’s definitive Proxy Statement for the 2017 Annual Meeting.

 

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PART IV

 

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

(a)List of documents filed as part of this report:

 

1.Financial Statements

 

  Page
Report of Independent Registered Public Accounting Firm 59
Consolidated Balance Sheets, December 31, 2016 and 2015 60
Consolidated Statements of Income for the Three Years Ended December 31, 2016 62
Consolidated Statements of Comprehensive Income for the Three Years Ended December 31, 2016 63
Consolidated Statements of Common Shareholders’ Equity for the Three Years Ended December 31, 2016 64
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2016 65
Consolidated Statements of Capitalization, December 31, 2016 and 2015 66
Notes to Consolidated Financial Statements 67

 

2.Financial Statement Schedules

 

SCHEDULE 1 - Condensed financial information of registrant

 

Otter Tail Corporation (PARENT COMPANY)
Condensed Balance Sheets, December 31
(in thousands)  2016   2015 
Assets          
Current Assets          
Cash and Cash Equivalents  $6,218   $— 
Accounts Receivable   12    38 
Accounts Receivable from Subsidiaries   1,706    2,311 
Interest Receivable from Subsidiaries   141    175 
Income Taxes Receivable   662    4,000 
Notes Receivable from Subsidiaries   1,671    5,645 
Other   936    1,096 
Total Current Assets   11,346    13,265 
Investments in Subsidiaries   692,723    713,344 
Notes Receivable from Subsidiaries   79,843    72,560 
Deferred Income Taxes   35,387    37,406 
Other Assets   29,079    26,957 
Total Assets  $848,378   $863,532 
           
Liabilities and Equity          
           
Current Liabilities          
Short-Term Debt  $—   $59,666 
Current Maturities of Long-Term Debt   231    52,422 
Accounts Payable to Subsidiaries   5,958    5,959 
Notes Payable to Subsidiaries   38,519    99,467 
Other   5,838    6,035 
Total Current Liabilities   50,546    223,549 
           
Other Noncurrent Liabilities   32,556    34,015 
Commitments and Contingencies          
Capitalization          
Long-Term Debt, Net of Current Maturities   95,172    945 
Common Shareholder Equity   670,104    605,023 
Total Capitalization   765,276    605,968 
Total Liabilities and Equity  $848,378   $863,532 
See accompanying notes to condensed financial statements.          

 

120

 

 

Otter Tail Corporation (PARENT COMPANY)
Condensed Statements of Income—For the Years Ended December 31
(in thousands)  2016   2015   2014 
             
Operating Loss               
Revenue  $—   $—   $— 
Operating Expenses   9,689    10,188    12,593 
Operating Loss   (9,689)   (10,188)   (12,593)
                
Other Income (Expense)               
Equity Income in Earnings of Subsidiaries   67,047    66,067    64,926 
Interest Charges   (6,817)   (6,786)   (6,326)
Interest Charges to Subsidiaries   (173)   (193)   (117)
Interest Income from Subsidiaries   4,897    4,786    4,980 
Other Income   1,621    421    1,379 
Total Other Income   66,575    64,295    64,842 
                
Income Before Income Taxes   56,886    54,107    52,249 
Income Tax Benefit   (5,435)   (5,238)   (5,474)
Net Income  $62,321   $59,345   $57,723 
See accompanying notes to condensed financial statements.               

 

Otter Tail Corporation (PARENT COMPANY)
Condensed Statements of Cash Flows—For the Years Ended December 31
(in thousands)  2016   2015   2014 
Cash Flows from Operating Activities               
                
Net Cash Provided by Operating Activities  $83,296   $53,958   $47,697 
                
Cash Flows from Investing Activities               
Return of Capital (Investment in Subsidiaries)   9,912    (88,079)   (44,000)
Debt Issued to Subsidiaries   (3,309)   (12,592)   (7,662)
Cash Provided by (Used in) Investing Activities   106    (11)   (44)
Net Cash Provided by (Used in) Investing Activities   6,709    (100,682)   (51,706)
                
Cash Flows from Financing Activities               
Change in Checks Written in Excess of Cash   (428)   213    215 
Net Short-Term (Repayments) Borrowings   (59,666)   48,812    10,854 
(Repayments to) Borrowings from Subsidiaries   (60,948)   32,249    4,656 
Proceeds from Issuance of Common Stock   44,435    14,233    26,259 
Common Stock Issuance Expenses   (562)   (451)   (673)
Payments for Retirement of Capital Stock   (104)   (1,596)   (590)
Proceeds from the Issuance of Long-Term Debt   130,000    —    — 
Short-Term and Long-Term Debt Issuance Expenses   (723)   (312)   (170)
Payments for Retirement of Long-Term Debt   (87,547)   (201)   (188)
Dividends Paid and Other Distributions   (48,244)   (46,223)   (44,261)
Net Cash (Used in) Provided by Financing Activities   (83,787)   46,724    (3,898)
Net Change in Cash and Cash Equivalents   6,218    —    (7,907)
Cash and Cash Equivalents at Beginning of Period   —    —    7,907 
Cash and Cash Equivalents at End of Period  $6,218   $—   $— 
See accompanying notes to condensed financial statements.               

 

121

 

 

Otter Tail Corporation (Parent Company)

Notes to Condensed Financial Statements

For the years ended December 31, 2016, 2015 and 2014

 

Incorporated by reference are Otter Tail Corporation’s consolidated statements of comprehensive income and common shareholders’ equity in Part II, Item 8.

 

Basis of Presentation

 

The condensed financial information of Otter Tail Corporation is presented to comply with Rule 12-04 of Regulation S-X. The unconsolidated condensed financial statements do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read with the consolidated financial statements and related notes included in this Annual Report on Form 10-K.

 

Otter Tail Corporation’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income (loss) from operations of the subsidiaries is reported on a net basis as equity income (loss) in earnings of subsidiaries.

 

Related Party Transactions

 

As of December 31, 2016:
(in thousands)		  Accounts
Receivable		   Interest
Receivable		   Current
Notes
Receivable		   Long-Term
Notes
Receivable		   Accounts
Payable		   Current
Notes
Payable		 
Otter Tail Power Company  $1,572   $—   $—   $—   $10   $— 
Vinyltech Corporation   3    20    —    11,500    —    15,951 
Northern Pipe Products, Inc.   —    10    —    5,943    —    6,560 
BTD Manufacturing, Inc.   —    92    —    52,000    —    2,342 
Wind Tower Business   —    —    1,441    —    —    — 
Dock and Boatlift Business   —    —    230    —    —    — 
T.O. Plastics, Inc.   —    19    —    10,400    —    12,378 
Varistar Corporation   60    —    —    —    5,948    1,288 
Otter Tail Assurance Limited   71    —    —    —    —    — 
   $1,706   $141   $1,671   $79,843   $5,958   $38,519 

 

As of December 31, 2015:
(in thousands)		  Accounts
Receivable		   Interest
Receivable		   Current
Notes
Receivable		   Long-Term
Notes
Receivable		   Accounts
Payable		   Current
Notes
Payable		 
Otter Tail Power Company  $1,928   $—   $—   $—   $11   $— 
Vinyltech Corporation   —    32    —    8,500    —    14,844 
Northern Pipe Products, Inc.   —    8    —    3,160    —    7,088 
BTD Manufacturing, Inc.   13    107    3,924    53,500    —    — 
Wind Tower Business   —    —    1,444    —    —    — 
Dock and Boatlift Business   —    —    277    —    —    — 
T.O. Plastics, Inc.   —    28    —    7,400    —    6,405 
Varistar Corporation   60    —    —    —    5,948    71,130 
Otter Tail Assurance Limited   310    —    —    —    —    — 
   $2,311   $175   $5,645   $72,560   $5,959   $99,467 

 

Dividends

 

Dividends paid to Otter Tail Corporation (the Parent) from its subsidiaries were as follows:

 

(in thousands)  2016   2015   2014 
Cash Dividends Paid to Parent by Subsidiaries  $77,779   $46,188   $44,261 

 

See Otter Tail Corporation’s notes to consolidated financial statements in Part II, Item 8 for other disclosures.

 

Other schedules are omitted because of the absence of the conditions under which they are required, because the amounts are insignificant or because the information required is included in the financial statements or the notes thereto.

 

122

 

 

3.Exhibits

The following Exhibits are filed as part of, or incorporated by reference into, this report.

 

  Previously Filed    
  File No. As Exhibit No.    
2-A 8-K filed 7/1/09 2.1 — Plan of Merger, dated as of June 30, 2009, by and among Otter Tail Corporation (now known as Otter Tail Power Company), Otter Tail Holding Company (now known as Otter Tail Corporation) and Otter Tail Merger Sub Inc.
2-B     — Asset Purchase Agreement, dated as of November 16, 2016, among Otter Tail Power Company, EDF Renewable Development, Inc., Power Partners Midwest, LLC, EDF-RE US Development, LLC and Merricourt Power Partners, LLC.**/***
2-C     — Turnkey Engineering, Procurement and Construction Services Agreement, dated as of November 16, 2016, between Otter Tail Power Company and EDF-RE US Development, LLC.**/***
3-A 8-K filed 7/1/09 3.1 — Restated Articles of Incorporation.
3-B 8-K filed 7/1/09 3.2 — Restated Bylaws.
4-A 8-K filed 8/23/07 4.1 — Note Purchase Agreement, dated as of August 20, 2007.
4-A-1 8-K filed 12/20/07 4.3 — First Amendment, dated as of December 14, 2007, to Note Purchase Agreement, dated as of August 20, 2007.
4-A-2 8-K filed 9/15/08 4.1 — Second Amendment, dated as of September 11, 2008, to Note Purchase Agreement, dated as of August 20, 2007.
4-A-3 8-K filed 7/1/09 4.2 — Third Amendment, dated as of June 26, 2009, to Note Purchase Agreement dated as of August 20, 2007.
4-B 8-K filed 11/2/12 4.1 — Third Amended and Restated Credit Agreement dated as of October 29, 2012 among Otter Tail Corporation, the Banks named therein, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents, KeyBank National Association, as Documentation Agent, U.S. Bank National Association, as administration agent for the Banks and U.S. Bank National Association, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as Joint Lead Arrangers and Joint Book Runners.
4-B-1 8-K filed 11/1/13 4.1 — First Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2013, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West and Union Bank, N.A., as Banks.
4-B-2 8-K filed 11/4/14 4.1 — Second Amendment to Third Amended and Restated Credit Agreement, dated as of November 3, 2014, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.
4-B-3 8-K filed 11/3/15 4.1 — Third Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2015, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.

 

123

 

 

 

  Previously Filed    
  File No. As Exhibit No.    
4-B-4 8-K filed 11/3/16 4.1 — Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.
4-C 8-K filed 11/2/12 4.2 — Second Amended and Restated Credit Agreement dated as of October 29, 2012 among Otter Tail Power Company, the Banks named therein, JPMorgan Chase Bank, N.A. and Bank of America, N.A., as Co-Syndication Agents, KeyBank National Association and CoBank, ACB, as Co-Documentation Agents, U.S. Bank National Association, as administrative agent for the Banks, and U.S. Bank National Association, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as Joint Lead Arrangers and Joint Book Runners.
4-C-1 8-K filed 11/1/13 4.2 — First Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2013, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association and Union Bank, N.A., as Banks.
4-C-2 8-K filed 11/4/14 4.2 — Second Amendment to Second Amended and Restated Credit Agreement, dated as of November 3, 2014, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.
4-C-3 8-K filed 11/3/15 4.2 — Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2015, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.
4-C-4 8-K filed 11/3/16 4.2 — Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2016, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.
4-D 8-K filed 8/3/11 4.1 — Note Purchase Agreement, dated as of July 29, 2011, between Otter Tail Power Company and the Purchasers named therein.
4-E 8-K filed 8/16/13 4.1 — Note Purchase Agreement dated as of August 14, 2013 between Otter Tail Power Company and the Purchasers named therein.
         

 

124

 

 

  Previously Filed    
  File No. As Exhibit No.    
4-F 8-K filed 2/9/16 4.1 — Term Loan Agreement dated as of February 5, 2016 among Otter Tail Corporation, the Banks named therein and JPMorgan Chase Bank, N.A., as administrative agent for the Banks, and J.P. Morgan Securities LLC, as Lead Arranger and Book Runner.
4-G 8-K filed 9/27/16 4.1 — Note Purchase Agreement dated as of September 23, 2016 between Otter Tail Corporation and the Purchasers named therein.
10-A 2-55813 5-F — Contract dated April 12, 1973, between the Bureau of Reclamation and the Company.
10-B 2-55813 5-G — Contract dated January 8, 1973, between East River Electric Power Cooperative and the Company.
10-B-1 2-62815 5-E-1 — Supplement One dated February 20, 1978.
10-B-2 10-K for year ended 12/31/89 10-E-3 — Supplement Two dated June 10, 1983.
10-B-3 10-K for year ended 12/31/90 10-E-4 — Supplement Three dated June 6, 1985.
10-B-4 10-K for year ended 12/31/92 10-E-5 — Supplement No. Four, dated as of September 10, 1986.
10-B-5 10-K for year ended 12/31/92 10-E-6 — Supplement No. Five, dated as of January 7, 1993.
10-B-6 10-K for year ended 12/31/93 10-E-7 — Supplement No. Six, dated as of December 2, 1993.
10-C 10-K for year ended 12/31/89 10-F — Agreement for Sharing Ownership of Generating Plant by and between the Company, Montana-Dakota Utilities Co., and Northwestern Public Service Company (dated as of January 7, 1970).
10-C-1 10-K for year ended 12/31/89 10-F-1 — Letter of Intent for purchase of share of Big Stone Plant from Northwestern Public Service Company (dated as of May 8, 1984).
10-C-2 10-K for year ended 12/31/91 10-F-2 — Supplemental Agreement No. 1 to Agreement for Sharing Ownership of Big Stone Plant (dated as of July 1, 1983).
10-C-3 10-K for year ended 12/31/91 10-F-3 — Supplemental Agreement No. 2 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 1, 1985).
10-C-4 10-K for year ended 12/31/91 10-F-4 — Supplemental Agreement No. 3 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 31, 1986).
10-C-5 10-Q for quarter ended 9/30/03 10.1 — Supplemental Agreement No. 4 to Agreement for Sharing Ownership of Big Stone Plant (dated as of April 24, 2003).
10-C-6 10-K for year ended 12/31/92 10-F-5 — Amendment I to Letter of Intent dated May 8, 1984, for purchase of share of Big Stone Plant.
10-D 10-Q for quarter ended 6/30/15 10.3 — Big Stone South – Ellendale Project Ownership Agreement dated as of June 12, 2015 between Otter Tail Power Company, a wholly owned subsidiary of Otter Tail Corporation, and Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.**
10-E 2-61043 5-H — Agreement for Sharing Ownership of Coyote Station Generating Unit No. 1 by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company and Minnesota Power & Light Company (dated as of July 1, 1977).
10-E-1 10-K for year ended 12/31/89 10-H-1 — Supplemental Agreement No. One, dated as of November 30, 1978, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.

 

125

 

 

  Previously Filed    
  File No. As Exhibit No.    
10-E-2 10-K for year ended 12/31/89 10-H-2 — Supplemental Agreement No. Two, dated as of March 1, 1981, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1 and Amendment No. 2 dated March 1, 1981, to Coyote Plant Coal Agreement.
10-E-3 10-K for year ended 12/31/89 10-H-3 — Amendment, dated as of July 29, 1983, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10-E-4 10-K for year ended 12/31/92 10-H-4 — Agreement, dated as of September 5, 1985, containing Amendment No. 3 to Agreement for Sharing Ownership of Coyote Generating Unit No. 1, dated as of July 1, 1977, and Amendment No. 5 to Coyote Plant Coal Agreement, dated as of January 1, 1978.
10-E-5 10-Q for quarter ended 9/30/01 10-A — Amendment, dated as of June 14, 2001, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10-E-6 10-Q for quarter ended 9/30/03 10.2 — Amendment, dated as of April 24, 2003, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10-F 2-63744 5-I — Coyote Plant Coal Agreement by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company, Minnesota Power & Light Company, and Knife River Coal Mining Company (dated as of January 1, 1978).
10-F-1 10-K for year ended 12/31/92 10-I-1 — Addendum, dated as of March 10, 1980, to Coyote Plant Coal Agreement.
10-F-2 10-K for year ended 12/31/92 10-I-2 — Amendment (No. 3), dated as of May 28, 1980, to Coyote Plant Coal Agreement.
10-F-3 10-K for year ended 12/31/92 10-I-3 — Fourth Amendment, dated as of August 19, 1985, to Coyote Plant Coal Agreement.
10-F-4 10-Q for quarter ended 6/30/93 19-A — Sixth Amendment, dated as of February 17, 1993, to Coyote Plant Coal Agreement.
10-F-5 10-K for year ended 12/31/01 10-I-5 — Agreement and Consent to Assignment of the Coyote Plant Coal Agreement.
10-G 10-K for year ended 12/31/12 10-J — Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., Northwestern Corporation, dated as of October 10, 2012.**
10-G-1 8-K filed 1/31/14 10.1 — First Amendment to Lignite Sales Agreement dated as of January 30, 2014 among Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C.
10-G-2 8-K filed 3/18/15 10.1 — Second Amendment to Lignite Sales Agreement dated as of March 16, 2015 among Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C.
10-H 10-Q for quarter ended 3/31/13 10.1 — General Work Construction Agreement, dated as of February 1, 2013, between Otter Tail Power Company, in its capacity as agent for itself, Northwestern Corporation d/b/a NorthWestern Energy and Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and Graycor Industrial Constructors Inc.**
10-I 10-Q/A for quarter ended 6/30/13 10.1 — Wind Energy Purchase Agreement dated May 9, 2013 between Otter Tail Power Company and Ashtabula Wind III, LLC.**

 

126

 

 

  Previously Filed    
  File No. As Exhibit No.    
10-J-1 10-K for year ended 12/31/02 10-N-1 — Deferred Compensation Plan for Directors, as amended.*
10-J-1a 10-K for year ended 12/31/10 10-N-1A — First Amendment of Deferred Compensation Plan for Directors (2003 Restatement), as amended.*
10-J-1b 8-K filed 4/17/14 10.5 — Second Amendment of Deferred Compensation Plan for Directors (2003 Restatement), as amended.*
10-J-2 8-K filed 2/04/05 10.1 — Executive Survivor and Supplemental Retirement Plan (2005 Restatement).*
10-J-2a 10-K for year ended 12/31/06 10-N-2a — First Amendment of Executive Survivor and Supplemental Retirement Plan (2005 Restatement).*
10-J-2b 10-K for year ended 12/31/10 10-N-2B — Second Amendment of Executive Survivor and Supplemental Retirement Plan (2005 Restatement).*
10-J-3 10-Q for quarter ended 9/30/11 10.1 — Nonqualified Retirement Plan (2011 Restatement).*
10-J-4 10-Q for  quarter ended 9/30/16 10.1 — 1999 Employee Stock Purchase Plan, As Amended (2016).
10-J-5 8-K filed 4/13/06 10.4 — 1999 Stock Incentive Plan, As Amended (2006).
10-J-6 8-K filed 4/19/12 10.2 — Form of 2012 Restricted Stock Award Agreement for Executive Officers.*
10-J-7 8-K filed 4/19/12 10.4 — Form of 2012 Restricted Stock Unit Award Agreement.*
10-J-8 8-K filed 4/13/06 10.1 — Form of Restricted Stock Award Agreement for Directors.*
10-J-9 10-K for year ended 12/31/13 10-O-12 — 2014 Executive Annual Incentive Plan.*
10-J-10 333-195337 4.1 — Otter Tail Corporation 2014 Stock Incentive Plan.
10-J-11 8-K filed 4/17/14 10.1 — Form of 2014 Performance Award Agreement.*
10-J-12 8-K filed 4/17/14 10.2 — Form of 2014 Restricted Stock Award Agreement for Executive Officers.*
10-J-13 8-K filed 4/17/14 10.3 — Form of 2014 Restricted Stock Award Agreement for Directors.*
10-J-14     — Summary of Non-Employee Director Compensation (2016).
10-J-15 8-K filed 9/26/14 10.1 — Amendment to 2014 Performance Award Agreement with Edward J. McIntyre.*
10-J-16 8-K filed 2/11/15 10.1 — Form of 2015 Performance Award Agreement (Executives).*
10-J-17 8-K filed 2/11/15 10.2 — Form of 2015 Performance Award Agreement (Legacy).*
10-J-18 8-K filed 2/11/15 10.3 — Form of 2015 Restricted Stock Unit Award Agreement (Executives).*
10-J-19 8-K filed 2/11/15 10.4 — Form of 2015 Restricted Stock Unit Award Agreement (Legacy).*
10-J-20 8-K filed 2/11/15 10.5 — Otter Tail Corporation Executive Restoration Plus Plan, as Amended and Restated.
10-J-21 8-K filed 4/15/15 10.2 — Form of 2015 Restricted Stock Award Agreement for Directors.*
10-K 8-K filed 5/11/15 1.1 — Distribution Agreement dated May 11, 2015, between Otter Tail Corporation and J.P. Morgan Securities LLC.
10-L-1 10-K for year ended 12/31/12 10-O-1 — Executive Employment Agreement, Kevin Moug.*
10-L-2 10-K for year ended 12/31/12 10-O-2 — Executive Employment Agreement, George Koeck.*
10-M-1 10-K for year ended 12/31/10 10-Q-3 — Change in Control Severance Agreement, Kevin G. Moug.*

 

127

 

 

  Previously Filed    
  File No. As Exhibit No.    
10-M-2 10-K for year ended 12/31/10 10-Q-4 — Change in Control Severance Agreement, George Koeck.*
10-M-3 10-K for year ended 12/31/11 10-Q-5 — Change in Control Severance Agreement, Chuck MacFarlane.*
10-M-4 10-Q for quarter ended 9/30/14 10.3 — Change in Control Severance Agreement, Timothy Rogelstad.*
10-M-5 10-Q for quarter ended 9/30/14 10.6 — Change in Control Severance Agreement, Paul Knutson.*
10-M-6 10-K for year ended 12/31/15 10-R-6 — Change in Control Severance Agreement, John Abbott.*
10-N 8-K filed 4/15/15 10.1 — Otter Tail Corporation Executive Severance Plan.*
12.1     — Calculation of Ratios of Earnings to Fixed Charges and Preferred Dividends.
21-A     — Subsidiaries of Registrant.
23-A     — Consent of Deloitte & Touche LLP.
24-A     — Powers of Attorney.
31.1     — Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2     — Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1     — Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2     — Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101     — Financial statements from the Annual Report on Form 10-K of Otter Tail Corporation for the year ended December 31, 2016, formatted in Extensible Business Reporting Language: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Common Shareholders’ Equity, (v) the Consolidated Statements of Cash Flows, (vi) the Consolidated Statements of Capitalization, (vii) the Notes to Consolidated Financial Statements and (viii) Schedule I.

 

*Management contract, compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.

 

**Confidential information has been omitted from this Exhibit and filed separately with the Securities and Exchange Commission pursuant to a confidential treatment request under Rule 24b-2.

 

***Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company hereby undertakes to furnish copies of any of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.

 

Pursuant to Item 601(b)(4)(iii) of Regulation S-K, copies of certain instruments defining the rights of holders of certain long-term debt of the Company are not filed, and in lieu thereof, the Company agrees to furnish copies thereof to the Securities and Exchange Commission upon request.

 

Item 16. FORM 10-K SUMMARY

 

None

 

128

 

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

  OTTER TAIL CORPORATION
     
  By /s/ Kevin G. Moug
    Kevin G. Moug
    Chief Financial Officer and Senior Vice President
    (authorized officer and principal financial officer)
     
  Dated:    February 22, 2017

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

 

Signature and Title      
       
Charles S. MacFarlane )    
President and Chief Executive Officer )    
(principal executive officer) and Director )    
  )    
Kevin G. Moug )    
Chief Financial Officer and Senior Vice President )    
(principal financial and accounting officer) )    
  ) By /s/ Charles S. MacFarlane
Nathan I. Partain )   Charles S. MacFarlane
Chairman of the Board and Director )   Pro Se and Attorney-in-Fact
  )   Dated February 22, 2017
Karen M. Bohn, Director )    
  )    
John D. Erickson, Director )    
  )    
Steven L. Fritze, Director )    
  )    
Kathryn O. Johnson, Director )    
  )    
Timothy J. O’Keefe, Director )    
  )    
Joyce Nelson Schuette, Director )    
  )    
James B. Stake, Director )    

 

129

 

 

EXHIBIT INDEX

 

Exhibit Number   Description
     
2-B   Asset Purchase Agreement, dated as of November 16, 2016, among Otter Tail Power Company, EDF Renewable Development, Inc., Power Partners Midwest, LLC, EDF-RE US Development, LLC and Merricourt Power Partners, LLC.*/**
     
2-C   Turnkey Engineering, Procurement and Construction Services Agreement, dated as of November 16, 2016, between Otter Tail Power Company and EDF-RE US Development, LLC.*/**
     
10-J-14   Summary of Non-Employee Director Compensation (2016).
     
12.1   Calculation of Ratios of Earnings to Fixed Charges and Preferred Dividends.
     
21-A   Subsidiaries of the Registrant.
     
23-A   Consent of Deloitte & Touche LLP.
     
24-A   Power of Attorney.
     
31.1   Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
31.2   Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
32.1   Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
32.2   Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
101   Financial statements from the Annual Report on Form 10-K of Otter Tail Corporation for the year ended December 31, 2016, formatted in Extensible Business Reporting Language: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Common Shareholders’ Equity, (v) the Consolidated Statements of Cash Flows, (vi) the Consolidated Statements of Capitalization, (vii) the Notes to Condensed Consolidated Financial Statements and (viii) Schedule I.

 

*Confidential information has been omitted from this Exhibit and filed separately with the Securities and Exchange Commission pursuant to a confidential treatment request under Rule 24b-2.

 

**Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company hereby undertakes to furnish copies of any of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.

 

 

 

 EX-2.B 2 t1700069_ex2-b.htm EXHIBIT 2-B

 

 

Exhibit 2-B

 

Confidential treatment has been requested for portions of this exhibit pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended. The copy filed herewith omits the information subject to the confidentiality request. Omissions are designated as [**]. A complete version of this exhibit has been filed separately with the Securities and Exchange Commission.

 

Execution Version

 

 

ASSET PURCHASE AGREEMENT

by and among

EDF RENEWABLE DEVELOPMENT, INC.,

 

POWER PARTNERS MIDWEST, LLC,

 

EDF-RE US DEVELOPMENT, LLC,

 

MERRICOURT POWER PARTNERS, LLC

as Sellers

and

OTTER TAIL POWER COMPANY

as Buyer

dated as of November 16, 2016

 

Merricourt Wind Project

 

 

 

 

 

Table of Contents

 

    Page
Article 1 DEFINITIONS AND CONSTRUCTION 2
Section 1.1 Definitions 2
Section 1.2 Rules of Construction 16
     
Article 2 PURCHASE AND SALE 17
Section 2.1 Purchase and Sale of Assets 17
Section 2.2 Excluded Assets 18
Section 2.3 Assumed Liabilities 19
Section 2.4 Excluded Liabilities 19
Section 2.5 Purchase Price; Closing Payment 20
Section 2.6 Allocation of Purchase Price 20
     
Article 3 PURCHASE AND SALE AND CLOSING 21
Section 3.1 Closing 21
Section 3.2 Closing Deliveries by Sellers to Buyer 21
Section 3.3 Closing Deliveries by Buyer to Seller 22
Section 3.4 Exclusivity 22
     
Article 4 REPRESENTATIONS AND WARRANTIES OF SELLERS 22
Section 4.1 Organization 22
Section 4.2 Authority; Enforceability 23
Section 4.3 No Conflicts; Consents and Approvals 23
Section 4.4 Title to Assets 23
Section 4.5 Legal Proceedings 23
Section 4.6 Compliance with Laws 24
Section 4.7 Taxes 24
Section 4.8 Regulatory Status 24
Section 4.9 Contracts 25
Section 4.10 Real Property 25
Section 4.11 Permits 27
Section 4.12 Environmental Matters 27
Section 4.13 Brokers 28
Section 4.14 Wind Data 29
Section 4.15 Insurance 29
Section 4.16 PTCs 29
Section 4.17 No Other Agreements to Sell Purchased Assets 30
Section 4.18 Reports 30
     
Article 5 REPRESENTATIONS AND WARRANTIES OF BUYER 30
Section 5.1 Organization 30
Section 5.2 Authority; Enforceability 31
Section 5.3 No Conflicts 31
Section 5.4 Legal Proceedings 31
Section 5.5 Brokers 32
Section 5.6 Financial Resources 32

 

 -i- 

 

 

Table of Contents

(continued)

 

    Page
     
Section 5.7 Independent Investigation; No Knowledge of Misrepresentations or Omissions 32
     
Article 6 COVENANTS 32
Section 6.1 Books and Records 32
Section 6.2 Tax Matters 33
Section 6.3 Conduct of Sellers Prior to Closing 33
Section 6.4 Access to Information 34
Section 6.5 Efforts; Consents; Regulatory and Required Seller Approval 36
Section 6.6 Public Announcements 37
Section 6.7 Further Assurances 37
Section 6.8 Updated Schedules 38
Section 6.9 Representations and Warranties 38
Section 6.10 Interconnection Costs 38
Section 6.11 Easement Agreement Extensions 40
Section 6.12 Non-Compete 40
Section 6.13 Letters of Credit; Guaranty 41
Section 6.14 Title Commitment; Survey; Title Policy 42
Section 6.15 Site Plan 43
Section 6.16 5% Safe Harbor Turbines 44
     
Article 7 CONDITIONS TO CLOSING 44
Section 7.1 Conditions to Obligations of Each Party 44
Section 7.2 Additional Conditions to Obligations of Buyer 44
Section 7.3 Additional Conditions to Obligations of Seller 47
     
Article 8 Termination 47
Section 8.1 Termination 47
Section 8.2 Effect of Termination 50
     
Article 9 INDEMNIFICATION, LIMITATIONS OF LIABILITY AND WAIVERS 50
Section 9.1 Survival 50
Section 9.2 Indemnification by Seller 50
Section 9.3 Indemnification by Buyer 51
Section 9.4 Limitations on Liability 51
Section 9.5 Procedures for Third Party Claims 52
Section 9.6 Indemnification Procedures 54
Section 9.7 Payments of Indemnity Amounts Payable by Buyer 56
Section 9.8 Payments of Indemnity Amounts Payable by Sellers 56
Section 9.9 Exclusive Remedy 56
     
Article 10 MISCELLANEOUS 56
Section 10.1 Notices 56
Section 10.2 Entire Agreement 58
Section 10.3 Expenses 58
Section 10.4 Disclosure 58

 

 -ii- 

 

 

Table of Contents

(continued)

 

    Page
     
Section 10.5 Waiver 59
Section 10.6 Amendment 59
Section 10.7 No Third Party Beneficiary 59
Section 10.8 Assignment; Binding Effect 59
Section 10.9 Headings 59
Section 10.10 Invalid Provisions 59
Section 10.11 Counterparts; Facsimile 60
Section 10.12 Governing Law; Venue; and Jurisdiction 60
Section 10.13 Specific Performance 61

 

 

 -iii- 

 

 

EXHIBITS

 

Exhibit A [Intentionally Omitted]
Exhibit B   Form of Assignment and Assumption Agreement
Exhibit C Form of Bill of Sale
Exhibit D Form of Warranty Deed
Exhibit E Site Description
Exhibit F [Intentionally Omitted]
Exhibit G [Intentionally Omitted]
Exhibit H [Intentionally Omitted]
Exhibit I Title Policy

 

SCHEDULES

 

1.1 Knowledge
4.3(a) Purchased Contract Conflicts
4.3(b) Seller Consents
4.5 Legal Proceedings
4.6 Compliance with Laws
4.7 Taxes
4.8 Regulatory Status
4.9 Purchased Contracts
4.10(a) Real Property
4.10(g) Land Contract Defaults
4.10(h) Condemnation Proceedings
4.10(i) Violations of Laws
4.10(j) Options; Zoning Changes
4.10(m) Mineral Developments
4.11(a) Permits
4.11(b) Additional Required Permits
4.11(c) Permit Noncompliance
4.11(d) Permit Conflicts
4.12 Environmental Matters
4.14 Wind Data
4.15 Insurance
4.16 Physical Work
4.18 Reports
5.3 Buyer Consents
6.3 Conduct of Business
6.5(d) BBCS Changes
6.14(a) Title Objection Letter

 

 -iv- 

 

 

ASSET PURCHASE AGREEMENT

 

This Asset Purchase Agreement, dated as of November 16, 2016 (this “Agreement”), is made by, between and between EDF Renewable Development, Inc., a Delaware corporation (“EDF-RD”), Power Partners Midwest, LLC, a Delaware limited liability company (“PPM”), EDF-RE US Development, LLC, a Delaware limited liability company (“EDF-USD”), and Merricourt Power Partners, LLC, a Delaware limited liability company (“Merricourt,” collectively, “Sellers”), on the one hand, and Otter Tail Power Company, a Minnesota corporation (“Buyer”), on the other hand.

 

W•I•T•N•E•S•S•E•T•H:

 

WHEREAS, Buyer desires to acquire a wind farm development site in the State of North Dakota and construct on such site seventy-five (75) Vestas-American Wind Technology, Inc., a California corporation (“Vestas”), 2.0 V110 wind turbine generators on eighty (80) meter towers (“WTGs” or each, a “WTG”) for a total nameplate capacity of one hundred fifty (150) megawatts;

 

WHEREAS, Sellers and their Affiliates are in the process of developing a site in McIntosh and Dickey Counties, North Dakota for a wind energy generation project capable of supporting the installation and operation of seventy-five (75) WTGs and in connection therewith have acquired certain real estate rights and other assets and commenced certain development activities;

 

WHEREAS, Sellers desire to sell and assign to Buyer, and Buyer desires to purchase and assume substantially all of the assets, and certain specified liabilities, related to the Project (as defined below), subject to the terms and subject to the conditions set forth in this Agreement;

 

WHEREAS, concurrently with the execution and delivery of this Agreement, as a condition and inducement to Buyer’s willingness to enter into this Agreement, EDF-USD, and Buyer are entering into a separate Turnkey Engineering, Procurement and Construction Agreement (the “TEPC”), pursuant to which EDF-USD will provide the engineering, procurement, construction, commissioning, start-up and related services, on a fixed price turnkey basis, to install the seventy-five (75) WTGs and to provide other services to Buyer as specified in the TEPC; and

 

WHEREAS, concurrently with the execution and delivery of this Agreement, as a condition and inducement to Buyer’s willingness to enter into this Agreement, EDF Énergies Nouvelles, S.A., a French société anonyme and an indirect parent company of Sellers (“EDF-EN”), is executing and delivering the EDF-EN Guaranty (as defined below) pursuant to which EDF-EN is guaranteeing Sellers’ full and timely payment of their obligations under this Agreement.

 

NOW, THEREFORE, in consideration of the premises and the mutual representations, warranties, covenants and agreements in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

 

- 1 - 

 

 

Article 1

DEFINITIONS AND CONSTRUCTION

 

Section 1.1           Definitions. As used in this Agreement, the following capitalized terms have the meanings set forth below:

 

“5% Safe Harbor Turbines” means [**] to be delivered under the Daughter Contract from Vestas to EDF-USD, as specified in Exhibit D of the Daughter Contract, for a purchase price of not less than [**] ($[**]).

 

“Action” means any legal, administrative, arbitral, mediation or other alternative dispute resolution procedure or other action, proceeding, claim, assessment, audit, inquiry or similar investigation before any court, arbitrator or other Governmental Authority.

 

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries, controls, is controlled by or is under common control with such Person. The term “control” (including, with correlative meaning, the terms “controlled by” and “under common control with”), as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities or partnership interests, by contract or otherwise.

 

“Agreement” is defined in the introduction to this Agreement.

 

“Ancillary Agreements” means the Bill of Sale, the Assignment and Assumption Agreement, the Deed and the other documents and agreements to be delivered pursuant to this Agreement.

 

“Assets” of any Person means all assets, properties and rights of every kind, nature, character and description (whether real, personal or mixed, whether tangible or intangible and wherever situated), including the related goodwill, which assets and properties are operated, owned or leased by such Person.

 

“Assignment and Assumption Agreement” means an assignment and assumption agreement, substantially in the form attached as Exhibit B hereto.

 

“Assumed Liabilities” is defined in Section 2.3.

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

 

- 2 - 

 

 

“Avian Assessment” means the existing avian survey(s) of Sellers and any other avian survey(s) of Sellers currently underway related to the Project which shall be delivered to Buyer in final form pursuant to Section 7.2(n).

 

“Backup LOC” has the meaning given such term in the TEPC.

 

“Bat Assessment” means the existing bat survey(s) of Sellers related to the Project which shall be delivered to Buyer in final form pursuant to Section 7.2(n).

 

“Bill of Sale” means a bill of sale, substantially in the form attached as Exhibit C hereto.

 

“Bird and Bat Conservation Strategy” is a voluntary project specific document that describes the environmental studies that were undertaken to identify potential sensitive resources and incorporates best management practices that will be implemented in order to avoid and minimize impact to birds and bats, as well as documents, specific analyses and decisions consistent with the tiered approach and the USFWS Land-Based Wind Energy Guidelines (USFWS 2012).

 

“Books and Records” means any and all data, reports, studies, external, non-attorney-client privileged correspondence, maps, surveys and other business records of Sellers necessary or useful to the development, construction and operation of the Project.

 

“Business Day” means any day other than Saturday, a Sunday, or a holiday, on which banks are generally open for business in both Fargo, ND and Minneapolis, MN.

 

“Buyer” is defined in the introduction to this Agreement.

 

“Buyer Group” is defined in Section 9.2.

 

“Certificate of Site Compatibility” means the Certificate of Site Compatibility required by the NDPSC to construct the Project, updated to account for the WTGs that EDF-USD is to supply under the TEPC and including five (5) alternate WTG locations.

 

“Claim” means any demand, claim, action, investigation, legal proceeding (whether administrative or judicial, at law or in equity and whether informal or formal), arbitration or mediation.

 

“Clean Water Act” means the Federal Water Pollution Control Act, as amended by the Clean Water Act of 1977, 33 U.S.C. § 1251 et seq.

 

“Closing” means the closing of the transactions contemplated by this Agreement, as provided for in Section 3.1.

 

“Closing Date” means the date on which Closing occurs.

 

“COD Purchased Contracts” means those Purchased Contracts identified as such on Schedule 4.9 and that will be assigned to Buyer on the Commercial Operation Date.

 

- 3 - 

 

 

“Code” means the Internal Revenue Code of 1986, as amended and in effect.

 

“Commercial Operation Date” means the date on which Project Commercial Operation is achieved.

 

“Confidentiality Agreement” means the Confidentiality and Nondisclosure Agreement by and between EDF Renewable Energy, Inc. and Buyer, dated as of March 24, 2016.

 

“Consent” means a consent, approval, authorization, waiver, filing, notice, registration, declaration or similar action of, with or by any Person.

 

“Construction Period Guaranty” has the meaning given such term in the TEPC.

 

“Construction Period Guaranty Expiration” has the meaning given such term in the TEPC.

 

“Contract” means any legally binding contract, lease, license, evidence of indebtedness, mortgage, indenture, purchase order, binding bid, letter of credit, security agreement or other legally binding arrangement, whether oral or written, but excludes Permits.

 

“Credit Trigger Event” means (a) with respect to EDF-EN, the failure of (i) Électricité de France S.A. to own, directly or indirectly, at least fifty percent (50%) of the issued and outstanding equity of EDF-EN, or (ii) EDF-EN to have a Tangible Net Worth of at least €1,750,000,000.00; (b) with respect to EDF-RE, the failure of EDF-RE to have a Tangible Net Worth of at least $50,000,000.00; and (c) with respect to Buyer, the downgrading of Buyer’s senior unsecured credit rating by any two Rating Agencies to below BBB- (or Baa3 in the case of Moody’s).

 

“Cultural Resource Study” means the cultural resource study to be prepared by Kadrmas, Lee & Jackson, or another consultant selected by Sellers and approved by Buyer (such approval not to be unreasonably withheld), which shall be delivered to Buyer in final form pursuant to Section 7.2(n).

 

“Data Site” means the electronic documentation site established by Sellers in connection with the transactions contemplated by this Agreement.

 

“Daughter Contract” means that certain contract between EDF-USD and Vestas splitting WTGs designated for the Project from the Framework Agreement and executed on November 16, 2016.

 

“Deductible” is defined in Section 9.4(c).

 

“Deed” means a warranty deed, substantially in the form attached as Exhibit D hereto.

 

“Default” means, with respect to any Person, any circumstance, event or condition that would constitute, with or without notice or the passage of time or both, a violation, breach, default, conflict with, or give rise to any right of termination, modification, cancellation, prepayment, suspension, limitation, revocation, purchase, re-purchase or acceleration.

 

- 4 - 

 

 

“Designated Representations” means the representations and warranties contained in Section 4.1 (Organization), Section 4.2 (Authority; Enforceability), Section 4.4(a) (Title to Assets), Section 4.13 (Brokers), Section 5.1 (Organization), Section 5.2 (Authority; Enforceability) and Section 5.5 (Brokers).

 

“Dispute Notice” is defined in Section 9.6(b).

 

“EDF-EN” is defined in the recitals.

 

“EDF-EN Guaranty” has the meaning given such term in the TEPC.

 

“EDF-EN Guaranty Expiration” has the meaning given such term in the TEPC.

 

“EDF-RD” is defined in the introduction to this Agreement.

 

“EDF-RE” means EDF Renewable Energy, Inc., a Delaware corporation.

 

“EDF-USD” is defined in the introduction to this Agreement.

 

“Energy Resource Interconnection Service” has the meaning given to such term in the MISO FERC Electric Tariff.

 

“Environmental Claim” means any Claim or Loss arising out of or related to Hazardous Materials, environmental or workplace contamination or pollution, or any violation or alleged violation of Environmental Law.

 

“Environmental Law” means all Laws that regulate or relate to (a) the protection or clean-up of the environment; (b) the handling of Hazardous Materials; (c) the preservation or protection of waterways, groundwater, drinking water, air, wildlife, plants or other natural resources; and (d) the health and safety of persons or property, including, without limitation, protection of the health and safety of employees, including the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq.; the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq.; the Clean Water Act; the Clean Air Act, 42 U.S.C. § 7401 et seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Occupational Safety and Health Act, 29 U.S.C. § 651 et seq.; the Hazardous Materials Transportation Act, 49 U.S.C. § 5101 et seq.; the Endangered Species Act, 16 U.S.C. § 1531 et seq.; the Migratory Bird Treaty Act 16 U.S.C § 703 et seq.; the Bald and Golden Eagle Protection Act 16 U.S.C § 668 et seq; Centers for Disease Control guidelines, policies and procedures; and all other analogous or related Laws currently in effect (including implementing regulations promulgated pursuant thereto) of any Governmental Authority having jurisdiction over the assets in question addressing pollution control or protection of Protected Species, the environment, wildlife, plants, natural resources, or human health.

 

- 5 - 

 

 

“ERIS Interconnection Costs” means the sum of (i) the network upgrade costs associated with the New GIA for Energy Resource Interconnection Service plus (ii) the network upgrade costs required to obtain Network Integration Transmission Service for yearly “Firm Network Designated” service (as referenced in MISO Business Practice Manual 11 – Resource Adequacy, Articles 4.2.1.1 and 4.2.3.1) for 40% of the 150 MW to be requested by Buyer (the “Service Level Trigger”) on or before June 1, 2017; provided, that, if either Party deems the cost of one or more upgrades required to achieve the Service Level Trigger to be excessive in light of the increase in Firm Network Designated service obtained from such upgrade, the Parties shall negotiate in good faith to agree to a level of upgrade costs that is commercially reasonable in light of the Firm Network Designated service obtained by such costs; provided, further, that Buyer shall, in its reasonable discretion in light of the costs and benefits to Buyer, make any determination to accept “Firm Network Designated” service at a level below the Service Trigger Level. For the avoidance of doubt, ERIS Interconnection costs shall include network upgrade costs regardless of whether they are assigned to the Project by MISO or by any other RTO or transmission owner, but shall not include any reimbursable costs.

 

“Estimated Interconnection Costs” means the estimate for Interconnection Costs set forth in the New GIA and, if applicable, the service agreement applicable to the transmission service contemplated in clause (ii) of the definition of “ERIS Interconnection Costs.”

 

“Excess Interconnection Costs” is defined in Section 6.10(d).

 

“Excluded Assets” is defined in Section 2.2.

 

“Excluded Liabilities” is defined in Section 2.4.

 

“Exclusivity Period” is defined in Section 3.4.

 

“Existing GIA” means the Generator Interconnection Agreement made and entered into as of October 10, 2011 by and between EDF-RD (f/k/a enXco Development Corporation), Montana-Dakota Utilities Co., a division of MDU Resources Group Inc. and MISO and associated with MISO Interconnection Queue Request G359, together with all other rights in MISO Interconnection Queue Request G359 and all associated studies, reports and communications with MISO related thereto.

 

“Existing Permitted Exceptions” is defined in Section 6.14(a).

 

“Existing Title Evidence” is defined in Section 6.14(a).

 

“Existing Title Objections” is defined in Section 6.14(a). 

 

“FAA” means the U.S. Federal Aviation Administration.

 

“FAA Determination” means either an FAA No Hazard Determination or an FAA Determination Not to Exceed, in either case issued by the FAA with respect to a WTG Location.

 

“FERC” means the Federal Energy Regulatory Commission.

 

“Final Order” means a final order of a court of competent jurisdiction, (i) from which there is no right of appeal to a higher court or (ii) with respect to which either (A) all applicable time periods during which an appeal may be made have expired or (B) no appeal has been made within a period of two months from issuance of an appealable order, whichever is the earliest to occur.

 

- 6 - 

 

 

“Fitch” means Fitch Ratings Inc.

 

“FPA” means the Federal Power Act, as amended.

 

“Framework Agreement” means that certain contract between EDF-EN and Vestas France SAS for the purchase of certain WTGs or components and executed on January 19, 2016.

 

“Geotechnical Report” means the report with respect to the geotechnical borings and analysis conducted for each WTG Location to be prepared by a geotechnical engineering firm selected by Sellers and approved by Buyer (such approval not to be unreasonably withheld), which shall be delivered to Buyer in final form pursuant to Section 7.2(n).

 

“GIA” means either (a) the Existing GIA, or (b) if the Existing GIA is not determined prior to Closing to be valid and outstanding and it is deemed to be terminated, the New GIA.

 

“GIA Delay Damages” means an amount of liquidated damages resulting from a failure of the closing condition in Section 7.2(t) to be met, equal to (a) $[**], multiplied by (b) the number of megawatts of nameplate capacity which are not able to operate following the Commercial Operation Date until the limitations specified in the Interconnection Notice have been cured, multiplied by (c) the number of days in the period between the Commercial Operation Date until the date the limitations specified in the Interconnection Notice have been cured.

 

“Governmental Authority” means any court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States or any state, county, city or other political subdivision or similar governing entity, and including any governmental, quasi-governmental or non-governmental body administering, regulating or having general oversight over natural gas, electricity, power or other markets.

 

“Guarantor” has the meaning given such term in the TEPC.

 

“Hazardous Material” means any substance pollutant, contaminant, chemical, material or waste that is regulated, listed or identified under any Environmental Law, or which is deemed or may be deemed hazardous, dangerous, damaging or toxic to living things or the environment, and shall include, without limitation, any flammable, explosive, or radioactive materials; hazardous materials; radioactive wastes; hazardous wastes; hazardous or toxic substances or related materials; polychlorinated biphenyls; petroleum products, fractions and by-products thereof; asbestos and asbestos-containing materials; medical waste, solid waste, and any excavated soil, debris, or groundwater that is contaminated with such materials; any hazardous substance under the Comprehensive Environmental Response, Compensation and Liability Act, as amended (42 U.S.C.A. § 9601 et seq.), any solid waste under the Resource Conservation and Recovery Act of 1976, as amended (42 U.S.C.A. § 6901 et seq.), or any contaminant, pollutant, waste or toxic substance under the Clean Air Act, as amended (42 U.S.C.A. § 7401 et seq.), the Federal Water Pollution Control Act, as amended (33 U.S.C.A. § 1251 et seq.), the Safe Drinking Water Act, as amended (42 U.S.C.A. § 300f et seq.), the Emergency Planning and Community Right-To-Know Act, as amended (42 U.S.C.A. sec. 110001 et seq.), the Occupational Safety and Health Act, as amended (29 U.S.C.A. sec. 651 et seq.), the Hazardous Materials Transportation Act, as amended, (49 U.S.C.A. sec. 5101 et seq.) or the Toxic Substances Control Act, as amended (15 U.S.CA. § 2601 et seq.).

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

 

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“Indemnified Party” means a Person entitled to be indemnified by another Person pursuant to the terms of this Agreement.

 

“Indemnifying Party” means a Person required to indemnify another Person pursuant to the terms of this Agreement.

 

“Indemnity Amount Payable” means any Indemnity Claim Amount which has become an Indemnity Amount Payable in accordance with Article 9, plus interest on such Indemnity Claim Amount at the Interest Rate commencing ten (10) Business Days after the date it becomes an Indemnity Amount Payable.

 

“Indemnity Claim” means any claim made for indemnification in accordance with Article 9.

 

“Indemnity Claim Amount” means the amount of Losses claimed in any Notice of Claim, which amount, if not finally determined, may be a good faith estimate of the Losses that may be subject to indemnification pursuant to this Agreement.

 

“Independent Accountant” means any of the “Big Four” independent accounting firms or such other accounting firm mutually selected by Buyer and Sellers, other than any such firm that regularly provides audit services to Buyer or Sellers.

 

“Interconnection Costs” means either the NRIS Interconnection Costs or the ERIS Interconnection Costs, as the case may be.

 

“Interconnection Notice” is defined in Section 8.1(d).

 

“Interest Rate” means LIBOR plus three percent (3%).

 

“International Financial Reporting Standards” or “IFRS” means the accounting standards developed and maintained by the International Accounting Standards Board.

 

“Knowledge” means, when used in a particular representation in this Agreement with respect to Sellers, the actual knowledge of any of the Persons listed on Schedule 1.1, together with such knowledge as such individuals would reasonably have obtained in the ordinary course of their duties.

 

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“Land Contracts” means all easement and lease agreements contemplated to construct and operate the Project (together with any amendments thereto and any associated recorded memoranda), including (a) all easements required for sufficient land to site eighty (80) contiguous WTG Locations in accordance with the Site Plan (b) wind leases or easements for purposes of creating a leasehold and/or easement interest in wind rights associated with such real property included in the Site for buffers, set-backs or otherwise not associated with WTG Locations; and (c) to the extent not included in the foregoing, easements for collection cables, electrical transmission lines, crane paths and access road routes; provided, that, in each case, such easement and lease agreements shall have an operating period of at least thirty (30) years from the Commercial Operation Date (as extended pursuant to Section 6.11) and shall be freely transferable, in whole or in part, without consent of the landowners.

 

“Laws” means all laws, statutes, rules, regulations, ordinances, orders, decrees, court decisions, and other pronouncements having the effect of law of any Governmental Authority.

 

“Liability” or “Liabilities” means all debts, liabilities, obligations, Contracts and commitments, whether known or unknown, asserted or unasserted, fixed, absolute or contingent, matured or unmatured, accrued or unaccrued, liquidated or unliquidated, due or to become due, whenever or however arising (including, whether arising out of any Contract or tort based on negligence, strict liability or otherwise).

 

“LIBOR” means, for any day, a rate per annum equal to the “London Interbank Offered Rate (Libor)” for a three (3) month period as set forth in the Money Rates section of The Wall Street Journal, Western Regional Edition (“The Wall Street Journal”), on such day (or, if The Wall Street Journal is not published on such day, the next preceding Business Day on which The Wall Street Journal is so published); provided that, if The Wall Street Journal is no longer published or the applicable LIBOR rate is no longer quoted therein, then “LIBOR” shall be a reasonably comparable rate as shall be mutually agreed upon by Buyer and Sellers.

 

“Lien” means, with respect to any property or other assets of a Person, any lien, charge, claim, community property interest, pledge, mortgage, hypothecation, condition, equitable interest, option, security agreement, deed of trust, encumbrance, easement, encroachment, license, sublicense, right of first refusal, right of first offer, or other restriction of any kind, including any restrictions on use, voting, transfer receipt of income or exercise of any other attribute of ownership.

 

“Loss” means any and all actual losses, liabilities, amounts paid in settlement, damages, fines, penalties, costs, charges, Taxes, obligations, demands, fees, interest, losses and expenses (including court costs and reasonable fees of attorneys, accountants and other experts in connection with any Claim).

 

“Material Adverse Effect” means an event, change, occurrence, circumstance, development or effect, which, individually or when taken together with the effect of all other events or circumstances has had or could reasonably be expected to have a material adverse effect on the business, assets, properties, liabilities, condition (financial or otherwise) or results of operations of the Project or the Purchased Assets; provided, however, that the following will not be considered when determining whether a Material Adverse Effect has occurred: any change, event, effect or occurrence (or changes, events, effects or occurrences taken together) resulting from (a) any change generally affecting the international, national or regional electric generating, transmission or distribution industry; (b) any change generally affecting the international, national or regional wholesale or retail markets for electric power; (c) any change generally affecting the wind-generated energy business generally, (d) any change in general regulatory or political conditions, including any engagements of hostilities, acts of war or terrorist activities or changes imposed by a Governmental Authority associated with additional security; (e) any change in any Laws, IFRS or other applicable accounting or auditing standards or industry standards; (f) any change in the financial condition or results of operation of Sellers caused solely by the transactions contemplated by this Agreement; (g) any change in the financial, banking, or securities markets (including any suspension of trading in, or limitation on prices for, securities on the New York Stock Exchange, American Stock Exchange, or Nasdaq Stock Market) or any change in the general national or regional economic or financial conditions; or (h) any actions required to be taken pursuant to or in accordance with this Agreement, except in the case of (a), (b) and (c), to the extent such effect has a materially disproportionate impact on the Project as compared to other similarly situated wind development projects.

 

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“Merricourt” is defined in the introduction to this Agreement.

 

“MET Towers” means four (4) temporary meteorological towers installed on the Site in accordance with industry practice and standards, with related meteorological equipment.

 

“MISO” means the Midcontinent Independent Transmission System Operator, Inc. or its successors.

 

“MNPUC” means the Minnesota Public Utilities Commission.

 

“Moody’s” means Moody’s Investors Service, Inc.

 

“NDPSC” means the North Dakota Public Service Commission.

 

“Network Integration Transmission Service“ has the meaning given to such term in the MISO FERC Electric Tariff.

 

“Network Resource Interconnection Service” has the meaning given to such term in the MISO FERC Electric Tariff.

 

“New Exceptions” is defined in Section 6.14(c).

 

“New GIA” means the Generator Interconnection Agreement to be entered into for MISO Interconnection Queue Request J457, together with all other rights in MISO Interconnection Queue Request J457 and all associated studies, reports and communications with MISO related thereto.

 

“Noise Study” means a study with respect to the compliance of the Project as designed with noise standards to be completed by Sellers, or another qualified consultant selected by Sellers and approved by Buyer (such approval not to be unreasonably withheld) and delivered to Buyer in final pursuant to Section 7.2(n).

 

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“NRIS Interconnection Costs” means the network upgrade costs associated with the New GIA for Network Resource Interconnection Service. For the avoidance of doubt, NRIS Interconnection costs shall include network upgrade costs regardless of whether they are assigned to the Project by MISO or by any other RTO or transmission owner, but shall not include any reimbursable costs.

 

“Obstacle Evaluation Study” means an obstacle evaluation study to be prepared by Capitol Airspace Group, or another consultant selected by Sellers and approved by Buyer (such approval not to be unreasonably withheld), which shall be delivered to Buyer in final form pursuant to Section 7.2(n).

 

“Owned Real Property” means the fee simple interests in real property, and the fixtures located thereon and affixed thereto, the privileges and appurtenances therein and thereto, suitable for an operating and maintenance facility and collection substation(s) within the Project boundaries in accordance with the Site Plan, which real property shall not be subject to any further governmental approval or conditions in order to initiate construction other than obtaining building permits, which building permits shall be obtained as provided in the TEPC.

 

“Ordinary course of business” means, with respect to any Person, its ordinary course of business consistent with its past practice.

 

“Organizational Documents” means, with respect to any Person, the articles or certificate of incorporation or organization and by-laws, the limited partnership agreement, the partnership agreement or the limited liability company agreement, member control agreement, trust agreement, or other organizational documents of such Person.

 

“Outside Date” means July 1, 2019; provided that if, on or before July 1, 2019, Buyer issues a Limited Notice to Proceed (as defined in the TEPC) pursuant to the TEPC, the Outside Date shall be extended to September 1, 2019.

 

“Parties” means collectively, Buyer and Sellers.

 

“Permits” means all licenses, permits, certificates of authority, authorizations, approvals, registrations, franchises and similar consents and orders issued or granted by a Governmental Authority necessary for the siting, ownership and operation of the Project (other than permits to be delivered under the TEPC), including the Certificate of Site Compatibility.

 

“Permitted Lien” means (a) any Lien for Taxes not yet due and payable; (b) utility easements, building restrictions and such other imperfections of title that (i) are of a nature generally existing with respect to properties of a similar character, (ii) do not present any risk of sale or forfeiture of the Asset subject to the Lien, and (iii) which do not materially detract from the value or materially interfere with the construction, operation or maintenance of the Project as contemplated in the Site Plan; (c) mechanics', carriers', workmen's, repairmen’s or other like liens arising or incurred in the ordinary course of business that are not yet due and payable or being contested in good faith by appropriate procedures; (d) zoning ordinances affecting Project Real Property; (e) the terms and conditions of the Purchased Contracts and the Permits listed on Schedule 4.11(a); (f) Existing Permitted Exceptions; and (g) any other Lien created or permitted with the written consent of Buyer; provided, for the avoidance of doubt, that nothing in this definition shall limit Buyer’s right to indemnification under Section 9.2(e) related to Losses arising from Taxes accrued before or through the Closing Date.

 

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“Person” means any natural person, corporation, general partnership, limited partnership, limited liability company, proprietorship, other business organization, trust, union, association or Governmental Authority.

 

“Post-Construction Guaranty” has the meaning given such term in the TEPC.

 

“Post-Construction Guaranty Expiration” has the meaning given such term in the TEPC.

 

“PPM” is defined in the introduction to this Agreement.

 

“Prime Subcontract” has the meaning given it in the TEPC.

 

“Project” means the complete integrated wind-powered electricity generating plant, consisting of the infrastructure facilities and the WTGs, with a nominal nameplate capacity of 150 megawatts to be located on the Site to be developed, designed, procured, constructed, interconnected, tested and commissioned under TEPC, including all structures, facilities, appliances, lines, conductors, instruments, equipment, apparatus, components, roads and other real and personal property and/or Real Property Rights comprising and integrating the entire facility described generally in the Technical Specifications (as defined in the TEPC).

 

“Project Commercial Operation” means the achievement of Project Substantial Completion (as such term is defined in the TEPC).

 

“Project Substantial Completion Date” has the meaning given such term in the TEPC.

 

“Project Surety Bond” has the meaning given such term in the TEPC.

 

“Protected Species” means all species and their associated habitat protected by the Endangered Species Act, 16 U.S.C. § 1531 et seq., the Migratory Bird Treaty Act 16 U.S.C § 703 et seq., the Bald and Golden Eagle Protection Act 16 U.S.C § 668 et seq., and applicable state and local counterparts, and their implementing regulations and guidance documents.

 

“Prudent Industry Practices” has the meaning given it in the TEPC.

 

“PTC” means production tax credits under Section 45 of the Code.

 

“PTC Advance Payment” means the payment described in Section 4.16(d).

 

“PTC Guidance” means any of IRS Notices 2013-29, 2013-60, 2014-46, 2015-25 or 2016-31 or any future written (electronic or otherwise) commentary, guidance, rule, regulation, notice or ruling in relation to the requirements under Section 45 of the Code.

 

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“PTC Representations” is defined in Section 9.1.

 

“PUHCA” means the Public Utility Holding Company Act of 2005, as amended.

 

“Purchase Price” is defined in Section 2.5(a).

 

“Purchased Assets” is defined in Section 2.1.

 

“Purchased Contracts” is defined in Section 4.9(a).

 

“Qualified Institution” means (i) the United States office of a commercial bank or trust company (which is not an Affiliate of either party) organized under the laws of the United States (or any state or a political subdivision thereof), or (ii) the United States branch of a foreign bank (which is not an Affiliate of either party), in either case having assets of at least $10 billion, and having Credit Ratings from two Ratings Agencies of at least A3 (in the case of Moody's) or A- (in the case of S&P or Fitch).

 

“Rating Agencies” means S&P, Moody’s and Fitch.

 

“Real Property Interests” means the real property interests created under the Land Contracts and the Owned Real Property.

 

“Regulatory Approval” means the following approvals from the specified Governmental Authorities: (i) the issuance of a final and nonappealable amended Certificate of Site Compatibility by the NDPSC; (ii) approval by the NDPSC of matters impacting the Project, including approval of the transfer to Buyer of the amended Certificate of Site Compatibility and approval of Buyer’s request for an advance determination of prudency, in form and substance reasonably satisfactory to Buyer, (iii) the approval of the MNPUC, in form and substance reasonably satisfactory to Buyer, and (iv) any other approvals that may be necessary for Buyer to purchase the Purchased Assets and construct, own and operate the Project but only to the extent such approvals relate to any new Laws or any amendments to existing Laws, in each case enacted after the date of this Agreement.

 

“Release” means any release, spill, emission, leaking, pumping, injection, deposit, pouring, emptying, leaching, dumping, disposal or discharge of any Hazardous Materials into the environment or workplace, and otherwise as defined in any Environmental Law.

 

“Reports” means (a) a Phase I Environmental Site Assessment dated within 180 days of the Closing Date and prepared by a qualified environmental consulting firm and any Phase II Environmental Site Assessments if required; (b) the Avian Assessment; (c) the Bat Assessment; (d) the Cultural Resource Study; (e) the Wetlands Assessment; (f) the Standard Broadcast Site Review Study; (g) the Obstacle Evaluation Study; (h) the Geotechnical Report; (i) the Noise Study; and (j) any additional study or report necessary for the development, permitting, construction, operation or transfer of the Project or the Purchased Assets.

 

“Representatives” means, as to any Person, its officers, directors, partners, members, stockholders, or other equity holders, and employees, counsel, accountants, financial advisors and consultants.

 

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“Required Consents” is defined in Section 7.2(i).

 

“Review Period” is defined in Section 6.15.

 

“RTO” means a Regional Transmission Organization, including, without limitation, MISO, the Southwest Power Pool, and PJM.

 

“S&P” means Standard and Poor’s Ratings Services, a division of The McGraw Hill Companies, Inc.

 

“Schedules” means the disclosure schedules for this Agreement.

 

“Sellers” is defined in the introduction to this Agreement.

 

“Seller Group” is defined in Section 9.3.

 

“Signing Milestone Payment” is defined in Section 2.5

 

“Site” means all those parcels of land that are subject to the Real Property Interests on which the Project will be located, as more particularly described in Exhibit E attached hereto.

 

“Site Plan” means the site layout of the Project, including the intended WTG Location of each of the seventy-five (75) WTGs, at least five (5) alternate WTG Locations, preliminary collection, substation and civil designs, access roads, communication lines, and set-backs of the WTG Locations from roads and other structures, which such Site Plan shall overlay the Site and show the location of existing roads, buildings, and other structures.

 

“SMA” is defined in Schedule 4.3(a).

 

“Standard Broadcast Site Review Study” means the Engineering Report Concerning Effects Upon FCC Licensed RF Facilities Due to Construction of the Project to be prepared by Evans Engineering Solutions, or another consultant selected by Sellers and approved by Buyer (such approval not to be unreasonably withheld), which shall be delivered to Buyer in final form pursuant to Section 7.2(n).

 

“Survey” means a survey prepared by Kadrmas, Lee & Jackson (or such other firm reasonably acceptable to Sellers, Buyer and the Title Company licensed in the State of North Dakota) of the Owned Real Property and the real property covered by the Land Contracts certified to Buyer and the Title Company, in form and substance reasonably acceptable to Buyer, including an overlay of the Site Plan and sufficient for the Title Company to provide survey coverage in the Title Policy in compliance with the “2016 Minimum Standard Detail Requirements for ALTA/NSPS Land Title Surveys” jointly established and adopted by the American Land Title Association and the National Society of Professional Surveyors effective February 23, 2016 showing and including optional items 3, 4, 6(b), 7(a), 7(c) for the Owned Real Property, 8, 11, 13, 14, 16, 17, 18 and 19 and disclosing the location of all improvements, plottable easements, encroachments, roadways, utility lines, set back lines, wetlands and other matters shown customarily on such windpark surveys, and showing access affirmatively to public streets and roads.

 

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“Tangible Net Worth” means, with respect to any Person, the aggregate of its tangible assets (total assets less intangibles) less the aggregate of its liabilities as documented in its annual audited financial statement.

 

“Tax” or “Taxes” means any federal, state, local or foreign income, gross receipts, ad valorem, sales and use, employment, social security, disability, occupation, property, severance, value added, transfer, capital stock, excise, withholding, premium, occupation or other taxes, levies or other like assessments, customs, duties, imposts, charges surcharges or fees imposed by or on behalf of any Governmental Authority, including any interest, penalty thereon or addition thereto.

 

“Tax Authority” means, with respect to any Tax, the governmental entity or political subdivision thereof that imposes such Tax, and the agency (if any) charged with the collection of such Tax for such entity or subdivision.

 

“Tax Counsel” means Akin Gump Strauss Hauer & Feld, or other nationally recognized tax counsel selected by Buyer and reasonably acceptable to Sellers.

 

“Tax Return” means any report, form, claim for refund, return, statement or other information (including any amendments) required to be supplied to any Person with respect to Taxes, including information returns, any amendments thereof or schedule or attachment thereto.

 

“TEPC” is defined in the recitals to this Agreement.

 

“Third-Party Claim” is defined in Section 9.5(a).

 

“Title Commitment” means an irrevocable American Land Title Association (ALTA) 2006 Commitment for Title Insurance prepared by the Title Company for the Owned Real Property and each parcel of real property covered by the Land Contracts, and including searches for real estate taxes, pending and levied special assessments, judgments, bankruptcies and state and federal tax liens as of the date of the Title Commitment, together with a legible copy of all underlying documents identified on the Title Commitment.

 

“Title Company” means Chicago Title Insurance Company or such other title company mutually acceptable to the Parties.

 

“Title Evidence” is defined in Section 6.14(c).

 

“Title Objection” is defined in Section 6.14(c).

 

“Title Objection Letter” is defined in Section 6.14(c).

 

“Title Policy” means an American Land Title Association (ALTA) 2006 Owner’s Policy of Title Insurance, insuring the Real Property Interests in an amount equal to the sum of the Purchase Price and the Agreement Price (as such term is defined in the TEPC) or such other amount specified by Buyer and issued by the Title Company, subject only to the Permitted Liens and in form and substance reasonably acceptable to Buyer, and providing for (a) full extended coverage over all general title exceptions contained in such policy provided that such coverage is available in the state of North Dakota, (b) the special endorsements set forth on Exhibit I with full extended coverage, (c) deletion of standard exceptions, including but not limited those general standard exceptions based on (i) mechanics or materialmen’s liens, (ii) matters affecting title that may be disclosed by an accurate survey, and (iii) the rights of parties in possession except tenants in possession, (d) endorsements for zoning, survey, owner’s comprehensive, non-imputation, access, deletion of mandatory arbitration, subdivision, contiguity, tax parcel, environmental, energy and any other endorsements reasonably requested by the Buyer and available in North Dakota, and (e) such additional affirmative coverage as the Buyer may reasonably request.

 

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“Turbine Supply Agreement” has the meaning given it in the TEPC.

 

“Update” is defined in Section 6.8.

 

“USFWS” means the United States Fish & Wildlife Service.

 

“Vestas” is defined in the recitals to this Agreement.

 

“Wetlands Assessment” means the wetlands study with respect to the Site to be prepared by Kadrmas, Lee & Jackson, or another consultant selected by Sellers and approved by Buyer (such approval not to be unreasonably withheld), which does not indicate any further permitting or mitigation required pursuant to the Clean Water Act and which shall be delivered to Buyer in final form pursuant to Section 7.2(n).

 

“Wind Data” means any and all raw wind speed data and other relevant wind characteristics data obtained by or on behalf of Sellers or any of their Affiliates or representatives in respect to the Project, along with all supporting documentation.

 

“Wind Study” means the wind data study prepared by AWS Truepower, Inc. and delivered to Buyer prior to the date of this Agreement.

 

“WTG” or “WTGs” is defined in the recitals to this Agreement.

 

“WTG Location” means the location of each of seventy-five (75) WTGs and at least five (5) additional alternate WTG locations, in each case as shown in the Site Plan.

 

Section 1.2           Rules of Construction.

 

(a)          All article, section, subsection, schedule and exhibit references used in this Agreement are to articles, sections, subsections, schedules and exhibits to this Agreement unless otherwise specified. The exhibits and schedules attached to this Agreement constitute a part of this Agreement and are incorporated in this Agreement for all purposes.

 

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(b)          If a term is defined as one part of speech (such as a noun), it will have a corresponding meaning when used as another part of speech (such as a verb). Unless the context of this Agreement clearly requires otherwise, words importing the masculine gender will include the feminine and neutral genders and vice versa. The words “includes” or “including” will mean “including without limitation,” the words “hereof,” “hereby,” “herein,” “hereunder” and similar terms in this Agreement will refer to this Agreement as a whole and not any particular Section or article in which such words appear. The term “will” and “shall” have the same meaning. Any reference to a Law includes any amendment thereof or any successor thereto and any rules and regulations promulgated thereunder, whether prior to or after the date of this Agreement. Any reference to a Contract will be to that Contract as it may have been amended, modified, supplemented or restated prior to the date hereof. Currency amounts referenced in this Agreement are in U.S. Dollars. The words “unreasonably withheld” and similar terms in this Agreement will mean “unreasonably withheld, conditioned or delayed”.

 

(c)          Whenever this Agreement refers to a number of days, such number will refer to calendar days unless Business Days are specified. Whenever any action must be taken hereunder on or by a day that is not a Business Day, then such action may be validly taken on or by the next day that is a Business Day. For determining any period of time, “from” means “including and after,” “to” means “to but excluding” and “through” means “through and including.”

 

(d)          Each Party acknowledges that it and its attorneys have been given an equal opportunity to negotiate the terms and conditions of this Agreement and that any rule of construction to the effect that ambiguities are to be resolved against the drafting Party or any similar rule operating against the drafter of an agreement will not be applicable to the construction or interpretation of this Agreement.

 

(e)          All accounting terms used herein and not expressly defined herein will have the respective meanings given such terms under IFRS.

 

(f)          Whenever this Agreement states that any document has been “made available,” unless otherwise expressly provided herein, that means the document was available in the Data Site or otherwise delivered to Buyer or any of its Affiliates prior to the date such statement is effective.

 

Article 2

PURCHASE AND SALE

 

Section 2.1           Purchase and Sale of Assets. On the terms and subject to the conditions set forth in this Agreement, on the Closing Date, or in the case of the COD Purchased Contracts, on the Commercial Operation Date, Sellers shall sell, assign, transfer, convey and deliver to Buyer (or its assignees as to certain assets), and Buyer shall purchase from Sellers, free and clear of any Liens other than Permitted Liens, all right, title and interest in, to and under all of the Assets of Sellers related to the development, construction and operation of the Project, wherever located and whether now existing or hereafter acquired (other than the Excluded Assets) (collectively, the “Purchased Assets”) in accordance with the Deeds, Bills of Sale and Assignment and Assumption Agreements, including, without limitation, the following:

 

(a)          the Permits and Permit applications;

 

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(b)          the Owned Real Property, including all ownership documents related thereto;

 

(c)          the Land Contracts;

 

(d)          the Purchased Contracts, including the GIA;

 

(e)          an FAA Determination with respect to each WTG Location;

 

(f)           the final versions of the Reports;

 

(g)          the Bird and Bat Conservation Strategy;

 

(h)          the Site Plan;

 

(i)           the Wind Data (provided, that EDF-USD automatically and without further action shall be granted an irrevocable, perpetual, royalty-free, non-exclusive license to use such Wind Data);

 

(j)           the MET Towers;

 

(k)          the 5% Safe Harbor Turbines, provided, that in the event that some or all of the 5% Safe Harbor Turbines are determined prior to the Closing Date not to qualify the Project for 100% PTCs, then in accordance with Section 6.16 such other Vestas 2.0MW V110 wind turbine components owned by Sellers or any Affiliates of Seller necessary for the Project to qualify for 100% PTCs shall be substituted for the 5% Safe Harbor Turbines;

 

(l)           any other Books and Records; and

 

(m)         any other assets reasonably necessary to achieve Project Commercial Operation.

 

Section 2.2           Excluded Assets. Notwithstanding the foregoing, the Purchased Assets shall not include the following assets (all Assets other than the Purchased Assets, collectively, the “Excluded Assets”):

 

(a)          any equity interests of Sellers or owned by Sellers;

 

(b)          all identification numbers, seals, minute books, software, and other documents relating to the organization, maintenance, and existence of Sellers or their Affiliates as business entities;

 

(c)          cash and cash equivalents; and

 

(d)          any of the rights of Sellers or their Affiliates under this Agreement, the Ancillary Agreements or the TEPC.

 

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Section 2.3           Assumed Liabilities. Subject to the terms and conditions set forth herein, Buyer shall assume and agree to pay, perform and discharge only the following Liabilities of Sellers (collectively, the “Assumed Liabilities”) in accordance with the Assignment and Assumption Agreements, and no other Liabilities:

 

(a)          the Permitted Liens;

 

(b)          those obligations of Sellers accruing or arising, or covenants or agreements of Sellers to be performed (other than indemnification obligations for matters accruing or arising prior to the Closing Date), from and after the Closing Date under the Land Contracts, Purchased Contracts (other than the GIA and the COD Purchased Contracts), Permits, and Permit applications;

 

(c)           Buyer’s portion of the costs associated with the GIA as set forth in Section 6.10;

 

(d)           Those obligations of EDF-USD accruing or arising, or covenants or agreements of Sellers to be performed (other than indemnification obligations for matters accruing or arising prior to the Project Substantial Completion Date), from and after the Project Substantial Completion Date under the SMA; and

 

(e)           other than as provided for in this Agreement, any Liability arising from and after the Closing Date with respect to the ownership or operation of the Purchased Assets and the Project.

 

Section 2.4           Excluded Liabilities. Notwithstanding the provisions of Section 2.3 or any other provision in this Agreement to the contrary, Buyer shall not assume and shall not be responsible to pay, perform or discharge any Liabilities of Sellers or any of their Affiliates of any kind or nature whatsoever other than the Assumed Liabilities (the “Excluded Liabilities”). Sellers shall, and shall cause each of their Affiliates to, pay and satisfy in due course all Excluded Liabilities which they are obligated to pay and satisfy. Without limiting the generality of the foregoing, the Excluded Liabilities shall include, but not be limited to, the following:

 

(a)           any Liabilities relating to the Project or any present or former developer, owner or operator of the Project incurred prior to the Closing Date, whether or not associated with, or arising from, any of the Purchased Assets, and whether fixed, contingent or otherwise, known or unknown;

 

(b)           any Liabilities related to the Excluded Assets;

 

(c)           any Liability of Sellers for Taxes accrued before or through the Closing Date with respect to Purchased Assets;

 

(d)           any Liability of Sellers for costs and expenses incurred in connection with this Agreement and the transactions contemplated hereby;

 

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(e)           any Liability under the Land Contracts, Purchased Contracts (other than the GIA), Permits or Permit applications to the extent such Liability, but for a breach or default by Sellers or a waiver or extension given to or by Sellers, would have been paid, performed or otherwise discharged on or prior to the Closing Date or to the extent such Liability arises out of any such breach, default, waiver or extension given to or by Sellers;

 

(f)           any obligations owed to any Governmental Authority arising out of commitments (other than Permits or Purchased Contracts) which were made by Sellers prior to the Closing Date;

 

(g)           Sellers’ portion of the costs associated with the GIA as set forth in Section 6.10;

 

(h)           any Environmental Claims, or Liabilities under Environmental Laws, to the extent arising out of any actions or omissions of Sellers on or prior to the Closing Date; and

 

(i)            any Liabilities arising out of, in respect of or in connection with the failure by Sellers or any of their Affiliates to comply with any Law on or prior to the Closing Date.

 

Section 2.5           Purchase Price; Closing Payment.

 

(a)          The purchase price (the “Purchase Price”) for the purchase and sale described in Section 2.1 is equal to $34,682,118.

 

(b)          On the date hereof, Buyer shall pay to Sellers by wire transfer of immediately available funds (to such account or accounts as Sellers will have notified Buyer of no later than two (2) Business Days prior to the date hereof) an amount equal to [**] ($[**]) (the “Signing Milestone Payment”), which amount shall be nonrefundable absent fraud or intentional misconduct or a termination of this Agreement by Sellers pursuant to Section 8.1(l).

 

(c)          At the Closing, Buyer shall pay to Sellers by wire transfer of immediately available funds (to such account or accounts as Sellers will have notified Buyer of no later than two (2) Business Days prior to the Closing Date) an amount equal to the Purchase Price, less the Signing Milestone Payment.

 

Section 2.6           Allocation of Purchase Price. Within ninety (90) days after Closing, Buyer will provide Sellers a schedule proposing how to allocate the Purchase Price among the Purchased Assets.  Sellers will have thirty (30) Business Days following receipt of Buyer’s proposed allocation to propose changes.  In the event there are proposed changes, the Parties will work promptly and in good faith to resolve the differences. Failing agreement, they will jointly select an Independent Accountant to resolve the differences. Except to the extent otherwise required by Law, Buyer and Sellers will, and will cause their Affiliates to, report the transaction for Tax and other purposes consistently with the final Purchase Price allocation.

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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Article 3

PURCHASE AND SALE AND CLOSING

 

Section 3.1           Closing. The Closing will take place at the offices of Dorsey & Whitney LLP, 50 South Sixth Street, Suite 1500, Minneapolis, Minnesota, or by remote electronic exchange of documents (by facsimile, .pdf, e-mail, or other form of electronic communication) on the later to occur of (a) July 1, 2018 and (b) a mutually acceptable date within fifteen (15) days after satisfaction of all closing conditions, including either execution of the New GIA or reinstatement of the Existing GIA, or at such other time, place and date as the Parties may agree in writing. All actions listed in Section 3.2 or Section 3.3 that occur on the Closing Date will be deemed to occur simultaneously at the Closing. The Closing will be deemed to be effective as of 11:59:59 p.m. Central Time on the Closing Date.

 

Section 3.2           Closing Deliveries by Sellers to Buyer. At the Closing, Sellers shall deliver to Buyer (or the Title Company in the case of (i) and (k)):

 

(a)          a Deed for the Owned Real Property;

 

(b)          an executed counterpart by each Seller of an Assignment and Assumption Agreement;

 

(c)          an executed counterpart by each Seller of a Bill of Sale;

 

(d)          a certification of non-foreign status in the form prescribed by Treasury Regulation Section 1.1445-2(b) with respect to each Seller;

 

(e)          an executed counterpart by each Seller of each other Ancillary Agreement to be executed and delivered at the Closing to which Seller is a party;

 

(f)           the Closing deliverables described in Section 7.2 below;

 

(g)          copies of the Required Consents;

 

(h)          a standard form of seller’s affidavit of title as required by the Title Company;

 

(i)           the Title Policy, payment of the fees incurred for the Title Commitments, Surveys and those fees and costs allocated to and payable by Sellers in accordance with the Title Company’s settlement statement;

 

(j)           a recordable assignment and assumption agreement for each Land Contract; and

 

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(k)          any other documents reasonably determined by the Title Company to be necessary to transfer the Owned Real Property to Buyer.

 

Section 3.3           Closing Deliveries by Buyer to Sellers. At the Closing, Buyer shall deliver to Sellers (or the Title Company in the case of (f)):

 

(a)          an executed counterpart by Buyer of the Assignment and Assumption Agreement;

 

(b)          an executed counterpart by Buyer of a Bill of Sale;

 

(c)          payment of the Purchase Price (less the Signing Milestone Payment;

 

(d)          the Closing deliverables described in Section 7.3 below;

 

(e)          an executed counterpart by Buyer of each other Ancillary Agreement to be executed and delivered at the Closing to which Buyer is a party; and

 

(f)           payment of the Title Policy premium and those fees and costs allocated to and payable by Buyer in accordance with the Title Company’s settlement statement.

 

Section 3.4           Exclusivity. From and after the date of execution and until Closing or this Agreement is otherwise terminated in accordance with its terms (“Exclusivity Period”), Sellers shall not contract or negotiate to contract for the sale, lease, or hypothecation of the Project or the Purchased Assets, or for the sale of energy from the Project, and no commitment with respect to the Project will be entered into during the Exclusivity Period to proceed with any third party immediately following termination of this Agreement.

 

Article 4

REPRESENTATIONS AND WARRANTIES OF SELLERS

 

The Sellers hereby jointly and severally represent and warrant to Buyer that each and all of the following representations and warranties set forth in this Article 4 (as modified by the applicable section of the Schedules) are true and correct as of the date of this Agreement and as of the Closing Date (except for such representations and warranties that speak as of a specific date, in which case such representations and warranties are true and correct as of such date):

 

Section 4.1           Organization. Such Seller is validly existing and in good standing under the Laws of the State of Delaware, and has all requisite power and authority to conduct its business as it is now being conducted and to develop, own, operate, lease and sell the Purchased Assets. Such Seller is duly qualified or licensed to do business and is in good standing in each jurisdiction in which such qualification or licensure is necessary, except in those jurisdictions where the failure to be so duly qualified or licensed would not have a Material Adverse Effect. Sellers have made available to Buyer all of the Organizational Documents of Sellers as in effect on the date of this Agreement.

 

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Section 4.2           Authority; Enforceability. Such Seller has all requisite limited liability company or corporate power and authority to execute and deliver this Agreement and the Ancillary Agreements to which such Seller is a party, to perform its obligations hereunder and thereunder and to consummate the transactions contemplated hereby and thereby. The execution and delivery by such Seller of this Agreement and the Ancillary Agreements to which such Seller is a party, and the performance by such Seller of its obligations hereunder and thereunder, have been duly and validly authorized by all necessary limited liability company or corporate action. This Agreement has been, and each Ancillary Agreement to which such Seller is a party has been, duly and validly executed and delivered by such Seller and constitutes the legal, valid and binding obligation of such Seller enforceable against such Seller in accordance with its terms, except as the same may be limited by bankruptcy, insolvency, reorganization, fraudulent conveyance, arrangement, moratorium or other similar Laws relating to or affecting the rights of creditors generally, or by general equitable principles.

 

Section 4.3           No Conflicts; Consents and Approvals.

 

(a)          The execution and delivery by Sellers of this Agreement and the Ancillary Agreements to which each Seller is a party, the performance by Sellers of their obligations hereunder and thereunder and the consummation of the transactions contemplated hereby and thereby and the taking of any action contemplated to be taken by Sellers hereunder or thereunder do not (i) result in a violation or breach of any of the terms, conditions or provisions of the Organizational Documents of Sellers; (ii) except as set forth on Schedule 4.3(a), (A) result in a violation or breach of any term or provision of any Law, Permit or order applicable to Sellers or any of the Purchased Assets; or (B) cause a Default, or require the Consent of any Person, under any Purchased Contract, Land Contract, Real Property Interest or Permit; or (iii) result in the imposition or creation of any Lien, other than Permitted Liens, on any of the Purchased Assets or the Project.

 

(b)          Other than as set out in Schedule 4.3(b), no Consent of any Governmental Authority or any other Person is required to be made or obtained by Sellers in connection with the execution and delivery of this Agreement and the Ancillary Agreements or the consummation of the transactions contemplated hereby and thereby.

 

Section 4.4           Title to Assets

 

(a)          Sellers have good, valid and marketable title to, or rights by Contract or other agreement to use, all of the Purchased Assets free and clear of all Liens (except for Permitted Liens).

 

(b)          As of the Closing, the Purchased Assets, together with all rights of Buyer under the TEPC, will constitute Assets sufficient to reach Project Commercial Operation, subject to the terms and conditions under the TEPC.

 

Section 4.5           Legal Proceedings. Except as set forth on Schedule 4.5, no Claim is pending, and to Seller’s Knowledge, none has been threatened in writing, (a) relating to, arising out of or affecting the Purchased Assets or the Project or (b) seeking a writ, judgment, order, injunction or decree restraining, enjoining or otherwise prohibiting or making illegal any of the transactions contemplated by this Agreement.

 

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Section 4.6           Compliance with Laws. Except as set forth on Schedule 4.6, with respect to the Project and the Purchased Assets, each Seller currently is in compliance in all material respects with all Laws and orders of all Governmental Authorities applicable to it, the Project and the Purchased Assets, and Sellers have not received any notification indicating any violation of such Laws and orders.

 

Section 4.7           Taxes.

 

Except as set forth on Schedule 4.7:

 

(a)          Each Seller has filed all Tax Returns, if any, required to be filed with Tax Authorities relating to the Project or the Purchased Assets, and all such Taxes required to be paid or withheld by such Seller have been paid or withheld as required by Law.

 

(b)          No Tax Returns of any Seller with respect to the Project or any Purchased Assets have been audited or examined by any Tax Authority.  There are no ongoing or pending or threatened in writing Tax audits, examinations, claims, assessments or proposed deficiencies against any Seller with respect to the Project or the Purchased Assets.

 

(c)          No Tax Authority in a jurisdiction where any Seller does not file a Tax Return has made a claim or assertion in writing, or threatened in writing, that the Project or any of the Purchased Assets is or may be subject to Tax by such jurisdiction.

 

(d)          No Seller is a party to a Tax allocation or Tax sharing agreement or Tax indemnity or similar arrangement with respect to the Project or the Purchased Assets.

 

(e)          No Seller has been issued or is the subject of any ruling from any Taxing Authority with respect to its Taxes with respect to the Project or the Purchased Assets or has entered into (or is subject to) any contract with a Taxing Authority with respect to its Taxes related to the Project or the Purchased Assets.

 

(f)           No Seller has entered into a closing agreement pursuant to Section 7121 of the Code (or any similar provision of state, local or foreign law) with respect to the Project or the Purchased Assets.

 

Section 4.8           Regulatory Status. Except as set forth on Schedule 4.8, each Seller is not subject to or is exempt from, (i) regulation under the PUHCA and (ii) regulation by FERC as a public utility under the FPA. Furthermore, each Seller does not provide electric service directly to the public in Minnesota, North Dakota or South Dakota as of the date of this Agreement nor will it as of the Closing Date.

 

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Section 4.9           Contracts.

 

(a)          Schedule 4.9 sets forth a list, as of the date of this Agreement, of all Contracts (other than the Land Contracts) by which the Purchased Assets are bound or to which any Seller is a party to the extent related to the Purchased Assets (collectively, the “Purchased Contracts”).

 

(b)          Sellers have made available to Buyer true, correct and complete copies of all Purchased Contracts, including all amendments, material waivers or modifications thereto.

 

(c)          Each of the Purchased Contracts is in full force and effect and constitutes a legal, valid and binding obligation of the applicable Seller, and, to Sellers’ Knowledge, of the other parties thereto.

 

(d)          Except as set forth on Schedule 4.9, no Seller is in breach or default under any Purchased Contract and, to Sellers’ Knowledge, no other party to any of the Purchased Contracts is in breach or default thereunder. No event has occurred that (with or without notice, lapse of time or both) could reasonably be expected to constitute a material default by any Seller under any such Purchased Contract. No Seller has received any written notice or, to Sellers’ Knowledge, oral notice, from any counterparties in connection with any of the Purchased Contracts of (i) any material breach or default under any Purchased Contract, (ii) the fact that any such party will terminate, not renew, cancel or substantially decrease its business with any Seller, or (iii) any claim for damages or indemnification with respect to the products or performance of services pursuant to any Purchased Contract.

 

(e)          The consummation of the transactions contemplated by this Agreement will not require the consent or approval of any party to a Purchased Contract except as specifically set forth on Schedule 4.3(a).

 

Section 4.10         Real Property.

 

(a)          Schedule 4.10(a) sets forth a list of all Land Contracts and the Owned Real Property.

 

(b)          Sellers have made available to Buyer copies of all Land Contracts, and those copies are complete and accurate in all respects.

 

(c)          Other than the Real Property Interests, the Purchased Assets do not include any other rights or interests in real property.

 

(d)          Sellers hold good, insurable and valid title to the Real Property Interests free and clear of all Liens (other than Permitted Liens), adverse claims and other matters materially adversely affecting Sellers’ title to such Real Property Interests.

 

(e)          There are no leases or possessory rights of any party other than Sellers regarding the Owned Real Property.

 

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(f)          Each Land Contract (i) is a legal, valid and binding agreement of the applicable Seller party thereto, (ii) is in full force and effect, (iii) is enforceable against the applicable Seller party thereto, and to the Knowledge of the Sellers, each other Person that is a party thereto, and (iv) will continue to be legal, valid and binding and enforceable against the Seller Party thereto, and to the Knowledge of the Sellers, each other Person thereto, on identical terms immediately following the consummation of the transactions contemplated hereby. No Land Contract requires the consent or approval of any counterparties thereto in order to consummate the transactions contemplated hereby (including the construction and operation of the Project and the sale of the Purchased Assets to Buyer), or if required on or prior to the date this representation is made, such consent has already been obtained, or if not yet required, Sellers have no reason to believe such consent will not be given in due course. Sellers have paid, or caused to be paid, all amounts currently due and payable with respect to each Land Contract.

 

(g)          Except as set forth on Schedule 4.10(g), there exists no default under any Land Contract by Sellers or, to Sellers’ Knowledge, any other Person that is a party thereto.

 

(h)          Except as set forth on Schedule 4.10(h), there are no pending, or, to Sellers’ Knowledge, threatened appropriation, condemnation or like proceedings relating to the Owned Real Property, and to Sellers’ Knowledge, there are no pending or threatened appropriation, condemnation or like proceedings relating to any real property encumbered by the Land Contracts, the Project or any portion thereof.

 

(i)          Except as set forth on Schedule 4.10(i), no Seller has received any written notice from a Governmental Authority of any violation of any applicable zoning law, regulation or rule or other Law relating to or affecting any of such real property.

 

(j)          No Seller has granted any options or rights of first offer or first refusal to purchase or lease any Real Property Interest, or any portion thereof or interest therein. Except as set forth on Schedule 4.10(j), to Sellers’ knowledge the zoning and any public or private land use restrictions for the Owned Real Property or the real property which is the subject of the Land Contracts permits the development, construction, and operation of the Project thereon. Except as set forth on Schedule 4.10(j), to Sellers’ Knowledge there is no action pending before any Governmental Authority to change the applicable zoning or building ordinances or any other Law affecting the Real Property Interests that could reasonably be expected to have an adverse effect on the Project.

 

(k)          No Seller has assigned, transferred, conveyed, mortgaged, deeded in trust or encumbered any of the Real Property Interests.

 

(l)          There are no rents, royalties, fees or other amounts (except for potential indemnity claims) receivable by Sellers in connection with the Land Contracts.

 

(m)          Except as set forth on Schedule 4.10(m), to Sellers’ Knowledge, there are no development activities ongoing or contemplated related to any mineral, oil or gas rights on the Site.

 

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(n)          As of the Closing Date, all Land Contracts will comply with applicable Laws, including, without limitation, North Dakota Century Code, Chapter 17-04.

 

Section 4.11         Permits.

 

(a)          Schedule 4.11(a) (as may be updated pursuant to Section 6.8) sets forth all (i) Permits held by Sellers, (ii) applications for Permits which have been filed by Sellers in connection with the Project, and (iii) to the extent not listed in response to (i) or (ii), Permits that will be required to achieve Project Commercial Operation (other than permits to be issued pursuant to the TEPC).

 

(b)          Except as set forth on Schedule 4.11(b), as of the Closing, all Permits included in the Purchased Assets (together with all permits to be issued pursuant to the TEPC) will constitute all Permits necessary to achieve Project Commercial Operation, except for any Permits that are required exclusively as a result of Buyer’s ownership of the Purchased Assets and the Project.

 

(c)          Except as set forth on Schedule 4.11(c): (i) all Permits and applications for Permits set forth on Schedule 4.11(a) currently held by Sellers are valid and in full force and effect, and Sellers have performed in all material respects and are in compliance in all material respects with such Permits and applications for Permits; (ii) to Sellers’ Knowledge, all other parties to such Permits have performed in all material respects and are in compliance in all material respects with the Permits; and (iii) no event has occurred that (with or without notice, lapse of time or both) could reasonably be expected to constitute a material default by any Seller under any such Permit.

 

(d)          Except as set forth on Schedule 4.11(d), the consummation of the transactions contemplated by this Agreement will not affect the legality, validity, binding nature, enforceability or force and effect of any Permit listed on Schedule 4.11(a).

 

Section 4.12         Environmental Matters.

 

(a)          Except as set forth on Schedule 4.12:

 

(i)          With respect to the Project and the Purchased Assets, each Seller is, and since its formation has been, in compliance in all material respects with applicable Environmental Laws, and no Seller has any Liabilities under Environmental Laws related to the Project and the Purchased Assets, except for Liabilities set forth in the Permits;

 

(ii)         Sellers have obtained, maintained and complied with all Permits necessary under any applicable Environmental Law for the Project, each of which Permits is set forth on Schedule 4.12, and such Permits are in full force and effect and not subject to appeal (except pursuant to applicable Law);

 

(iii)        no Seller has been served with written notice of any Environmental Claims with respect to the Project or the Purchased Assets that are currently outstanding, and no such Environmental Claims are pending or, to Sellers’ Knowledge, threatened, against Sellers under any Environmental Laws;

 

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(iv)         to Sellers’ Knowledge, there are no current or previous facts, circumstances, conditions or occurrences relating to the Purchased Assets that would be expected to form the basis of a claim under any Environmental Law against Sellers or their Affiliates;

 

(v)          to Sellers’ Knowledge, no portion of the Site contains or has ever contained any underground storage tank, surface impoundment or similar device used for the management of wastewater, or other waste management unit dedicated to the disposal, treatment, or long-term storage (greater than thirty (30) days) of waste materials;

 

(vi)         there is no site to which any Seller has transported or arranged for the transport of Hazardous Materials associated with the Project or the Purchased Assets which, to Sellers’ Knowledge, is the subject of any environmental action that would result in an Environmental Claim; and

 

(vii)        there has been no Release of any Hazardous Material at or from the Project in connection with or Sellers’ operations at the Project that would result in an Environmental Claim.

 

(b)          In August 2015, representatives of Sellers had a telephone conversation with representatives of the USFWS in which Sellers’ representatives stated that Sellers did not intend to pursue an incidental take permit for the piping plover or whooping crane and describing the measures to be taken at the Site to protect these species. On September 3, 2015, Sellers hosted a webinar with the USFWS that further specified the avoidance and minimization measures. During that webinar, Kevin Shelley, USFWS Acting North Dakota Field Supervisor, North Dakota Field Office, stated that neither a habitat conservation plan nor an incidental take permit was recommended if the proposed avoidance and minimization measures for piping plover and whooping crane were implemented. EDF-RE, on behalf of Merricourt, submitted a letter to the USFWS on September 11, 2015 confirming its commitment to the proposed avoidance and minimization measures. To Sellers’ Knowledge, USFWS does not intend to formally respond to the September 11, 2015 letter, nor has the USFWS communicated to Sellers any objection to the September 11, 2015 letter or information presented therein.

 

(c)          The representations and warranties set forth in this Section 4.12, Section 4.11 and Section 4.18 are Seller’s sole and exclusive representations and warranties concerning environmental matters, including Environmental Laws, Environmental Claims and Permits.

 

Section 4.13         Brokers. Sellers do not have any liability or obligation to pay fees or commissions to any broker, finder or agent with respect to the transactions contemplated by this Agreement.

 

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Section 4.14         Wind Data. Schedule 4.14 sets forth a list of all books and records containing Wind Data, and Sellers have delivered to Buyer true, correct and complete copies of all such books and records, including records documenting the installation of the temporary meteorological towers. The Wind Data were collected at the locations and during the times set forth in such documents. To Sellers’ Knowledge, the Wind Data is true, accurate and correct in all material respects. No Seller has omitted or failed to provide to Buyer any Wind Data measured and recorded at the Site on or before the dates specified on Schedule 4.14 by or on behalf of such Seller or any of its Affiliates, to the extent that the same are in such Seller’s or its Affiliates’, representatives or agents’ possession or under such Seller’s or its Affiliates’, representatives or agents’ control prepared by or on behalf of any other Person.

 

Section 4.15         Insurance. Schedule 4.15 sets forth all policies of fire, liability and other forms of insurance insuring the Purchased Assets. Such policies are in full force and effect, all premiums with respect thereto covering all periods up to and including the date as of which this representation is being made have been paid (other than retroactive premiums which may be payable with respect to comprehensive general liability insurance policies), and no written notice of cancellation or termination has been received by the owner or holder of any such policy with respect to any such policy which was not replaced on substantially similar terms prior to the date of such cancellation. No pending claims by or for the benefit of Sellers exist under any such policies of insurance.

 

Section 4.16         PTCs.

 

(a)           The only physical work performed prior to January 1, 2016 with respect to the Project (or any other project on the Site), either on the Site or with respect to equipment that will be incorporated into the Project, is set forth on Schedule 4.16.

 

(b)          The aggregate cost basis for federal income tax purposes of the Sellers (including affiliates or predecessors in interest), with respect to the Project or any other project on the Site prior to January 1, 2016, was not more than $[**].

 

(c)          Merricourt is a “disregarded entity” that is considered part of EDF-USD as one taxpayer for federal income tax purposes.

 

(d)          On or after December 27, 2016, but before December 31, 2016, EDF-USD will pay in full to Vestas for the 5% Safe Harbor Turbines an aggregate amount of not less than [**] ($[**]) (the “PTC Advance Payment”).

 

(e)          Neither EDF-USD nor an Affiliate will have a right to cancel the order for the 5% Safe Harbor Turbines or receive a refund of the PTC Advance Payment, in each case, except in the case of certain breaches by Vestas or force majeure.

 

(f)          The PTC Advance Payment will not be paid as compensation for any on-site storage, any warranty or any other equipment, component or service, other than the 5% Safe Harbor Turbines. Transportation or storage costs will be paid separately from the PTC Advance Payment.

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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(g)          No portion of the PTC Advance Payment will be or was loaned to EDF-USD, or any Affiliate of EDF-USD, by Vestas or any Affiliate of Vestas.

 

(h)          EDF-USD is an accrual basis taxpayer for federal income tax purposes.

 

(i)           For federal income tax purposes, EDF-USD may utilize, as a method of accounting, the rule described in Treasury Regulation 1.461-4(d)(6)(ii).

 

(j)           EDF-USD and/or Merricourt will be, or were, responsible for insurance of the 5% Safe Harbor Turbines as of the “Ex Works Date” (as defined in the Daughter Contract) and will take, or took, title and risk of loss for, and will or did contractually accept under the Daughter Contract, each such 5% Safe Harbor Turbine on or before such Ex Work Date.

 

(k)          The Ex Works Date (as defined in the Daughter Contract) for each 5% Safe Harbor Turbine will occur before three and one half months of the date of the PTC Advance Payment (the “PTC Deadline”).

 

(l)           On or before the Ex Works Date (as defined in the Daughter Contract), for each 5% Safe Harbor Turbine, either EDF-USD or Merricourt, or Vestas (as agent or bailee or warehouseman for EDF-USD or Merricourt) shall have physical custody, care and control of such 5% Safe Harbor Turbine; provided that any storage fees will be payable by EDF-USD or Merricourt.

 

(m)          After the PTC Advance Payment is made or was made, no change to the Framework Agreement (to the extent such change could affect the WTGs purchased under the Daughter Contract) or the Daughter Contract that reduces the amount described in Section 4.16(d) for the 5% Safe Harbor Turbines will occur.

 

Section 4.17         No Other Agreements to Sell Purchased Assets. Sellers do not have any legal obligation to, or non-binding agreement in principle with, any other person (a) to sell or effect a sale of all, or any portion of the Purchased Assets or (b) related to the sale of energy upon development of the Site.

 

Section 4.18         Reports. Except as set forth in Schedule 4.18, to Sellers’ Knowledge, there has been no change in circumstances in any material matters described in a Report or in the Wind Study that would have a Material Adverse Effect.

 

Article 5

REPRESENTATIONS AND WARRANTIES OF BUYER

 

Buyer hereby represents and warrants to Sellers that:

 

Section 5.1           Organization. Buyer is a corporation, validly existing and in good standing under the Laws of the State of Minnesota. Buyer is duly qualified or licensed to do business in each other jurisdiction where the actions to be performed by it under this Agreement makes such qualification or licensing necessary, except in those jurisdictions where the failure to be so qualified or licensed would not have a material adverse effect on its ability to perform such actions. Buyer has delivered to Sellers all of the Organizational Documents of Buyer as in effect on the date of this Agreement.

 

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Section 5.2           Authority; Enforceability. Buyer has all requisite corporate power and authority to enter into this Agreement and the Ancillary Agreements to which Buyer is a party, to perform its obligations hereunder and thereunder and to consummate the transactions contemplated hereby and thereby. The execution and delivery by Buyer of this Agreement and the Ancillary Agreements to which Buyer is a party and the performance by Buyer of its obligations under this Agreement and the Ancillary Agreements to which Buyer is a party have been duly and validly authorized by all necessary corporate action. This Agreement and each Ancillary Agreement to which Buyer is a party has been duly and validly executed and delivered by Buyer and constitutes the legal, valid and binding obligation of Buyer enforceable against Buyer in accordance with its terms except as the same may be limited by bankruptcy, insolvency, reorganization, fraudulent conveyance, arrangement, moratorium or other similar Laws relating to or affecting the rights of creditors generally or by general equitable principles.

 

Section 5.3           No Conflicts; Consents and Approvals. The execution and delivery by Buyer of this Agreement and the Ancillary Agreements to which Buyer is a party do not, and the performance by Buyer of its obligations hereunder and thereunder and the consummation of the transactions contemplated hereby and thereby will not:

 

(a)          result in a violation of or a breach of any of the terms, conditions or provisions of the Organizational Documents of Buyer;

 

(b)          result in a Default under any material Contract to which Buyer is a party, except for any such Default which would not, in the aggregate, have a material adverse effect on Buyer’s ability to perform its obligations under this Agreement or any Ancillary Agreements to which Buyer is or will be a party; or

 

(c)          (i) violate or breach any term or provision of any Law applicable to Buyer or any of its Assets, except as would not have a material adverse effect on Buyer’s ability to perform its obligations under this Agreement or any Ancillary Agreements to which Buyer is a party or (ii) require any material Consent of any Governmental Authority under any applicable Law, other than (A) the Regulatory Approvals, and (B) such Consents, which, if not made or obtained, would not have a material adverse effect on Buyer’s ability to perform its obligations under this Agreement or any Ancillary Agreements to which Buyer is a party.

 

Other than as set out in Schedule 5.3, no Consent of any Governmental Authority or any other Person, is required to be made or obtained by Buyer in connection with the execution and delivery of this Agreement and the Ancillary Agreements or the consummation of the transactions contemplated hereby and thereby.

 

Section 5.4           Legal Proceedings. Buyer has not been served with notice of any Claim, and to Buyer’s knowledge, none is threatened in writing, against Buyer which seeks a writ, judgment, order or decree restraining, enjoining or otherwise prohibiting or making illegal any of the transactions contemplated under this Agreement or any Ancillary Agreements to which Buyer is a party.

 

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Section 5.5           Brokers. Buyer does not have any liability or obligation to pay fees or commissions to any broker, finder or agent with respect to the transactions contemplated by this Agreement.

 

Section 5.6           Financial Resources. Buyer currently has, and will have available at the Closing Date, funds sufficient to meet all its obligations under this Agreement and pay the amount payable by Buyer to Sellers pursuant to Section 2.5.

 

Section 5.7           Independent Investigation; No Knowledge of Misrepresentations or Omissions. Buyer has such knowledge and experience in financial and business matters, as well as the electric and wind energy businesses, that it is capable of evaluating the merits and risks of its participation in the transactions contemplated by this Agreement. In entering into this Agreement, Buyer has relied solely upon its own review and analysis and the specific representations and warranties of the Sellers expressly set forth in Article 4 and the TEPC. Buyer acknowledges that, except for the representations and warranties expressly set forth in Article 4 and the TEPC, none of the Sellers, their respective Affiliates or any of their respective Representatives has made or makes, and Buyer has not relied on and is not relying on, any representation, warranty or statement, either express or implied, (a) as to the accuracy or completeness of any of the information delivered or made available to Buyer, any of its Affiliates or any of its or their respective Representatives and (b) with respect to any projections, forecasts, estimates, plans or budgets of future revenues, expenses or expenditures, future results of operations (or any component thereof), future cash flows (or any component thereof) or future financial condition (or any component thereof) of the Purchased Assets or the Project delivered or made available to Buyer, any of its Affiliates or any of its Representatives. Buyer confirms that the Sellers have made available to Buyer and its Representatives, and they have been given the opportunity to ask questions of, the Representatives of the Sellers to Buyer’s satisfaction. Buyer does not have actual knowledge of a breach of any representation and warranty set forth in Article 4 of this Agreement or in the TEPC; provided, that, the mere existence of any information in the electronic data room provided by Seller shall not, in and of itself, be deemed to be actual knowledge of Buyer.

 

Article 6

COVENANTS

 

The Parties hereby covenant and agree as follows:

 

Section 6.1           Books and Records.

 

(a)          From and after Closing, Buyer will preserve and keep the Books and Records related to the Purchased Assets that relate to the period prior to the Closing Date (including all accounting records) for a period of seven (7) years from the Closing, or for any longer periods as may be required by any Governmental Authority or ongoing litigation. From and after Closing, Buyer, upon reasonable prior notice from Sellers, will provide to Sellers and its Representatives access to or copies of Books and Records of Seller to the extent relating to events that occurred prior to Closing and to the extent needed for a legitimate business purpose or to enforce rights under this Agreement provided that all such Books and Records shall be confidential and the information therein not used or disclosed except as required by law, for a legitimate business purpose, or to enforce rights under this Agreement.

 

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(b)          Sellers will deliver the Books and Records in Seller’s possession to Buyer as promptly as practicable following the Closing Date. Sellers may retain a copy of such Books and Records.

 

Section 6.2           Tax Matters.

 

(a)          Except as set forth in Section 6.2(b), the Purchase Price includes all Taxes. The Purchase Price shall not be increased with respect to any Taxes that Buyer may be required to make as part of the Closing. Notwithstanding the foregoing, Sellers shall not be liable for, and the Purchase Price shall not include any taxes for which Buyer is responsible pursuant to Section 6.2(b). Sellers shall provide to Buyer all information reasonably requested by Buyer to confirm that the correct amount of sales and use tax or other like taxes will be paid on the Purchased Assets.

 

(b)          Notwithstanding anything to the contrary in this Agreement, the Purchase Price shall not include, but Buyer shall pay or reimburse Sellers for, any sales, use, or transfer tax levied by any state, county or local government with respect to the purchase of the Purchase Assets (“Sales Tax”), without regard to whether the person required by law to report, collect or pay such Sales Tax was Buyer or Sellers, or any other person.

 

(c)          The Party required by Law to file a Tax Return related to Taxes described in Section 6.2(a) in connection with the Closing will do so within the time period required by Law and provide a copy of the return to the other Parties, but will alert the other Parties of the need to file such a return first in writing in case there is any disagreement about whether Sales Taxes are owed and work in good faith to resolve any disagreement.

 

(d)          The Parties agree that prior to the Closing, none of the Parties will negotiate with any taxing authority regarding tax rates or structures for the Project without the prior written reasonable consent of the other Parties, and that if such consent to negotiate is provided, any such agreement regarding tax rates or structures entered into prior to the Closing is also subject to the prior written consent of the other Parties (which consent shall not be unreasonably withheld).

 

(e)          Sellers will reasonably cooperate with Buyer in connection with any request made by Tax Counsel, the IRS, or any state, county, or local taxing authority.

 

Section 6.3           Conduct of Sellers Prior to Closing. Except as described in Schedule 6.3, as contemplated, permitted or required by this Agreement, or as required by applicable Laws, between the date hereof and the Closing, each Seller will conduct its business with respect to the Project and use commercially reasonable efforts to preserve the Purchased Assets in the ordinary course of business. Notwithstanding the preceding sentence, between the date hereof and the earlier to occur of the Closing and the termination of this Agreement, except as permitted or contemplated by the terms of this Agreement, without the prior written consent of Buyer (which consent shall not be unreasonably withheld), no Seller shall do any of the following:

 

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(a)          take any action which would materially interfere with or prevent the consummation of the transactions contemplated by this Agreement;

 

(b)          except for actions taken pursuant to Section 6.11, enter into, amend, modify, cancel or terminate any (i) Contract which would be a material Purchased Contract or (ii) Land Contract, in each case, in a manner that would have an adverse impact on the ownership or operation of the Project or increase the liability of Buyer under such Land Contract or Contract after Closing; provided, that Sellers may enter into Land Contracts that are in substantially the same form as the Land Contracts provided to Buyer for review prior to the date of this Agreement (so long as such new Land Contracts have a term of at least 60 years from the Commercial Operation Date and Seller uses commercially reasonable efforts to have a lease term of 99 years from the Commercial Operation Date, and further such new Land Contracts shall conform to all applicable Laws, including the requirements of North Dakota Century Code, Chapter 17-04);

 

(c)          amend the organizational documents of any Seller in a manner that would have an adverse impact on such Seller’s ability to perform its obligations under this Agreement, the TEPC or the Ancillary Agreements;

 

(d)          adopt a voluntary plan of complete or partial liquidation or dissolution;

 

(e)          sell, lease, license, encumber or otherwise dispose of any Purchased Assets or enter into any written or oral agreement with a third party with respect to the distribution or sale of any Purchased Assets or electricity produced by any Purchased Assets;

 

(f)           make any request for a ruling or guidance to the IRS with respect to the applicability of Section 45 of the Code to the Project;

 

(g)          amend the Daughter Contract without the consent of Buyer, which consent shall not be unreasonably withheld; or

 

(h)          commit to do any of the foregoing.

 

Section 6.4           Access to Information.

 

(a)          Subject to the terms of the Confidentiality Agreement, from the date hereof until the earlier of (a) the Closing and (b) the termination of this Agreement in accordance with Article 8, upon reasonable notice, each Seller will (i) afford Buyer and its authorized representatives reasonable access to the Site, representatives, Contracts, and Books and Records of Purchased Assets and the Project; (ii) furnish to Buyer and authorized representatives of Buyer such additional financial and operating data and other information regarding the Project (or copies thereof) as Buyer may from time to time reasonably request; and (iii) furnish to Buyer and authorized representatives of Buyer any other information concerning or otherwise relating to the Purchased Assets and the Project as Buyer or its representatives may reasonably request.

 

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(b)          Subject to the terms of the Confidentiality Agreement, from the date hereof until the Commercial Operation Date, each Seller will (i) afford Buyer and its authorized representatives reasonable access to the Site, representatives, Contracts, and Books and Records of Purchased Assets and the Project; (ii) furnish to Buyer and authorized representatives of Buyer such additional financial and operating data and other information regarding Sellers and the Project (or copies thereof) as Buyer may from time to time reasonably request; and (iii) furnish to Buyer and authorized representatives of Buyer any other information, in each case to the extent reasonably related to facts and circumstances relevant to the Project’s qualification for 100% PTCs.

 

(c)          Subject to the terms of the Confidentiality Agreement, from the date hereof until the sixth anniversary of the Commercial Operation Date, Sellers will deliver to Buyer (i) within 90 days after the close of each of the fiscal years of EDF-EN, a consolidated balance sheet and income statement of EDF-EN as of the end of such fiscal year, together with related consolidated statements of cash flows for such fiscal year, setting forth in comparative form consolidated figures for the preceding fiscal year, all such consolidated financial information described above to be in reasonable form and detail and accompanied by an unqualified opinion of KPMG S.A. or other independent certified public accountants of recognized international standing reasonably acceptable to Buyer, which opinion shall state that such financial statements present fairly, in all material respects, the financial condition of EDF-EN and its results of operations and cash flows and have been prepared in conformity with International Financial Reporting Standards, and that the examination of such accountants in connection with such financial statements has been made in accordance with generally accepted auditing standards, and that such audit provides a reasonable basis for such opinion in the circumstances and (ii) within 90 days after the close of the second quarterly period of each of the fiscal years of EDF-EN, an unaudited consolidated balance sheet and income statement of EDF-EN, as of the end of such fiscal semester or half year, together with related consolidated statements of cash flows for such fiscal semester or half year, all in reasonable detail, prepared in accordance with International Financial Reporting Standards applicable to semester or half year financial statements generally, and fairly presenting, in all material respects, the financial condition of the companies being reported on and their results of operations and cash flows, subject to changes resulting from year-end adjustments.

 

(d)          Subject to the terms of the Confidentiality Agreement, from the date hereof until the sixth anniversary of the Commercial Operation Date, Sellers will deliver to Buyer (i) within 90 days after the close of each of the fiscal years of EDF-RE, a consolidated balance sheet and income statement of EDF-RE as of the end of such fiscal year, together with related consolidated statements of cash flows for such fiscal year, setting forth in comparative form consolidated figures for the preceding fiscal year, all such consolidated financial information described above to be in reasonable form and detail and accompanied by a certificate of KPMG S.A. or other independent certified public accountants of recognized international standing reasonably acceptable to Buyer, which opinion shall state that such financial statements are the financial statements of EDF-RE that were incorporated into the audited financial statements of EDF-EN delivered to Buyer pursuant to Section 6.4(c) and (ii) within 90 days after the close of the second quarterly period of each of the fiscal years of EDF-RE, an unaudited consolidated balance sheet and income statement of EDF-RE, as of the end of such fiscal semester or half year, together with related consolidated statements of cash flows for such fiscal semester or half year, all in reasonable detail, prepared in accordance with International Financial Reporting Standards applicable to semester or half year financial statements generally, and fairly presenting, in all material respects, the financial condition of the companies being reported on and their results of operations and cash flows, subject to changes resulting from year-end adjustments.

 

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Section 6.5           Efforts; Consents; Regulatory and Required Seller Approval.

 

(a)          Each Party will use diligent and commercially reasonable efforts to (i) take, or cause to be taken, all appropriate action, and do, or cause to be done, all things necessary, proper or advisable under applicable Laws or otherwise to promptly consummate and make effective the transactions contemplated by this Agreement, including cooperating with the other Parties; (ii) obtain all authorizations, consents, orders and approvals of, and give all notices to and make all filings with, all Governmental Authorities and other third parties that may be or become necessary for the performance of its obligations under this Agreement and the consummation of the transactions contemplated by this Agreement, or that may be or become necessary, proper or advisable pursuant to any Permit, Land Contract or Purchased Contract to which Sellers is bound or by which any of Seller’s assets or properties are bound, including the Regulatory Approvals and (iii) satisfy all conditions to such Party’s obligations under this Agreement. Notwithstanding the foregoing or anything to the contrary set forth in this Agreement, in connection with obtaining such authorizations, consents, orders and approvals from Governmental Authorities or third parties, no Party will be required to make payments (other than the payment of routine filing fees), commence legal or regulatory proceedings (other than the Regulatory Approvals) or agree to modifications of the terms and conditions of any agreements with third parties or Permits. Nothing in this Section 6.5 shall require any Party to (A) consent to any action or omission by the other Party or its Affiliates that would be inconsistent with Section 6.3 absent such consent or (B) agree to amend or waive any provision of this Agreement. Each Party shall reasonably cooperate with the other Party in performing the obligations required by this Section 6.5(a), including the negotiation, execution, and assignment of Land Contracts, Purchased Contracts and other agreements related to the Project. The Parties will not take any action that is reasonably likely to have the effect of unreasonably delaying, impairing or impeding the receipt of any required authorizations, consents, orders or approvals.

 

(b)          Within 30 days following the execution of this Agreement, Sellers shall send the USFWS a letter, email, or other written communication informing the USFWS that (i) Sellers and Buyer have entered into an agreement under which Buyer will purchase the Project from Sellers, (ii) the Parties intend to proceed with construction of the Project, and (iii) the Parties do not intend to obtain an incidental take permit in connection with the Project. Seller must allow Buyer a reasonable opportunity to review and comment on any such written communication prior to submission, and any proposed edits shall not be unreasonably rejected.

 

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(c)          From time to time, but no less often than once a year following the execution of this Agreement and prior to the Closing, Sellers shall send the USFWS a letter, email, or other written communication informing the USFWS in summary form on new developments relating to the Project. Seller must allow Buyer a reasonable opportunity to review and comment on any such written communication prior to submission, and any proposed edits shall not be unreasonably rejected.

 

(d)          At least 30 days prior to the Closing Date, Sellers shall submit the final version of the Bird and Bat Conservation Strategy to the USFWS (and provide a copy thereof to Buyer). Sellers must allow Buyer a reasonable opportunity to comment on the Bird and Bat Conservation Strategy prior to submission, and any proposed edits shall not be unreasonably rejected. Sellers agree that the comments set forth in Schedule 6.5(d) are reasonable and shall be reflected in the final Bird and Bat Conservation Strategy.

 

Section 6.6           Public Announcements. Subject to a Party’s reasonable judgment that it is required by Law or by the rules of a national securities exchange to make such disclosure, no Party shall issue any public announcement or other statement with respect to this Agreement or the transactions contemplated hereby without the prior consent of the other Parties. Additionally, subject to Buyer providing Sellers with advance written notice and an opportunity to review and comment on such disclosures, each Seller hereby consents to the disclosure of confidential information regarding the Project and its current status in public filings and informal communications with regulators to be made by Buyer, but only to the extent that such confidential information is reasonably necessary or required (based on the advice of counsel) in connection with seeking approval of the transaction contemplated by this Agreement and in developing the Project; and hereby waives any confidentiality provisions relating thereto currently in effect. Notwithstanding the immediately preceding sentence, Buyer shall not make any disclosure of confidential information related to the Prime Subcontract or Turbine Supply Agreement; provided, that Buyer may disclose such confidential information if it is required by a regulator and Buyer uses reasonable efforts to seek trade secret protection.

 

Section 6.7           Further Assurances. Subject to the terms and conditions of this Agreement, at any time or from time to time after the Closing, at any Party’s request and without further consideration, the other Parties will execute and deliver to such Party such other instruments of sale, transfer, conveyance, assignment and confirmation, provide such materials and information and take such other actions as such Party may reasonably request in order to consummate the transactions contemplated by this Agreement.

 

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Section 6.8           Updated Schedules. From time to time prior to and up to ten (10) Days prior to the Closing Date, a disclosing Party shall provide written notice to the other Party of any fact, matter, condition, event or circumstance that occurs following the date of this Agreement and that, individually or in the aggregate, renders the disclosing Party unable, without amending the Schedules, to satisfy their condition precedent under Article 7 (each, an “Update”). In the event the other Party does not terminate this Agreement pursuant to Article 8 following delivery of such Update, the disclosing Party shall be permitted to update the applicable Schedule(s) to properly reflect the fact, matter, condition, event or circumstance disclosed to the other Party in such Update, and all of the disclosing Party’s representations and warranties set forth in this Agreement made following the Update shall be subject to the Schedules attached hereto, as modified or amended by such an Update, for purposes of satisfying the conditions to Closing set forth in Article 7; provided, further, that, if the Closing occurs, such Update shall not be deemed to have modified the Schedules for purposes of determining whether there has been a breach of the applicable representations and warranties related to Sellers’ indemnification obligations in Section 9.2. Notwithstanding the foregoing, to the extent Buyer has a claim for indemnification in accordance with Section 9.2 resulting from a breach of the applicable representations and warranties based on the fact, matter, condition, event or circumstance described in the Update, Buyer shall provide Seller with written notice of such claim in accordance with Article 9 (such notice, an “Update Indemnification Notice”) within ten (10) days of receiving the Update, which notice shall include a description of the claim and Buyer’s good faith estimate of the amount of such claim; provided, that, in the event that Buyer delivers an Update Indemnification Notice within such ten (10)-day period, Seller shall have a termination right in accordance with Section 8.1(l). If Buyer fails to deliver an Update Indemnification Notice within such ten (10)-day period, then Buyer be deemed to have irrevocably waived such claim.

 

Section 6.9           Representations and Warranties. Subject to Section 5.7 of this Agreement, Buyer shall have the right to rely on the representations set forth in Article 4 regardless of (a) any due diligence done by Buyer and its representatives and (b) any knowledge or information known or available to Buyer from Sellers or any other source.

 

Section 6.10         Interconnection Costs.

 

(a)          The Parties hereby agree to cooperate in good faith to evaluate interconnection studies and share information related to the timing and costs of the Project interconnection. Without limiting the generality of the foregoing, Sellers shall (i) promptly upon receipt thereof, provide copies of all studies and other communications received from MISO or any other RTO or transmission owner with respect to MISO Interconnection Queue Request J457; (ii) promptly provide Buyer with copies all drafts of the New GIA and any facility construction agreements received from MISO or the applicable transmission owner prior to Closing; (iii) provide Buyer a period of not less than ten (10) days following Buyer’s receipt from Sellers of copies of such draft documents to review and comment on such draft documents; and (iv) allow Buyer to participate in any telephone calls or negotiating sessions regarding the same.

 

(b)          If the Existing GIA is assigned to Buyer at Closing pursuant to Section 2.1, then (i) Sellers shall bear, and Buyer shall have no obligation with respect to, the historic costs associated with the Existing GIA prior to the Closing, (ii) Buyer shall bear 100% of any additional costs assessed by MISO with respect to the Existing GIA following the Closing, and (iii) Sellers shall be entitled to any MISO refunds arising from the pre-Closing termination or withdrawal of MISO Interconnection Queue Request J457.

 

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(c)          From time to time as the study process associated with MISO Interconnection Queue Request J457 progresses, Buyer and Sellers will in good faith consider whether the NRIS Interconnection Costs or the ERIS Interconnection Costs will be lower, and if the ERIS Interconnection Costs are lower, consider whether Sellers should amend MISO Interconnection Queue Request J457 to request “ERIS;” provided, that Buyer acknowledges and agrees that the final decision as to whether to amend MISO Interconnection Queue Request J457 shall be in the sole discretion of Sellers; provided, further, that if (i) Buyer requests that Sellers amend MISO Interconnection Queue Request J457 to request “ERIS,” (ii) at the time Buyer requests “ERIS,” the ERIS Interconnection Costs are estimated to be lower than the NRIS Interconnection Costs, and (iii) Sellers do not amend MISO Interconnection Queue Request J457 to request “ERIS” prior to the expiration of the time during which such amendment is permitted, then, notwithstanding Sections 6.10(d) and (e), Sellers agree to pay all Interconnection Costs in excess of the ERIS Interconnection Costs.

 

(d)          Subject to Section 6.10(c), if, following completion of all system impact and facilities studies, the Estimated Interconnection Costs exceed $[**] (such excess amount, the “Excess Interconnection Costs”), this Agreement shall automatically terminate within thirty (30) days after such determination unless any Party provides written notice to the other Parties within such 30-day period that it will pay such Excess Interconnection Costs. For the avoidance of doubt, the Parties agree that the Estimated Interconnection Costs cannot be determined prior to completion of all system impact and facilities studies associated with MISO Interconnection Queue Request J457.

 

(e)          Subject to Section 6.10(c), if the New GIA is assigned to Buyer at Closing pursuant to Section 2.1, then the responsibility for the Interconnection Costs shall be as follows:

 

(i)          Buyer shall pay all Interconnection Costs up to the base cost of $[**].

 

(ii)         If the Interconnection Costs are between $[**] and $[**], such incremental costs shall be paid one-half by Buyer and one-half by Sellers.

 

(iii)        If the Interconnection Costs exceed an amount equal to the higher of (A) $[**] or (B) any higher amount agreed to be paid by a Party pursuant to Section 6.10(d)), then Buyer will pay the amount of such excess.

 

(iv)         If Sellers make a cash payment of any portion of the Interconnection Costs owed by Buyer pursuant to this Section 6.10(e) prior to Closing, and have not received a refund of such amount, Buyer shall reimburse Sellers for such amounts at Closing. If Sellers subsequently receive a refund of any amounts reimbursed by Buyer, Sellers shall pay such refund to Buyer. If Buyer pays any portion of the costs associated with the interconnection studies for MISO Interconnection Queue Request J457 (whether before or after Closing), Sellers shall promptly reimburse Buyer for such amount upon request. Any difference between the Estimated Interconnection Costs and the actual Interconnection Costs incurred shall be trued up between the Parties at the Commercial Operation Date; provided, that (A) subject to Sections 6.10(c) and (d), following the Closing Buyer shall bear all Excess Interconnection Costs and (B) following the Commercial Operation Date, Buyer shall (1) bear any new interconnection costs in addition to those known and allocated between the parties before such date and (2) be entitled to receive 100% of any refunds related to the New GIA that aren’t known as of the Commercial Operation Date.

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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(v)          Sellers shall be entitled to any MISO refunds arising from termination or withdrawal of the Existing GIA.

 

Section 6.11         Easement Agreement Extensions and Amendments. Prior to the Closing Date, Sellers shall (a) use commercially reasonably efforts to extend the term of all Land Contracts covering [**] contiguous WTG Locations to [**] years from the Commercial Operation Date; provided, that, Sellers must, at a minimum, extend the term of Land Contracts covering [**] contiguous WTG Locations to at least [**] years from the Commercial Operation Date; provided, further, that all Land Contracts not so extended pursuant to this Section 6.11 shall have a term of at least [**] years from the Commercial Operation Date and (b) amend all Land Contracts not conforming to the requirements of North Dakota Century Code, Chapter 17-04 so as to conform with such Laws. At Closing, Buyer shall reimburse Sellers for the amount of any upfront payments paid to landowners by Sellers to obtain such amendments to the Land Contracts in an amount not to exceed [**] ($[**]) per landowner or [**] ($[**]) in the aggregate.

 

Section 6.12         Non-Compete.

 

(a)          For a period beginning on the date of this Agreement and ending on the date that is three (3) years following the Commercial Operation Date, none of Sellers or any of their respective Affiliates will develop, construct, own or operate a wind energy facility within three (3) miles of a Project WTG.

 

(b)          Each Seller acknowledges that a breach or threatened breach of this Section 6.12 would give rise to irreparable harm to Buyer, for which monetary damages would not be an adequate remedy, and hereby agrees that in the event of a breach or a threatened breach by such Seller or its Affiliates of any such obligations, Buyer shall, in addition to any and all other rights and remedies that may be available to it in respect of such breach, be entitled to equitable relief, including a temporary restraining order, an injunction, specific performance and any other relief that may be available from a court of competent jurisdiction (without any requirement to post bond).

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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(c)          Each Seller acknowledges that the restrictions contained in this Section 6.12 are reasonable and necessary to protect the legitimate interests of Buyer and constitute a material inducement to Buyer to enter into this Agreement and consummate the transactions contemplated by this Agreement. In the event that any covenant contained in this Section 6.12 should ever be adjudicated to exceed the time, geographic, product or service or other limitations permitted by applicable Law in any jurisdiction, then any court is expressly empowered to reform such covenant, and such covenant shall be deemed reformed, in such jurisdiction to the maximum time, geographic, product or service or other limitations permitted by applicable Law. The covenants contained in this Section 6.12 and each provision hereof are severable and distinct covenants and provisions. The invalidity or unenforceability of any such covenant or provision as written shall not invalidate or render unenforceable the remaining covenants or provisions hereof, and any such invalidity or unenforceability in any jurisdiction shall not invalidate or render unenforceable such covenant or provision in any other jurisdiction.

 

Section 6.13         Letters of Credit; Guaranty.

 

(a)          To fulfill Sellers’ full and timely payment obligations hereunder, Sellers shall cause (i) EDF-EN to execute and deliver to Buyer contemporaneous with the execution of this Agreement, and maintain in full force and effect, the EDF-EN Guaranty, which shall be subject to the limitations set forth therein, including the EDF-EN Guaranty Expiration; (ii) on or before January 1, 2018, either (x) EDF-EN to execute and deliver to Buyer and maintain in full force and effect, the Construction Period Guaranty, or (y) the execution and delivery to Buyer of the Project Surety Bond, in each case subject to the limitations set forth therein, including the Construction Period Guaranty Expiration; and (iii) EDF-RE to execute and deliver to Buyer on or prior to the Project Substantial Completion Date, and maintain in full force and effect, the Post-Construction Guaranty, subject to the limitations set forth therein, including the Post-Construction Guaranty Expiration. Upon the occurrence of a Credit Trigger Event with respect to a Guarantor, Sellers shall provide Buyer with a Backup LOC with respect to each Guaranty issued by such Guarantor and outstanding at the time of such Credit Trigger Event. Each such Backup LOC, if issued, shall secure (x) Guarantor’s obligations under the Guaranty with respect to which such Backup LOC was issued, (y) Sellers’ payment obligations under this Agreement, including all indemnity and liquidated damages obligations hereunder, and (z) EDF-USD’s payment obligations under the TEPC, including performance through the end of applicable Infrastructure Facilities Warranty Periods (as defined in the TEPC). The Backup LOC shall terminate on the sixth (6th) anniversary of the Project Substantial Completion Date. Buyer shall be entitled to draw on such letter of credit for any uncured breach by Sellers of this Agreement (to the extent Buyer is entitled to indemnification for Losses arising from such breach under Article 9), by EDF-USD under the TEPC or by the Guarantor of the applicable Guaranty. For the avoidance of doubt, the EDF-EN Guaranty, the Construction Period Guaranty, the Post-Construction Guaranty, and the Backup LOC(s), each referenced in this Section 6.13(a), are the same agreements as those referenced in the TEPC, and not in addition to such agreements.

 

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(b)          Upon the occurrence of a Credit Trigger Event with respect to Buyer, Buyer shall provide Sellers with an irrevocable letter of credit in the form attached as Exhibit 4.1.2 to the TEPC, issued by a Qualified Institution, with a drawable amount equal to Fifteen Million and 00/100 Dollars ($15,000,000). Such letter of credit, if issued, shall secure Buyer’s payment obligations, including Buyer’s indemnity obligations, hereunder. Sellers shall be entitled to draw on such letter of credit for any uncured breach by Buyer of this Agreement.

 

Section 6.14         Title Commitment; Survey; Title Policy.

 

(a)          Buyer has reviewed the Survey dated as of October 21, 2016 and the Title Commitment dated as of September 15, 2016 (collectively, the “Existing Title Evidence”) and accepts those documents and exceptions identified on such Title Commitment, except as identified in that certain title objection letter dated November 15, 2016 (the “Title Objection Letter”) attached as Schedule 6.14(a) hereto.  The matters, documents and exceptions not objected to in the Title Objection Letter shall be Permitted Liens (“Existing Permitted Exceptions”).  Based on Buyer’s review of the Existing Title Evidence, the Title Objection Letter also contains Buyer’s objections to, and Buyer’s proposed curative measures for, the Existing Title Evidence (“Existing Title Objections”).  Sellers have agreed to cure the Existing Title Objections prior to Closing as set forth in the Title Objection Letter.

 

(b)          Notwithstanding Section 6.14(a) or Section 6.14(c), Buyer reserves the right to object to the Existing Permitted Exceptions based upon its review of the then current Title Commitment and updated Survey delivered in connection with Closing pursuant to Section 6.14(c) below, the Site Plan, any changes in Laws, and the requirements of the Permits, provided, however, that such objections must result from changes in the Title Commitment, updated Survey, updated Site Plan or Permits which address matters that would materially detract from the value or materially interfere with the construction, operation or maintenance of the Project as contemplated in the Site Plan.

 

(c)          At least ninety (90) days prior to Closing, Sellers shall cause the Title Company to deliver to Buyer an updated Survey, which updated Survey shall depict the final Project layout pursuant to the Site Plan and include current wetland information and cultural data, and current Title Commitment, along with legible copies of all documents identified on such Title Commitment (“Title Evidence”). If the Title Evidence shows any new documents, new title exceptions or new survey issues not identified on the Existing Title Evidence (collectively, the “New Exceptions”), then Buyer shall have the right to reasonably approve or disapprove such New Exceptions. Within twenty (20) days after receipt of the last of the Title Evidence, Buyer shall provide Sellers with a title objection letter setting forth Buyer’s objections to items identified in the Title Evidence (“Updated Title Objection Letter”), other than, except as provided in Section 6.14(b), the Existing Permitted Exceptions (together with the Existing Title Objections, “Title Objections”). Sellers will use their commercially reasonable efforts to cure each Title Objection. Except for Permitted Liens, prior to the Closing, all Title Objections shall have been eliminated as an exception to the Title Policy, committed to be insured over by the Title Company in the Title Policy in form and substance reasonably acceptable to Buyer, or otherwise cured to Buyer’s reasonable satisfaction; provided that any fee mortgage of landowners under the Land Contracts, manure easement or tenant lease that is superior to the interest of Sellers and with respect to which a non-disturbance agreement in form and substance acceptable to Buyer has been obtained and delivered to Buyer at or prior to Closing shall be considered Permitted Liens at Closing.

 

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(d)          At Closing, Sellers shall cause the Title Company to issue the Title Policy. Sellers shall pay for the Survey (and any amendments, updates and supplements thereto) and the costs and search fees for the Title Commitments (and any amendments, updates and supplements thereto) and all recording charges and expenses incurred in connection with recording any Land Contract (or amendments or memoranda thereof) and any curative documents. Buyer shall pay all Title Policy premiums and the cost to record the Deed.

 

(e)          General real estate Taxes and installments of special assessments for the Owned Real Property shall be pro-rated as of the Closing Date, on a per diem basis based on the latest available data and in accordance with local custom, which proration will be final as of the Closing Date and not subject to recalculation after the Closing.

 

Section 6.15         Site Plan. Promptly following completion, and in any case prior to January 15, 2017, Sellers shall deliver the final Site Plan to Buyer. The Site Plan shall be reviewed by Buyer in collaboration with Sellers for a period of thirty (30) days following delivery thereof by Sellers (the “Review Period”). In the event Buyer fails to provide comments to Sellers prior to the expiration of the Review Period, the Site Plan shall be deemed approved by Buyer as of the date of delivery thereof by Sellers. In the event Buyer provides comments on the Site Plan to Sellers prior to the termination of the Review Period, Sellers shall review such Buyer comments and include them in the Site Plan so long as such Buyer comments do not result in an increase in Sellers’ costs or are consistent with Prudent Industry Practices. To the extent that Buyer still would like changes made that result in an increase in Sellers’ costs and which are not consistent with Prudent Industry Practices, Buyer shall be responsible for any such costs arising from those design changes requested by Buyer. Sellers shall deliver to Buyer a revised Site Plan that addresses Buyer’s comments as soon as reasonably possible after receipt of Buyer’s comments and Buyer shall approve or disapprove such revised Site Plan in accordance with the same procedures. Notwithstanding the foregoing, Sellers shall (a) use reasonable efforts and employ best practices to avoid impacts to aquatic features determined to be jurisdictional under the federal Clean Water Act, and in no case shall the impact to such jurisdictional waters require authorization from the US Army Corps of Engineers, (b) ensure that the Site Plan conforms in all material respects to all recommendations in the Bird and Bat Conservation Strategy, (c) use reasonable efforts and employ best practices to avoid impacts to areas which are enrolled as acreage under the Conservation Reserve Program except for areas with respect to which Sellers have secured authorization for permissive use consistent with standard industry practices from all relevant agencies, including the United States Department of Agriculture, (d) not locate WTGs in areas subject to Waterfowl Habitat Protection Easements, and (e) not locate any other facilities in areas subject to Waterfowl Habitat Protection Easements unless it has obtained appropriate consents from USFWS (for initial construction and all future maintenance and repair activities) and written confirmation from the USFWS that such consents will not create a federal nexus and require consultation under the Endangered Species Act.

 

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Section 6.16         5% Safe Harbor Turbines. In the event that some or all of the 5% Safe Harbor Turbines designated in the Daughter Contract are determined prior to the Closing Date not to qualify the Project for 100% PTCs due to a failure of one or more of the representations in Section 4.16 to be true, then to the extent owned by Sellers or any Affiliates of Sellers, Sellers shall, or shall cause their Affiliates to, allocate other Vestas 2.0MW V110 wind turbine components to the Project such that the Project will qualify for 100% PTCs.

 

Article 7

CONDITIONS TO CLOSING

 

Section 7.1           Conditions to Obligations of Each Party. The obligations of the Parties to effect the Closing are subject to the satisfaction prior to the Closing of the following conditions:

 

(a)          No Governmental Authority shall have instituted any Actions to restrain, prohibit or otherwise challenge the legality or validity of the transactions contemplated herein that has not been dismissed or otherwise resolved in a manner that does not materially adversely affect such transactions, and no Final Order shall be in effect that restrains or prohibits the consummation of such transactions.

 

(b)          All Regulatory Approvals shall have been obtained.

 

Section 7.2           Additional Conditions to Obligations of Buyer. The obligation of Buyer to effect the Closing is subject to the satisfaction at or before Closing of all of the following conditions, any one or more of which may be waived by Buyer in writing, in Buyer’s sole discretion:

 

(a)          each of the Designated Representations of Sellers will be true and correct in all respects, and each of the other representations and warranties of Sellers contained in this Agreement shall be true and correct in all material respects (other than such representations and warranties qualified by materiality or Material Adverse Effect, which shall be true and correct in all respects), in each case on and as of the Closing Date as though made on and as of the Closing Date;

 

(b)          Sellers shall have performed, and complied with, in all material respects all covenants and agreements required by this Agreement to be performed, and complied with, by Sellers on or before the Closing Date;

 

(c)          Sellers shall have delivered to Buyer a certificate from a duly authorized officer of each Seller, dated the Closing Date and executed by such officer, in a form reasonably acceptable to Buyer, certifying the items in Section 7.2(a) and Section 7.2(b);

 

(d)          Sellers shall have delivered (or caused to be delivered) to Buyer, the Closing deliverables described in Section 3.2 above;

 

(e)          Each Seller shall have delivered to Buyer a current Certificate of Good Standing;

 

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(f)          The Purchased Assets shall be free and clear of all Liens other than Permitted Liens, and each Seller shall have delivered to Buyer copies acceptable to Buyer of documentation releasing any such Liens;

 

(g)          Each Seller shall have delivered a copy, certified by the Secretary of Seller, of resolutions of such Seller authorizing and approving the transactions contemplated hereby;

 

(h)          No Material Adverse Effect shall have occurred since the date of this Agreement;

 

(i)          Sellers shall have obtained all Consents required in connection with the transactions contemplated by this Agreement that are listed on Schedule 4.3(a) (the “Required Consents”);

 

(j)           Sellers shall not have sold, transferred or otherwise disposed of any Purchased Assets, except as otherwise permitted by this Agreement;

 

(k)          Subject to delivery of all Required Consents, all material Land Contracts and all other material Purchased Contracts shall be fully transferable to Buyer and shall be in full force and effect and not subject to any appeal or dispute;

 

(l)          Sellers shall have obtained all Permits which shall be in form reasonably satisfactory to Buyer and such Permits shall either be freely transferable to Buyer or Seller shall have obtained any necessary consent to such transfer;

 

(m)          Sellers shall have obtained and delivered to Buyer an FAA Determination for each WTG Location;

 

(n)          Sellers shall have delivered to Buyer the Reports in final form, which such Reports shall not indicate any issues that would have a Material Adverse Effect (or in the event a preliminary or draft Report was delivered to Buyer prior to the execution of this Agreement, such final Report shall not indicate any issues beyond those issues disclosed in the drafts of such Reports made available to Buyer prior to execution of this Agreement and that would have a Material Adverse Effect); provided, that in the event there is a change in any findings or conclusions of a Report delivered and accepted as satisfactory by Sellers prior to the Closing Date, Sellers shall redeliver such Report to Buyer in final form as revised to address such changes;

 

(o)          Sellers shall have obtained all Land Contracts covering eighty (80) contiguous WTG locations in substantially the form of the existing Land Contracts, including full satisfaction of the term, extension and amendment requirements set forth in Section 6.11;

 

(p)          Except for Permitted Liens, prior to the Closing, all Title Objections shall have been eliminated as an exception to the Title Policy, cured consistent with the Title Objection Letter and Updated Title Objection Letter or otherwise cured to Buyer’s reasonable satisfaction;

 

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(q)          The Title Company shall have issued the Title Policy;

 

(r)          The TEPC shall be in full force and effect and both the EDF-EN Guaranty and either the Construction Period Guaranty or the Project Surety Bond shall have been delivered to Buyer and both shall be in full force and effect.

 

(s)          The BOP Contract shall be executed at Closing and be in full force and effect;

 

(t)           The GIA shall (i) be executed and in full force and effect at Closing, and (ii) together with studies and other information, and subject to Section 8.1(d), shall not indicate network upgrades or other work that will prevent the full nameplate capacity of the Project to be interconnected to the grid and operated by no later than the Commercial Operation Date;

 

(u)          There shall have been no enactment, promulgation or issuance, as applicable, of any of the types of authorities described in Treasury Regulations Section 1.6662-4(d)(3) after the date hereof that has a material adverse effect on the qualification of the Project for 100% PTCs;

 

(v)          Buyer shall have received an opinion from Tax Counsel, bringing down the opinion received at signing of this Agreement and based upon any changes to relevant facts or federal income tax law (including any differences in facts identified by Buyer between signing and closing of this Agreement), to the effect that Project will qualify for 100% PTCs;

 

(w)         There shall have been no current issuance of a recommendation to seek a take permit by any state or federal wildlife agency with respect to the Project; and

 

(x)           Either (i) Sellers shall have obtained and delivered to Buyer and Title Company surface use agreements with respect to any severed mineral rights, or (ii) the Title Policy includes a special endorsement with respect to such severed mineral rights; in either case in form and substance reasonably acceptable to Buyer. If, after using diligent and commercially reasonable efforts (including the process set forth in Chapter 38-18.1 of the North Dakota Century Code), Sellers are unable to obtain surface use agreements or a special endorsement, in either case reasonably acceptable to Buyer:  (A) Buyer will waive the requirements of this Section 7.2(x) with respect to such parcels if the severed mineral rights on such parcels would not be reasonably likely to have a Material Adverse Effect or (B) allow Sellers to revise the Site Plan to avoid such parcels, subject to reasonable approval by Buyer (provided that any such revision which results in an overall Project net capacity factor of less than 50.0% shall be deemed reasonable cause to reject such revision); provided that if neither the conditions for Buyer waiver under (A) nor the Buyer approval under (B) is satisfied or obtained, respectively, Buyer and Sellers shall negotiate in good faith for a period of thirty (30) days to identify an alternative solution.

 

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(y)          Sellers shall have provided evidence of the payment to the United States Department of Agriculture of any amounts payable as a result of Project improvements in Conservation Reserve Program areas.

 

Section 7.3           Additional Conditions to Obligations of Seller. The obligation of Sellers to effect the Closing is subject to the satisfaction at or before Closing of all of the following conditions, any one or more of which may be waived by Sellers in writing, in Seller’s sole discretion:

 

(a)          each of the representations and warranties of Buyer contained in this Agreement shall be true and correct in all material respects (other than such representations and warranties qualified by materiality, which shall be true and correct in all respects), in each case on and as of the Closing Date as though made on and as of the Closing Date;

 

(b)          Buyer shall have performed, and complied with, in all material respects all covenants and agreements required by this Agreement to be performed, and complied with, by Buyer on or before the Closing Date;

 

(c)          Buyer shall have delivered to Sellers a certificate from a duly authorized officer of Buyer, dated the Closing Date and executed by such officer, in a form reasonably acceptable to Sellers, certifying the items in Section 7.3(a) and Section 7.3(b); and

 

(d)          Buyer shall have delivered (or caused to be delivered) to Sellers, the Closing deliverables described in Section 3.3 above.

 

Article 8

Termination

 

Section 8.1           Termination. This Agreement and the transactions contemplated hereby may be terminated at any time prior to the Closing:

 

(a)          by mutual written consent of the Parties;

 

(b)          by either Sellers on the one hand or Buyer on the other hand if the other Party (i) becomes insolvent, (ii) files a petition in bankruptcy (or has a petition filed against it that is not dismissed by the suffering party within thirty (30) days of such filing), or (iii) makes an assignment for benefit of its creditors;

 

(c)          by either Sellers on the one hand or Buyer on the other hand if the Closing shall not have occurred on or prior to the Outside Date for any reason whatsoever except to the extent the Closing shall have been delayed by a material breach of this Agreement by the Party seeking to terminate the Agreement;

 

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(d)          by either Sellers on the one hand or Buyer on the other hand if, following completion of all system impact and facilities studies associated with MISO Interconnection Queue Request J457, such Party determines that it is reasonably likely that the full nameplate capacity of the Project will not be fully interconnected to the grid and operated as of the Commercial Operation Date such that the closing condition set forth in Section 7.2(t) will not be met; provided, that such terminating Party has given the other Party at least thirty (30) days’ prior notice (the “Interconnection Notice”) of such fact, including a description of the limitations causing such condition not to be met; provided, further, that this Agreement shall not be terminated pursuant to this Section 8.1(d) if prior to the end of such 30-day period (i) Sellers undertake in writing to pay GIA Delay Damages to Buyer as they are determined (and such undertaking shall survive until the resolution of the issues identified in the Interconnection Notice); provided, that the aggregate GIA Delay Damages shall not exceed $[**]; or (ii) Buyer notifies Sellers in writing that Buyer is waiving such condition precedent set forth in Section 7.2(t) with respect to the limitation(s) specified in the Interconnection Notice;

 

(e)          by Buyer, if any condition in Section 7.1 or Section 7.2 becomes incapable of fulfillment by the Outside Date; or if Sellers are in material breach or violation of any provision of this Agreement; provided, that Buyer (i) has given Sellers at least sixty (60) days’ prior notice of the violation or breach and Sellers have not cured such violation or breach in all material respects during such sixty (60) day period, and (ii) has not waived such condition in writing;

 

(f)          by Buyer, if a fact, matter, condition, event or circumstance first disclosed in an Update from Sellers has had or would reasonably be expected to have a Material Adverse Effect; provided, that Buyer must give written notice of its intent to terminate with within 10 days of receipt of any such Update or it irrevocably waives its right to terminate this Agreement; and provide further, that (i) Buyer has given Sellers at least sixty (60) days’ prior notice of the intent to terminate and Sellers have not cured such Material Adverse Effect during such sixty (60) day period or such longer period as is reasonably necessary to cure such Material Adverse Effect, provided Seller diligently pursues such cure, and (ii) such event or occurrence was not caused by Buyer;

 

(g)          by Buyer if:

 

(i)          Sellers have not commenced micrositing with respect to the Project by January 31, 2017;

 

(ii)         Sellers have not filed for the FAA Determinations by March 31, 2017;

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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(iii)        Sellers have not filed, by March 3, 2017, an application for an amendment of the Certificate of Site Compatibility to the NDPSC (which application for amendment notes the Sellers’ decisions, in connection with the Project and the Site, not to provide a buffer for all active sharp-tailed grouse leks and not to pursue an incidental take permit or prepare a habitat conservation plan for the whooping crane or the piping plover); provided, that such date shall be subject to an extension of thirty (30) days as long as (A) Sellers are diligently pursuing such application, (B) the filing of such application is reasonably achievable during such extension, and (C) such delay is not a direct result of any action or failure to act by Sellers; provided, further, that such extended date shall be subject to a further extension of thirty (30) days as long as (x) Sellers are continuing to diligently pursue the filing of such application, (y) the filing of such application is reasonably achievable during such extension, and (z) such delay is not a direct result of any action or failure to act by a Seller;

 

(iv)         Sellers shall have failed to satisfy the requirements of Section 6.11 by August 1, 2017; provided, that such date shall be subject to an extension of ninety (90) days as long as (A) Sellers are diligently pursuing the requirements of Section 6.11, (B) such requirements are reasonably achievable during such extension, and (C) such delay is not a direct result of any action or failure to act by Sellers; or

 

(v)          Sellers shall have failed to deliver to Buyer by December 31, 2017 a current Bird and Bat Conservation Strategy;

 

(h)          by Sellers, if any condition in Section 7.1 or Section 7.3 becomes incapable of fulfillment by the Outside Date; or if Buyer is in material breach or violation of any provision of this Agreement; provided, that Sellers (i) have given Buyer at least sixty (60) days’ prior notice of the violation or breach and Buyer has not cured such violation or breach in all material respects during such sixty (60) day period, and (ii) have not waived such condition in writing;

 

(i)          by Sellers, if a fact, matter, condition, event or circumstance first disclosed in an Update from Buyer has had or would reasonably be expected to have a Material Adverse Effect; provided, that Seller must give written notice of its intent to terminate with within 10 days of receipt of any such Update or it irrevocably waives it right to terminate this Agreement; and provide further, that (i) Sellers have given Buyer at least sixty (60) days’ prior notice of the intent to terminate and Buyer has not cured such Material Adverse Effect during such sixty (60) day period, or such longer period as is reasonably necessary to cure such Material Adverse Effect, provided Buyer diligently pursues such cure, and (ii) such event or occurrence was not caused by Sellers;

 

(j)          automatically in accordance with the terms of Section 6.10(d); or

 

(k)          automatically upon termination of the TEPC in accordance with its terms; or

 

(l)          by Sellers, if Buyer delivers an Update Indemnification Notice in accordance with Section 6.8; provided, that as a condition to such termination, Seller shall be required to pay Buyer an amount equal to the Signing Milestone Payment.

 

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Notwithstanding any term in this Section 8.1, a Party will not have the right to terminate this Agreement if the failure to satisfy any condition to the Closing or consummate the transactions contemplated in this Agreement resulted from the material breach by such Party of any of its representations, warranties, covenants or agreements herein, or if such Party is otherwise in material breach of this Agreement.

 

Section 8.2           Effect of Termination. In the event of the termination of this Agreement and the abandonment of the transactions contemplated hereby pursuant to this Article 8, this Agreement shall be of no further force or effect and there shall be no Liability to any Party hereunder in connection with this Agreement or the transactions contemplated by this Agreement; provided, however that nothing herein shall relieve any Party from liability or damages resulting from any breach of this Agreement prior to the effective date of termination; provided, further that the obligations of the parties set forth in this Section 8.2, Article 10 (including, in each case, the definitions of the terms set forth in Section 1.1) and the Confidentiality Agreement shall survive any such termination and shall be enforceable hereunder.

 

Article 9

INDEMNIFICATION, LIMITATIONS OF LIABILITY AND WAIVERS

 

Section 9.1           Survival. All representations, warranties, covenants and obligations in this Agreement will survive the Closing; provided that, any Indemnity Claim based on a breach of any representation or warranty must be made in accordance with this Article 9 to the Indemnifying Party (or not at all) on or prior to the date that is eighteen (18) months following the Closing Date, except that (i) any Indemnity Claim for a breach of any Designated Representation or any Indemnity Claims based on fraud or intentional misconduct will survive until the end of the applicable statute of limitations and (ii) any Indemnity Claim for a breach of the representations and warranties set forth in Section 4.16 (the “PTC Representations”) shall survive until six (6) years following the Commercial Operation Date. The covenants and obligations of the Parties will survive the Closing and will remain in full force and effect until fully performed.

 

Section 9.2           Indemnification by Sellers. Subject to Sections 9.1 and 9.4, Sellers shall jointly and severally indemnify Buyer and its Affiliates and Representatives (the “Buyer Group”) from and against all Losses arising, directly or indirectly, from or in connection with:

 

(a)          any breach of any representation or warranty made in Article 4 of this Agreement other than Designated Representations;

 

(b)          any breach of any Designated Representation of Sellers;

 

(c)          any breach of the PTC Representations, provided, however, that the ability of the Project to qualify for 80% PTCs  or 60% PTCs, as the case may be, shall be taken into account in determining the Losses arising from such breach of the PTC Representations;

 

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(d)          any breach of any covenant, agreement or other obligation of Sellers contained in this Agreement; and

 

(e)          the retention of the Excluded Liabilities by Sellers.

 

Section 9.3           Indemnification by Buyer. Subject to Sections 9.1 and 9.4, Buyer will indemnify Sellers and their Affiliates and Representatives (the “Seller Group”) from and against all Losses arising, directly or indirectly, from or in connection with:

 

(a)          any breach of any representation or warranty made in Article 5 of this Agreement other than Designated Representations;

 

(b)          any breach of any Designated Representations of Buyer;

 

(c)          any breach of any covenant, agreement or other obligation of Buyer contained in this Agreement; and

 

(d)          the assumption of the Assumed Liabilities by Buyer.

 

Section 9.4           Limitations on Liability. Notwithstanding any contrary provision in this Agreement:

 

(a)          Time Bar on Claims. No Indemnified Party will be entitled to any recovery (including by way of off-set) from any Indemnifying Party unless a Notice of Claim has been given on or before the expiration of time period for survival set forth in Section 9.1.

 

(b)          Insurance Recoveries; Tax Gross-Up. Losses for which any Indemnified Party will be reimbursed hereunder will be decreased by insurance proceeds or payments from any other responsible parties actually received by such Indemnified Party (after deducting costs and expenses incurred in connection with recovery of such proceeds) and will be increased to take account of any net tax cost incurred by the Indemnified Party in the year any indemnification payment for such Losses was received (or an earlier year) arising from the receipt of any such payment hereunder (grossed up for such increase) and will be decreased to take into account any net tax benefit realized by the Indemnified Party in the year the Losses were incurred or paid (or an earlier year) arising from the incurrence or payment of any such Losses.)

 

(c)          Deductible. An Indemnified Party will be entitled to make an Indemnity Claim under Section 9.2 or 9.3 for any and all Indemnity Claims once the aggregate amount of all Indemnity Claims by such Indemnified Party exceeds [**] ($[**]) (the “Deductible”), in which case the Indemnifying Party shall be required to pay all such Losses in excess of the Deductible. Indemnity Claims based on fraud or intentional misconduct shall not be subject to the Deductible.

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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(d)          General Cap. Notwithstanding the foregoing, the aggregate amount of Losses for which an Indemnifying Party shall be liable pursuant to this Article 9 shall not exceed an amount equal to [**]; provided, that such limitation shall not apply to Losses arising out of (i) Indemnity Claims under Section 9.2(b) or Section 9.3(b) which shall not exceed [**], and Section 9.2(c) which shall be limited in accordance with Section 9.4(e), (ii) Indemnity Claims based on fraud or willful misconduct or (iii) Indemnity Claims under Section 9.3(c) based on the failure of Buyer to pay the Purchase Price.

 

(e)          PTC Cap. Notwithstanding the foregoing, the aggregate amount of Losses for which Sellers shall be liable for Indemnity Claims under Section 9.2(c) arising from breaches of the PTC Representations set forth in Section 4.16 (after adjustment pursuant to Section 9.4(b)) shall not exceed an amount equal to [**] ($[**]).

 

(f)          Tax Treatment. Any indemnity payment made pursuant to this Agreement will be treated as an adjustment to the Purchase Price for Tax purposes, unless an audit or other administrative or judicial action with respect to the Indemnified Party causes any such payment not to constitute an adjustment to the Purchase Price for U.S. federal income tax purposes.

 

(g)          NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS SECTION 9.4, THE PARTIES RETAIN ALL RIGHTS AND REMEDIES AT LAW WITH RESPECT TO FRAUD OR ANY WILLFUL MISCONDUCT.

 

(h)          EXCEPT IN THE CASE OF AN INDEMNITY CLAIM UNDER SECTION 9.2(C), IN NO EVENT SHALL EITHER PARTY BE LIABLE FOR ANY LOST OR PROSPECTIVE PROFITS NOR ANY PUNITIVE, EXEMPLARY, CONSEQUENTIAL, INCIDENTAL OR INDIRECT LOSSES OR DAMAGES (IN TORT, CONTRACT OR OTHERWISE) UNDER OR IN RESPECT TO THIS AGREEMENT, OTHER THAN SUCH DAMAGES THAT ARISE OUT OF A CLAIM MADE BY A THIRD PARTY AGAINST BUYER OR SELLERS, AS APPLICABLE.

 

Section 9.5           Procedures for Third Party Claims.

 

(a)          Promptly after receipt by an Indemnified Party of notice of the commencement of any Action by a third party (a “Third Party Claim”) with respect to any matter for which indemnification is or may be owing pursuant to Section 9.2 or 9.3 hereof, the Indemnified Party will give notice thereof to the Indemnifying Party, provided, however, that the failure of the Indemnified Party to notify the Indemnifying Party will not relieve the Indemnifying Party of any of its obligations hereunder, except to the extent that the Indemnifying Party demonstrates that the defense of such Third Party Claim has been actually prejudiced by the Indemnified Party’s failure to give such notice.

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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(b)          If any Action referred to in Section 9.5(a) is brought against an Indemnified Party and the Indemnified Party gives notice to the Indemnifying Party of the commencement of such Action, the Indemnifying Party will be entitled to participate in such Action, and (unless (x) the Indemnifying Party is also a party to such Action and the Indemnified Party determines in good faith that joint representation would be inappropriate upon the advice of outside counsel that a conflict of interest exists between the Indemnified Party and the Indemnifying Party with respect to such Action, or (y) the Indemnifying Party fails to provide reasonable assurance to the Indemnified Party of its financial capacity to defend such Action and provide indemnification with respect to such Action) may assume the defense of such Action with counsel satisfactory to the Indemnified Party and, after notice from the Indemnifying Party to the Indemnified Party of its election to assume the defense of such Action, the Indemnifying Party will not, as long as it diligently conducts such defense, be liable to the Indemnified Party under this Section 9.5 for any fees of other counsel with respect to the defense of such Action, in each case subsequently incurred by the Indemnified Party in connection with the defense of such Action.

 

(c)          If the Indemnifying Party is entitled to and assumes the defense of an Action, no compromise or settlement of such claims or Action may be effected by the Indemnifying Party without the Indemnified Party’s written consent (which shall not be unreasonably withheld) unless (i) there is no finding or admission of any violation of Law or any violation of the rights of any Person and no effect on or grounds for the basis of any other Claims that may be made against the Indemnified Party, and (ii) the sole relief provided is monetary damages that are paid in full by the Indemnifying Party; and the Indemnified Party will have no Liability with respect to any compromise or settlement of such claims or Action effected without Indemnified Party’s written consent. Notwithstanding the assumption by the Indemnifying Party of the defense of any Claim or Action, the Indemnified Party will be permitted to join in such defense and to employ counsel at its own expense. If notice pursuant to Section 9.5(a) is given to an Indemnified Party of the commencement of any Action and the Indemnifying Party does not, within ten (10) Business Days after such Indemnified Party’s notice is given, give notice to the Indemnified Party of its election to assume the defense of such Action, the Indemnifying Party will be bound by any determination made in such Action or any compromise or settlement effected by the Indemnified Party.

 

(d)          Notwithstanding the foregoing, if the Indemnified Party determines in good faith that there is a reasonable probability that an Action may adversely affect the Indemnified Party or its Affiliates other than as a result of monetary Losses for which it would be entitled to indemnification under this Agreement, the Indemnified Party may, by notice to the Indemnifying Party, assume the exclusive right to defend, compromise or settle such Action, but the Indemnifying Party will not be bound by any compromise or settlement effected without its written consent (which may not be unreasonably withheld).

 

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(e)          The Indemnifying Party and the Indemnified Party agree to provide each other with reasonable access during regular business hours to the properties, books and records and Representatives of the other, as reasonably necessary in connection with the preparation for an existing or anticipated Action involving a Third Party Claim and its obligations with respect thereto pursuant to this Article 9.

 

Section 9.6           Indemnification Procedures. The following procedures will apply to any claim for indemnification by Buyer Group or the Seller Group that does not involve a Third Party Claim:

 

(a)          Notice of Claim. A Notice of Claim will be given as soon as practicable, but in no event later than sixty (60) days, after the Indemnified Party determines that it is or may be entitled to indemnification pursuant to this Agreement; provided, however, that failure to provide notice will not prejudice the Indemnified Party’s right to indemnity, except to the extent the Indemnifying Party is irrevocably prejudiced. Notice of Claim will be made as follows:

 

(i)          in the case of any Indemnity Claim by any member of Buyer Group, by Buyer to Sellers at the address and in the manner provided in Section 10.1 (Notices). Buyer will be the Indemnified Party with respect to Indemnity Claims pursuant to Section 9.2, and no liability in respect of any such Indemnity Claim will be contested, settled, admitted, litigated or otherwise dealt with by or on behalf of Buyer Group for this purpose by any person other than Buyer; and

 

(ii)         in the case of any Indemnity Claim by any member of the Seller Group against Buyer, by Sellers to Buyer at the address and in the manner provided in Section 10.1 (Notices). Sellers will be the Indemnified Party with respect to Indemnity Claims pursuant to Section 9.3, and no liability in respect of any such Indemnity Claim will be contested, settled, admitted, litigated or otherwise dealt with by or on behalf of the Seller Group for this purpose by any person other than Sellers.

 

(b)          Dispute Notice. If the Indemnifying Party disputes (x) its obligation to indemnify the Indemnified Party in respect of any Indemnity Claim set forth in a Notice of Claim, or (y) the Indemnity Claim Amount set forth in a Notice of Claim, a dispute notice (“Dispute Notice”) will be given as soon as practicable, but in no event later than forty-five (45) days, after the Notice of Claim is given, as follows:

 

(i)          in the case of any Indemnity Claim by any member of Buyer Group against Sellers, a Dispute Notice may be given only by Sellers, and if given, will be sent by Sellers to Buyer at the address and in the manner provided in Section 10.1 (Notices); and

 

(ii)         in the case of any Indemnity Claim by any member of the Seller Group against Buyer, a Dispute Notice may be given only by Buyer, and if given, will be sent by Buyer to Sellers at the address and in the manner provided in Section 10.1 (Notices).

 

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(A)         If no Dispute Notice is given within such thirty (30) day period, the validity of the claim for indemnification and the Indemnity Claim Amount, each as set forth in the Notice of Claim, will be deemed to be agreed, effective on the first (1st) day following such thirty (30) day period, and the Indemnity Claim Amount set forth in the Notice of Claim will immediately be an “Indemnity Amount Payable” of the relevant Indemnifying Party.

 

(B)         If a Dispute Notice is given within such thirty (30) day period, then:

 

(1)         The portion, if any, of the Indemnity Claim Amount which is not disputed in the Dispute Notice will immediately be an Indemnity Amount Payable of the relevant Indemnifying Party.

 

(2)         Buyer and Sellers will negotiate in good faith to settle the dispute, and the portion, if any, of the Indemnity Claim Amount which Buyer and Sellers agree in writing is payable will immediately be an Indemnity Amount Payable of the relevant Indemnifying Party.

 

(3)         If Buyer and Sellers are unable to resolve any portion of the Indemnity Claim Amount within two (2) months following the date the Dispute Notice is given, either Buyer or Sellers may initiate proceedings specified in Section 10.12 (Governing Law; Venue; and Jurisdiction) of this Agreement to obtain resolution of the dispute.

 

(4)         If neither Buyer nor any Seller initiates legal proceedings in respect of the dispute within twelve (12) months following the date the Dispute Notice is given, the portion of the Indemnity Claim Amount which is disputed will not be an Indemnity Amount Payable, and the Indemnified Party will have no further right, under this Agreement, to seek to recover such amount from the Indemnifying Party.

 

(5)         If Buyer or Sellers initiates legal proceedings within the twelve (12) month period specified in Section 9.6(b)(ii)(B)(4), the amount, if any, determined in a Final Order as payable by the Indemnifying Party will be an Indemnity Amount Payable of the relevant Indemnifying Party as of the date of such Final Order.

 

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Section 9.7           Payments of Indemnity Amounts Payable by Buyer. Subject to the limitations in Section 9.4, Buyer will pay to each relevant Indemnified Party any Indemnity Amount Payable by Buyer, by wire transfer of immediately available dollars (or as otherwise directed pursuant to any Final Order or as otherwise agreed by the Indemnified Party and the Indemnifying Party) to an account designated by Sellers, promptly and in no event later than ten (10) Business Days after such Indemnity Amount Payable is established in accordance with this Agreement.

 

Section 9.8           Payments of Indemnity Amounts Payable by Sellers. Subject to the limitations in Section 9.4, any Indemnity Amount Payable by Sellers to each relevant Indemnified Party will be paid by wire transfer of immediately available dollars (or as otherwise directed pursuant to any Final Order or as otherwise agreed by the Indemnified Party and the Indemnifying Party) to an account designated by Buyer, promptly and in no event later than ten (10) Business Days after such Indemnity Amount Payable is established in accordance with this Agreement.

 

Section 9.9           Exclusive Remedy. Except for fraud or willful misconduct, the sole and exclusive remedies for any breach of the terms and provisions of this Agreement (including any representations and warranties and covenants set forth herein, made in connection herewith or as an inducement to enter into this Agreement) or any claim or cause of action otherwise arising out of or related to the subject matter hereof, will be such remedies set forth in this Agreement, including and subject to the limitations set forth in this Article 9.

 

Article 10

MISCELLANEOUS

 

Section 10.1         Notices.

 

(a)          Unless this Agreement specifically requires otherwise, any notice, demand or request provided for in this Agreement, or served, given or made in connection with it, will be in writing and will be deemed properly served, given or made if delivered in person or sent by facsimile or email (in the case of delivery by facsimile or email, solely if receipt is confirmed) or sent by registered or certified mail, postage prepaid, or by a nationally recognized overnight courier service that provides a receipt of delivery, in each case, to the Parties at the addresses specified below:

 

If to Buyer, to:

 

Otter Tail Power Company
215 South Cascade Street

Fergus Falls, MN 56537

Attention: Harvey McMahon, Manager, Renewable Energy Construction & Operations

Telephone: (701) 253-4732

Facsimile: (218) 739-8629

Email: HMcMahon@otpco.com

 

With a copy to:

 

Otter Tail Power Company
215 South Cascade Street

Fergus Falls, MN 56537

Attention: Legal Department

Telephone: (218) 739-8922

Facsimile: (218) 998-3165

Email: mbring@otpco.com

 

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And a copy to:

 

Dorsey & Whitney LLP

Suite 1500

50 South Sixth Street

Minneapolis, MN 55402

Attention: John Seymour

Telephone: (612) 492-6020

Facsimile: (612) 340-2868

Email: Seymour.John@dorsey.com

 

If to Sellers, to:

 

EDF Renewable Energy

15445 Innovation Drive

San Diego, CA 92128

Attention: Sohinaz Sotoudeh

Telephone: (917) 549-3346

Facsimile: (858) 521-3333

Email: Sohinaz.Sotoudeh@edf-re.com

 

With a copy to:

 

EDF Renewable Energy

15445 Innovation Drive

San Diego, CA 92128

Attention: Joshua Pearson

Telephone: (858) 521-3467

Facsimile: (858) 521-3333

Email: Joshua.Pearson@edf-re.com

 

With a copy to:

 

Stoel Rives LLP

33 South Sixth Street, Suite 4200

Minneapolis, MN 55402

Attention: David Quinby

Telephone: (612) 373-8825

Facsimile: (612) 373-8881

Email: david.quinby@stoel.com

 

(b)          Notice given by personal delivery, mail or overnight courier pursuant to this Section 10.1 will be effective upon physical receipt. Notice given by facsimile or email pursuant to this Section 10.1 will be effective as of the date of confirmed delivery if delivered before 5:00 p.m. Central Time on any Business Day or the next succeeding Business Day if confirmed delivery is after 5:00 p.m. Central Time on any Business Day or during any non-Business Day.

 

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Section 10.2         Entire Agreement. Except for the Confidentiality Agreement, this Agreement, the TEPC and the Ancillary Agreements supersede all prior discussions and agreements between the Parties with respect to the subject matter hereof, and this Agreement, the Ancillary Agreements, the Confidentiality Agreement and the other documents delivered pursuant to this Agreement contain the sole and entire agreement between the Parties hereto with respect to the subject matter hereof. The Parties hereto have voluntarily agreed to define their rights, liabilities and obligations with respect to the subject matter hereof exclusively in contract pursuant to the express terms and provisions of this Agreement, the Ancillary Agreements, the Confidentiality Agreement and the other documents delivered pursuant to this Agreement; and the Parties hereto expressly disclaim that they are owed any duties or are entitled to any remedies not expressly set forth in this Agreement. Furthermore, the Parties each hereby acknowledge that this Agreement embodies the justifiable expectations of sophisticated parties derived from arm’s-length negotiations; all Parties specifically acknowledge that no Seller has any special relationship with Buyer that would justify any expectation beyond that of an ordinary buyer and an ordinary seller in an arm’s-length transaction.

 

Section 10.3         Expenses. Except as otherwise expressly provided in this Agreement, whether or not the transactions contemplated hereby are consummated, each Party will pay its own costs and expenses incurred in anticipation of, relating to and in connection with the negotiation and execution of this Agreement and the transactions contemplated hereby, including all expenses and costs incurred to obtain approvals required by such Party from Governmental Authorities.

 

Section 10.4         Disclosure. Sellers may, at their option, include in the Schedules items that are not material in order to avoid any misunderstanding, and any such inclusion, or any references to dollar amounts, will not be deemed to be an acknowledgment or representation that such items are material, to establish any standard of materiality or to define further the meaning of such terms for purposes of this Agreement. Information disclosed in any Schedule will constitute a disclosure for purposes of all other Schedules notwithstanding the lack of specific cross-reference thereto, but only to the extent the applicability of such disclosure to such other Schedule is readily apparent. In no event will the inclusion of any matter in the Schedules be deemed or interpreted to broaden Sellers’ representations, warranties, covenants or agreements contained in this Agreement. The mere inclusion of an item in the Schedules will not be deemed an admission by Sellers that such item represents a material exception or fact, event, or circumstance or that such item is reasonably likely to result in a Material Adverse Effect. Each Party will promptly notify the other Party upon becoming aware of (a) the occurrence, or failure to occur, of any event, which occurrence or failure has caused any representation or warranty of such Party contained in this Agreement or in any exhibit, schedule, certificate, document or written instrument attached hereto to be untrue or inaccurate, (b) any failure of such Party to comply with, perform or satisfy, in any respect, any covenant, condition or agreement to be complied with, performed by or satisfied by it under this Agreement or any exhibit, schedule, certificate, document or written instrument attached hereto and (c) any notice or other communication from any Governmental Authority in connection with this Agreement or the transactions contemplated herein and therein; provided, that such disclosure will not be deemed to cure, or to relieve any Party of any liability or obligation with respect to, any breach of or failure to satisfy any representation, warranty, covenant or agreement or any condition hereunder, and will not affect any Party’s right with respect to indemnification hereunder, except as provided in Section 6.8.

 

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Section 10.5         Waiver. Any term or condition of this Agreement may be waived at any time by the Party that is entitled to the benefit thereof, but no such waiver will be effective unless set forth in a written instrument duly executed by or on behalf of the Party waiving such term or condition. No waiver by any Party of any term or condition of this Agreement, in any one or more instances, will be deemed to be or construed as a waiver of the same or any other term or condition of this Agreement on any future occasion. All remedies under this Agreement will be cumulative and not alternative.

 

Section 10.6         Amendment. This Agreement may be amended, supplemented or modified only by a written instrument duly executed by or on behalf of each Party.

 

Section 10.7         No Third Party Beneficiary. Except for the provisions of Sections 9.2 and 9.3 (which are intended for the benefit of the Persons identified therein), the terms and provisions of this Agreement are intended solely for the benefit of the Parties and their respective successors or permitted assigns, and it is not the intention of the Parties to confer third-party beneficiary rights upon any other Person. For the avoidance of doubt, no Person who is not a Party to this Agreement, may challenge any termination of this Agreement, for any reason, or enforce or seek to enforce any provisions of this Agreement (except as set forth in the first sentence of this Section).

 

Section 10.8         Assignment; Binding Effect. Buyer may assign its rights to indemnification under this Agreement to any Affiliate or to Buyer’s lenders for collateral security purposes, but such assignment will not release Buyer from its obligations hereunder. Except as provided in the preceding sentence, neither this Agreement nor any right, interest or obligation hereunder may be assigned by any Party without the prior written consent of each of the other Party.

 

Section 10.9         Headings. The headings used in this Agreement have been inserted for convenience of reference only and do not define or limit the provisions hereof.

 

Section 10.10         Invalid Provisions. If any provision of this Agreement is held to be illegal, invalid or unenforceable under any present or future Law, and if the rights or obligations of any Party under this Agreement will not be materially and adversely affected thereby, such provision will be fully severable, this Agreement will be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, the remaining provisions of this Agreement will remain in full force and effect and will not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom and in lieu of such illegal, invalid or unenforceable provision, there will be added automatically as a part of this Agreement a legal, valid and enforceable provision as similar in terms to such illegal, invalid or unenforceable provision as may be possible.

 

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Section 10.11         Counterparts; Facsimile. This Agreement may be executed in any number of counterparts, each of which will be deemed an original, but all of which together will constitute one and the same instrument. Any facsimile or portable document format (pdf) copies hereof or signature hereon will, for all purposes, be deemed originals.

 

Section 10.12         Governing Law; Venue; and Jurisdiction.

 

(a)          This Agreement, and all claims or causes of action (whether in contract or tort) that may be based upon, arise out of or relate to this Agreement, or the negotiation, execution or performance of this Agreement (including any claim or cause of action based upon, arising out of or related to any representation or warranty made in or in connection with this Agreement or as an inducement to enter into this Agreement), will be governed by the laws of the State of New York without giving effect to any conflict or choice of law provision.

 

(b)          THE PARTIES HEREBY IRREVOCABLY SUBMIT TO THE EXCLUSIVE JURISDICTION OF ANY STATE OR FEDERAL COURT IN MINNEAPOLIS, MINNESOTA FOR PURPOSES OF ANY SUIT, ACTION OR OTHER PROCEEDING ARISING OUT OF THIS AGREEMENT OR ANY TRANSACTION CONTEMPLATED HEREBY AND EACH PARTY HEREBY CONSENTS TO THE JURISDICTION OF SUCH COURTS (AND OF THE APPROPRIATE APPELLATE COURTS THEREFROM) IN ANY SUCH SUIT, ACTION OR PROCEEDING AND IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING IN ANY SUCH COURT OR THAT ANY SUCH SUIT, ACTION OR PROCEEDING THAT IS BROUGHT IN ANY SUCH COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. DURING THE PERIOD A LEGAL DISPUTE THAT IS FILED IN ACCORDANCE WITH THIS SECTION 10.12 IS PENDING BEFORE A COURT, ALL ACTIONS, SUITS OR PROCEEDINGS WITH RESPECT TO SUCH LEGAL DISPUTE OR ANY OTHER LEGAL DISPUTE, INCLUDING ANY COUNTERCLAIM, CROSS-CLAIM OR INTERPLEADER, WILL BE SUBJECT TO THE EXCLUSIVE JURISDICTION OF SUCH COURT. EACH PARTY HEREBY WAIVES, AND WILL NOT ASSERT AS A DEFENSE IN ANY LEGAL DISPUTE, THAT (A) SUCH PARTY IS NOT SUBJECT THERETO, (B) SUCH ACTION, SUIT OR PROCEEDING MAY NOT BE BROUGHT OR IS NOT MAINTAINABLE IN SUCH COURT, (C) SUCH PARTY’S PROPERTY IS EXEMPT OR IMMUNE FROM EXECUTION, (D) SUCH ACTION, SUIT OR PROCEEDING IS BROUGHT IN AN INCONVENIENT FORUM OR (E) THE VENUE OF SUCH ACTION, SUIT OR PROCEEDING IS IMPROPER. A FINAL JUDGMENT IN ANY ACTION, SUIT OR PROCEEDING DESCRIBED IN THIS SECTION 10.12 FOLLOWING THE EXPIRATION OF ANY PERIOD PERMITTED FOR APPEAL AND SUBJECT TO ANY STAY DURING APPEAL WILL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY APPLICABLE LAWS.

 

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(c)          EACH PARTY HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY.

 

Section 10.13         Specific Performance. The Parties acknowledge and agree that irreparable damage would occur in the event that any of the provisions of this Agreement were not performed in accordance with their specific terms or were otherwise breached. It is accordingly agreed that the Parties shall be entitled to an injunction or injunctions to prevent breaches or threatened breaches of this Agreement and to specifically enforce the terms and provisions of this Agreement and any other agreement or instrument executed in connection herewith or contemplated hereby, and the Parties agree that specific performance is the remedy intended by the parties for any such breaches or threatened breaches. The Parties further agree that (a) by seeking the remedies provided for in this Section 10.13, a Party shall not in any respect waive its right to seek any other form of relief that may be available to a party under this Agreement, including monetary damages and (b) the commencement of any Action pursuant to this Section 10.13 or anything contained in this Section 10.13 shall not restrict or limit any other remedies under this Agreement that may be available then or thereafter.

 

[signature pages follow]

 

- 61 - 

 

 

IN WITNESS WHEREOF, this Agreement has been duly executed and delivered by the duly authorized officer of each Party as of the date first above written.

 

  SELLERS:
   
  EDF RENEWABLE DEVELOPMENT, INC.,
  a Delaware corporation
     
  By: /s/ Tristan Grimbert
    Name: Tristan Grimbert
    Title: President and Chief Executive Officer
   
  POWER PARTNERS MIDWEST, LLC,
  a Delaware limited liability company
     
  By: EDF Renewable Energy, Inc., its Manager
     
    By: /s/ Tristan Grimbert
      Name: Tristan Grimbert
      Title: President and Chief Executive Officer
   
  EDF-RE US DEVELOPMENT, LLC,
  a Delaware limited liability company
   
  By: EDF Renewable Development, Inc., its Managing Member
     
    By: /s/ Tristan Grimbert
      Name: Tristan Grimbert
      Title: President and Chief Executive Officer

 

[Signature pages to Asset Purchase Agreement]

 

 

 

 

  MERRICOURT POWER PARTNERS, LLC,
  a Delaware limited liability company
   
  By: EDF-RE US Development, LLC, its Manager
  By: EDF Renewable Development, Inc., its Managing Member
   
    By: /s/ Tristan Grimbert
      Name: Tristan Grimbert
      Title: President and Chief Executive Officer

 

[Signature pages to Asset Purchase Agreement]

 

 

 

 

  BUYER:
   
  OTTER TAIL POWER COMPANY,
  a Minnesota corporation
     
  By: /s/ Timothy J. Rogelstad
    Name: Timothy J. Rogelstad
    Title: President

 

[Signature pages to Asset Purchase Agreement]

 

 

 

 EX-2.C 3 t1700069_ex2-c.htm EXHIBIT 2-C

 

 

 

Exhibit 2-C

 

Confidential treatment has been requested for portions of this exhibit pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended. The copy filed herewith omits the information subject to the confidentiality request. Omissions are designated as [**]. A complete version of this exhibit has been filed separately with the Securities and Exchange Commission.

 

Execution Version

 

TURNKEY ENGINEERING, PROCUREMENT AND CONSTRUCTION

SERVICES AGREEMENT

(MERRICOURT WIND PROJECT)

 

Dated as of November 16, 2016

 

By and between

 

OTTER TAIL POWER COMPANY

 

as Owner

 

and

 

EDF-RE US DEVELOPMENT, LLC

as Contractor

 

 

 

 

TABLE OF CONTENTS

 

  Page
   
Article 1 DEFINITIONS AND RULES OF INTERPRETATION 1
   
Section 1.1 Definitions 1
Section 1.2 Rules of Interpretation 18
     
Article 2 THE PROJECT 19
   
Section 2.1 Scope of Work 19
Section 2.2 Contractor Obligations 20
Section 2.3 Compliance 22
Section 2.4 Project Schedule; Monthly Progress Report; Recovery Plan 22
Section 2.5 Engineering and Design 24
Section 2.6 Procurement 26
Section 2.7 Labor and Personnel 27
Section 2.8 Project Quality Assurance Plan 28
Section 2.9 Permits and Other Approvals 28
Section 2.10 Real Property Rights 29
Section 2.11 Turnover Packages. 29
Section 2.12 Construction Methods and Safety Procedures 30
Section 2.13 Commissioning and Testing 33
Section 2.14 Clean-up; Non-interference 33
Section 2.15 Books and Records; Audit Rights 33
Section 2.16 Commencement of the Work 34
Section 2.17 Interconnection 34
Section 2.18 Owner’s Right to Inspect 34
Section 2.19 Notice of Claims and Liens 35
Section 2.20 Cooperation 35
Section 2.21 Security and Assignment Agreements and Consents 36
     
Article 3 SUBCONTRACTORS 36
   
Section 3.1 Subcontractors 36
Section 3.2 Major Subcontracts 37
Section 3.3 Change in Major Subcontractor due to Owner’s Objections 37
     
Article 4 Agreement PRICE AND PAYMENTS 37
   
Section 4.1 Agreement Price 37
Section 4.2 Taxes 38
Section 4.3 Payment of the Agreement Price 40
Section 4.4 Disputed Invoices 41
Section 4.5 Conditions of Payment 41
Section 4.6 Evidence of Payments to Turbine Supplier 41
Section 4.7 Guarantees; Backup Letter of Credit 41
Section 4.8 Interest 42

 

 i

 

 

Section 4.9 Effect of Payment 42
Section 4.10 Set-off 43
Section 4.11 Payment Dates 43
Section 4.12 Payment Withheld 43
Section 4.13 Release of Liens 43
Section 4.14 Final Payment 43
     
Article 5 OWNER RESPONSIBILITIES 43
   
Section 5.1 Project Site Access 43
Section 5.2 Permits 44
Section 5.3 [Reserved] 44
Section 5.4 Review of Design Documents 44
Section 5.5 Owner-Caused Delay 44
     
Article 6 COMPLETION; COMMISSIONING AND TURNOVER 44
   
Section 6.1 General 44
Section 6.2 Foundation Completion 44
Section 6.3 WTG Mechanical Completion 45
Section 6.4 Commissioning and Turnover of Electrical Works 46
Section 6.5 Project Substantial Completion 47
Section 6.6 Final Completion 48
Section 6.7 Achievement of Foundation Completion, Commissioning and Turnover of Electrical Works, Mechanical Completion, WTG Substantial Completion, Project Substantial Completion and Final Completion 49
Section 6.8 Completion Guarantees 50
Section 6.9 Delay Liquidated Damages 50
     
Article 7 WARRANTIES 51
   
Section 7.1 Infrastructure Facilities Warranty 51
Section 7.2 WTG Warranties 54
Section 7.3 Subcontractor Warranties 54
Section 7.4 General Limitations on Warranties and Remedies 54
     
Article 8 FORCE MAJEURE 54
   
Section 8.1 Performance Excused 54
Section 8.2 Disputes; Burden of Proof 56
     
Article 9 SCOPE CHANGES 56
   
Section 9.1 Scope Changes 56
Section 9.2 Scope Change by Owner 57
Section 9.3 No Unapproved Scope Changes 57
Section 9.4 Required Scope Changes 57
Section 9.5 Authorization for Scope Change 58
Section 9.6 Agreement on Firm or Unit Prices 58

 

 ii

 

 

Section 9.7 Absence of Agreement on Firm or Unit Prices 58
Section 9.8 Scope Changes Due to Concealed Subsurface Conditions 58
Section 9.9 Scope Changes Caused by a Force Majeure Event 59
Section 9.10 Owner-Caused Delays 59
Section 9.11 Weather Delay Days 59
     
Article 10 INDEMNIFICATION 60
   
Section 10.1 Indemnities 60
     
Article 11 LIMITATION OF LIABILITY 63
   
Section 11.1 Contractor Delay Liquidated Damages Cap 63
Section 11.2 Contractor’s Aggregate Liability Cap 63
Section 11.3 Contractor Buy-Back Right 63
Section 11.4 PTC Liquidated Damages 63
Section 11.5 CONSEQUENTIAL DAMAGES 64
Section 11.6 Liquidated Damages Not a Penalty 64
Section 11.7 Limitation of Owner Liabilities 65
Section 11.8 Releases Valid in All Events 65
     
Article 12 INSURANCE 65
   
Section 12.1 Coverage by Contractor and Owner 65
Section 12.2 No Limitation Intended 65
Section 12.3 Failure to Obtain or Maintain Coverage 65
     
Article 13 DEFAULT; TERMINATION AND SUSPENSION 66
   
Section 13.1 Contractor Defaults 66
Section 13.2 Owner Remedies 67
Section 13.3 Owner Default 68
Section 13.4 Contractor Rights to Terminate 69
Section 13.5 Termination of Asset Purchase Agreement 70
Section 13.6 Actions Required Following Termination 70
     
Article 14 TITLE AND RISK OF LOSS 71
   
Section 14.1 Title to WTGs, Infrastructure Facilities and the Work 71
Section 14.2 Ownership of Work Documents 71
Section 14.3 Risk of Loss 72
Section 14.4 Revenues 72
     
Article 15 DISPUTE RESOLUTION 72
   
Section 15.1 Choice of Law 72
Section 15.2 Attempt to Resolve Disputes 72
Section 15.3 Forum Selection 72
Section 15.4 WAIVER OF JURY TRIAL; ENFORCEMENT PROCEEDINGS 73
Section 15.5 Service of Process 73
Section 15.6 Continued Performance 73

 

 iii

 

 

Article 16 REPRESENTATIONS AND WARRANTIES 73
   
Section 16.1 Contractor Representations 73
Section 16.2 Owner Representations 74
     
Article 17 MISCELLANEOUS PROVISIONS 75
   
Section 17.1 Confidentiality 75
Section 17.2 Public Announcements; Press Release 76
Section 17.3 Software and Other Proprietary Material 76
Section 17.4 Notice 77
Section 17.5 No Rights in Third Parties 78
Section 17.6 Conflicting Provisions 78
Section 17.7 Entire Agreement 78
Section 17.8 Amendments 78
Section 17.9 [Reserved] 79
Section 17.10 Right of Waiver 79
Section 17.11 Severability 79
Section 17.12 Assignment 79
Section 17.13 Successors and Assigns 79
Section 17.14 No Partnership Created 79
Section 17.15 Survival 79
Section 17.16 Effectiveness 79
Section 17.17 Further Assurances 80
Section 17.18 Captions 80
Section 17.19 Equal Employment Opportunity 80
Section 17.20 Counterparts 80

 

EXHIBITS

 

Exhibit 1.1 Description of Project Site and Real Property Rights
Exhibit 2.2.2 Part 0 – Scope of Work
  Part 1 – WTG Technical Specifications
  Part 2a – Road Specification
  Part 2b – Hydrology Specification
  Part 3 –Transformer Specification
  Part 4 – Foundation Technical Specifications
  Part 5 – Infrastructure Layout
  Part 6 – Collection System Technical Specifications
  Part 7 –  O&M Building Technical Specifications and Floor Plan
  Part 8 – Power System Study Specification
  Part 9 - SCADA Specification
  Part 10 - General Engineering Specification
  Part 11 – Substation Specification
Exhibit 2.2.7 Training Program
Exhibit 2.4.1 Project Schedule
Exhibit 2.4.3 Form of Monthly Progress Report

 

 iv

 

 

Exhibit 2.5.2 Owner’s Safety Procedures
Exhibit 2.5.5 Project Document Submittals and As-Built Drawings Schedule
Exhibit 2.6.1   Project One-Line Diagrams, Equipment and Material List
  Part 1 Project One-Line Diagram
  Part 2 Example Equipment and Material List
Exhibit 2.8 Project Quality Assurance Plan
Exhibit 2.9 List of Permits
Exhibit 2.12.1 Contractor’s Safety Program
Exhibit 3.1.2 Form of Assignment Clause for Subcontracts
Exhibit 3.2 List of Approved Subcontractors
Exhibit 4.1 Payment Schedule
Exhibit 4.1.1 Options
Exhibit 4.1.2 Form of Owner LOC
Exhibit 4.2.4 Tax Exemption Certificate
Exhibit 4.3 Form of Milestone Payment Request
Exhibit 4.5 Form of Partial Lien Waivers
Exhibit 4.5.a Form of Final Lien Waivers
Exhibit 4.7 Form of EDF-EN Guaranty
Exhibit 4.7.a Form of Construction Period Guaranty
Exhibit 4.7.b Form of Post-Construction Guaranty
Exhibit 4.7.c Form of Backup LOC
Exhibit 6.2.7 Form of Foundation Completion Certificate
Exhibit 6.3 Form of WTG Mechanical Completion Certificate
Exhibit 6.3.1 Mechanical Completion Checklist
Exhibit 6.4 Form of Electrical Works Commissioning and Turnover Certificate
Exhibit 6.4.3 Commissioning, Test and Inspection Procedures
Exhibit 6.5 Form of WTG Commissioning and Turnover Certificate
Exhibit 6.5.10 Part 1  [Reserved]
  Part 2  WTG Substantial Completion Certificate
  Part 3  Project Substantial Completion Certificate
Exhibit 6.6.13 Form of Final Completion Certificate
Exhibit 9.11 Contractor’s Time and Materials Rates
Exhibit 12 Insurance
Exhibit 13.2.2 Turbine Supply Security and Collateral Assignment
Exhibit 13.2.2.a Turbine Supplier Consent to Assignment
Exhibit 13.2.2.b Prime Subcontract Security and Collateral Assignment

 

SCHEDULES

 

Schedule 11.4 Adjustment of PTC Liquidated Damages

  

 v

 

 

TURNKEY ENGINEERING, PROCUREMENT AND CONSTRUCTION SERVICES AGREEMENT

 

THIS TURNKEY ENGINEERING, PROCUREMENT AND CONSTRUCTION SERVICES AGREEMENT (this “Agreement”), is made, entered into and effective as of November 16, 2016, (“Effective Date”) by and between OTTER TAIL POWER COMPANY, a Minnesota corporation (“Owner”), and EDF-RE US DEVELOPMENT, LLC, a Delaware limited liability company (“Contractor”) (each of Owner and Contractor individually referred to as a “Party” and together as the “Parties”).

 

RECITALS

 

A.           Contractor is in the process of developing a 150 MW wind energy generation project in McIntosh and Dickey Counties, North Dakota, capable of supporting the installation and operation of seventy-five (75) Vestas 2.0 V110 wind turbines, each with a 2.0 megawatt nameplate rating, and in connection therewith has acquired certain real estate rights and other assets and commenced certain development activities (the “Project”).

 

B.           Owner desires to acquire the Project prior to the commencement of construction thereof.

 

C.           Pursuant to a separate Asset Purchase Agreement entered into between the Parties concurrently herewith, Owner, Contractor and certain Affiliates of Contractor have agreed upon the terms whereby Contractor will sell the Project Site, the 5% Safe Harbor Turbines and certain other assets related to the Project to the Owner.

 

D.           Owner desires to engage and hire Contractor to provide certain project management, design, engineering, procurement, construction, commissioning, start-up, turnover and related services for the Project, all on a turnkey fixed price basis, and in accordance with the terms and conditions specified herein.

 

E.           The Parties desire to enter into this Agreement in order to set forth their respective rights and obligations.

 

AGREEMENT

 

NOW THEREFORE, in consideration of the foregoing premises, the mutual agreements herein contained, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

 

Article 1
DEFINITIONS AND RULES OF INTERPRETATION

 

Section 1.1           Definitions. As used in this Agreement, the following terms shall have the meanings indicated:

 

“5% Safe Harbor Turbines” has the meaning set forth in the Asset Purchase Agreement.

 

 

 

 

“Affiliate” means with respect to any Person, any other Person that directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with that Person. The term “control” (including, with correlative meaning, the terms “controlled by” and “under common control with”), as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities or partnership interests, by contract or otherwise.

 

“Agreement” means this Turnkey Engineering, Procurement and Construction Services Agreement and all Exhibits hereto, as the same may be modified, amended, or supplemented from time to time in accordance with the terms hereof.

 

“Agreement Documents” means this Agreement, Exhibits, Drawings, As-Built Drawings, Documents, Technical Specifications, Scope Change Orders and Design Documents.

 

“Agreement Price” has the meaning set forth in Section 4.1.

 

“Applicable Laws” means all statutes, laws, treaties, ordinances, exemptions, judgments, decrees, injunctions, writs, orders, rules, regulations, any necessary permits, authorizations or licenses, and interpretations of any governmental authorities having proper jurisdiction over, or otherwise exercising authority with respect to, the Parties, the Project, the performance of the obligations to be performed hereunder, or the operation of the Project.

 

“Applicable Standards” means Prudent Industry Practices and Prudent Engineering Practices; provided, however, that if any portion of such standards or codes conflict with or is less stringent than any Applicable Laws, such conflicting or less stringent portions of such standards shall not be deemed “applicable.”

 

“As-Built Drawings and Documentation” has the meaning set forth in Section 2.5.

 

“Asset Purchase Agreement” means that certain Asset Purchase Agreement dated as of the Effective Date by and between Owner, Contractor, Power Partners Midwest, LLC, a Delaware limited liability company, EDF Renewable Development, Inc., a Delaware corporation, and Merricourt Power Partners, LLC, a Delaware limited liability company.

 

“Authorized Representatives” means Contractor’s Representative and Owner’s Representative collectively.

 

“Backup LOC” has the meaning set forth in Section 4.7.

 

“Business Day” means any day other than Saturday, a Sunday, or a holiday, on which banks are generally open for business in both Minneapolis, Minnesota and Fargo, North Dakota.

 

“Buy-Back Amount” has the meaning set forth in Section 11.3

 

“Buy-Back Right” has the meaning set forth in Section 11.3.

 

 2 

 

 

“Change in Law” means the enactment, adoption, promulgation, issuance, modification, or repeal after the Effective Date of any Applicable Laws or Permit or any material change in the interpretation of any Applicable Laws or Permit by any Governmental Authority or court of law that adversely affects Contractor’s costs or schedule for performing the Work, except that (i) a change in federal, state, or local income tax law shall not be a Change in Law and (ii) an enactment, adoption, promulgation, or material change in the interpretation of an Applicable Law or Permit that is published prior to the Effective Date but that becomes effective after the Effective Date shall not be a Change in Law.

 

“Closing Date” shall mean the “Closing Date” under and as such term is defined in the Asset Purchase Agreement.

 

“Code” means the Internal Revenue Code of 1986, as amended and in effect.

 

“Commissioning” means the start-up and commissioning activities to be conducted in accordance with the Commissioning Test and Inspection Procedures.

 

“Commissioning and Turnover of Electrical Works” has the meaning set forth in Section 6.4.

 

“Commissioning Test and Inspection Procedures” means the test and inspection procedures set forth in Exhibit 6.4.3.

 

“Completion Certificate” or “Completion Certificates” has the meaning set forth in Section 6.7.

 

“Concealed Subsurface Conditions” has the meaning set forth in Section 9.8.

 

“Confidential Information” has the meaning set forth in Section 17.1.

 

“Collection Substation” means the substation to be constructed as part of the Project described in Exhibit 2.2.2, Part 11.

 

“Construction Period Guaranty” means a guaranty by EDF-EN of the full and timely payment of the obligations of Contractor hereunder and of Sellers under the Asset Purchase Agreement, in the form of Exhibit 4.7.a in an amount not to exceed [**] ($[**]).

 

“Construction Period Guaranty Expiration” has the meaning set forth in Section 4.7.2.

 

“Construction Services” means all services required to construct a fully operational Project; and further provided that any Change in Law shall not affect Contractor’s obligation to complete such actions and services, including the Permits.

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 3 

 

 

“Consumable Parts” has the meaning set forth in Section 2.6.2.

 

“Contractor” has the meaning set forth in the Preamble.

 

“Contractor Event of Default” has the meaning set forth in Section 13.1.

 

“Contractor Indemnified Party” has the meaning set forth in Section 10.1.4.

 

“Contractor’s Representative” means Benjamin Pillod, as such person may be changed from time to time by Contractor in writing to Owner.

 

“Contractor’s Safety Program” means the safety plan and program prepared by Contractor in accordance with Section 2.12.1.

 

“Coordinator of Local Hiring Services” has the meaning set forth in Section 2.7.3.

 

“Counties” has the meaning set forth in Section 2.7.3.

 

“Credit Trigger Event” means (a) with respect to EDF-EN, the failure of (i) Électricité de France S.A.to own, directly or indirectly, at least fifty percent (50%) of the issued and outstanding equity of EDF-EN; or (ii) EDF-EN to have a Tangible Net Worth of at least €1,750,000,000.00, (b) with respect to EDF-RE, the failure of EDF-RE to have a Tangible Net Worth of at least $50,000,000.00 and (c) with respect to Owner, the downgrading of Owner’s senior unsecured credit rating by any two Rating Agencies to below BBB- (or Baa3 in the case of Moody’s).

 

“Critical Path” means the sequence of activities and milestones required to complete the Project within the time period set forth in the Project Schedule.

 

“Day” or “Days” means one or more calendar days.

 

“Defect” or “Defective” means (a) a failure to perform engineering or design services that are a part of the Work in accordance with the Requirements of the Agreement or (b) any construction of the Work, or a part or a component thereof, that (i) breaks, (ii) ceases to perform the function for which it was designed or installed, (iii) fails to conform to the Requirements of this Agreement, or (iv) is not free of defects or deficiencies in material or workmanship. The term “Defects” shall neither be construed to include damage caused by Owner’s or any third parties’ acts or omissions (other than the acts and omissions of Contractor, its Subcontractors or any Person directly or indirectly employed by any of them or for whom any of them are responsible) to the extent arising out of abuse, misuse, negligence in operation, maintenance and repair (unless such act or omission was taken or made at the written direction of Contractor) or failure to follow Contractor’s or manufacturers’ written recommendations and directions set forth in Documents required to be delivered hereunder and Prudent Industry Practices, nor shall the term “Defects” be construed to include ordinary wear and tear (unless as a result of a defect or deficiency).

 

“Delay Liquidated Damages” has the meaning set forth in Section 6.9.

 

 4 

 

 

“Design Development” means the process in which the Contractor prepares and revises Design Documents.

 

“Design Documents” has the meaning set forth in Section 2.5.2.

 

“Documents” shall have the meaning set forth in Section 14.2 of this Agreement.

 

“Dollars” or “$” means the lawful currency of the United States of America.

 

“Drawings” means all (i) drawings or supplementary drawings furnished by Contractor as a basis for soliciting proposals, (ii) drawings, if any, submitted by Contractor with its proposal which are included in this Agreement, and (iii) engineering data and drawings submitted by Contractor, if any, during the progress of the Work, provided such drawings are prepared in collaboration with Owner in accordance with the Requirements and the terms of this Agreement.

 

“EDF-EN” means EDF Energies Nouvelles, S.A., a French société anonyme.

 

“EDF-EN Guaranty” means a guaranty by EDF-EN of the full and timely payment of the obligations of Contractor hereunder and of Sellers under the Asset Purchase Agreement, in the form of Exhibit 4.7.1 in an amount not to exceed [**] ($[**]).

 

“EDF-EN Guaranty Expiration” has the meaning set forth in Section 4.7.1.

 

“EDF-RE” means EDF Renewable Energy, Inc., a Delaware corporation.

 

“Effective Date” has the meaning set forth in the Preamble.

 

“Electrical Works Commissioning and Turnover Certificate” means a certificate in the form of Exhibit 6.4.

 

“Electrical Works” means the facilities, equipment and work described in Exhibit 2.2.2-Part 3, Exhibit 2.2.2-Part 6 and Exhibit 2.2.2-Part 11.

 

“Environmental Laws” means all Laws that regulate or relate to (a) the protection or clean-up of the environment; (b) the Handling of Hazardous Materials; (c) the preservation or protection of waterways, groundwater, drinking water, air, wildlife, plants or other natural resources; and (d) the health and safety of persons or property, including, without limitation, protection of the health and safety of employees, including the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq.; the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq.; the Clean Water Act; the Clean Air Act, 42 U.S.C. § 7401 et seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Occupational Safety and Health Act, 29 U.S.C. § 651 et seq.; the Hazardous Materials Transportation Act, 49 U.S.C. § 5101 et seq.; the Endangered Species Act, 16 U.S.C. § 1531 et seq.; the Migratory Bird Treaty Act 16 U.S.C. § 703 et seq.; the Bald and Golden Eagle Protection Act 16 U.S.C. § 668 et seq.; Centers for Disease Control guidelines, policies and procedures; and all other analogous or related Laws currently in effect (including implementing regulations promulgated pursuant thereto) of any Governmental Authority having jurisdiction over the assets in question addressing pollution control or protection of Protected Species, the environment, wildlife, plants, natural resources, or human health.

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

 5 

 

 

“Exhibits” means each Exhibit attached hereto and incorporated in its entirety by this reference.

 

“Extended Force Majeure Event” has the meaning set forth in Section 8.1.8.

 

“Final Completion” has the meaning set forth in Section 6.6.

 

“Final Completion Certificate” means the certificate in the form of Exhibit 6.6.13.

 

“Final Lien Waiver” means a sworn statement and waiver of liens prepared by Contractor and each Major Subcontractor, as applicable, which provides that such Person unconditionally waives and releases all mechanic’s liens with respect to all Work for which Contractor requested final payment in the form set forth in Exhibit 4.5.a, Final Lien Waivers.

 

“Final IRS Determination” means (a) a decision, judgment, decree or other order by any court of competent jurisdiction, which decision, judgment, decree or other order has become final after all allowable appeals (other than appeals to the United States Supreme Court) by the parties to the action have been exhausted or the time for filing such appeals has expired, (b) a closing agreement entered into under Section 7121 of the Code or any other settlement agreement entered into in connection with an administrative or judicial proceeding entered into in accordance with this Agreement, (c) the expiration of the time for instituting suit with respect to a claimed deficiency or (d) the expiration of the time for instituting a claim for refund, or if such a claim was filed, the expiration of the time for instituting suit with respect thereto.

 

“Force Majeure Event” means any event that wholly or partly prevents or delays the performance by the Party affected of any obligation arising under the Agreement Documents, but only if and to the extent (i) such event is beyond the reasonable control of, and (ii) without fault or negligence of the Party claiming the Force Majeure Event. Subject to the foregoing, Force Majeure Event may include, without limitation: condemnation; expropriation; invasion; plague; drought; landslide; tornado; hurricane; tsunami; flood; a lightning strike that causes damage to equipment or materials on the Project Site; earthquake; fire; blizzards; ice storms; precipitation in excess of the 25-year, 24-hour precipitation event threshold as determined by the National Climatic Data Center, National Oceanic and Atmospheric Administration, for the area in which the Jamestown Regional Airport is located; explosion; epidemic; quarantine; war (declared or undeclared), terrorism or other armed conflict; material physical damage to the Project caused by third parties (which shall not include any of Contractor’s Subcontractors or their employees); strikes and other labor disputes of a regional nature not occurring on the Project Site; riot or similar civil disturbance or commotion; other acts of God; acts of the public enemy; blockade; insurrection, riot or revolution; sabotage or vandalism; embargoes; and, actions of a Governmental Authority including any Change in Law.

 

 6 

 

 

Force Majeure Event shall also include the following: (a)  failure of Subcontractors of Contractor to deliver goods or Work in a timely manner due to a Force Majeure Event affecting such suppliers; (b) the unavailability of interconnection to the Transmission Provider’s transmission system or receipt of back feed power to the Project, which results from any cause or event (unless caused by the acts or omissions of Contractor or any of its Subcontractors) but only to the extent that such transmission or backfeed power unavailability prevents Contractor from commissioning the infrastructure facilities in order to achieve Substantial Completion by the Guaranteed Project Substantial Completion Date; (c) delays in transportation resulting from accidents or closure of roads or other transportation routes by governmental authorities which are caused by a Force Majeure Event, and (d) with respect to completion of any Punch List Items required to achieve Final Completion (if Substantial Completion has occurred) that require the movement or penetration of soil, including, without limitation, re-grading or re-seeding, seasonal frozen ground conditions at the Project Site.

 

In no instance shall the following be considered events beyond Contractor’s reasonable control or constitute a Force Majeure Event: (i) labor disturbances related only to the Project Site (except that such exclusion of labor disturbances from a Force Majeure Event shall not include national or regional labor disturbances that affect the Project Site), (ii) availability of, or price levels or fluctuations with respect to labor, goods, materials, services, supplies or components of equipment related to the Work to be supplied by Contractor under this Agreement, (iii) economic hardship (including lack of money), (iv) any failure by the Contractor to obtain or maintain any applicable permit it is required to obtain and maintain hereunder caused by Contractor’s own act or omission, (v) any other act, omission, delay, default or failure (financial or otherwise) of a Subcontractor, other than those caused by a Force Majeure Event, (vi) Weather Delay Days, or (vii) any delay or failure of Contractor to obtain equipment due to the delay or failure of any Subcontractor to perform any obligation to Contractor unless such delay or failure is caused by a Force Majeure Event.

 

“Foundation Completion” means the satisfaction of all of the requirements set forth in Section 6.2.

 

“Foundation Completion Certificate” means a certificate in the form set forth in Exhibit 6.2.7 hereto.

 

“Foundation Load Specifications” shall mean the design loads for the Foundations set forth in Exhibit 2.2.2-Part 4, Foundation Technical Specifications.

 

“Foundations” mean WTG foundations constructed pursuant to the Foundation Load Specifications.

 

“Governmental Authority” means any federal, state, local or other governmental, judicial, public or statutory instrumentality, tribunal, agency, authority, body or entity, or any political subdivision thereof having legal jurisdiction over the Agreement, the performance of the Work, or the Parties.

 

 7 

 

 

“Guaranteed Completion Dates” has the meaning set forth in Section 6.8.

 

“Guaranteed Final Completion Date” has the meaning set forth in Section 6.8.

 

“Guaranteed Project Substantial Completion Date” means October 31, 2019, as modified in accordance with Section 5.5 and Article 9; provided, that (a) if the Closing Date occurs after November 1, 2018 and on or prior to March 1, 2019, the Guaranteed Project Substantial Completion Date shall be extended on a day for day basis for each day between November 2, 2018 and the Closing Date, (b) if the Closing Date occurs on or after March 2, 2019 and on or before June 30, 2019, the Guaranteed Project Substantial Completion Date shall mean August 31, 2020, and (c) if, following issuance by Owner of a Limited Notice to Proceed on or before July 1, 2019, the Closing Date occurs on or before September 1, 2019, the Guaranteed Project Substantial Completion Date shall mean October 31, 2020, in each case as modified in accordance with Section 5.5 and Article 9.

 

“Guaranteed Mechanical Completion Date” means September 30, 2019 as modified in accordance with Section 5.5 and Article 9; provided, that (a) if the Closing Date occurs after November 1, 2018 and on or prior to March 1, 2019, the Guaranteed Mechanical Completion Date shall be extended on a day for day basis for each day between November 2, 2018 and the Closing Date, (b) if the Closing Date occurs on or after March 2, 2019 and on or before June 30, 2019, the Guaranteed Mechanical Completion Date shall mean July 31, 2020, and (c) if, following issuance by Owner of a Limited Notice to Proceed on or before July 1, 2019, the Closing Date occurs on or before September 1, 2019, the Guaranteed Mechanical Completion Date shall mean September 30, 2020, in each case as modified in accordance with Section 5.5 and Article 9.

 

“Guarantor” means (i) EDF-EN with respect to the EDF-EN Guaranty and the Construction Period Guaranty and (ii) EDF-RE with respect to the Post-Construction Guaranty.

 

“Guaranty” means each of the EDF-EN Guaranty, the Construction Period Guaranty and the Post-Construction Guaranty.

 

“Hazardous Materials” means any substance pollutant, contaminant, chemical, material or waste that is regulated, listed or identified under any Environmental Law, or which is deemed or may be deemed hazardous, dangerous, damaging or toxic to living things or the environment, and shall include, without limitation, any flammable, explosive, or radioactive materials; hazardous materials; radioactive wastes; hazardous wastes; hazardous or toxic substances or related materials; polychlorinated biphenyls; petroleum products, fractions and by-products thereof; asbestos and asbestos-containing materials; medical waste, solid waste, and any excavated soil, debris, or groundwater that is contaminated with such materials; any hazardous substance under the Comprehensive Environmental Response, Compensation and Liability Act, as amended (42 U.S.C.A. § 9601 et seq.), any solid waste under the Resource Conservation and Recovery Act of 1976, as amended (42 U.S.C.A. § 6901 et seq.), or any contaminant, pollutant, waste or toxic substance under the Clean Air Act, as amended (42 U.S.C.A. § 7401 et seq.), the Federal Water Pollution Control Act, as amended (33 U.S.C.A. § 1251 et seq.), the Safe Drinking Water Act, as amended (42 U.S.C.A. § 300f et seq.), the Emergency Planning and Community Right-To-Know Act, as amended (42 U.S.C.A. sec. 110001 et seq.), the Occupational Safety and Health Act, as amended (29 U.S.C.A. sec. 651 et seq.), the Hazardous Materials Transportation Act, as amended, (49 U.S.C.A. sec. 5101 et seq.) or the Toxic Substances Control Act, as amended (15 U.S.CA. § 2601 et seq.).

 

 8 

 

 

“Infrastructure Facilities” means all of the balance of the plant work, including but not limited to, buildings, roads, Foundations, laydown areas, Electrical Works and other permanent fixtures as more fully described in Exhibit 2.2.2-Part 5.

 

“Infrastructure Facilities Warranty” has the meaning set forth in Section 7.1.1.

 

“Infrastructure Facilities Warranty Period” has the meaning set forth in Section 7.1.2.

 

“Infrastructure Facilities Warranty Service” has the meaning set forth in Section 7.1.3.

 

“Intellectual Property Rights” has the meaning set forth in Section 17.3.

 

“Interconnection Agreement” means either (i) the Generator Interconnection Agreement made and entered into as of October 10, 2011 by and between EDF Renewable Development, Inc. (formerly known as enXco Development Corporation), Montana-Dakota Utilities, a Division of MDU Resources Group Inc. and MISO and associated with MISO Interconnection Queue Request G359, together with all other rights in MISO Interconnection Queue Request G359 and all associated studies, reports and communications with MISO related thereto or (ii) the Generator Interconnection Agreement to be entered into for MISO Interconnection Queue Request J457, together with all other rights in MISO Interconnection Queue Request J457 and all associated studies, reports and communications with MISO related thereto, as applicable.

 

“Interconnection Substation” means the Transmission Owner’s Wishek substation, located in McIntosh County, North Dakota, at which the Point of Interconnection is made.

 

“Kick-Off Meeting” has the meaning set forth in Section 2.5.4.

 

“LIBOR” means, for any day, a rate per annum equal to the “London Interbank Offered Rate (Libor)” for a three (3) month period as set forth in the Money Rates Section of The Wall Street Journal, Western Regional Edition (“The Wall Street Journal”), on such day (or, if The Wall Street Journal is not published on such day, the next preceding Business Day on which The Wall Street Journal is so published); provided that, if The Wall Street Journal is no longer published or the applicable LIBOR rate is no longer quoted therein, then “LIBOR” shall be a reasonably comparable rate as shall be mutually agreed upon by Owner and Contractor.

 

“Limited Notice to Proceed” means the limited notice issued by Owner and reasonably agreed to by Contractor prior to the issuance of the full Notice to Proceed, directing Contractor to commence certain engineering work and to carry out the purchase of long lead-time materials related to the Project, the aggregate value of which shall be equal to Three Million Five Hundred Thousand and 00/100 Dollars ($3,500,000) (or such other amount as the Parties may agree) and will be non-refundable subject to Contractor’s compliance with the last sentence of Section 2.16.

 

 9 

 

 

“Major Subcontract” means any agreement(s) between Contractor and a first-tier Subcontractor having an aggregate value in excess of Five Hundred Thousand and 00/100 Dollars ($500,000.00) for performance of any part of the Work at the Project Site. Notwithstanding anything herein to the contrary, the Turbine Supply Agreement shall not be considered to be a Major Subcontract.

 

“Major Subcontractor” means any Subcontractor with whom Contractor will enter (or has entered) into a Major Subcontract to perform work on the Project. Notwithstanding anything herein to the contrary, the Turbine Supplier shall not be considered to be a Major Subcontractor.

 

“Mandatory Comments” has the meaning set forth in Section 2.5.6.2.

 

“Mechanical Completion” has the meaning set forth in Section 6.3.

 

“Mechanical Completion Certificate” means a certificate in the form set forth in Exhibit 6.3, Form of WTG Mechanical Completion Certificate.

 

“Milestone” means Critical Path ‘milestone’ designated as such in Exhibit 2.4.1.

 

“Milestone Payments” has the meaning set forth in Section 4.3 and as further described in Exhibit 4.1 Payment Schedule.

 

“Milestone Payment Request” means the written request for a Milestone Payment in substantially the form of Exhibit 4.3, Form of Milestone Payment Request.

 

“Monthly Progress Report” means a monthly written report prepared by Contractor in the form of Exhibit 2.4.3, Form of Monthly Report describing the actual progress of the Work showing in detail the progress to date and the then-current scheduling of all major elements of design, procurement, construction, testing and other aspects of the Work, including the incorporation of delay and acceleration analyses where appropriate, as specified in the Project Schedule.

 

“MPT” means the main power transformer for the Project.

 

“MPT Supply Agreement” means that certain MPT supply agreement entered into between Contractor and any MPT supplier.

 

“MW” means megawatt.

 

“Notice to Proceed” means the notice deemed issued by Owner and received by Contractor directing Contractor to commence the Work in accordance with the terms of this Agreement which shall be deemed issued by Owner and received by Contractor as of the Closing Date under the Asset Purchase Agreement.

 

“Notice to Proceed Date” means the date of issuance of the Notice to Proceed which shall be the same as the Closing Date.

 

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“Owner” has the meaning set forth in the Preamble.

 

“Owner-Caused Delay” has the meaning set forth in Section 5.5.

 

“Owner Event of Default” has the meaning set forth in Section 13.3.

 

“Owner Indemnified Party” has the meaning set forth in Section 10.1.1.

 

“Owner LOC” has the meaning set forth in Section 4.1.2.

 

“Owner’s Representative” means Harvey McMahon, as such person may be changed from time to time by Owner in writing to Contractor.

 

“O&M Manual” means the complete system instructions and procedures for the operation and maintenance of the WTG and the Infrastructure Facilities, including Contractor’s manufacturers’, vendors’, suppliers’ and Subcontractors’ recommended list of Spare Parts, all safety information and any precautionary measures therefore.

 

“Partial Lien Waiver” means a sworn statement prepared by the Contractor and each Subcontractor performing work at the Project Site in the form set forth in Exhibit 4.5, Form of Partial Lien Waivers.

 

“Party” or “Parties” have the meaning set forth in the Preamble.

 

“Payment Schedule” means the schedule of payments to be made by Owner to Contractor set forth in Exhibit 4.1, Payment Schedule.

 

“Permissible Materials” has the meaning set forth in Section 2.12.5.1.

 

“Permit” means any valid waiver, exemption, variance, certificate, franchise, permit, authorization, license or similar order, of or from, or registration or filing with, or notice to, any Governmental Authority that is required by Applicable Laws to be obtained or maintained in connection with design, engineering, procurement, construction, testing, operation or maintenance of the Project, the Project Site, performance of the Work, testing, Commissioning, health and safety, or the environmental condition of the Project or the Project Site.

 

“Person” means any individual, corporation, partnership, limited liability company, association, joint stock company, trust, unincorporated organization, joint venture, government or political subdivision or agency thereof, Governmental Authority, or any other entity or organization.

 

“Point of Interconnection” means the Wishek-to-Ellendale 230kV transmission line owned by Transmission Owner where the Merricourt Project substation will connect into the Transmission Provider’s system.

 

“Post-Construction Guaranty” means a guaranty by EDF-RE of the full and timely payment of the obligations of Contractor hereunder and of Sellers under the Asset Purchase Agreement, in the form of Exhibit 4.7.b in an amount not to exceed [**] ($[**]).

 

____________________________ 

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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“Post-Construction Guaranty Expiration” has the meaning set forth in Section 4.7.3.

 

“Pre-Existing Hazardous Material” means (i) any Hazardous Material that existed on or in the Project Site prior to the date when Contractor or any Subcontractor or other representative of Contractor is present on the Project Site on or following the Notice to Proceed Date and (ii) any Hazardous Material brought to the Project Site by Owner or any third party (other than any Subcontractor) after the Notice to Proceed Date.

 

“Prime Subcontract” means the Engineering, Procurement and Construction Services Agreement, dated as of the Closing Date, by and between Contractor and Prime Subcontractor.

 

“Prime Subcontract Security and Collateral Assignment Agreement” means the agreement under which Contractor has created a security interest in the Prime Subcontract in favor of Owner, substantially in the form set forth in Exhibit 13.2.2.b.

 

“Prime Subcontractor” means the Contractor approved prime subcontractor selected from the list set forth in Exhibit 3.2 prior to the Notice to Proceed Date.

 

“Prime Subcontractor Consent to Assignment” means a consent to assignment by Prime Contractor and acknowledged by Contractor, in form and substance reasonably satisfactory to Owner.

 

“Project” means the complete integrated wind-powered electricity generating plant, consisting of the Infrastructure Facilities and the WTGs, with a nominal nameplate capacity of 150 MW to be located on the Project Site to be developed, designed, procured, constructed, interconnected, tested and commissioned under this Agreement, including all structures, facilities, appliances, lines, conductors, instruments, equipment, apparatus, components, roads and other real and personal property and/or Real Property Rights comprising and integrating the entire facility described generally in the Technical Specifications.

 

“Project Closing” shall mean the “Closing” with respect to the “Project” under and as such terms are defined in the Asset Purchase Agreement.

 

“Project Quality Assurance Plan” shall mean the quality assurance plan described in Section 2.8 and as attached hereto as Exhibit 2.8, Project Quality Assurance Plan.

 

“Project Schedule” means the schedule in Primavera, Microsoft Project or other mutually agreeable electronic format as set forth in Exhibit 2.4.1 that describes certain dates and the time of completion of key milestones for timely completion of the Work as provided pursuant to Section 2.4.1.

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“Project Site” means all those parcels of land that are subject to the Real Property Rights on which the Project will be located, as more particularly described in Exhibit 1.1, Description of Project Site and Real Property Rights.

 

“Project Substantial Completion” has the meaning set forth in Section 6.5.

 

“Project Substantial Completion Certificate” means a certificate in the form of Exhibit 6.5.10-Part 3.

 

“Project Substantial Completion Date” means the date on which Project Substantial Completion has been achieved under Section 6.5.

 

“Project Surety Bond” has the meaning set forth in Section 4.7.2.

 

“Prudent Engineering Practices” means those practices, methods, equipment, specifications and standards of safety and performance, as the same may change from time to time, that prevail among national professional construction and engineering firms performing engineering, procurement and construction services on wind energy facilities in the U.S. of a type and size and having geographical and climatic attributes similar to the Project which, in the exercise of reasonable judgment and in the light of the facts known at the time the decision was made, are considered good, safe and prudent practice in connection with the design, construction and use of wind energy generating and operating, electrical and other equipment, facilities and improvements, with commensurate standards of safety, performance, dependability, efficiency and economy, and as are in accordance with Applicable Laws and generally accepted national standards of professional care, skill, diligence and competence applicable to design, engineering, construction and project management practices. Prudent Engineering Practices are not intended to be limited to the optimum practices, methods or acts to the exclusion of all others, but rather to be a spectrum of good and proper practices, methods and acts.

 

“Prudent Industry Practices” means for wind electric generation facilities of a type and size and having geographical and climatic attributes similar to the Project, those practices, methods, specifications and standards of safety, performance, dependability, efficiency and economy recognized by a significant portion of the industry members in the U.S. as good and proper, and such other practices, methods or acts which, in the exercise of reasonable judgment by those reasonably experienced in the industry in light of the facts known at the time a decision is made, would be expected to accomplish the result intended at a reasonable cost and consistent with Applicable Laws, reliability, safety, and expedition. Prudent Industry Practices are not intended to be limited to the optimum practices, methods or acts to the exclusion of all others, but rather to be a spectrum of good and proper practices, methods and acts.

 

“PTC” means production tax credits under Section 45 of the Code.

 

“PTC Liquidated Damages” has the meaning set forth in Section 11.4.

 

“Punch List Items” means a monetized list which includes each item of Work that:

 

(a)          Owner and Contractor agree remains to be performed by Contractor following Project Substantial Completion;

 

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(b)          does not, in Contractor’s and Owner’s reasonable judgment, affect the ability of Owner to safely operate the Project in accordance with Applicable Standards and in compliance with all Applicable Laws;

 

(c)          does not, in Contractor’s and Owner’s reasonable judgment, affect the operability (including capacity, efficiency, reliability, or cost effectiveness), safety or mechanical or electrical integrity of the Project; and

 

(d)          does not, in Contractor’s and Owner’s reasonable judgment, affect the ability to Commission and test the WTGs, Infrastructure Facilities and the other components of the Project.

 

“Purchase Order” means the Owner issued purchase order that is issued, among other things, for the administrative purpose of facilitating the invoice and payment process.

 

“Qualified Institution” means the United States office of a commercial bank or trust company (which is not an Affiliate of any Party), having assets of at least $10 billion, and having Credit Ratings from two Ratings Agencies of at least A3 (in the case of Moody’s) or A- (in the case of S&P or Fitch).

 

“Real Property Rights” means all rights in or to real property (such as easement rights or other rights to use or access the Project Site), leases, agreements, Permits, easements, licenses, private rights-of-way, crossing and other rights required to be obtained or maintained in connection with construction of the Project on the Project Site, transmission of electricity to Transmission Provider, performance of the Work, or operation of the Project, a description of which is set forth in Exhibit 1.1.

 

“Recovery Plan” has the meaning set forth in Section 2.4.4.

 

“Release” means any spilling, leaking, pumping, pouring, emitting, emptying, discharging, injecting, escaping, leaching, dumping, migrating or disposing into the environment or the workplace of any Hazardous Material, and otherwise as defined in any Environmental Law.

 

“Requirements of this Agreement” means in accordance with the terms and conditions of this Agreement, and with Prudent Industry Practices, Prudent Engineering Practices, Applicable Standards and Applicable Laws.

 

“Retainage” has the meaning set forth in Section 4.3.

 

“Retainage Cap” has the meaning set forth in Section 4.3.

 

“SCADA System” means the automated remote monitoring system (Wind SCADA 1) including central computer, to be supplied by Contractor as part of the Work, as more fully described in the Technical Specifications, that collects (i) availability and power generation data from each WTG, (ii) wind direction and speed data, and (iii) other operational parameters describing the status of the Project and the Interconnection facilities.

 

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“Scope Change” has the meaning set forth in Section 9.1.

 

“Scope Change Order” means a written order to Contractor pursuant to Article 9, signed by Owner and countersigned by Contractor, authorizing a Scope Change.

 

“Scope of Work” means specific requirements regarding the Work, including the Technical Specifications for the Project, specifically as set forth in Exhibit 2.2.2.

 

“Sellers” means Contractor and each Affiliate of Contractor that is a party to the Asset Purchase Agreement.

 

“Settlement Agreement” has the meaning given to such term in Section 15.2.

 

“Site Safety Manual” has the meaning set forth in Section 2.12.2.

 

“Spare Parts” means the spare parts necessary to operate and maintain the WTGs and the Infrastructure Facilities.

 

“SMA” means that certain Service and Maintenance Agreement dated November 16, 2016 by and between Turbine Supplier and Contractor.

 

“SPCC” has the meaning given to such term in Section 2.12.5.7.

 

“State” shall mean the State of North Dakota for the purpose of Section 4.2.4.

 

“Step-In Notice” has the meaning set forth in Section 13.2.2.

 

“Step-In Rights” has the meaning set forth in Section 13.2.2.

 

“Subcontract” means an agreement between Contractor and any Subcontractor.

 

“Subcontractor” means any subcontractor, of any tier, or supplier of materials, equipment or services to Contractor or any subcontractor, of any tier, of any Person engaged or employed by Contractor in connection with the performance of the Work, including the Turbine Supplier.

 

“Submittals” is defined in Exhibit 2.5.5.

 

“Tangible Net Worth” means, with respect to Guarantor, the aggregate of its tangible assets (total assets less intangibles) less the aggregate of its liabilities as documented in its annual audited financial statement.

 

“Taxes” has the meaning set forth in Section 4.2.2.

 

“Tax Exemption Certificate” has the meaning set forth in Section 4.2.4.

 

“Technical Specifications” means the description of the Work, Infrastructure Facilities and WTGs, including the technical specifications referenced or described therein for the Project, set forth as Exhibit 2.2.2.

 

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“Termination for Cause” has the meaning set forth in Section 13.2.

 

“Termination Due to Force Majeure” has the meaning set forth in Section 13.4.1.2.

 

“Termination Notice” has the meaning set forth in Section 13.2.

 

“Tower” means each steel tubular tower component of a Wind Turbine Generator each of which shall have a hub height of approximately eighty (80) meters in each case, measured from the base of such tower to the center of the WTG hub upon which a Turbine Nacelle shall be mounted, including all ladders, platforms, internal lighting, safety equipment and all parts and assemblies necessary for a complete turbine tower, all as further described in the WTG Technical Specifications set forth in Exhibit 2.2.2-Part 1, WTG Technical Specifications.

 

“Tower Foundation Specifications” means the specifications (including bolt configurations, conduit placement grounding requirements and Tower load specifications) for the Foundations upon which the Towers shall be mounted, all as set forth in the Technical Specifications.

 

“Transformer Guarantees” has the meaning set forth in Section 6.8.1.

 

“Transmission Line” means the Wishek-to-Ellendale 230 kV transmission line owned by Transmission Owner.

 

“Transmission Owner” means Montana–Dakota Utilities or its successor in interest in its capacity as the owner and/or operator of the electrical transmission and distribution system to which the Project will be interconnected.

 

“Transmission Provider” means Midcontinent Independent Transmission System Operator (“MISO”) or its successors.

 

“Transmission Provider Safety and Interconnection Requirements” means any of Transmission Provider’s safety requirements and other regulations and requirements applicable to Work relating to the Point of Interconnection at the Interconnection Substation.

 

“Turbine Assembly Drawings” means the master set of Drawings, (including electrical Drawings) that sets forth the information required to perform assembly, installation, and erection of the WTGs and Towers, as set forth in the WTG Technical Specifications set forth in Exhibit 2.2.2 - Part 1, WTG Technical Specifications.

 

“Turbine Blade” means a turbine blade (approximately fifty-five (55) meters in length) component of a Wind Turbine Generator, the specifications for which are set forth in the WTG Technical Specifications set forth in Exhibit 2.2.2 - Part 1, WTG Technical Specifications.

 

“Turbine Nacelle” means the turbine nacelle component of a WTG, including hubs, main shafts, main bearings, gearboxes, generators, lightning protection system, gear reducers, nacelle yaw systems (including yaw motors and yaw gears), nacelle frames, brake systems, associated control equipment and ancillary equipment, as more particularly described in the WTG Technical Specifications set forth in Exhibit 2.2.2 - Part 1, WTG Technical Specifications.

 

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“Turbine Supplier” means Vestas-American Wind Technology, Inc., a California corporation.

 

“Turbine Supplier Consent to Assignment” means the consent to assignment by Turbine Supplier and acknowledged by Contractor substantially in the form set forth in Exhibit 13.2.2.a.

 

“Turbine Supply Agreement” means that certain turbine supply agreement dated November 16, 2016 between Contractor and Turbine Supplier.

 

“Turbine Supply Security and Collateral Assignment Agreement” means the agreement under which Contractor has created a security interest in the Turbine Supply Agreement in favor of Owner substantially in the form set forth in Exhibit 13.2.2.

 

“Turnover Package” means the following:

 

(a)          the WTG Turnover Package; and

 

(b)          all engineering, design, purchasing and other information relating to the Infrastructure Facilities, including, but not limited to: (a)  a Drawing index; (b)  a reference index; (c)  copies of Contractor’s and Subcontractors’ Permits; (d)  copies of all purchase orders on Major Subcontractor’s equipment (non-priced) with addenda; (e)  Subcontractor information for equipment purchased (as received from vendors) including instruction and maintenance manuals from Subcontractors; (f)  one copy of the As-Built Drawings and Documentation; (g)  training manuals; (h)   electrical 1-line diagrams for the Infrastructure Facilities; (i)  a cable and raceway schedule for the Infrastructure Facilities; (j)  connection report/loop diagrams for the Infrastructure Facilities; (k)  a final list and summary of the work performed by all Subcontractors and verification of the payment of all amounts due to each Subcontractor; (l) the final Project Quality Assurance Plan documents, and (m) tests results.

 

“Warranty Parts” has the meaning set forth in the Turbine Supply Agreement.

 

“Weather Delay Day” means a Day during which: (i) wind speeds above the limits the lift plan for that specific crane interfere with and prevent the safe movement (including the lifting) of WTG components; (ii) wind speeds above the limits set forth in the Turbine Supply Agreement that interfere with and prevent the performance of work necessary to achieve WTG Mechanical Completion; or (iii) other unusually severe or not reasonably anticipated inclement weather or cumulative weather events that prevents or interferes with the performance of Contractor or any of its Subcontractors if such effect can be demonstrated by Contractor as having a material adverse effect on the Project Schedule’s Critical Path. The existence of a Weather Delay Day shall be determined in increments of half of the work day otherwise scheduled. For the purpose of clarity, such half-day increment shall be defined by Contractor or any of its Subcontractors as the number of half work day increment hours on a Day in which Work was originally scheduled. In the event the weather event continues for more than the defined number of half work day increment hours in a Day, such period will be deemed to be a full Day.

 

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“Wind Conversion System Equipment” has the meaning set forth in Section 4.2.4.1.

 

“Wind Study” has the meaning set forth in the Asset Purchase Agreement.

 

“Wind Turbine Generator” or “WTG” means all or any portion of seventy-five (75) 2.0 MW wind turbine generators manufactured by Turbine Supplier with a fifty-five (55) meter blade supplied, delivered, assembled, erected and installed by Contractor, each including equipment, machinery, materials and Consumable Parts related thereto and the following components: a Tower, a Turbine Nacelle, Turbine Blades, controller (including interconnecting cabling from the Turbine Nacelle to the ground controller), control panels, converters, WindVar (or other Var control technology supplied by the Turbine Supplier), wind vanes, FAA lighting (if and as required), grounding, and anemometers, all as more particularly described in the Technical Specifications. WTGs shall not include special tools required for operation of the Project or Spare Parts. For the avoidance of doubt, the WTGs include the 5% Safe Harbor Turbines.

 

“Work” has the meaning set forth in Section 2.1.1.

 

“WTG Commissioning and Turnover Certificate” means a certificate in the form of Exhibit 6.5.

 

“WTG Cure Period” has the meaning set forth in Section 11.3.

 

“WTG Substantial Completion” means, with respect to a WTG, (i) the achievement of Mechanical Completion, (ii) the completion of the Electrical Works and (iii) the completion of Commissioning.

 

“WTG Substantial Completion Certificate” means a certificate in the form of Exhibit 6.5.10, Part 2.

 

“WTG Turnover Package” means the following: (a)  O&M Manuals; (b)  the erection and start-up manual including Turbine Assembly Drawings, erection diagrams, connection diagrams for the WTGs and the SCADA System, details of all interface points and connections and a cable schedule; and (c)  the SCADA System logic diagram.

 

Section 1.2           Rules of Interpretation. Unless otherwise required by the context in which any term appears:

 

1.2.1      capitalized terms used in this Agreement have the meanings specified in this Article 1;

 

1.2.2      the singular shall include the plural;

 

1.2.3      references to “Articles,” “Sections,” “Schedules,” “Annexes,” “Appendices” or “Exhibits” (if any) shall be to articles, sections, schedules, annexes, appendices or Exhibits (if any) of this Agreement, as the same may be amended, modified, supplemented or replaced pursuant to the terms hereof from time to time hereunder;

 

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1.2.4           all references to a particular entity shall include a reference to such entity’s successors and permitted assigns;

 

1.2.5           the words “herein,” “hereof” and “hereunder” shall refer to this Agreement as a whole and not to any particular Section or subsection of this Agreement;

 

1.2.6           all accounting terms not specifically defined herein shall be construed in accordance with generally accepted accounting principles as established by the Financial Accounting Standards Board in the United States of America, consistently applied;

 

1.2.7           references to this Agreement shall include a reference to all appendices, annexes, schedules and Exhibits hereto, as the same may be amended, modified, supplemented or replaced pursuant to the terms hereof from time to time;

 

1.2.8           references to any agreement, document or instrument shall mean a reference to such agreement, document or instrument as the same may be amended, modified, supplemented or replaced from time to time;

 

1.2.9           the use of the word “including” in this Agreement to refer to specific examples shall be construed to mean “including, without limitation” or “including but not limited to” and shall not be construed to mean that the examples given are an exclusive list of the topics covered; and

 

1.2.10         references to an Applicable Law shall mean a reference to such Applicable Law as the same may be amended, modified, supplemented or restated and be in effect from time to time.

 

1.2.11         The Parties collectively have prepared this Agreement, and none of the provisions hereof shall be construed against one Party on the ground that such Party is the author of this Agreement or any part hereof.

 

Article 2
THE PROJECT

 

Section 2.1                Scope of Work.

 

2.1.1           Appointment. Owner hereby retains Contractor to perform or cause to be performed all work for the design and engineering, procurement, construction, Commissioning and start-up of the Infrastructure Facilities and the procurement, delivery, assembly, erection, installation, Commissioning and start-up of the WTGs, which work and services shall include the Construction Services and the provision of all materials, equipment, machinery, tools, labor, transportation, administration and other services and items required to complete and deliver to Owner the fully integrated and operational Infrastructure Facilities and the fully assembled, installed, tested and operational WTGs, all on a fixed price, turnkey basis, and otherwise in accordance with this Agreement (collectively, the “Work”).

 

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2.1.2        Fixed Price; Turnkey. Contractor acknowledges that this Agreement constitutes a fixed price obligation to design and engineer, procure, construct, test, start-up and Commission the Project.

 

Section 2.2           Contractor Obligations. Without limiting the foregoing, Contractor shall perform the following as part of the Work:

 

2.2.1        Independent Contractor.

 

2.2.1.1           The Parties expressly agree that Contractor is an independent contractor and is not an employee, partner or joint venturer of Owner. Contractor shall (i) exercise its independent professional judgment in the performance of this Agreement, and (ii) supply the manner and means of performance of the Work hereunder. Contractor, its Subcontractors and their respective employees, agents and other representatives shall not have the right to represent or bind Owner in any manner. Owner, its employees, agents and other representatives shall not have the right to represent or bind Contractor or its Subcontractors in any manner.

 

2.2.1.2            Contractor and its Subcontractors are directly and solely responsible for the safety of their respective agents, employees and other representatives. Owner in no way assumes any of the duties, obligations or liabilities attributed to Contractor under this Agreement. Contractor shall promptly report via telephone and in writing to an Owner representative all material accidents in connection with the Work that result in death, personal injury, or property damage.

 

2.2.1.3            Any and all agents, employees and Subcontractors of Contractor provided to perform the Work shall be the agent, employee or Subcontractor of Contractor. Contractor shall be solely responsible for the wages, salary, overtime, taxes, benefits (if any) and any and all other payments or benefits owed to an agent, employee or Subcontractor of Contractor for Work provided under or pursuant to this Agreement. No Contractor’s employee shall be entitled to any retirement, welfare, fringe or other benefit provided by Owner to its employees.

 

2.2.1.4            If for any reason an investigation is conducted or a proceeding commenced by any Governmental Authority, the purpose of which is to determine whether for any reason a Contractor’s employee is an employee of Owner, Contractor shall assist and cooperate with Owner in preparing a response to or defending against, as the case may be, any such investigation or proceeding or the appeal of any such investigation or proceeding.

 

2.2.1.5           The Parties further agree that if a Governmental Authority determines that a Contractor’s employee is an employee of Owner, such Contractor’s employee shall be considered to be an employee of Owner only and solely to the extent set forth in the determination of the Governmental Authority and for no other purpose.

 

2.2.2           Project Management. Contractor shall be responsible for all Project management, all civil and electrical Infrastructure design, and the coordination and general management of the Work in accordance with the Scope of Work set forth in Exhibit 2.2.2. Contractor shall procure, deliver, handle and store and have risk of loss for all materials and equipment used in the Work, subject to the provisions of Article 14 below.

 

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2.2.3           Infrastructure Facilities. Contractor shall perform all services related to the Infrastructure Facilities in accordance with the Scope of Work set forth in Exhibit 2.2.2.

 

2.2.4           WTGs. Contractor shall procure and deliver, or cause to be procured and delivered the WTGs to the Project Site and provide or cause to be provided, all services, labor, equipment and materials necessary to assemble, erect and install the WTGs, all in accordance with the Scope of Work attached as set forth in Exhibit 2.2.2.

 

2.2.5           Storage; Security; Equipment. Following delivery of the WTGs to the Project Site and prior to the date of Commissioning and Turnover of the WTGs, Contractor shall provide appropriate storage and security for all WTGs, Consumable Parts, materials, supplies and other equipment required to assemble, erect and install the WTGs and other property owned or leased by Contractor or any Subcontractor located at the Project Site pursuant to the Real Property Rights or as otherwise provided by Contractor, incorporated in the WTGs, or stored or warehoused off the Project Site. All WTGs stored at a location other than the Project Site shall be segregated from the property of Contractor and third parties. Contractor shall use the same care to protect any of Owner’s property at any time in its possession or under its control while performing the Work as it does with its own property. Notwithstanding properly meeting the standard of care prescribed in the foregoing sentence, Contractor shall be responsible for any damage to such property while such property is in Contractor’s care, custody and control.

 

2.2.6           Nature of the Work. Contractor shall be responsible for having taken and shall take all steps necessary to fully understand the nature of the Work, the general local conditions which can affect the Work and the cost thereof. Except to the extent of a Force Majeure Event determined in accordance with Article 8 or as contemplated in Section 9.4 and Section 9.5, Contractor agrees that any schedule delays or cost increases related to or resulting from any failure by Contractor to fully acquaint itself with general local conditions which may affect the Work, including conditions relating to transportation, handling, storage of materials, import/export issues, Taxes, insurance, availability of labor, water, electricity, roads, or other public goods or services, normal climatic conditions (but specifically excluding conditions existing on during any Weather Delay Day), Applicable Law and the character and availability of equipment and facilities needed preliminary to and during the prosecution of the Work (collectively, “Conditions of the Nature of the Work”) shall not give rise to Contractor’s claim for additional time to perform the Work or an increase in the Agreement Price. Subject to Article 8 and Section 9.4 and Section 9.5, in no event shall the Conditions of the Nature of the Work relieve Contractor of its responsibilities under this Agreement, nor shall any Conditions of the Nature of the Work constitute a basis for a Scope Change Order under any circumstances.

 

2.2.7           Training. In accordance with the Project Schedule, Contractor shall provide the facilities, material, supplies, Personnel and other items required to train the operations and maintenance Personnel provided by Owner in the proper and safe operation and maintenance of the Facility and all Equipment incorporated therein and shall administer all training at the Facility Site in accordance with the Training Program set forth in Exhibit 2.2.7

 

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2.2.8           Geotechnical Survey. Contractor shall perform geotechnical surveys at each WTG pad site, O&M building sites, and Collection Substation sites to fully understand the nature of the soils and allow for proper design of foundations and other Work. Final engineered design of all access roads and foundations are the responsibility of the Contractor.

 

2.2.9           Environmental/Construction Stormwater Permit. The Construction Stormwater Permit shall remain in the name of Contractor and the Contractor shall retain ownership of the Construction Stormwater Permit until the Notice of Termination (NOT) has been submitted and the Construction Stormwater Permit has been closed (which is expected to extend beyond Final Completion).

 

Section 2.3             Compliance. Contractor shall cause the Work to be performed in compliance with the Requirements of this Agreement. Notwithstanding anything to the contrary in this Agreement, after the Guaranteed Project Substantial Completion Date, the sole remedy for any claim by Owner of a breach of this Section 2.3 shall be a warranty claim pursuant to Article 7.

 

Section 2.4               Project Schedule; Monthly Progress Report; Recovery Plan.

 

2.4.1           Project Schedule. Contractor shall administer the Work and perform the Work or cause the Work to be performed in accordance with the dates set forth in Exhibit 2.4.1. Contractor shall submit to Owner a Project Schedule no later than one (1) Month before the Notice to Proceed Date. The Project Schedule shall be reviewed and approved by Owner and shall be incorporated into this Agreement. Owner shall have the opportunity to review the Project Schedule and deliver comments to Contractor no later than the end of the fifth (5th) calendar day after Contractor delivers the Project Schedule to Owner. In the event Owner fails to timely provide comments to Contractor as provided by this Section 2.4.1, the Project Schedule shall be deemed approved by Owner as of the date of delivery thereof by Contractor. In the event Owner provided reasonable comments to Contractor as provided by the Section 2.4.1, Contractor shall include such Owner comments in the Project Schedule, provided that such Owner comments do not violate Applicable Standards.

 

2.4.2           The Project Schedule shall clearly depict the Critical Path of the work, and be in sufficient detail to portray the work of each phase, discipline, work type, system and area of the Project. Specific activity codes may be requested by Owner to facilitate grouping and sorting of the schedule. Contractor shall coordinate and incorporate the schedules of all Subcontractors into all applicable schedules, work plans and progress reports. Contractor shall provide Owner a weekly update to the Project Schedule, including the incorporation of delay and acceleration analyses where appropriate. Contractor shall provide Owner with the construction activities plan of the day for each particular construction day. The Contractor shall not be relieved from the obligation to meet any date set forth in Section 6.8 unless such date is extended pursuant to a Scope Change Order or in accordance with Article 8 as a result of a Force Majeure Event or Owner-Caused Delay. Contractor shall furnish to Owner updated schedules of the Work supplementing the Project Schedule, weekly work plans of activities being performed at the Project Site and Monthly Progress Reports. If Owner so directs, Contractor shall conduct monthly project meetings at mutually agreeable locations between representatives of Owner and Contractor to review the status of the Work. Contractor shall promptly notify Owner in writing at any time that Contractor has reason to believe that there shall be a material deviation in the Project Schedule that may result in Contractor not achieving the dates set forth in Exhibit 2.4.1 and shall set forth in such notice the corrective action planned by Contractor. Delivery of such notice shall not relieve Contractor of its obligations to meet the dates specified in Section 6.8 hereunder. In the event of a conflict between the dates set forth in the Project Schedule and the dates set forth in Section 6.8, the provisions of Section 6.8 shall prevail.

 

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2.4.3           Monthly Progress Report. Within ten (10) Business Days after the end of each calendar month, Contractor shall prepare and submit a Monthly Progress Report for the prior calendar month utilizing the form of Exhibit 2.4.3; except that in the event of any serious accidents at the Project Site, Contractor shall provide Owner with expedited notice and copies of all written communications with Governmental Authorities and insurance companies with respect to such accident.

 

2.4.4           Failure to Maintain Progress; Recovery Plan. If at any time during the performance of the Work Contractor has failed to achieve one or more Milestones by the date(s) set forth in Exhibit 2.4.1 for such Milestone(s), Owner may, at its sole discretion, unless Contractor demonstrates to Owner that it is still able to achieve the Guaranteed Project Completion Dates due to float included in Exhibit 2.4.1, order the Contractor to develop a Recovery Plan (the “Recovery Plan”) in order to meet the Project Schedule. Neither such notice by Owner, nor Owner’s failure to issue such notice, shall relieve the Contractor of its obligation to perform the Work in accordance with the Scope of Work, the Guaranteed Project Completion Dates, or any other requirement of this Agreement.

 

    2.4.4.1           Review; Approval; Implementation. Contractor shall submit such proposed Recovery Plan to Owner within seven (7) Days of receiving notice from Owner. Upon receipt of such proposed Recovery Plan, Owner shall, in good faith, promptly review and comment upon the proposed Recovery Plan within five (5) Days. Contractor shall accept Owner’s reasonable comments unless such comments are inconsistent with Applicable Standards and incorporate all reasonable Owner comments and resubmit, within seven (7) Days of receiving such Owner comments, the proposed Recovery Plan to Owner for approval. Contractor shall diligently pursue the implementation and completion of the Recovery Plan in order to cause the completion of the Work to meet the Guaranteed Completion Dates, including the utilization of additional shifts, additional manpower, overtime, additional construction equipment and re-sequencing of activities. Owner’s request for or approval of a Recovery Plan shall not constitute a Change Order or give rise to a claim by Contractor hereunder except to the extent such delay is an Owner-Caused Delay, Force Majeure Event, or is otherwise excused under this Agreement or Applicable Law, in which case Contractor may submit a Scope Change Order request under Article 9.

 

   2.4.4.2            Content of Recovery Plan. The Recovery Plan must improve progress through actions taken on the Project Site rather than through schedule manipulations. The Contractor shall not artificially improve its progress by revising schedule logic restraints or shortening planned activity durations that do not reflect actual achievable progress. The Recovery Plan shall include resources and commodity quantities in the schedule. A comparison of baseline and actual productivity versus proposed recovery productivity shall be included along with the specific actions proposed to increase productivity. Failure of Contractor to comply with such notice of Owner or failure of Contractor to adhere to the Recovery Plan in accordance with Section 2.4.4 shall constitute a material breach by Contractor.

 

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Section 2.5               Engineering and Design.

 

2.5.1           Engineering. Contractor shall perform or cause to be performed all engineering and design services for completion of the Work in conformity with the Requirements of this Agreement. All engineering work requiring certification shall be certified, if required, and all Design Documents requiring sealing shall be sealed, in each case by professional engineers licensed and properly qualified to perform such engineering and design services in all appropriate jurisdictions.

 

2.5.2           Design. Contractor shall design (or cause to be designed) the Project, including the Infrastructure Facilities, such that they are in compliance with the conditions and Requirements of this Agreement. Contractor shall use its commercially reasonable efforts to design the electrical collection and transmission systems to minimize interference with telephone and global positioning systems service in the vicinity of the Project. Owner shall participate in Design development by reviewing preliminary Design Documents and providing timely feedback to Contractor (and in any event, within ten (10) Business Days after receipt of such preliminary Design Drawings). On or before the Notice to Proceed Date, Contractor shall finalize and submit to Owner all preliminary Drawings and specifications for the Work (“Design Documents”); provided, however, that Contractor and Owner shall cooperate during such period in the preparation and design review of such Design Documents. The Design Documents shall comply with OSHA O&M lockout requirements and Owner safety policies and procedures as set forth in Exhibit 2.5.2. All final Design Documents shall be determined by Contractor in its sole discretion in accordance with the terms and conditions of this Agreement. Based on the Technical Specifications, Contractor shall prepare comprehensive Drawings and specifications setting forth in detail the requirements for the procurement and construction of the Work. As the Drawings and specifications for the Work are issued, they shall be clearly identified as Design Documents.

 

2.5.3           Final Wind Study. Contractor shall design the Project such that the final micro-siting of the WTGs shall be at the location assumed in the Wind Study, with only such WTG relocations (i) that do not require the movement of the WTG location more than two hundred (200) feet from the location assumed in the Site Plan, as such term is defined in the Asset Purchase Agreement or (ii) as are otherwise approved by Owner (with Owner’s approval not being unreasonably withheld). Contractor shall submit a properly addressed written request to Owner seeking approval of any proposed relocations where Owner’s prior approval is required pursuant to this Section 2.5.3. Owner shall have the right to reasonably object to any proposed relocations where Owner’s prior approval is required pursuant to this Section 2.5.3 within ten (10) Business Days after receipt of such request. If Owner has not provided notice to Contractor within ten (10) Business Days of receipt of such request that Owner does not approve of such relocations, including the Owner’s reasons for not approving such relocation(s), Owner shall be deemed to have approved such relocations. Contractor shall be responsible under this Agreement for obtaining any new or amended Permits in connection with any such relocation. All cost resulting from any such relocations will be borne by Contractor. Each Contractor request to Owner seeking approval of proposed relocations shall include a report identifying the net annual energy production impact of such moves as well as the cumulative net annual energy production impact of all moves from the locations assumed in the Wind Study.

 

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2.5.4           Construction Plan. No later than forty-five (45) Days after the date of Project Closing, Contractor shall develop and provide to Owner a written construction plan. Contractor’s construction plan shall be reasonably satisfactory to Owner and shall include a description of Contractor’s plans and programs outlining the systematic construction, installation, fabrication and assembly of the Infrastructure Facilities and the WTGs in accordance with the Requirements of this Agreement. Owner shall review Contractor’s written construction plan and, within ten (10) Days after Owner’s receipt of such plan, shall provide Contractor with Owner’s comments. If any comments are received from Owner during such ten (10) Day period, Contractor shall incorporate into such plan those comments as it deems appropriate in its reasonable discretion. Contractor’s construction plan will comply with the Requirements and this Agreement in all material respects. Contractor shall provide Owner an update of Contractor’s construction plan on a weekly basis (as a part of Contractor’s weekly report) until Project Substantial Completion is achieved. Contractor shall meet with Owner prior to beginning major phases of the Work (each a “Kick-Off Meeting”), including but not limited to, Access Road, Foundation, Collection System, and Collection Substation construction, and WTG erection, to review the detailed plan for those phases of work. Contractor shall provide Owner an update of Contractor’s construction plan on at least a weekly basis until Project Substantial Completion is achieved.

 

2.5.5           Document Submittals and As-Built Drawings. Contractor shall prepare and submit to Owner all Submittals specified in Exhibit 2.5.5, on or before the dates specified therein including a complete set of as-built Drawings prepared by Contractor in accordance with the requirements set forth in Exhibit 2.5.5, which accurately and completely represent the physical placement, of all WTGs and Infrastructure Facilities as assembled, erected and installed (“As-Built Drawings and Documentation”) and an as-built Survey (as such term is defined in the Asset Purchase Agreement) no later than the date of Final Completion.

 

2.5.6           Review of Drawings.

 

2.5.6.1            Plan for Review Schedule. Contractor shall provide to Owner a copy of each Document or Drawing that Owner is required to review pursuant to Exhibit 2.5.5, Section 2.5.2 and Section 2.5.6.2. Contractor shall transmit to Owner one (1) set of reproducible Drawings and other Design Documents as prepared by Contractor or a Subcontractor in conjunction with the performance of the Work (in addition to the As-Built Drawings and Documentation to be included in the Turnover Package) for each Turnover Package deliverable under Section 2.11.

 

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2.5.6.2            Owner Comment. Owner shall have the right, but not the obligation, to comment on any Document or Drawing delivered to Owner by Contractor pursuant to Exhibit 2.5.5, Section 2.5.2 and Section 2.5.6.2. Within ten (10) Business Days of receipt of any Drawing or Document required to be submitted to Owner for review under this Agreement, Owner shall provide Contractor any resulting comments or queries. If Owner fails to respond within such period, then such Drawing or Document shall be deemed to have been reviewed by Owner. In the event Owner’s comments identify errors in designs, specifications or any other inconformity with the Requirements of this Agreement (“Mandatory Comments”), Contractor shall within ten (10) Business Days implement changes to such Drawing or Document that are responsive to such comments; provided, however, that Contractor shall have an additional ten (10) Business Day period if consultation with any Subcontractor is required to respond to Owner’s comments. Any comments or suggested changes requested by Owner that are not Mandatory Comments (i) shall be implemented by Contractor if such comments are processed as a Scope Change Order or (ii) may be implemented at Contractor’s discretion. Owner’s comments shall not relieve Contractor from any of Contractor’s obligations hereunder, including responsibility for:

 

2.5.6.1            complying with this Agreement;

 

2.5.6.2            any errors or omissions in any Submittals;

 

2.5.6.3            confirming and correlating all quantities, details and dimensions;

 

2.5.6.4            selecting fabrication processes and construction techniques; and

 

2.5.6.5            performing the Work in a safe and workmanlike manner.

 

2.5.7           Preparatory Work and Survey. Contractor shall undertake all geotechnical work at the Project Site. Contractor shall undertake all necessary Project Site preparation. All such preparatory work contained in this Section 2.5.7 shall be performed in accordance with the Requirements of this Agreement.

 

Section 2.6               Procurement.

 

2.6.1           Materials and Equipment. Contractor shall procure and supply, at its own expense, whether by producing itself or by procuring from others, all materials and equipment set forth in Exhibit 2.6.1 and services required for performance of its obligations under this Agreement (whether on or off the Project Site), including the furnishing of labor, equipment, materials and tools for performance of the Work. Contractor shall be responsible, at its sole expense, for furnishing and installing all temporary construction materials, equipment, supplies, construction utilities and facilities, special tools (except for the special tools supplied by the Turbine Supplier), telephone, data lines, cabling and wiring necessary for all activities associated with the completion of the Work. All equipment and materials purchased by Contractor for the performance of Contractor’s obligations under this Agreement, other than Contractor Equipment, shall be new and all such equipment and materials, including Contractor Equipment, shall be of suitable grade for their respective purpose pursuant to Prudent Industry Practices. Contractor shall provide appropriate storage, in accordance with the manufacturers’ requirements, for materials, supplies and equipment for use in performance of the Work. All materials, supplies and equipment which may be used in performance of the Work and which are stored at a location other than on the Project Site shall be segregated from other goods or identified as belonging to Owner.

 

2.6.2           Consumable Parts. Contractor shall provide all assembly parts required for assembling WTGs (e.g., touchup paint, bolts and nuts normally required to assemble WTGs (“Consumable Parts”). Consumable Parts shall not include any Spare Parts or any consumable parts used or necessary for use in connection with the regularly scheduled service and maintenance of the WTGs.

 

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2.6.3           Spare Parts. Contractor and Owner acknowledge and agree that (i) the Agreement Price does not include Spare Parts and (ii) Contractor will be unable to provide a Spare Parts list with pricing prior to the Notice to Proceed Date. In the event Owner desires to purchase Spare Parts, it must purchase such Spare Parts as an “Option” as described in Section 4.1.1. On the Notice to Proceed Date, Contractor shall deliver to Owner a preliminary draft of Exhibit 4.1.1 with a preliminary Spare Parts list with pricing. The final and effective Exhibit 4.1.1 shall be delivered to Owner by Contractor no later than the date of WTG Mechanical Completion for the first WTG.

 

Section 2.7               Labor and Personnel.

 

2.7.1           Contractor Personnel. As part of the Work, Contractor shall provide competent and suitable qualified personnel to survey and layout the Work and perform construction in accordance with the Agreement Documents as applicable, and Contractor shall be solely responsible for all labor and personnel required in connection with the Work, including: (a) professional engineers licensed to perform engineering services in accordance with Applicable Legal Requirements and qualified to perform the type of engineering services required by Contractor hereunder; and (b) the Contractor’s Prime Subcontractor who has the experience to otherwise ensure the completion of the Work. Contractor’s staff shall include the following key personnel, who shall be solely dedicated to the performance of the Work once they are approved or deemed approved by Owner (the “Contractor’s Key Personnel”): Project Manager, Construction Manager, and Engineering Manager (if Contractor employs such position for the Work). The Prime Subcontractor shall be identified by the Contractor and Contractor shall notify Owner of such company at least ninety (90) days prior to the commencement of physical construction work at the Project Site. The remaining list of Contractor’s Key Personnel shall be identified by Contractor and provided to Owner no later than sixty (60) days prior to the commencement of physical construction work at the Project Site.

 

2.7.2           Owner’s Approval of Contractor Personnel. Once the identity of a Contractor’s Key Personnel is submitted to Owner pursuant to Section 2.7.1, Owner shall have ten (10) Business Days to review and approve such person or demonstrate that Contractor’s Key Personnel is not suitably qualified. If Owner disapproves any person as one of Contractor’s Key Personnel, Owner shall set forth the reasons for its disapproval in writing. If Owner fails to disapprove a proposed Contractor’s Key Personnel in writing within such ten (10) Business Day period, then Owner shall be deemed to have approved such proposed Contractor’s Key Personnel. Following any removal of any of Contractor’s Key Personnel, Contractor shall not replace such Contractor’s Key Personnel without three (3) Business Days prior Notice to Owner setting forth the reasons therefore. Owner shall have the right to review such replacement’s qualifications and to approve such replacement or demonstrate that Contractor’s Key Personnel is not suitably qualified. Contractor shall be responsible for abiding by the terms of the collective bargaining agreements applicable to each relevant craft union that is involved in the performance of any portion of the Work.

 

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2.7.3           Local Requirements. Owner expects Contractor to undertake, and Contractor accepts the obligation to undertake substantial good faith efforts to recruit and retain qualified local Subcontractors ,vendors, supplies and materials located in McIntosh County and Dickey County, North Dakota (collectively, the “Counties”) in connection with the performance of the Work. Notwithstanding the foregoing, Contractor will not be required to use goods and services provided by local contractors or vendors where such local goods or services are not of similar quality or are not qualitatively and or quantitatively comparable to those provided by nonresidents or where such goods and services are not available on terms and conditions (including price and bonding capacity) comparable to those offered by nonresidents. Contractor shall act as coordinator of local services to be a liaison between any individuals (“Coordinator of Local Hiring Services”), businesses or contractors residing or doing business in the county who are interested in obtaining information about providing goods or services related to the construction of the improvements. Contractor shall hold a Job Fair in either of the Counties no later than thirty (30) days prior to the anticipated date of Project Site mobilization where information will be provided regarding the construction and hiring needs of the Project. Contractor shall document to Owner that Contractor is in compliance with said plan, and provide to Owner documentation as is reasonably requested from time to time to confirm such compliance. Contractor shall provide Owner with access to all records of Contractor necessary to demonstrate compliance with this Section 2.7.3.

 

Section 2.8           Project Quality Assurance Plan. Contractor shall submit a project quality assurance plan (the “Project Quality Assurance Plan”) to Owner. The Project Quality Assurance Plan shall require compliance with Applicable Laws and meet the requirements specified in Exhibit 2.8. Upon acceptance by Owner, the Project Quality Assurance Plan shall be incorporated into this Agreement as Exhibit 2.8. Contractor shall perform the Work in accordance with Exhibit 2.8.

 

Section 2.9           Permits and Other Approvals. Contractor shall be responsible for obtaining and maintaining the Permits listed in Exhibit 2.9, including assisting Owner in obtaining any such Permits listed in Exhibit 2.9 required to be obtained in Owner’s name as specified in Exhibit 2.9. Contractor shall obtain and maintain in full force and effect all of the Permits required under Applicable Laws or otherwise necessary or desirable for Contractor to perform the Work in accordance with the Requirements of this Agreement. Upon request by Contractor, Owner shall provide Contractor with reasonable assistance in obtaining such Permits so long as such assistance does not require Owner to incur any out-of-pocket-cost. If any Permit is required for the Work or to perform the Work that is not identified in Exhibit 2.9, Contractor or Owner, as applicable, shall promptly after it becomes aware of the need for such Permit, notify the other Party that such Permit is required. If such Permit is required to be obtained by contractors performing work in the state of North Dakota, Contractor shall, at its sole cost and expense (unless such permitting requirement is the result of a Change of Law entitling Contractor to seek reimbursement from Owner under Section 9.4), be obligated to obtain and maintain such Permit; otherwise Owner shall obtain and maintain such Permit. If any Permit required to be obtained by contractors performing work in the state of North Dakota has been omitted inadvertently by Contractor from Exhibit 2.9, such omission shall not constitute a breach of this Agreement if (i) Contractor timely obtains such Permit and (ii) Owner is not otherwise damaged by such inadvertent omission or Contractor compensates Owner for any direct costs Owner incurs as a result of such inadvertent omission. Owner shall be named as the holder of those Permits that are required to be in the Owner’s name. Contractor represents it shall remain in compliance with the terms and conditions of the Permits, as applicable.

 

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Section 2.10              Real Property Rights.

 

2.10.1          Relocation of Facilities. If relocation of any utilities, transmission lines or other facilities from their existing or currently planned location is necessary for the Project, the Contractor shall bear the sole cost associated with relocating any such utilities, transmission lines or other facilities.

 

2.10.2          Crop Damages and Other Damages from Construction. Contractor shall perform the Work in a commercially reasonable manner that is intended to cause the minimum of inconvenience, injury or damage to the property of the landowners and tenants affected by the Work. Contractor shall familiarize itself with all agreements setting forth the Real Property Rights and comply with all requirements thereof with respect to the performance of the Work. Without limiting the generality of the foregoing, Contractor shall pay all payments required to be made to landowners under the Real Property Rights prior to Project Substantial Completion; provided, that if as of the Closing Date the Guaranteed Project Substantial Completion Date is after December 31, 2019, then Owner shall pay those payments required to be made to landowners under the Real Property Rights which come due in 2020 up to an aggregate amount of $151,000. Contractor shall restore all property damaged in connection with the Work as nearly as practicable to as good condition as before the damage occurred. Contractor shall be required to reimburse Owner for any payment Owner is required to make to any other party to the agreements setting forth the Real Property Rights for damages arising out of or in connection with Contractor’s performance of the Work, provided that Contractor shall only be required to reimburse Owner for crop damage payments relating to the growing season in which the Work was performed. Prior to Final Completion, Contractor shall provide Owner such information as Owner shall reasonably request in support of Owner’s obligations related to the Real Property Rights and as is in Contractor’s possession or as is reasonably available to Contractor.

 

Section 2.11              Turnover Packages.

 

2.11.1         Not later than five (5) Days prior to the date the first Foundation achieves Foundation Completion, Contractor shall deliver to Owner two (2) paper copies of the draft of the Foundation Turnover Package, for review by Owner in accordance with Section 2.5, either in Turnover Package format or in a form and format available as a result of the design and construction process, as appropriate.

 

2.11.2         With respect to each WTG, Contractor shall provide to Owner three (3) paper copies of the draft of the WTG Turnover Package and three (3) paper copies and one (1) electronic copy of the final and complete version of the WTG Turnover Package within ten (10) days of Contractor’s receipt of such material from Prime Subcontractor.

 

2.11.3         Within thirty (30) Days after the Project Substantial Completion Date, Contractor shall deliver to Owner two (2) paper copies and one (1) electronic copy of the final and complete Turnover Package, reviewed and approved by Owner in accordance with Section 2.5.

 

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2.11.4         Where any of the information in the Turnover Package was produced by computer-aided design and is available to Contractor or any Subcontractor, Contractor shall provide or cause to be provided to Owner a disk copy of such information in an Intergraph- or AutoCAD-compatible format. Owner shall have a limited license to use such information solely for the purposes of construction, operation, repair and maintenance of the Project.

 

Section 2.12            Construction Methods and Safety Procedures. Contractor shall have exclusive responsibility for construction methods, means, techniques and procedures required to complete the Work and for the establishment of and compliance with safety procedures at the Project Site.

 

2.12.1         Safety. During performance of the Work, Contractor shall initiate and maintain safety precautions and programs in accordance with Exhibit 2.12.1, the “Contractor’s Safety Program,” and to conform with Applicable Laws, including Environmental Laws, or other requirements designed to prevent injury to persons or damage to property on the Project Site including the Transmission Provider Safety and Interconnection Requirements. Contractor shall be solely responsible for initiating, maintaining and supervising all safety measures and programs in connection with the performance of Work, which shall include precautions and programs for the prevention of injury to local wildlife, flora and fauna. Contractor shall erect and maintain reasonable safeguards for the protection of workers and the public. Contractor shall exercise reasonable efforts to eliminate or abate all reasonably foreseeable safety hazards created by or otherwise resulting from performance of the Work. Contractor shall, and shall cause all of its employees, agents and Subcontractors to, follow the Contractor’s Safety Program and to follow at a minimum the Transmission Provider Safety and Interconnection Requirements during the performance of the Work, including any Work relating to the Point of Interconnection, or when performing work at the Interconnection Substation.

 

2.12.2         Site Safety Manual. No later than thirty (30) days after the Notice to Proceed Date, Contractor shall provide Owner with the final version of a safety manual for the Project Site (the “Site Safety Manual”) for review by Owner in accordance with Exhibit 2.12.1 and Exhibit 2.5.2. Such final version of the Site Safety Manual shall:

 

   2.12.2.1            include proper training and workplace examinations;

 

   2.12.2.2            take into account the interaction of Contractor and its Subcontractor’s or third party contractors on the Site;

 

   2.12.2.3            require compliance with Applicable Laws; and

 

   2.12.2.4            meet the requirements specified in Exhibit 2.12.1 and Exhibit 2.5.2.

 

2.12.3      Safety Reporting. During the performance of the Work at the Project Site, Contractor shall furnish to Owner on a weekly basis a safety report summarizing weekly hours worked at the Project Site by, and head counts of, labor and personnel of Contractor and its Subcontractors performing Work at the Project Site and all accidents, near misses or injuries at the Project Site required by Applicable Laws to be recorded or reported to any Governmental Authority.

 

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2.12.4         Emergencies. In the event of any emergency endangering persons or property, Contractor shall promptly take all reasonable and prudent actions to prevent, avoid or mitigate injury, damage or loss, regardless of the source of fault, and shall as soon as possible, report any such incidents, including Contractor’s response thereto, to Owner. If Contractor does not take such actions promptly, then Owner may take such actions as are necessary to prevent, avoid or mitigate injury, damage or loss and Contractor shall reimburse Owner for any actual costs incurred by Owner in taking such actions in the event of an emergency (not otherwise caused by Owner). Contractor shall assist Owner in any safety or accident investigation and promptly provide information as requested by Owner related thereto.

 

2.12.5         Hazardous Materials and Regulated Materials.

 

    2.12.5.1           In the performance of any Work, Contractor shall, and shall cause its Subcontractors to, comply with all Applicable Laws, including Environmental Laws, relating to Hazardous Materials, Regulated Materials, and the terms and conditions of all Permits. Contractor shall not, nor shall it permit any Subcontractor to, bring any Hazardous Materials on the Project Site (other than materials to be used by Contractor, in a manner that both (a) does not violate, or require reporting or disclosure under, any Environmental Law, and (b) is consistent with customary business practice for manufacturing, delivering, installing, assembling, erecting, Commissioning, start-up testing, operating and maintaining wind energy projects, such as lubricants (“Permissible Materials”)).

 

    2.12.5.2           Contractor shall bear all responsibility and liability for Hazardous Materials and Regulated Materials brought on the Project Site by Contractor or its Subcontractors, whether such materials are permitted to be brought on the Project Site pursuant to this Section 2.12.5 or are brought on the Project Site in violation of this Section 2.12.5. Contractor shall be solely responsible for performing and paying the costs of any remediation required by Applicable Laws as a result of any Releases by Contractor or its Subcontractors of any such Hazardous Materials.

 

    2.12.5.3           Notwithstanding anything to the contrary herein, Contractor shall not be responsible for any Pre-Existing Hazardous Materials encountered at the Project Site. If such Pre-Existing Hazardous Materials are encountered at the Project Site by Contractor, Contractor shall immediately, upon recognizing such condition (a) stop the Work in the affected area of the Project Site, and (b) report such condition to Owner in writing. In addition to Contractor’s obligations as set forth above, if Owner desires Contractor to perform all or part of any excavation or removal that may become necessary as a result of the discovery of any such Pre-Existing Hazardous Material, it shall request a Scope Change pursuant to Article 9. If so requested by Owner, Contractor shall cooperate with and assist Owner in making the Project Site available for taking necessary remedial steps to clean-up any such contamination at Owner’s expense as determined in accordance with Article 9. Contractor shall not be required to perform clean-up of Pre-Existing Hazardous Materials to the extent Contractor is not responsible therefor, unless the Parties mutually agree that Contractor will perform such clean-up.

 

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    2.12.5.4           Title to all materials incorporated into the Work or other Permissible Materials stored at the Project Site shall transfer to Owner upon transfer of title of such Work in accordance with Article 14.

 

    2.12.5.5           Contractor shall minimize the use of Hazardous Materials in performance of the Work and shall not utilize, or permit or cause any Subcontractor, to utilize, such Hazardous Materials as are prohibited under Applicable Law from being imported into or used in the United States. Contractor shall maintain an updated file of all safety data sheets for all materials used in connection with performance of the Work at the Project Site or at any construction area related to the Project and shall deliver an update of such file to Owner no later than ten (10) Business Days after the end of each month. In accordance with Applicable Laws, Contractor shall maintain an accurate record and current inventory of all Hazardous Materials used in performance of the Work at the Project Site or at any construction area related to the Project, which record shall identify quantities, location of storage, use and final disposition of such materials.

 

    2.12.5.6           Contractor shall be solely responsible for collecting, handling, storing and removing from the Project Site and areas adjacent thereto, and for properly disposing of, in compliance with this Agreement, all Applicable Laws and all Permits, materials that were brought onto the Project Site by Contractor, its Personnel, vendors, or Subcontractors. If a Release of Hazardous Materials brought onto the Project Site by Contractor or its employees, or Subcontractors, occurs on the Project Site that triggers a requirement under Applicable Laws to remediate such Release, and Contractor fails or refuses to remediate such Release or prepare a reasonable plan of remediation for such Release, then Owner may, at its discretion and after three (3) Business Days prior notice to Contractor, perform such remediation as it deems necessary or adequate. All reasonable costs and expenses of such remediation shall be for the account of Contractor, and Contractor shall promptly reimburse such amounts to Owner, except that all costs associated with any Release not from Hazardous Materials brought onto the Project Site by Contractor or any Subcontractor shall be borne by Owner. The Parties agree that Contractor simply discovering Pre-Existing Hazardous Materials is not a Release.

 

    2.12.5.7           Contractor shall implement and administer a Spill Prevention Control and Countermeasure (“SPCC”) program for all of its employees and all Subcontractors, which shall include development of guidelines and training with respect to the proper handling use and disposal of Permissible Materials and Hazardous Materials and the development, implementation and enforcement of procedures for notification of Owner and appropriate Governmental Authorities about, and clean-up of, spills and other emissions of Permissible Materials and Hazardous Materials, which such SPCC program shall be provided to Owner for review within sixty (60) days prior to any Work at the Project Site.

 

    2.12.5.8           Contractor shall promptly report any Contractor or Subcontractor Release or possible Release of known Hazardous Materials and potentially Hazardous Materials. Contractor shall act to contain any such Release in accordance with Applicable Law, including Environmental Law, and the provisions of this Agreement. Contractor’s obligations under this Section 2.12.5.8 shall be limited to Releases that occur prior to Final Completion.

 

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Section 2.13            Commissioning and Testing. Contractor shall submit commissioning procedures for Owner review per Exhibit 2.5.5. Owner shall provide comments on these procedures within ten (10) days after receipt of such procedures. In the event Owner fails to timely provide comments to Contractor as provided by this Section 2.13, the commissioning procedures shall be deemed approved by Owner as of the date of delivery thereof by Contractor. Contractor shall, in good faith, include Owner’s timely reasonable comments into the final commissioning procedures. Contractor shall perform the commissioning and testing of the Infrastructure Facilities in accordance with the Commissioning, Test and Inspection Procedures.

 

Section 2.14          Clean-up; Non-interference. Contractor shall at all times keep the Project Site free from non-hazardous waste materials or rubbish caused by its activities. During the period from Project Substantial Completion to completion of the Punch List Items, Contractor’s performance of the Work shall not interfere with the operation of the WTGs. As soon as practicable after the completion of all Punch List Items, Contractor shall (i) remove from and around the Project Site all of its equipment and materials not constituting part of the Project, (ii) tear down and remove all temporary structures on the Project Site built by it or its Subcontractors and restore such per requirements in the Real Property Rights agreements, Permits, and this Agreement, and (iii) remove from and around the Project Site all Permissible Materials not incorporated into the Work and all non-hazardous waste and rubbish resulting from the Work. All Permissible Materials and non-hazardous waste material and rubbish resulting from the Work shall be handled and disposed of by Contractor at its own expense in accordance with all Applicable Laws. Contractor shall provide to Owner copies of all waste disposal manifests, if any, upon request. Contractor’s obligations with respect to the handling and disposal of Hazardous Materials Released at the Project Site are set forth exclusively in Section 2.12.5 above.

 

Section 2.15             Books and Records; Audit Rights.

 

2.15.1         Books and Records of Contractor. Contractor shall maintain during the course of the Work, and retain not less than six (6) years after Final Completion, complete and accurate records of all Contractor’s records arising from, in connection with or incident to the Work or the Project, including without limitation, all Documents, granted authority, Permits and other evidentiary data that evidences compliance with the Requirements of this Agreement. Owner shall have the right for one year from Final Completion, during normal working hours, to inspect, reproduce, and audit such records of Contractor by Authorized Representatives of its own or any third party contract compliance-auditing firm selected by Owner for work performed pursuant to any Scope Change Orders on a time and material basis, except that such parties shall not have the right to audit or have audited Contractor’s books and records in connection with the internal composition of any markups, fixed rates or percentages or multipliers. The Scope Change Order records to be thus maintained and retained by Contractor for such work performed on a time and materials basis must provide sufficient detail to evidence the propriety of all such chargeable costs and compliance with the Requirements of this Agreement, and shall include (without limitation):

 

2.15.1.1           payroll records (hours, employee name, employee classification, multiplier breakdown etc.) that account for total time worked under such contract;

 

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2.15.1.2           invoices (including all back-up details) for purchases, receiving and issuing documents, and all inventory records for Contractor’s stock or capital items;

 

2.15.1.3           paid invoices and canceled checks for purchased materials, Subcontractor and third party charges;

 

2.15.1.4           records relating to airfreight and ground transportation, including but not limited to handling, hauling, and disposing of materials/equipment; and

 

2.15.1.5           accurate, auditable records of gifts, entertainment, and gratuities to individual Owner personnel.

 

2.15.2     Books and Records of Subcontractor. Contractor shall cause all of its Subcontractors to adhere to and comply with the requirements set forth in Section 2.15.1 for such work performed on a time and materials basis.

 

2.15.3     Audit Rights. Owner acknowledges that, except for any Scope Change Orders that are performed on a time and materials basis, all of the Work to be performed by Contractor hereunder shall be performed for a fixed price, and Owner shall have no right to review, audit or copy any detailed invoices, payroll records or any similar books or records maintained by Contractor with respect to the Work; provided that Contractor shall provide copies of all such books and records required by Owner to respond to any request of a Governmental Authority related to the Project. Contractor shall maintain detailed invoices, payroll records and similar books or records with respect to the Work to support any such requirement.

 

Section 2.16         Commencement of the Work. Except for that portion of the Work set forth in the Limited Notice to Proceed, Contractor shall not perform any Work before Owner issues the Notice to Proceed or otherwise authorizes, in writing, the Contractor to commence the Work. The Parties hereby acknowledge and agree that the Notice to Proceed will be deemed issued by Owner and received by Contractor on the Closing Date under the Asset Purchase Agreement. In the event the Agreement is terminated pursuant to Section 13.5 and no Notice to Proceed is issued, in such case title to any materials, engineering specifications and other work product (including foundation specifications, substation design, and road specifications), a main power transformer queue position, and any other preliminary work done by BOP contractor purchased by Contractor pursuant to the Limited Notice to Proceed shall immediately pass to Owner.

 

Section 2.17         Interconnection. Contractor shall be responsible for complying with all provisions of the final Interconnection Agreement to be executed between Owner and the Transmission Provider and Transmission Owner that are applicable to Contractor’s Work.

 

Section 2.18           Owner’s Right to Inspect. Subject to providing five (5) Business Days’ notice to Contractor, Owner and Owner’s Authorized Representatives shall have the right to inspect the Work and to maintain personnel at the Project Site for such purpose, subject in all cases to Contractor’s reasonable safety precautions. Such inspection of any part of the Work shall be conducted during normal operating hours at the Project Site and shall in no way relieve Contractor of its obligation to perform the Work in accordance with this Agreement. Neither Owner nor Owner’s Authorized Representative shall interfere with the execution of the Work in any material way during any inspection of the Project Site.

 

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Section 2.19         Notice of Claims and Liens. Provided that Owner makes all Milestone Payments due to Contractor in the amounts and at the time required by this Agreement, neither Contractor nor Prime Subcontractor shall assert or file a mechanics’ or materialman’s lien against Owner or the Project or the Project Site; provided, however, that this sentence shall not preclude the filing of a mechanics’ or materialman’s lien by the Prime Subcontractor against the Project or Project Site prior to the Notice to Proceed Date so long as Contractor removes such lien prior to the Notice to Proceed Date. Contractor agrees that neither Contractor nor Prime Subcontractor shall file a lien against Owner or the Project or the Project Site unless written notice thereof shall have been given to Owner at least ten (10) days prior to the date Contractor or Prime Subcontractor files a lien against Owner, the Project or the Project Site. Other than as provided for above in this Section 2.19 and for Permitted Liens (as defined in the Asset Purchase Agreement), Contractor shall not allow third party lien claims or any encumbrances to be (i) filed against Owner, or (ii) placed upon the Work and/or Owner property with respect to any of the Work performed hereunder. Contractor further agrees to defend, indemnify, save and hold harmless Owner from and against all such third party claims, damages and expenses, including liens of Subcontractors, laborers, equipment suppliers, service providers and other persons or entities arising out of, resulting from or in any way connected with the Work performed (or omitted to be performed) under or pursuant to this Agreement, including any Purchase Order(s). If a lien or encumbrance has been filed or noticed by a third party, Contractor shall bond-over the lien or encumbrances not later than the earlier of ten (10) Business Days after the lien or encumbrance has been filed or notice has been received. If Contractor chooses to bond-over the lien or encumbrance, the amount of the bond shall not be less than one hundred twenty-five percent (125%) of the claim. Any such bond shall survive the termination or expiration of this Agreement until such time as the applicable lien is released. Contractor will furnish, when requested by Owner, written evidence that any third party lien claims or encumbrance filed against Owner or the Project or the Project Site in connection with the Work, have either been paid in full or bonded-over, including, without limitation, releases or waivers of all liens and claims of Major Subcontractors and laborers. Except for liens properly filed by Contractor pursuant to this Section 2.19, if any liens, claims or other encumbrances are outstanding against Contractor or Owner as a consequence of the Work, if the claim or encumbrance is not bonded-over, Owner may retain from money due Contractor sufficient amounts to indemnify and hold Owner harmless. In the event Owner is notified in writing of a third party claim or claims arising from the Work performed by Contractor, Owner shall notify Contractor of such claim or claims and Contractor shall appoint a representative who will have the authority to settle any claims, provided, that any proposed settlement that would involve Owner, and not Contractor, bearing the financial responsibility of such settlement shall require the prior approval by Owner. If Contractor fails to appoint a representative to settle such claims, Owner shall have the right to make settlement thereof and charge the same to Contractor.

 

Section 2.20         Cooperation. Owner shall cooperate with Contractor in connection with Contractor’s efforts to obtain the approvals, certificates and Permits that Contractor is required to obtain to perform the Work.

 

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Section 2.21         Security and Assignment Agreements and Consents. As security for the performance of Contractor’s obligations under this Agreement and in order to preserve Owner’s Step-In Rights under Article 13, Contractor shall deliver to Owner (a) the Turbine Supply Security and Collateral Assignment Agreement, duly executed by Contractor, (b) the Turbine Supplier Consent to Assignment, duly executed by Contractor and Turbine Supplier, (c) the Prime Subcontract Security and Assignment Agreement, duly executed by Contractor, (d) the Prime Subcontractor Consent to Assignment, duly executed by Contractor and Prime Subcontractor, and (e) such other security and assignment agreements of Subcontracts as may be required by Owner to secure Owner’s rights under Article 13, duly executed by Contractor, together with consents to such assignments duly executed by Contractor and the relevant Subcontractor.

 

Article 3
SUBCONTRACTORS

 

Section 3.1             Subcontractors.

 

3.1.1        Subcontracts. Owner acknowledges that Contractor intends that portions of the Work shall be accomplished by Subcontractors pursuant to certain written Subcontracts between Contractor and such Subcontractors. Owner hereby approves Contractor’s engagement of the Turbine Supplier. Contractor agrees to provide Owner with the list of potential Subcontractors it is considering for performing aspects of the Work upon the reasonable request by Owner. Owner agrees to the use and engagement of Subcontractors by Contractor, provided, that Contractor may not enter in to any contract with a Major Subcontractor unless the Major Subcontractor has been approved by Owner in accordance with Section 3.2. Contractor shall require and shall cause all Work performed by Subcontractors to be in accordance with the Requirements of this Agreement. No Subcontractor is intended to be nor shall be deemed a third party beneficiary of this Agreement. Contractor agrees that it shall be fully responsible to Owner for the acts and omissions of Subcontractors and of Persons directly or indirectly employed by them, as it is for the acts or omissions of Persons directly employed by Contractor. Nothing contained herein shall obligate Owner to pay any Subcontractor and Contractor shall be solely responsible for paying each Subcontractor and any other Person to whom any amount is due from Contractor in connection with the Project.

 

3.1.2        Assignment. No Subcontract shall bind or purport to bind Owner. When entering into a Subcontract with a Major Subcontractor for work to be performed at the Project Site, Contractor shall cause Owner to be named as an intended third-party beneficiary and contain a provision substantially in the form of Exhibit 3.1.2 permitting its assignment to Owner upon Owner’s written request following default by Contractor, the exercise by Owner of Step-in-Rights, termination due to a Contractor Default, or expiration of this Agreement. With respect to any Subcontract assigned to Owner, as a condition to such Subcontractor accepting such an assignment, Owner shall provide reasonable assurances of performance.

 

3.1.3        Subcontractor and Vendor Warranties. To the extent assignable, Contractor shall assign all representations, warranties, guarantees and obligations of all Major Subcontractors upon Final Completion.

 

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Section 3.2   Major Subcontracts. Appended to this Agreement as Exhibit 3.2 is a list of approved Subcontractors. In the event that Contractor is considering the selection of a Subcontractor not listed in Exhibit 3.2 for a Major Subcontract, Contractor shall (i) notify Owner of the proposed Major Subcontractor(s) at the earliest practical point in its selection process and furnish to Owner all information reasonably requested by Owner with respect to Contractor’s selection criteria (including copies of bid packages furnished to prospective Major Subcontractors and the qualifications of proposed Major Subcontractors) and (ii) notify Owner no less than ten (10) Business Days prior to the proposed date of execution of a Major Subcontract. Owner shall have the right to reject for good cause any proposed Major Subcontractor; provided, that such good caused is based on and limited to the technical capacity, performance history or financial condition of such prospective Major Subcontractor. Contractor shall not enter into any Major Subcontract with a proposed Major Subcontractor rejected by Owner. Owner shall undertake in good faith to review the information provided by Contractor expeditiously and shall notify Contractor of any such rejection as soon as practicable after such decision is made. If at the end of the ten (10) Business Days after receipt of such information by Owner, Contractor has not received notice of Owner’s rejection of the proposed Major Subcontractor, Contractor shall have the right to execute such agreement with the proposed Major Subcontractor and such Major Subcontractor shall be deemed added to the list of approved Subcontractors in Exhibit 3.2. Owner’s approval not to be unreasonably withheld.

 

Section 3.3           Change in Major Subcontractor due to Owner’s Objections. In the event Owner’s rejection of such proposed Major Subcontractor results in Contractor entering into a Major Subcontract at a higher price than the proposed Major Subcontract, Owner shall issue a Scope Change Order for such increase.

 

Article 4
Agreement PRICE AND PAYMENTS

 

Section 4.1           Agreement Price. As consideration to Contractor for completing and furnishing the Work, Owner agrees to pay Contractor, and Contractor agrees to accept as full and complete payment for all of the Work, including construction aids, start-up and testing, supervision, travel and per diem costs, other Contractor expenses related to the Work and the performance of any warranty obligations hereunder, the fixed lump sum agreement price of TWO HUNDRED MILLION FIVE HUNDRED FORTY-EIGHT THOUSAND EIGHT HUNDRED SIXTY-FOUR AND 00/100 DOLLARS (US $200,548,864.00) (“Agreement Price”), and described on the Payment Schedule (as set forth at Exhibit 4.1 to this Agreement and in accordance with Section 4.3 below) and hereby purchased by Owner from Contractor at the prices set forth on the Payment Schedule but excludes sales and use Taxes associated therewith; provided, that if the Closing Date occurs after December 31, 2018, the Agreement Price shall be increased by an amount equal to [**] ($[**]) multiplied by the number of months the Closing Date occurs after December 31, 2018. Other than as provided for in this Section 4.1 or Section 4.1.1, except with respect to (i) certain Taxes as set forth in Section 4.2.3, and (ii) Scope Changes as provided in Article 9, the Agreement Price shall not be increased for any reason under this Agreement. The Agreement Price is stated in United States Dollars and is not subject to adjustment for exchange rate fluctuations.

 

______________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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4.1.1        Agreement Price Adjustments for Certain Options with respect to the Work. Set forth on the Exhibit 4.1.1 are (a) the prices for each item of Spare Parts, and any other materials or services designated in the Payment Schedule as “Options” (such other Spare Parts, materials and services being referred to as “Options” as identified in Exhibit 4.1.1). At any time and from time to time after the Effective Date of this Agreement, Owner may elect to purchase any one or more of the Options by giving notice of such election to Contractor. Each time Owner makes such an election, a Change Order shall adjust the Agreement Price to include the cost of any and all Options that Owner so elects to purchase at the prices set forth for such Option or Options on the Payment Schedule.

 

4.1.2       Owner Credit Support. No later than ten (10) Business Days after the occurrence of a Credit Trigger Event with respect to Owner, Owner shall provide Contractor with an irrevocable standby letter of credit in the form of Exhibit 4.1.2, issued by an Qualified Institution, with a drawable amount equal to [**] ($[**]) (the “Owner LOC”). The Owner LOC, if issued, shall secure Owner’s payment obligations, including Owner’s indemnity obligations, hereunder. Contractor shall be entitled to draw on the Owner LOC for any uncured breach by Owner of this Agreement. Owner shall maintain the Owner LOC in place until Contractor has been paid all amounts due to Contractor under this Agreement. For the avoidance of doubt, the Owner LOC referenced in this Section 4.1.2 is the same agreement as that referenced in the Asset Purchase Agreement and not in addition to such agreement.

 

Section 4.2            Taxes.

 

4.2.1         Import Taxes. The Agreement Price shall include payment for all duties, levies, imposts, fees, royalties or charges of any kind, whether in the United States or elsewhere, arising from the importation of any items into the United States.

 

______________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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4.2.2       Tax Responsibility. Except as provided in Section 4.2.3, the Agreement Price includes payment for: (i) all costs of equipment, temporary equipment, materials, labor, transportation, engineering, design and other services relating to Contractor’s performance of its obligations under this Agreement and the Work (including any intellectual property rights licensed under this Agreement, expressly or by implication) provided by Contractor or such Subcontractors; (ii) except as set forth in Section 4.2.3, all taxes of any nature whatsoever including all United States federal, state, regional, and local taxes, national and foreign taxes, goods and services taxes, sales and use taxes and occupational, excise, unemployment, ownership, value-added, gross receipts, and income taxes and any and all other taxes effective or enacted as of the Effective Date or thereafter (collectively referred to as “Taxes”), and (iii) all duties, customs, levies, imposts, fees, royalties or charges of any kind (whether in the United States or elsewhere and including any of the foregoing related to the importation of any items into the United States) arising out of the exportation and importation of any component or part of the WTG, Infrastructure Facilities, Drawings, designs or other Work or out of Contractor’s or any such Subcontractor’s performance of the Work, or with respect to any equipment, materials, labor, or services provided under this Agreement, including any increases thereof that may occur after the Effective Date. The Agreement Price shall not be increased with respect to any of the foregoing items in (ii) or (iii) above or with respect to any withholdings in respect of any of the foregoing items that Owner may be required to make. Notwithstanding the foregoing, Contractor shall not be liable for, and the Agreement Price shall not include any taxes for which Owner is responsible pursuant to Section 4.2.3. Contractor shall provide to Owner all information reasonably requested by Owner to confirm that the correct amount of sale and use tax or other like taxes will be paid on the Work and the Project, but only to the extent that the failure to provide such information is reasonably likely to create a liability for Owner.

 

4.2.3       Payment of Sales Tax. Notwithstanding anything to the contrary in this Agreement, the Agreement Price shall not include, but Owner shall pay or reimburse Contractor for, any sales, use, or transfer tax levied by any state, county or local government with respect to the purchase, sale, lease or use of any personal property or services that are part of the Work or the Project (“Sales Tax”), without regard to whether the person required by law to report, collect or pay such sales Tax was Contractor, any Subcontractor, a person selling to either of them, or any other person.

 

4.2.4       Tax Administration and Payment. Contractor shall timely administer and pay all Taxes for which Contractor is responsible, and timely furnish to the appropriate taxing authorities all required information and reports in connection with such Taxes and furnish copies of such information and reports (other than information specifically pertaining to Contractor’s income and profit) to Owner. Upon receipt of an invoice submitted by Contractor, Owner shall promptly pay to Contractor (or, at the request of Contractor, directly to the applicable Governmental Authority) any Sales Tax pursuant to Section 4.2.3. Owner, or transactions involving Owner, may be exempt from some Taxes or Sales Taxes under State of North Dakota or other Applicable Law. To the extent necessary, Owner will provide to Contractor valid information and forms, including the State of North Dakota tax exemption certificate (“Tax Exemption Certificate”) set forth in Exhibit 4.2.4, to allow Contractor to secure such exemptions for the benefit of Owner. All Contractor’s invoices shall be consistent with the provisions of this Section 4.2.4. All invoices must be accompanied by completed Tax Exemption Certificates. For a period of six (6) years after the Project Substantial Completion Date, and within thirty (30) Days of a request therefore, Contractor shall provide Owner with any information regarding quantities and descriptions of property installed at the Site that Owner shall reasonably request in connection with the preparation of its Tax returns.

 

4.2.4.1           Sales Tax Exemption for Renewable Energy Production Components. Contractor and Owner shall work together to develop and execute a tax strategy to minimize Sales Tax payable in connection with the Project. In the event that the North Dakota sales and use tax exemption (the “Renewable Energy Production Components Exemption”) applicable to the tangible personal property used in the construction of the Project (the “Wind Conversion System Equipment”) is extended beyond January 1, 2017, Contractor and each of its Subcontractors shall purchase all Wind Conversion System Equipment as a sale for resale or pursuant to the Renewable Energy Production Components Exemption and without collecting, paying or remitting any Sales Tax, other than to applicable local jurisdictions and Contractor shall not charge Sales Tax on billings to Owner for Owner’s purchases of Wind Conversion System Equipment, provided Owner provides Contractor with a valid Certificate of Exemption.

 

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4.2.4.2           Non-Wind Conversion System Equipment Taxes. Contractor and Owner agree that to the extent materials used or consumed in the production of the Project are not exempt from sales and use tax that Owner shall pay Contractor pursuant to Section 4.2.3 and Contractor shall remit the tax to the applicable jurisdiction pursuant to Section 4.2.4.  Each invoice submitted by Contractor with respect to any such materials shall show as separate line items the sales price, the sales and use tax and any associated labor.

 

4.2.4.3           Labor. Contractor and Owner assume that installation labor for Non-Wind Conversion System Equipment is non-taxable and Contractor and each of its Subcontractors shall not collect nor pay any State sales and use tax on any such Project labor. Notwithstanding then foregoing, Owner is not relieved of any liability for sales tax on labor.

 

4.2.4.4           Additional Information Requested by Owner. Contractor shall provide assistance as reasonably requested by Owner or Owner’s Tax consultant, in determining eligibility and qualifying for exemptions or exclusions from sales and use taxes (and any other Sales Tax exemptions or exclusions) for the relevant Governmental Authority and Owner agrees to take reasonable measures to protect Contractor’s proprietary business and pricing information.  To the extent that Owner requires additional documents or information from Contractor to complete or comply with Owner’s applications for a sales tax refund pursuant to Section 4.2.4.2 above, or in connection with a tax jurisdiction audit matter, Contractor shall only be required to provide such additional documents or information reasonably requested by Owner if (a) Owner confirms to Contractor in writing that such additional documents or information are necessary to complete or comply with applicable laws respecting such sales tax refunds or audit matter; and (b) Owner may disseminate such information to state taxing authorities and other third parties only as necessary to comply with applicable laws respecting such tax refund or audit matter.

 

Section 4.3           Payment of the Agreement Price. Owner shall pay the Agreement Price to Contractor in installments (each, a “Milestone Payments”) in accordance with the Payment Schedule set forth in Exhibit 4.1. Owner shall pay Contractor within twenty (20) Days from the date of Owner’s receipt of a Milestone Payment Request in substantially the form of Exhibit 4.3. An amount equal to ten percent (10%) of each Milestone Payment will be withheld by Owner as additional security (the “Retainage”) up to a maximum retainage of [**] ($[**]) (the “Retainage Cap”); provided, however, that the Retainage Cap will be increased by the amount of any retainage Contractor is entitled to hold back from payments made by it under the Turbine Supply Agreement. Upon the achievement of Project Substantial Completion, the Retainage will be reduced to an amount equal to 200% of the value of the Punch List Items and the balance thereof shall be paid to Contractor. THE PARTIES EXPRESSLY ACKNOWLEDGE THAT OWNER SHALL HAVE NO OBLIGATION TO PAY ANY AMOUNTS TO CONTRACTOR HEREUNDER, INCLUDING ANY MILESTONE PAYMENT, UNTIL AFTER (I) NOTICE TO PROCEED HAS BEEN DEEMED ISSUED; AND (II) THE SECURITY AND ASSIGNMENT AGREEMENTS AND CONSENTS REQUIRED PURSUANT TO Section 2.21 HAVE BEEN SIGNED AND DELIVERED TO OWNER.

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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Section 4.4           Disputed Invoices. If there is any dispute about any amount invoiced by Contractor, the amount not in dispute shall be promptly paid and any disputed amount that is ultimately determined to have been payable shall be paid, with interest calculated, as provided in Section 4.8.

 

Section 4.5           Conditions of Payment. Contractor’s right to receive any payment to be paid to it hereunder is conditioned upon its submitting to Owner, a Milestone Payment Request that shall include: (i) the amount of the Milestone Payment due; (ii) the Monthly Progress Report, and (iii) Partial Lien Waivers duly executed by Contractor and each Major Subcontractor (except that with respect to the final payment hereunder, a Final Lien Waiver is required from Contractor and each Major Subcontractor).

 

Section 4.6            Evidence of Payments to Turbine Supplier. Within five (5) Business Days after making any payment to Turbine Supplier with respect to this Agreement, and as a condition to Owner’s obligation to make any subsequent payment to Contractor hereunder, Contractor shall provide Owner with evidence that payment has been made to Turbine Supplier in the form of either (i) a wire transfer confirmation (redacted to delete precise payment amounts) indicating such payment to Turbine Supplier and a written confirmation from Turbine Supplier that Contractor is current in its payment obligations to Turbine Supplier, including confirmation of the percentage of the “Contract Price” (as defined in the Turbine Supply Agreement) paid to Turbine Supplier through the date of such payment or (ii) a Turbine Supplier lien waiver to Owner with respect to such payment, including confirmation of the percentage of the “Contract Price” (as defined in the Turbine Supply Agreement) paid to Turbine Supplier through the date of such payment.

 

Section 4.7           Guarantees; Backup Letter of Credit. To secure the performance of its obligations under this Agreement, Contractor shall provide, or cause to be provided to Owner with the following:

 

4.7.1         EDF-EN Guaranty. On the Effective Date, Contractor shall cause Guarantor to execute and deliver to Owner, and maintain in full force and effect, the EDF-EN Guaranty. The EDF-EN Guaranty shall remain in effect until the earlier to occur of (i) payment in full, or termination, of all of the payment obligations (including contingent obligations) guaranteed thereby and (ii) the sixth (6th) anniversary of the Project Substantial Completion Date (“EDF-EN Guaranty Expiration”).

 

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4.7.2           Construction Period Guaranty. On or prior to January 1, 2018, Contractor will to deliver to Owner and maintain in full force and effect either (i) the Construction Period Guaranty executed by Guarantor for the benefit of Owner or (ii) a payment bond in an amount equal to [**] ($[**]) in form and substance reasonably satisfactory to Owner and issued by a surety reasonably acceptable to Owner assuring the payments otherwise guaranteed by the Construction Period Guaranty (the “Project Surety Bond”). The Construction Period Guaranty or the Project Surety Bond, as the case may be, shall remain in effect until the earlier to occur of (x) payment in full, or termination, of all of the payment obligations (including contingent obligations) guaranteed thereby and (z) the delivery to Owner of the Post-Construction Guaranty (“Construction Period Guaranty Expiration”).

 

4.7.3           Post-Construction Guaranty. On or prior to the Project Substantial Completion Date, Contractor shall cause the Guarantor to execute and deliver to Owner, and maintain in full force and effect, the Post-Construction Guaranty. The Post-Construction Guaranty shall remain in effect until the earlier to occur of (i) payment in full, or termination, of all of the obligations guaranteed thereby and (ii) the sixth (6th) anniversary of the Project Substantial Completion Date (“Post-Construction Guaranty Expiration”).

 

4.7.4           Backup Letter of Credit. No later than ten (10) Business Days after the occurrence of a Credit Trigger Event with respect to a Guarantor, Contractor shall provide Owner with an irrevocable standby letter of credit in the form of Exhibit 4.7.c, issued by a Qualified Institution, with a drawable amount equal to [**] Dollars ($[**]) (the “Backup LOC”) with respect to each Guaranty issued by such Guarantor and outstanding at the time of such Credit Trigger Event. Each Backup LOC, if issued, shall secure (x) such Guarantor’s obligations under the applicable Guaranty, (y) Contractor’s performance and payment obligations under this Agreement, including performance through the end of applicable Infrastructure Facilities Warranty Periods and (z) Sellers’ payment obligations under the Asset Purchase Agreement, including all indemnity and liquidated damages obligations thereunder. The Backup LOC shall terminate on the sixth (6th) anniversary of the Project Substantial Completion Date. Owner shall be entitled to draw on the Backup LOC for any uncured breach by Contractor of this Agreement, by Sellers of the Asset Purchase Agreement or by the Guarantor of the applicable Guaranty.

 

4.7.5           No Duplication. For the avoidance of doubt, the EDF-EN Guaranty, the Construction Period Guaranty, the Post-Construction Guaranty, and the Backup LOC(s), each referenced in this Section 4.7, are the same agreements as those referenced in the Asset Purchase Agreement and not in addition to such agreements.

 

Section 4.8             Interest. Any amount owed to either Party beyond the date that such amount first becomes due and payable under this Agreement shall accrue interest from the date that it first became due and payable until the date that it is paid at the lesser of (a) the LIBOR plus three percent (3%) and (b) the maximum rate permitted by Applicable Laws.

 

Section 4.9            Effect of Payment. Payment of the Agreement Price shall not constitute Owner’s approval of any portion of the Project or the Work which has been determined not to be, or subsequently is determined not to have been, performed in accordance with the Requirements of this Agreement.

 

_______________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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Section 4.10         Set-off. Notwithstanding anything to the contrary in this Agreement, either Party may at any time deduct and set-off (including a draw on any security held by either Party) against any part of the balance due or to become due to the other Party under this Agreement, including any Delay Liquidated Damages due or accrued but not paid by Contractor to Owner hereunder and any other amounts payable by Contractor to Owner hereunder that are not subject to an unresolved dispute.

 

Section 4.11         Payment Dates. Notwithstanding anything to the contrary in this Article 4, in the event that any payment to be made under this Agreement falls due on any Day that is not a Business Day, the payment shall be deemed due on the first Business Day thereafter.

 

Section 4.12         Payment Withheld. Owner may withhold payment on any Milestone Payment or portion thereof in an amount reasonably necessary to protect Owner to cover the actual costs (calculated in a manner consistent with the terms of this Agreement, but subject to the limitations set forth in Section 11.2) of (i) Defects not remedied or (ii) Liens filed against the Project or the Project Site by Subcontractors that Contractor has not caused to be released or bonded over within fifteen (15) Days after the date of filing or, regardless of when filed, prior to the date that the final Milestone Payment will be due. Notwithstanding the foregoing, Owner must first apply any amounts held as Retainage to cover actual costs incurred prior to withholding any payment otherwise due to Contractor under this Agreement. No payment made by Owner to Contractor or withholding of any payment by Owner shall relieve Contractor of any liability under this Agreement or shall be deemed a waiver by Owner of any warranty of Contractor.

 

Section 4.13         Release of Liens. If any Lien or claim of Lien is filed or notification of withholding money for labor or material furnished under this Agreement is served on Owner and Owner has made all Milestone Payments properly due to Contractor in the amounts and at the time required by this Agreement, and Contractor fails to provide a lien bond or other security or otherwise cause the Lien or claim to be discharged or withdrawn within sixty (60) Days from the time such Lien or claim is made, Owner may discharge such Lien or claim with the monies withheld pursuant to Section 4.12, whereupon for purposes of this Agreement such monies shall be deemed to have been paid to Contractor.

 

Section 4.14         Final Payment. Upon the occurrence of Final Completion as evidenced by the Final Completion Certificate, Owner shall make the final Milestone Payment to Contractor. pursuant to Exhibit 4.1.

 

Article 5
OWNER RESPONSIBILITIES

 

Section 5.1           Project Site Access. Owner shall provide Contractor with access to the Project Site at all times Contractor determines necessary for performance of the Work. Except as otherwise provided in this Agreement, Owner shall not unreasonably prevent, obstruct or otherwise interfere with Contractor’s or Subcontractor’s reasonable rights of ingress or egress to and from the Project Site.

 

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Section 5.2           Permits. Owner shall cooperate with Contractor in connection with Contractor’s efforts to obtain the Permits required pursuant to Section 2.9. Owner shall be responsible for obtaining and maintaining those Permits listed in Exhibit 2.9 as Owner’s responsibility.

 

Section 5.3           [Reserved] 

 

Section 5.4           Review of Design Documents. Owner shall provide timely review of the Design Documents during Design Development, as provided in Section 2.5.2.

 

Section 5.5           Owner-Caused Delay. In the event of (i) any interruption or delay in the Project Schedule directly caused by Owner’s failure to perform any of its other obligations under this Agreement or (ii) Contractor’s receipt of an order or instruction from Owner to suspend the Work (each, an “Owner-Caused Delay”), Contractor shall provide prompt written notice to Owner describing the particulars of such delay or failure including an estimation of the expected duration and the probable impact on the performance of Contractor’s obligations hereunder. An Owner-Caused Delay shall entitle Contractor to a Scope Change in accordance with Article 9, but only to the extent that such Owner-Caused Delay causes or contributes to a delay in Contractor’s performance of the Work.

 

Article 6
COMPLETION; COMMISSIONING AND TURNOVER

 

Section 6.1           General.

 

6.1.1      Contractor shall perform the Work to mechanically complete the WTGs, the Infrastructure Facilities and the Project, in each case in accordance with the Requirements of this Agreement, applicable manufacturers’ (including the Turbine Supplier’s) instructions and warranty requirements and any and all applicable rules as agreed to by Owner, the Contractor, and the Turbine Supplier. Owner and its Authorized Representatives shall have the right to inspect the Work and to be present during the start-up, synchronization, operation and testing of the Project pursuant to this Article 6.

 

6.1.2      Contractor shall provide Owner with ten (10) days written notice of the date on which it intends to carry out tests. The Parties shall use commercially reasonable efforts to coordinate with the scheduling of any or all such tests to reasonably accommodate the schedules of Persons whom the Owner deems necessary to attend the tests. Contractor shall notify Owner of any proposed change in the schedule of tests. Under no circumstances will the unavailability of the Owner or Owner’s representatives delay the performance of the scheduled tests for which the required notice has been provided to Owner.

 

Section 6.2          Foundation Completion. Contractor shall achieve Foundation Completion with respect to each individual Foundation and associated Infrastructure Facilities in accordance with the Requirements of this Agreement. “Foundation Completion,” with respect to an individual Foundation, means the achievement of the following milestones:

 

6.2.1      such Foundation is mechanically completed and installed in accordance with the Agreement Documents;

 

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6.2.2      such Foundation is structurally complete and contains all necessary embedded inserts;

 

6.2.3      the concrete portion of such Foundation has cured so as to have achieved the minimum strength necessary to allow assembly, erection and installation of the WTG thereon in accordance with the Agreement Documents;

 

6.2.4      backfilling of the area surrounding such Foundation has been completed per contract and lease requirements;

 

6.2.5      hard copies of red-lined drawings have been submitted to Owner;

 

6.2.6      all quality assurance documentation has been provided to, received, reviewed, and approved by Owner in accordance with the Project Quality Assurance Plan and all non-conforming quality assurance issues have been resolved in accordance with the Project Quality Assurance Plan; and

 

6.2.7      Contractor has delivered a Foundation Completion Certificate in substantially the form of Exhibit 6.2.7 with respect to such Work, subject to Owner’s verification rights as set forth in Section 6.7.

 

Section 6.3          WTG Mechanical Completion. Contractor shall achieve Mechanical Completion with respect to each WTG in accordance with the Requirements of this Agreement. “Mechanical Completion” with respect to an individual WTG means achievement of the following:

 

6.3.1      Foundation Completion with respect to the Foundation for such WTG has occurred and such WTG is designed, fabricated, assembled, erected and installed so as to be completed in accordance with the Technical Specifications, the Mechanical Completion Checklist set forth in Exhibit 6.3.1 (the “Mechanical Completion Checklist”), and the other Requirements of this Agreement, and checked for adjustment;

 

6.3.2      all materials and equipment associated with such WTG have been installed in accordance with the Technical Specifications, the Mechanical Completion Checklist, the WTG Supplier Requirements, the applicable Project Quality Assurance Plan set forth in Exhibit 2.8, and the other Requirements of this Agreement, and checked for adjustment, rotation and lubrication;

 

6.3.3      all quality assurance documentation has been provided, received, and reviewed, and approved by Owner in accordance with the Project Quality Assurance Plan and all non-conforming quality assurance issues have been resolved in accordance with the Project Quality Assurance Plan;

 

6.3.4      the WTG is ready to commence Commissioning and testing; and

 

6.3.5      Owner has accepted a Mechanical Completion Certificate with respect to such WTG.

 

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Section 6.4           Commissioning and Turnover of Electrical Works. In connection with the Pre-Commissioning or Commissioning of each WTG, Contractor shall complete such additional Work as is necessary to energize such WTG and to achieve interconnection and shall Commission the Electrical Works related thereto. Upon completion of such Electrical Works related to each WTG, Contractor shall submit a Commissioning and Turnover Certificate to Owner on a per-circuit basis with respect thereto. Contractor shall cause Commissioning and turnover to occur with respect to the Electrical Works no later than the Guaranteed Project Substantial Completion Date. “Commissioning and Turnover of Electrical Works” with respect to an individual circuit of Electrical Works and equipment associated therewith means the achievement of the following milestones:

 

6.4.1      Foundation Completion with respect to the Foundation for such WTG and all other Electrical Works foundations has occurred;

 

6.4.2      all of the Electrical Works, including the installation of all grounding, necessary to energize the WTG, are completed in accordance with the Requirements of this Agreement;

 

6.4.3      all materials and equipment associated with such Electrical Works have been installed in accordance with the Technical Specifications, the Commissioning Test and Inspection Procedures and the other Requirements of this Agreement, and checked for adjustment;

 

6.4.4      such Electrical Works and all other Infrastructure Facilities necessary to achieve Interconnection, including connection of such WTG to Transmission Provider’s electricity transmission system, are either (i) energized or (ii) immediately capable of being energized upon provision of the necessary facilities required to be furnished by Owner hereunder, if any;

 

6.4.5      all of the Electrical Works necessary to achieve connection of such WTG to the Collection Substation in accordance with this Agreement have been installed, insulated, protected and tested, including synchronization with such system;

 

6.4.6      all of such Electrical Works have been properly constructed, installed, insulated and protected where required for such operation, have been correctly adjusted, tested and Commissioned, are mechanically, electrically and structurally constructed as set forth in the Technical Specifications, and can be used safely in accordance with the Agreement Documents, Applicable Laws and Applicable Standards;

 

6.4.7      all quality assurance documentation has been provided, received, and reviewed, and approved by Owner in accordance with the Project Quality Assurance Plan and all non-conforming quality assurance issues have been resolved in accordance with the Project Quality Assurance Plan; and

 

6.4.8      Owner has accepted an Electrical Works Commissioning and Turnover Certificate with respect to such Electrical Works.

 

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Section 6.5         Project Substantial Completion. Subject to Section 11.3, Contractor shall achieve substantial completion of the Project (“Project Substantial Completion”), which shall include achievement of Commissioning and Turnover of Electrical Works and WTG Mechanical Completion with respect to all WTGs and all WTGs have been commissioned in accordance with the Commissioning Test and Inspection Procedures and all requirements set forth therein have been met or exceeded and a corresponding WTG Commissioning and Turnover Certificate has been delivered (subject to adjustment in the event Contractor exercises its Buy-Back Right pursuant to Section 11.3), and the following other items:

 

6.5.1      Contractor has delivered to Owner, and Owner has accepted, a WTG Substantial Completion Certificate for each WTG;

 

6.5.2      the requirements set forth in the Commissioning Test and Inspection Procedures have been met or exceeded;

 

6.5.3      the requirements necessary to achieve Project Substantial Completion that are set forth in all Permits have been met;

 

6.5.4      Contractor has completed all of the Work for all of the Infrastructure Facilities and has delivered to Owner copies of the test reports and electrical schematics related to Infrastructure Facilities;

 

6.5.5      Contractor has delivered to Owner the draft O&M Manuals for equipment provided by Contractor or Subcontractors located within, and not limited to, the Collection Substation, O&M Building, Collection System and Federal Aviation Administration lighting, as applicable;

 

6.5.6      Contractor has prepared and submitted to Owner the final and complete list of Punch List Items;

 

6.5.7      Contractor has delivered copies of the draft Turnover Packages and O&M Manuals that are required by Section 2.11;

 

6.5.8      drafts or red-lines of As-Built Drawings and Documentation shall have been delivered to and accepted by Owner in accordance with Section 2.5.5;

 

6.5.9      Contractor has delivered to Owner all interim or progress payment Partial Lien Waivers or final payment Final Lien Waivers, as the case may be, from all Major Subcontractors for Work completed through such date;

 

6.5.10    all quality assurance documentation has been provided, received, and reviewed, and approved by Owner in accordance with the Project Quality Assurance Plan and all non-conforming quality assurance issues have been resolved in accordance with the Project Quality Assurance Plan;

 

6.5.11    Owner has accepted a Project Substantial Completion Certificate;

 

6.5.12    All Warranty Parts Inventory and any other All Spare Parts that Owner has elected to purchase in accordance with Section 4.1.1 have been delivered by Contractor to the Project Site; and

 

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6.5.13     Contractor has assigned to Owner (a) all remaining rights under the Turbine Supply Agreement, (b) the SMA, and (c) the MPT Supply Agreement in substantially the form of Exhibit 3.1.2 hereto.

 

Section 6.6           Final Completion. Contractor shall cause Final Completion to occur. “Final Completion” means the achievement of the following:

 

6.6.1      Project Substantial Completion has occurred;

 

6.6.2      Contractor has performed all of the Work (including the clean-up and restoration of that portion of the Project Site where Contractor conducted the Work, the removal from the Project Site of all waste materials introduced or created by Contractor in the performance of the Work, the recycling or disposal of such waste material and the re-grading or re-seeding of disturbed areas where appropriate) and any Defects found have been corrected;

 

6.6.3      Owner has received a final list and summary of the work performed by all Major Subcontractors;

 

6.6.4      Owner has received a Final Lien Waiver from Contractor;

 

6.6.5      Owner has received from Contractor Final Lien Waivers from all Major Subcontractors; or, if Contractor is unable to obtain all such waivers, a bond (approved by Owner) to protect Owner, the Project and the Project Site from any and all claims made on account of such Liens;

 

6.6.6      Contractor has delivered the Turnover Packages in accordance with Section 2.11.2;

 

6.6.7      all As-Built Drawings and Documentation associated with the Work as described in this Agreement and Exhibit 2.2.2 have been delivered to and accepted by Owner in accordance with Section 2.5.5;

 

6.6.8      all quality assurance documentation has been provided to, received, and reviewed, and approved by Owner in accordance with the Project Quality Assurance Plan and all non-conforming quality assurance issues have been resolved in accordance with the Project Quality Assurance Plan;

 

6.6.9      all of Contractor’s supplies, personnel and waste have been removed from the Project Site;

 

6.6.10    Contractor has provided copies of all environmental compliance documentation including, but not limited to:

 

6.6.10.1         Construction stormwater permits, inspections reports, stabilization information, and construction stormwater permit inactivation;

 

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6.6.10.2         construction dewatering compliance documentation including discharge monitoring reports;

 

6.6.10.3         directional bore incidental fluid release reports;

 

6.6.10.4         SPCC program compliance documentation;

 

6.6.10.5         waste identification numbers/permits; spill description, cleanup, reporting and disposal documentation;

 

6.6.10.6         concrete batch plant air permits and compliance information;

 

6.6.10.7         noxious weed control compliance information; and

 

6.6.10.8         compliance documentation required for threatened, endangered, and protected species, historic and cultural compliance.

 

6.6.11    final grading of the area surrounding each Foundation is complete;

 

6.6.12    All items on the Punch List are completed; and

 

6.6.13    Owner has accepted a Final Completion Certificate.

 

Section 6.7         Achievement of Foundation Completion, Commissioning and Turnover of Electrical Works, Mechanical Completion, WTG Substantial Completion, Project Substantial Completion and Final Completion. When Contractor believes that it has achieved any of Foundation Completion, Commissioning and Turnover of Electrical Works, Mechanical Completion, WTG Substantial Completion, Project Substantial Completion or Final Completion, it shall deliver to Owner a completed Foundation Completion Certificate, Commissioning and Turnover of Electrical Works Completion Certificate, Mechanical Completion Certificate, a WTG Substantial Completion Certificate for each WTG, Project Substantial Completion Certificate or Final Completion Certificate (each a “Completion Certificate” and, collectively, the “Completion Certificates”). Such Completion Certificate shall include the results of all testing relevant to achievement of such milestone and otherwise contain a report in a form reasonably acceptable to Owner and with sufficient detail to enable Owner to determine that Contractor has achieved Foundation Completion, Commissioning and Turnover of Electrical Works, Mechanical Completion, Project Substantial Completion or Final Completion, as the case may be. Owner shall, within two (2) Business Days, in the case of a Foundation Completion Certificate or a Commissioning and Turnover of Electrical Works Completion Certificate, three (3) Business Days, in the case of a Mechanical Completion Certificate, a WTG Substantial Completion Certificate and a Project Substantial Completion Certificate and five (5) Business Days, in the case of a Final Completion Certificate, following receipt of such Completion Certificate, either (a) deliver to Contractor a countersigned Completion Certificate, indicating its acceptance of the achievement of such milestone, or (b) if cause exists for doing so, notify Contractor in writing that such milestone has not been achieved, stating in detail the reasons therefore. If Owner fails to respond to Contractor within the relevant time periods set forth in the preceding sentence, in such case Owner shall be deemed to have accepted such Completion Certificate as of the date set forth in the Completion Certificate by Contractor as to when such completion occurred. If Owner delivers the notice under the preceding clause (b), Contractor shall promptly take such action, including the performance of additional Work to achieve such milestone, and upon completion of such actions shall issue to Owner another notice with respect to such milestone pursuant to this Section 6.7. Such procedure shall be repeated as necessary until such milestone has been achieved. For the purposes of this Agreement, the date of achievement of Foundation Completion, Commissioning and Turnover of Electrical Works, Mechanical Completion, WTG Substantial Completion, Project Substantial Completion or Final Completion, as the case may be, shall the date set forth in the applicable Completion Certificate by Contractor as to when such completion occurred that Owner ultimately accepts.

 

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Section 6.8         Completion Guarantees. Contractor acknowledges and agrees that it is responsible for the achievement of Mechanical Completion and Project Substantial Completion not later than the Guaranteed Mechanical Completion Date and the Guaranteed Project Substantial Completion Date, respectively (the “Guaranteed Completion Dates”). Subject to Section 11.1, Contractor warrants that Final Completion shall be achieved not later than two (2) months after the date of Project Substantial Completion (“Guaranteed Final Completion Date”), except for Punch List Items that, by their nature, cannot be completed because of seasonal weather conditions.

 

6.8.1      Transformer Guarantees. Contractor shall use reasonable commercial efforts to include in the MPT Supply Agreement an output guarantee with respect to the MPT transformer requiring the MPT supplier to pay liquidated damages to Owner for No-Load losses at [**] (the “Transformer Guarantees”) in the event that the actual losses of the MPT are below the guaranteed levels set forth in Exhibit 2.2.2- Part 3. In the event the MPT Supply Agreement does not contain an output guarantee equal to or better than the Transformer Guarantees, Contractor shall pay to Owner, as liquidated damages and as Owner’s sole, exclusive and final remedy for such failure, the difference, on a $/kW basis, between the output guarantees included in the MPT Supply Agreement and the Transformer Guarantees. Upon Project Substantial Completion, Contractor shall assign the MPT Supply Agreement to Owner. Upon the effective date of the assignment of the MPT Supply Agreement, if the MPT Supply Agreement contains the Transformer Guarantees, Owner shall look solely to its remedies under the MPT Supply Agreement for enforcement of the Transformer Guarantees. If the MPT Supply Agreement does not contain the Transformer Guarantees, Contractor shall continue to be liable for any liquidated damages payable to Owner as a result of any breach of the Transformer Guarantees.

 

Section 6.9          Delay Liquidated Damages. If Contractor has not achieved Project Substantial Completion by the Guaranteed Project Substantial Completion Date (as such date may be extended pursuant to Article 8 as a result of the occurrence of a Force Majeure Event or the occurrence of a Scope Change pursuant to Article 9), Contractor shall pay to Owner, as liquidated damages and as Owner’s sole and exclusive remedy for such late completion, [**] ($[**]) per incomplete WTG per Day following the Guaranteed Project Substantial Completion Date until the date that Contractor delivers to Owner a WTG Substantial Completion Certificate that is accepted by Owner (“Delay Liquidated Damages”); provided, however, in the event that Contractor achieves Project Substantial Completion within a period of sixty (60) Days after the Guaranteed Project Substantial Completion Date, then Owner will refund to Contractor all Delay Liquidated Damages that have been paid by Contractor. Delay Liquidated Damages shall be due and payable in weekly installments beginning with the seventh (7th) Day following the first (1st) Day after the Guaranteed Project Substantial Completion Date. Subject to the provisions set forth in Section 11.1, Contractor shall continue to make such payments of Delay Liquidated Damages for each incomplete WTG until achievement of Project Substantial Completion, at which time Contractor shall pay all previously accrued and unpaid Delay Liquidated Damages amounts. Any Delay Liquidated Damages not paid when due shall bear interest at a rate calculated in accordance with Section 4.8. In no event shall the payment of Delay Liquidated Damages excuse Contractor from performance of any of its other obligations hereunder, including the obligation to cause Project Substantial Completion to occur.

 

______________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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Article 7
WARRANTIES

 

Section 7.1           Infrastructure Facilities Warranty.

 

7.1.1      Infrastructure Facilities Warranty. Contractor warrants during the Infrastructure Facilities Warranty Period (with the exception of any Work for which the warranty provisions of Section 7.2 shall apply) that:

 

7.1.1.1           all parts, materials, equipment and the like incorporated into the Infrastructure Facilities to be delivered hereunder shall be free of Defects in material, workmanship and title, and shall be new, unused and undamaged and of suitable grade that is consistent with Prudent Industry Practices when installed (except as otherwise agreed to in advance in writing by Owner); and

 

7.1.1.2           the Construction Services shall be performed with due care, skill and in a competent, diligent manner in accordance with Applicable Law and Applicable Standards.

 

Sections 7.1.1.1, and 7.1.1.2, are collectively, “Infrastructure Facilities Warranty.”

 

7.1.2      Infrastructure Facilities Warranty Period.

 

7.1.2.1           The Infrastructure Facilities Warranty shall commence on the Project Substantial Completion Date.

 

7.1.2.2            All such Infrastructure Facilities Warranties shall continue until and expire upon the second (2nd) anniversary of the Project Substantial Completion Date (the “Infrastructure Facilities Warranty Period”). In addition, if any component is repaired pursuant to the Infrastructure Facilities Warranty, then the Infrastructure Facilities Warranty Period with respect to such component shall continue until the later of: (a) the expiration of the Infrastructure Facilities Warranty Period; or (b) two (2) years from the date of completion of such repair; but in no event shall such additional warranty extend for more than three (3) years from the Project Substantial Completion Date.

 

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7.1.3      Corrections of Deficiencies. If a Defect occurs during the Infrastructure Facilities Warranty Period, Owner shall notify Contractor in writing of such Defect within fifteen (15) Business Days after discovery of such Defect. Upon such notice, the Contractor, at its sole cost and expense, shall repair or, at its option, replace, or take other appropriate corrective action so as to cause the Defective Work to conform to the Requirements of this Agreement (“Infrastructure Facilities Warranty Service”). Owner shall have the right to operate and otherwise use the Work until such time that Owner, in consultation with Contractor, reasonably establishes it is prudent to suspend such operation or use for repair by Contractor, provided that Owner shall be responsible for the cost of any additional repairs resulting from any delay it seeks and provided further that in no event may Owner delay Contractor from repairing any such Work for more than ninety (90) Days from Owner’s notice to Contractor of such Defect. If the Defective Work has been placed in service, subject to the foregoing limitations, Owner shall, in consultation with Contractor, reasonably establish an appropriate time for Owner to remove the Defective Work from service for any Infrastructure Facilities Warranty Service by Contractor, even if the Infrastructure Facilities Warranty Period expires prior to the removal of such Defective Work from service. If Owner becomes aware during the Infrastructure Facilities Warranty Period of any operational abnormality that reasonably could indicate that Defective Work exists, Owner shall notify Contractor, and Contractor will have five (5) Days to recommend whether such Defective Work should be removed from service. If Contractor reasonably recommends in a notice to Owner that Owner remove the Defective Work from service and Owner continues to operate the Defective Work against the reasonable recommendation of Contractor after Contractor so notifies Owner, Owner shall assume the risk of any further damage or Defects that result from such continued operation. Neither payment by Owner nor partial or entire use or possession of the Work by Owner shall relieve Contractor of liability with respect to the Infrastructure Facilities Warranty contained in this Article 7. An analysis of the cause of a Defect shall be performed by Contractor in accordance with the Requirements of this Agreement, if a Defect occurs that could (1) impact safety of a worker or a member of the public, (2) result in an insurance claim or (3) have a cost impact of greater than [**] ($[**]). Contractor shall make the report of such analysis available to Owner reasonably promptly after its completion. Contractor shall not be excused from performing such Infrastructure Facilities Warranty Service after the end of the Infrastructure Facilities Warranty Period, if it receives notice of the Defect or breach of Infrastructure Facilities Warranty before or during the Infrastructure Facilities Warranty Period.

 

7.1.4      Risk of Loss or Damage. Whenever Infrastructure Facilities Warranty Service is required pursuant to this Article 7, Contractor shall bear the risk of loss or damage to the Work requiring repair during the period of such repair. If and to the extent any of the Work must be removed from the Project Site for purposes of any such repair, the transportation charges associated with any such repair shall be borne by Contractor.

 

________________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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7.1.5        Exclusions from Infrastructure Facilities Warranty. The Infrastructure Facilities Warranty set forth in this Section 7.1 shall not apply to:

 

7.1.5.1           normal wear and tear, including that due to environment or operation;

 

7.1.5.2           damage to any equipment to the extent such damage is caused by (a) Owner’s or its agent’s or operator’s (not including any Affiliate of Contractor) improper storage, operation or maintenance of the Infrastructure Facilities, or (b) Owner’s or its agent’s or operator’s (not including any Affiliate of Contractor) failure to conform to the operating instruction manuals (including revisions thereto) provided by the Contractor and/or its Subcontractors, as applicable;

 

7.1.5.3           the use of parts or consumables in the repair or maintenance of such equipment that are not in accordance with reasonable and practical specifications and recommendations set forth in the O&M Manuals;

 

7.1.5.4           any Force Majeure Event;

 

7.1.5.5           normal operating consumables or items that require replacement due to normal wear and tear or casualty loss (other than as a result of a failure under the Infrastructure Facilities Warranty); and

 

7.1.5.6           the WTGs, except to the extent related to a Defect in the performance of Construction Services.

 

7.1.6         Exclusive Remedy. This Section 7.1 sets forth Owner’s exclusive remedies with respect to the Infrastructure Facilities Warranty.

 

7.1.7         Delay. Contractor shall submit to Owner an action plan after being notified by Owner of a claim under the Infrastructure Facilities Warranty no later than twenty-one (21) days after such notice. If, after notification of a claim under the Infrastructure Facilities Warranty, Contractor shall delay past such date for submission of an action plan to address such claim with respect to such Defect or breach of Infrastructure Facilities Warranty, then Owner may correct or have others correct such Defect or breach of Infrastructure Facilities Warranty so that the Work complies with the Requirements of this Agreement, and Contractor shall be liable for all costs, charges and expenses incurred by Owner in connection with such correction and shall forthwith pay to Owner an amount equal to such costs, charges and expenses within thirty (30) Days after Contractor’s receipt of an invoice from Owner therefore (including reasonable supporting documentation). Contractor reserves its right to investigate and determine the eligibility of such warranty claims. If Owner has independently undertaken a warranty repair pursuant to this section, then within a reasonable period of time after the occurrence of such warranty repair, Owner shall issue to Contractor:

 

7.1.7.1           a failure report, which shall contain technical and logistical information in sufficient detail to enable Contractor to evaluate (1) Owner’s representation that repair of a defect is a warranty repair and not a standard maintenance activity or Defect caused by lack of regular maintenance consistent with Prudent Industry Practices, and (2) the appropriateness of the Owner’s corrective action; and

 

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7.1.7.2           copies of invoices received or prepared for costs and expenses claimed by Owner for reimbursement by Contractor (but only if such Owner work is due to a Defect in the Work). Work performed by Owner in relation to a warranty repair under this Section shall be billed on a “Time and Materials” basis.

 

Section 7.2            WTG Warranties. The warranty for the WTGs (the “WTG Warranty”) is set forth exclusively in the Turbine Supply Agreement. In the event Contractor does not enforce or pursue a justifiable (as reasonably determined by Owner) WTG Warranty claim against Turbine Supplier in accordance with the Turbine Supply Agreement prior to Project Substantial Completion, Owner shall have the right to require Contractor to pursue such claim; and in the event Contractor does not promptly do so, then Owner shall be entitled to pursue such claim on Contractor’s behalf and Contractor shall reimburse Owner for all reasonable costs and expenses incurred in such enforcement. Upon the effective date of an assignment of the Turbine Supply Agreement, Contractor shall be released from all of its WTG Warranty obligations hereunder, and Owner shall look solely to its remedies under the Turbine Supply Agreement for enforcement of WTG Warranty rights.

 

Section 7.3            Subcontractor Warranties. Contractor shall have the right and agrees to enforce the warranties of all Subcontractors during the Infrastructure Facilities Warranty Period. Any Subcontractor warranties, but not including the warranties of the Turbine Supplier, that are still in existence at the end of such Infrastructure Facilities Warranty Period shall be assigned on such date to Owner and Contractor shall ensure that the terms and conditions of such Subcontract allow for such assignment. Contractor shall use its good faith efforts to cause its Subcontractors to acquire assignable warranties from their vendors and to assign such warranties to Owner.

 

Section 7.4            General Limitations on Warranties and Remedies. The rights and remedies set forth in this Article 7 are Owner’s exclusive remedies for all claims based on breach of the warranties provided in this Article 7. No failure on the part of Owner in exercising any right shall operate as a waiver thereof. THE GUARANTEES AND WARRANTIES SET FORTH IN THIS ARTICLE 7 ARE EXCLUSIVE AND IN LIEU OF ALL OTHER WARRANTIES, EXPRESS OR IMPLIED. NO IMPLIED STATUTORY WARRANTY OF MERCHANTABILITY, OR FITNESS FOR A PARTICULAR PURPOSE SHALL APPLY. THERE ARE NO OTHER WARRANTIES, AGREEMENTS, OR UNDERSTANDINGS, WRITTEN OR ORAL, MADE BY OR BINDING UPON CONTRACTOR WITH RESPECT TO THE PROJECT THAT EXTEND BEYOND THOSE SET FORTH IN THIS ARTICLE 7 OR AS PROVIDED IN THE ASSET PURCHASE AGREEMENT. FOR THE AVOIDANCE OF DOUBT, CONTRACTOR MAKES NO WARRANTY IN RELATION TO THE OUTPUT OF THE PROJECT.

 

Article 8
FORCE MAJEURE

 

Section 8.1            Performance Excused. If either Party is rendered wholly or partially unable to perform its obligations under the Agreement Documents due to a Force Majeure Event, that Party shall be excused from whatever performance is affected by the Force Majeure Event to the extent so affected, and the Guaranteed Completion Dates and Milestones set forth in the Project Schedule so affected shall be extended and such Project Schedule shall be updated; provided, that:

 

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8.1.1           the Party claiming a Force Majeure Event shall give the other Party prompt notice describing the particulars of the cause and nature of the occurrence. The Party claiming a Force Majeure Event shall give the other Party sufficient proof of the occurrence of such Force Majeure Event and notice estimating the Force Majeure Event’s expected duration and probable impact on the performance of such Party’s obligations hereunder, and such affected Party shall continue to furnish timely regular reports with respect thereto during the continuation of the Force Majeure Event or its impact on the affected Party’s performance;

 

8.1.2           no breach or default of either Party which arose before the occurrence of the Force Majeure Event causing the suspension of performance shall be excused as a result of the occurrence, but so long as the affected Party shall have commenced and is diligently continuing to attempt to cure such default prior to the occurrence of the Force Majeure Event, the cure period (if any) provided in this Agreement with respect to such default shall be extended on a Day-for-Day basis to the extent a cure actually is prevented as a result of the Force Majeure Event;

 

8.1.3           the suspension of performance shall be of no greater scope and of no longer duration than is reasonably required by the Force Majeure Event;

 

8.1.4           the affected Party shall exercise all reasonable efforts to mitigate or limit damages to the other Party;

 

8.1.5           the affected Party shall exercise commercially reasonable efforts to alleviate and mitigate the cause and effect of such Force Majeure Event, remedy its inability to perform, and limit damages to the other Party;

 

8.1.6           the affected Party shall use all reasonable efforts to continue to perform its obligations hereunder and to limit, correct or cure the event or condition excusing performance; and

 

8.1.7           when the affected Party is able to resume performance of the affected obligations under the Agreement Documents, that Party shall give the other Party written notice to that effect, a Scope Change Order shall be executed pursuant to Section 9.9 to account for the actual effect, if any, on the affected Party’s performance of its obligations by the Force Majeure Event, and the affected Party promptly shall resume performance under the Agreement Documents; and

 

8.1.8           Unless Owner elects in writing, in the form of a Scope Change Order, to require Contractor to accelerate its schedule, Contractor shall not be entitled to an adjustment of the Agreement Price based on any Force Majeure Event; except that if one or more Force Majeure Events render Contractor unable to perform (and Contractor is excused, in accordance with the foregoing provisions of this Section 8.1, from its non-performance of) any material Work at the Project Site for an aggregate amount of time that exceeds three (3) Days (“Extended Force Majeure Event”), Contractor shall be entitled to an adjustment to the Agreement Price to reflect additional costs and expenses incurred or to be incurred by Contractor as a result of such Extended Force Majeure Event. The adjustment to the Agreement Price caused by an Extended Force Majeure Event shall be offset by any insurance proceeds available (to Contractor or Owner) as a result of the Extended Force Majeure Event.

 

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8.1.9       Owner-Caused Delay. In the event Contractor claims an Owner-Caused Delay, Contractor shall give Owner written notice describing the details of the Owner-Caused Delay, the anticipated length of such delay and any other effect on Contractor’s performance of its obligations hereunder. Contractor shall provide to Owner reasonable evidence of the occurrence and duration of such Owner-Caused Delay. So long as the conditions set forth in this Section 8.1.9 are satisfied, Contractor shall not be responsible or liable for or deemed in breach of this Agreement because of any failure or delay in completing the Work in accordance with the Project Schedule or achieving any Guaranteed Completion Date if and to the extent that such failure has been caused by one or more Owner-Caused Delays, provided that (i) such suspension of performance and extension of time shall be of no greater scope and of no longer duration than is required by the effects of the Owner-Caused Delay, and (ii) Contractor provides all assistance reasonably requested by Owner for the elimination or mitigation of the Owner-Caused Delay. In the event Contractor claims an Owner-Caused Delay, it shall be entitled to a Scope Change pursuant to Section 9.10 and Contractor shall be entitled to suspension of performance or extension of time (including an extension of the Guaranteed Completion Dates), together with an increase in the Agreement Price equal to its demonstrated, justified and reasonable additional costs incurred by reason of such delay plus an aggregate amount of ten percent (10%) for overhead and profit, to the extent agreed upon by both Parties pursuant to a Scope Change Order in accordance with Article 9.

 

Section 8.2           Disputes; Burden of Proof. If Owner and Contractor are unable in good faith to agree that a Force Majeure Event or an Owner-Caused Delay has occurred, either Party may submit the dispute to the applicable dispute resolution process provided for under Article 15.

 

Article 9
SCOPE CHANGES

 

Section 9.1           Scope Changes. A “Scope Change” means any addition to, deletion from, suspension of or other modification to the quality, function or intent of the Project as delineated in the Scope of Work, or a change to the Requirements of this Agreement. It is the intent of Owner and Contractor that the Scope of Work specified in Exhibit 2.2.2 includes all items necessary for the proper execution and completion of the Work. A Scope Change shall not effect a change to the essential nature of the Project. If either Owner or Contractor believes a Scope Change is necessary, it shall proceed as set forth in this Article 9; except that, notwithstanding anything in this Article 9 to the contrary, no Scope Change, or any adjustment of the Agreement Price or the Project Schedule, shall be made as a result of any errors, negligence, willful and wanton misconduct, intentional misconduct, deficiencies, or improper or defective work on the part of Contractor or any Subcontractor or as a result of any failure of Contractor to perform its obligations under this Agreement.

 

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Section 9.2           Scope Change by Owner. Owner may, from time to time, without invalidating this Agreement, order or approve a Scope Change (a) in the construction or features of the Infrastructure Facilities, (b) in all or a portion of any other components or aspects of the Work, or (c) in the Project Schedule in which event the Agreement Price or the Project Schedule shall be adjusted accordingly, if necessary, as agreed by Owner and Contractor. Contractor shall reasonably review and consider such requested Scope Change and shall make a written response thereto within seven (7) Days after receiving such request. If Contractor believes that giving effect to any Scope Change requested by Owner will increase or decrease its cost of performing the Work, shorten or lengthen the time needed for completion of the Work, require modification of its warranties in Article 7 or require a modification of any other provisions of this Agreement, its response to the Scope Change request shall set forth such changes (including any amendments to this Agreement) that Contractor deems necessary as a result of the requested Scope Change and its justification therefor. If Contractor accepts the Scope Changes requested by Owner (together with any amendments to this Agreement specified therein) or if the Parties agree upon a modification of such requested Scope Changes, the Parties shall set forth the agreed upon Scope Change in the Work and agreed upon amendments to this Agreement, if any, in a Scope Change Order.

 

Section 9.3           No Unapproved Scope Changes. Contractor shall not perform any Scope Changes nor shall Contractor be entitled to undertake any change to the Work until Owner has approved in writing the proposed adjustments. Upon receiving from Owner such written approval or such written authorization to perform, Contractor shall diligently perform the Scope Change in accordance with and subject to all of the terms of this Agreement. Any technical or engineering dispute between Owner and Contractor with respect to any Scope Change Order shall be resolved in accordance with Article 15.

 

Section 9.4           Required Scope Changes. If any of the following events occurs, Owner shall issue a Scope Change Order to Contractor, in each case to the extent the event results in increased costs or delays to Contractor in achieving the Milestones by the dates identified in Exhibit 2.4.1:

 

9.4.1       a Scope Change ordered by Owner as described in Section 9.2;

 

9.4.2       an Owner-Caused Delay (as described under Section 5.5) occurs;

 

9.4.3       a Concealed Subsurface Condition arises pursuant to Section 9.8;

 

9.4.4       a Scope Change Order is allowed in accordance with Section 3.3;

 

9.4.5       a Change in Law occurs;

 

9.4.6       a relocation of underground utilities as set forth in Section 2.10.1;

 

9.4.7       a Force Majeure Event occurs, as more particularly set forth in Section 9.9 (provided that Contractor shall only be entitled to a Scope Change Order for both schedule delays and increased costs associated with an Extended Force Majeure Event pursuant to Section 8.1.8, or if

 

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9.4.8      Turbine Supplier incurs a “Force Majeure Event” as defined in the Turbine Supply Agreement that affects Turbine Supplier’s performance of its obligations under the Turbine Supply Agreement, but otherwise shall be entitled to a Scope Change Order. The relief granted by Owner in the Scope Change Order shall be the same relief granted to Turbine Supplier under the Turbine Supply Agreement.

 

Section 9.5           Authorization for Scope Change. Contractor agrees that any extra work shall be performed only if Contractor has been so instructed in writing by Owner’s Authorized Representative via a Scope Change Order. Contractor shall not bill and Owner shall not pay claims for extra work unless the work is covered by a Scope Change Order. Contractor shall not have the right or the power to prosecute or maintain action in court to recover for extra work unless the claim is based upon a written Scope Change Order from Owner.

 

Section 9.6           Agreement on Firm or Unit Prices. When a modification increases the amount of the Work, the payment for the extra work may be based on an agreed to firm or unit price. Contractor shall submit a proposal to Owner on which it seeks agreement before the extra work is started. The proposal shall include a breakdown of costs including labor, materials, equipment, overhead and margin. The proposal shall indicate itemized quantities and charges for all elements of cost. This itemization shall include a listing by craft of the direct labor charges excluding percentage markups for overhead and margin.

 

Section 9.7           Absence of Agreement on Firm or Unit Prices. If no price is agreed to, but the Parties otherwise agree to the type and character of the work in a Scope Change Order, then except for any change in the Work to be supplied or performed by Turbine Supplier under the Turbine Supply Agreement (which change order shall only be made in accordance with the provisions of the Turbine Supply Agreement), payments for extra work will be based on the following:

 

9.7.1       Total direct labor costs including straight time labor, payroll taxes and insurance and fringe benefits incurred by Contractor plus 10% for overhead, plus 10% for margin.

 

9.7.2       Material or subcontracted work shall be invoiced at Contractor’s direct cost with a 10% markup overhead and a 10% markup for profit.

 

9.7.3       Markup percentages stated in this Section are inclusive of, but not limited to, all field and home office overhead expenses, salaried supervision, support facilities, small tools, etc.

 

Section 9.8           Scope Changes Due to Concealed Subsurface Conditions. Immediately upon discovery, Contractor shall notify Owner in writing of (i) subsurface or latent physical conditions at the Project Site differing materially from those indicated in this Agreement, (ii) the discovery of fossils, archeological remains or any other object of cultural significance, or (iii) previously unknown physical conditions at the Project Site of an unusual nature or differing materially from those ordinarily encountered and generally recognized as inherent in work of the character provided for in this Agreement (collectively, “Concealed Subsurface Conditions”). Concealed Subsurface Conditions shall not include conditions handled or mitigated by Contractor utilizing equipment planned to perform that component of the Work within a reasonable period of time. Contractor will take all reasonable steps to mitigate the impacts of Concealed Subsurface Conditions. Contractor shall take all reasonable steps to secure Concealed Subsurface Conditions, including fencing and avoiding further disturbance and shall at all-time comply with Applicable Laws. Upon notification, Owner shall promptly investigate the conditions, and Contractor shall be entitled to a Scope Change Order.

 

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Section 9.9           Scope Changes Caused by a Force Majeure Event. If Contractor’s performance hereunder is wholly or partially prevented due to the occurrence of a Force Majeure Event affecting Contractor and such Force Majeure Event has caused an extension of any guaranteed date under this Agreement or any other date under the Project Schedule as provided in Section 8.1, Contractor shall provide to Owner a written description of Contractor’s plan to make up Days lost under the Project Schedule due to the occurrence of such Force Majeure Event, including an estimate of the costs for such plan. To the extent that Owner desires to pay for the costs of acceleration of the Work or change to the Project Schedule set forth in Contractor’s proposal in order to compensate for delays in the Work caused by such Force Majeure Event, Owner may authorize a Scope Change Order increasing the Agreement Price and adjusting the Project Schedule (in addition to any automatic adjustments of Guaranteed Completion Dates hereunder). In addition, to the extent Contractor incurs or will incur additional out-of-pocket costs and expenses as a result of an Extended Force Majeure Event, Owner shall issue a Scope Change Order increasing the Agreement Price to include such increased out-of-pocket costs and expenses (without any mark-up by Contractor). Notwithstanding anything to the contrary, (a) to the extent Contractor is compensated for the effect of a Force Majeure Event by insurance maintained pursuant to Article 12, or (b) to the extent Owner would have been so compensated but for Contractor’s failure to provide such insurance as required under Article 12, Contractor shall not be entitled to a Scope Change Order in the Agreement Price in connection with such Scope Change Order issued for such Extended Force Majeure Event. Nothing contained in this Section 9.9 shall affect Contractor’s obligations under Article 8 in respect of the occurrence of any Force Majeure Event.

 

Section 9.10         Owner-Caused Delays. Owner-Caused Delays shall entitle Contractor to a change to the Agreement Price, in accordance with Section 8.1.9, and if applicable, an extension of time hereunder. Any extension permitted under this Section shall be of an equitable duration designed to reflect the delay actually caused by the relevant Owner-Caused Delay.

 

Section 9.11         Weather Delay Days. Contractor’s relief for any Weather Delay Day shall be limited to a one-day extension for each Full Weather Delay Day (or accumulation of Half Weather Delay Days that equate to a full Weather Delay Day) that actually delays the Guaranteed Project Substantial Completion Date and an adjustment in the Agreement Price through a Scope Change Order in an amount equal to the actual out-of-pocket expenses (calculated on a time and materials basis pursuant to the Contractor’s Time and Materials Rates set forth in Exhibit 9.11) incurred by Contractor from a Weather Delay Day; provided, that in no case shall Contractor be entitled to reimbursement of costs in excess of [**] ($[**]) per Day for a Weather Delay Day (unless more than two (2) main erection cranes and crews are located at the Site and idled during topping operations on such Weather Delay Day, in which case Contractor shall be entitled to reimbursement of such costs of up to [**] ($[**]) per Day); provided further, that Contractor shall not be entitled to any relief for a Weather Delay Day unless the wind speeds and other unusually severe weather conditions required for qualification of a Weather Delay Day are substantiated by Contractor on the scheduled work day next following the claimed Weather Delay Day. Except as provided in the preceding sentence, Contractor’s relief shall not include any increase in the Agreement Price or other additional compensation; and Contractor acknowledges that it has assumed the economic risk for delays caused by twenty (20) Weather Delay Days and has included an amount in the Agreement Price to cover for this risk. As noted above, Contractor has also incorporated into the Project Schedule the time necessary to experience of up twenty (20) Weather Delay Days for the various phases of the WTG installation, in aggregate, before the Project Schedule would be adversely impacted.

 

_______________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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Article 10
INDEMNIFICATION

 

Section 10.1         Indemnities.

 

10.1.1    Contractor’s General Indemnity. Contractor shall defend, indemnify and hold harmless Owner, Owner’s Representative and Owner’s subsidiaries and Affiliates, and the directors, officers, agents, employees, successors and assigns of each of them (each, an “Owner Indemnified Party”) from and against any and all third party losses of any character, type or description, including, but not limited to, all expenses of litigation, court costs and reasonable attorney’s fees, for injury or death to any person or damage to any property, to the extent caused by Contractor’s breach or default under this Agreement and any negligent act or omission (including strict liability), gross negligence or willful misconduct of Contractor, its Subcontractors, agents or employees, including but not limited to (a) relating to injury to or death of any Person, including employees of Contractor; or (b) resulting from loss or damage to property. Owner shall have no liability for, and Contractor agrees to indemnify, defend and hold Owner harmless against and from, any and all damages, losses, liabilities, claims, litigation, demands, proceedings, judgments, or suits of any kind or of any nature whatsoever (including, without limitation, reasonable attorney’s, consultants’ and experts’ fees and disbursements incurred in investigating, defending against, settling or prosecuting any claim, litigation or proceeding) which may at any time be imposed upon, incurred by or asserted or awarded against Owner arising out of or relating to the presence of any Hazardous Materials (other than Pre-Existing Hazardous Materials) which are released, generated, or discharged by Contractor or any of its subcontractors, agents, or employees in connection with the Project. Contractor’s indemnification obligations hereunder are not limited by insurance coverage.

 

________________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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10.1.2       Contractor’s Infringement Indemnity.

 

10.1.2.1           Prior to Project Substantial Completion, Contractor shall enforce for the benefit of Owner (at Contractor’s cost) the patent and intellectual property indemnity of the Turbine Supplier included in the Turbine Supply Agreement. Effective upon Project Substantial Completion, or any earlier termination of this Agreement, Contractor shall assign to Owner all rights with respect to such patent indemnity, and thereafter Owner shall be responsible for the enforcement thereof, provided that Contractor shall provide reasonable assistance to Owner as requested by and at the expense of Owner. Contractor’s indemnification obligations hereunder are not limited by insurance coverage

 

10.1.2.2           With respect to all Work (other than the WTGs), Contractor shall indemnify, defend, and hold each Owner Indemnified Party free and harmless from all losses, claims, liens, demands and causes of action of any kind and costs thereof, including judgments, penalties, interest, court costs and reasonable attorney’s fees incurred by or assessed against any Owner Indemnified Party on account of any claim of infringement of any United States or European Union patent, copyrighted or uncopyrighted work, secret process, trade secret, unpatented invention, or other intellectual property right related to or arising from Contractor’s performance under this Agreement. In addition, and in all such cases where the continued use of any item for the purpose intended is forbidden by any court of competent jurisdiction, Contractor shall at its option either (i) procure for Owner, or reimburse Owner for procuring, the right to continue using the infringing item, (ii) modify the infringing item so that it becomes non-infringing, or (iii) replace the infringing item with a non-infringing item; provided that in no such case shall Contractor take any action which demonstrably adversely affects Owner’s continued use and enjoyment of the Project without the prior written consent of Owner. This paragraph shall not apply to claims of infringement to the extent that the specific selection of the infringing process, material or equipment was made by Owner. Contractor’s indemnification obligations hereunder are not limited by insurance coverage.

 

10.1.3       Specific Indemnity. Contractor agrees to indemnify, defend and hold any Owner Indemnified Party harmless from and against all fines, penalties, related costs and expenses of any character, type or description, including, but not limited to, all expenses of litigation, court costs and attorney’s fees attributable to any failure of Contractor or Subcontractors to comply with all Applicable Laws and Permits in connection with the performance of the Work. Contractor’s indemnification obligations hereunder are not limited by insurance coverage.

 

10.1.4       Owner Indemnity. Owner shall protect, defend, indemnify and hold harmless Contractor, Contractor’s engineers and Subcontractors, and their respective partners and their parent corporations, subsidiaries and Affiliates, agents, officers, directors and employees (each, a “Contractor Indemnified Party”) from and against any and all third party Losses of any character, type or description, including, but not limited to, all expenses of litigation, court costs and reasonable attorney’s fees, for injury or death to any person or damage to any property, to the extent caused by the Owner’s breach or default under this Agreement and any negligent acts or omissions (including strict liability), gross negligence or willful misconduct of Owner, its subcontractors, agents or employees, arising out of this Agreement, including but not limited to (a) relating to injury to or death of any Person, including employees of Owner; or (b) resulting from loss or damage to property. Contractor shall have no liability for, and Owner agrees to indemnify, defend and hold Contractor harmless against and from, any and all damages, losses, liabilities, claims, litigation, demands, proceedings, judgments, or suits of any kind or of any nature whatsoever (including, without limitation, reasonable attorney’s, consultants’ and experts’ fees and disbursements incurred in investigating, defending against, settling or prosecuting any claim, litigation or proceeding) which may at any time be imposed upon, incurred by or asserted or awarded against Contractor arising out of or relating to the presence of any Hazardous Materials which are released, generated, or discharged by Owner or any of its subcontractors, agents, or employees in connection with the Project.

 

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10.1.5           Indemnification Procedure. When required to indemnify any Contractor Indemnified Party or Owner Indemnified Party or any other Person entitled to indemnification under Section 10.1 (“Indemnified Party”), the Party providing the indemnity (the “Indemnifying Party”) shall assume on behalf of such Indemnified Party and conduct with due diligence and in good faith the defense of any claim against such party, whether or not the Indemnifying Party shall be joined therein, and the Indemnified Party shall cooperate with the Indemnifying Party in such defense. The Indemnifying Party shall have charge and direction of the defense and settlement of such claim; provided, however, that without relieving the Indemnifying Party of its obligations hereunder or impairing the Indemnifying Party’s right to control the defense or settlement thereof, the Indemnified Party may elect to participate through separate counsel in the defense of any such claim, but the fees and expenses of such counsel shall be at the expense of such Indemnified Party unless (a) the employment of counsel by such Indemnified Party shall have reasonably concluded that there exists a material conflict of interest between the Indemnifying Party and such Indemnified Party in the conduct of the defense of such claim (in which case the Indemnifying Party shall not have the right to control the defense or settlement of such claim, on behalf of such Indemnified Party) or (b) the Indemnifying Party shall not have employed counsel to assume the defense of such claim within a reasonable time after notice of the commencement thereof. In each of such cases the fees and expenses of counsel shall be at the expense of the Indemnifying Party. The amount of any indemnity payment made under Section 10.1 shall be reduced by the amount of all insurance proceeds received by the Indemnified Party in respect of the event giving rise to the right of indemnity under Section 10.1. All payments made in respect of indemnities provided under this Article 10 shall be made on an After-Tax Basis.

 

10.1.6           Minimum Indemnity Claims. Notwithstanding anything to the contrary, no claim for indemnity shall be brought pursuant to this Article 10 until the total loss, damages or expenses incurred or suffered by the Indemnified Party hereunder exceeds $[**] in the aggregate, and then only to the extent such claim exceeds such $[**] threshold.

 

10.1.7           Survival of Indemnities. The indemnities set forth in this Article 10 shall expire and the Parties shall have no further liability under this Article 10 four (4) years after the date of Project Substantial Completion.

 

_____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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Article 11
LIMITATION OF LIABILITY

 

Section 11.1          Contractor Delay Liquidated Damages Cap. Contractor’s liability under this Agreement for Delay Liquidated Damages will be limited to [**] ($[**]).

 

Section 11.2          Contractor’s Aggregate Liability Cap. Notwithstanding any other provision of this Agreement, the aggregate amount of damages Owner shall be entitled to receive from Contractor (including, but not limited to, any damages to which Owner may be entitled as Delay Liquidated Damages as set forth in Section 6.9 or as otherwise set forth herein, and/or as a result of Contractor Defaults as set forth in Section 13.1, and/or for warranty obligations as set forth in Article 7, and/or under breach of contract, breach of warranty, and/or any other theory at law or in equity), shall be limited to [**]; provided, however, that Contractor’s liability for fraud, intentional misconduct, or diversion of one or more WTGs (by Contractor) covered under the Turbine Supply Agreement from the Project, or indemnity liability pursuant to Section 10.1 for third party Losses, shall be limited to [**].

 

Section 11.3         Contractor Buy-Back Right. With respect to any WTG that has not achieved Mechanical Completion and Commissioning and Turnover of Electrical Works before January 1, 2020, Contractor shall have One Hundred and Eighty (180) Days from the Guaranteed WTG Mechanical Completion Date to cause any such WTG to achieve Mechanical Completion and Commissioning and Turnover of Electrical Works (the “WTG Cure Period”). Following the expiration of such WTG Cure Period, the Parties shall work together and negotiate to arrive at a mutually agreeable resolution of Contractor’s failure to achieve Mechanical Completion. If the Parties fail to agree on a mutually agreeable resolution, Contractor shall have the right, but not the obligation, to buy back (the “Buy-Back Right”) up to seven (7) WTGs, at a price equal to (i) [**] ($[**]) per WTG for the first three (3) WTGs repurchased by Contractor or (ii) [**] ($[**]) per WTG for each WTG repurchased by Contractor thereafter up to the seven (7) WTG limit (the “Buy-Back Amount”), as applicable. Notwithstanding the foregoing, in the event Owner has not paid Contractor any amount related to a WTG with respect to which Contractor exercises its Buy-Back Right, the Buy-Back Amount shall be reduced by such unpaid amount. The payment of the Buy-Back Amount shall be made by Contractor to Owner on or before July 30, 2020. If Contractor exercises its Buy-Back Right with respect to any WTG, Contractor shall, at Contractor’s cost, remove any such WTG from the Project Site (if applicable) and restore any impacted property to its pre-construction condition within ninety (90) days of exercising such Buy-Back Right.

 

Section 11.4          PTC Liquidated Damages. In addition to Delay Liquidated Damages payable pursuant to Section 6.9, with respect to any WTG that does not achieve WTG Substantial Completion prior to the later of (i) January 1, 2021 and (ii) the Guaranteed Project Substantial Completion Date (as may be modified in accordance with Section 5.5 and Article 9 of this Agreement) and that Contractor does not buy back pursuant to Section 11.3, Contractor shall pay Owner liquidated damages in an amount equal to [**] ($[**]) per each such WTG (“PTC Liquidated Damages”) unless, prior to January 1, 2024, there is a Final IRS Determination that 100% PTCs are allowable with respect to each such WTG, and subject to adjustment in accordance with Schedule 11.4. Such PTC Liquidated Damages shall be due and payable on January 2, 2024. As provided in Schedule 11.4, in no event will PTC Liquidated Damages be payable with respect to lost PTCs to the extent Sellers have indemnified Owner pursuant to Section 9.2(c) of the Asset Purchase Agreement for the same lost PTCs. The Owner shall keep Contractor fully and timely informed by written notice of any audit, administrative or judicial proceedings, meetings or conferences with the IRS with respect to whether 100% PTCs are allowable with respect to each such WTG. Furthermore, Contractor shall have the right to review and comment on any submissions to the IRS, and attend and jointly participate in any such meetings or conferences with the IRS at its own expense. In any such proceedings, the Owner shall take or not take any action reasonably requested by Contractor that would materially affect whether 100% PTCs are allowable with respect to each such WTG. The PTC Liquidated Damages payable pursuant to this Section 11.4 shall not be subject to the cap on liability for Delay Liquidated Damages provided in Section 11.1 or the cap on aggregate maximum liability provided in Section 11.2.

 

____________________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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Section 11.5         CONSEQUENTIAL DAMAGES. SUBJECT TO THE NEXT SENTENCE, NEITHER OWNER NOR CONTRACTOR NOR ANY OF EITHER OF THEIR SUCCESSORS OR ASSIGNS, OR THE RESPECTIVE SHAREHOLDERS, PARTNERS, ASSIGNS, DIRECTORS, OFFICERS, AGENTS OR EMPLOYEES OR REPRESENTATIVES OF EITHER OF THEM, SHALL BE LIABLE TO THE OTHER FOR CONSEQUENTIAL, SPECIAL, EXEMPLARY, INDIRECT OR INCIDENTAL LOSSES OR DAMAGES, INCLUDING REVENUES FROM LOST POWER, LOSS OF USE, COST OF CAPITAL, LOSS OF GOODWILL, LOSS OF REVENUES OR PROFIT, AND OWNER AND CONTRACTOR EACH HEREBY RELEASES THE OTHER AND EACH OF SUCH PERSONS FROM ANY SUCH LIABILITY. THE FOREGOING EXCLUSION SHALL NOT (A) PRECLUDE RECOVERY, WHERE APPLICABLE, OF LIQUIDATED AMOUNTS HEREUNDER (EXCEPT AS PROVIDED IN Section 11.1), (B) BE CONSTRUED TO LIMIT RECOVERY UNDER ANY INDEMNITY IN Article 10, (C) LIMIT ANY LIABILITY OF A PARTY UNDER THE ASSET PURCHASE AGREEMENT OR LIABILITY OF OWNER UNDER THIS AGREEMENT TO THE EXTENT RESULTING FROM OWNER’S BREACH OF THE ASSET PURCHASE AGREEMENT, OR (D) PRECLUDE ANY RECOVERY BY OWNER AGAINST CONTRACTOR FOR ANY LIABILITY OF CONTRACTOR UNDER Section 11.2.

 

Section 11.6         Liquidated Damages Not a Penalty. The Parties acknowledge and agree that because of the unique nature of the WTGs, the Infrastructure Facilities and the Project and the unavailability of substitute equipment, it is difficult or impossible to determine with precision the amount of damages that would or might be incurred by Owner as a result of Contractor’s failure to achieve Project Substantial Completion by the Guaranteed Project Substantial Completion Date. It is understood and agreed by the Parties that (a) Owner shall be disadvantaged by failure of Contractor to meet such obligations, (b) it would be impracticable or extremely difficult to quantify the amount of time Owner’s disadvantage resulting therefrom, (c) any sums which would be payable under Section 6.9 and/or Section 11.4 are in the nature of liquidated damages are fair and reasonable, and (d) such payments represent a reasonable estimate of damages, and shall, without duplication, be the sole and exclusive remedy of Owner with respect to any such failure by Contractor (but without limiting Contractor’s obligation to achieve Project Substantial Completion).

 

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Section 11.7         Limitation of Owner Liabilities. Notwithstanding any other provision of this Agreement, the aggregate amount of damages Contractor shall be entitled to receive from Owner, regardless of the theory of liability, shall be [**].

 

Section 11.8         Releases Valid in All Events. The waivers, limitations and disclaimers of liability indemnities, releases from liability and limitations on liability or damages expressed in this Agreement shall survive cancellation or expiration of this Agreement, and shall apply (unless otherwise expressly indicated under this Agreement) irrespective of whether a Party or any Affiliate thereof or any partner, shareholder, officer, director or employee of a Party or an Affiliate thereof asserts a theory of liability in contract, equity or tort, even in the event of fault, misrepresentation (including negligent misrepresentation), negligence (including sole negligence), foreseeable damages, strict liability, breach of warranty or any other theory of liability, of the party indemnified, released or whose liabilities are limited, and, to the extent permitted by Applicable Law, shall extend to the partners, principals, directors, officers and employees, agents and Affiliates of such party, and their partners, principals, directors, officers and employees.

 

Article 12
INSURANCE

 

Section 12.1         Coverage by Contractor and Owner. Unless as otherwise set forth in Exhibit 12.0, Contractor and Owner shall maintain or cause to be maintained the insurance as specified in Exhibit 12.0, from the Notice to Proceed Date until the earlier to occur of (a) Final Completion and (b) the earlier termination of this Agreement.

 

Section 12.2         No Limitation Intended. The insurance coverage to be provided by Contractor or Owner as set forth in Exhibit 12.0, is not intended to and shall not in any manner limit or qualify the obligations of Contractor under this Agreement except to the extent that any proceeds of such insurance are received by Owner and are applied to the satisfaction of Contractor’s obligations hereunder.

 

Section 12.3         Failure to Obtain or Maintain Coverage. The failure by either Contractor or Owner to obtain or maintain the insurance required hereunder shall entitle the other Party, in addition to any other remedies available under this Agreement, at law or in equity, to obtain such coverage at the expense of the Party failing to obtain or maintain such insurance; provided, however, that such Party shall reimburse the other Party for the cost of obtaining or maintaining such insurance.

 

____________________________

[**] Denotes confidential information that has been omitted from the exhibit and filed separately, accompanied by a confidential treatment request, with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of 1934.

 

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Article 13
DEFAULT; TERMINATION AND SUSPENSION

 

Section 13.1           Contractor Defaults. The occurrence of any one or more of the following events shall constitute an event of default by Contractor hereunder (each a “Contractor Event of Default”):

 

13.1.1       Contractor, the surety (if any), or any Guarantor makes a general assignment for the benefit of its creditors, is unable to pay its debts as they become due, or becomes the subject of any voluntary or involuntary bankruptcy, insolvency, arrangement, reorganization or other debtor relief proceeding under any Applicable Laws, now in existence or hereafter becoming effective, and, in the case of any such involuntary proceeding, that is not dismissed or stayed within forty-five (45) Days after it is commenced;

 

13.1.2       Contractor fails, for any reason, to make prompt payments required to be made by Contractor to Owner that is not otherwise in dispute or, other than due to a failure of Owner to make payments to Contractor when obligated and in accordance with this Agreement, any Subcontractor, which failure continues for thirty (30) Days after notice of such non-payment;

 

13.1.3       there is a default under the Guaranty;

 

13.1.4       Contractor (or any other Seller) is in material default of the Asset Purchase Agreement and such default continues beyond the applicable cure period provided by the Asset Purchase Agreement;

 

13.1.5       Contractor is in material default of the Turbine Supply Agreement or the Prime Subcontract and such default continues beyond the applicable cure period provided by the Turbine Supply Agreement or the Prime Subcontract, as applicable;

 

13.1.6       Contractor intentionally disregards Applicable Laws, Applicable Standards, or the Contract Documents and does not commence to cure its noncompliance therewith within thirty (30) days after notice from Owner;

 

13.1.7       Contractor disregards any material instruction of Owner delivered in accordance with this Agreement (other than instructions that materially increase Contractor’s costs or the scope of the Work without an accompanying Scope Change Order) and does not commence to cure its noncompliance therewith within thirty (30) days after notice from Owner;

 

13.1.8       [Reserved] 

 

13.1.9       Delay Liquidated Damages accrued exceed the cap for Delay Liquidated Damages set forth in Section 11.1;

 

13.1.10     Contractor fails to deliver a Recovery Plan requested pursuant to Section 2.4.4 within fourteen (14) days after notice of delinquency and does not commence to cure such delinquency within ten (10) days after notice from Owner; provided that (i) if Contractor is engaged in good faith efforts to prepare and deliver the Recovery Plan to Owner, and (ii) it is not possible to prepare and deliver the Recovery Plan to Owner within the ten (10) Day cure period, the cure period shall be extended for an additional ten (10) Day period;

 

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13.1.11     [Reserved]

 

13.1.12     Contractor has made a material misrepresentation in this Agreement and fails to cure same within thirty (30) Days after receiving a notice from Owner that specifies the damages to Owner that have or will result from such misrepresentation;

 

13.1.13     Contractor diverts one or more WTGs from the Project (or a WTG is otherwise not available);

 

13.1.14     [Reserved]

 

13.1.15     Contractor fails to maintain the insurance required by Article 12;

 

13.1.16     Any Guarantor repudiates or otherwise challenges the validity or enforceability of any Guaranty, or Contractor fails to deliver a letter of credit to Owner as required pursuant to Section 4.7.4 following the occurrence of a Credit Trigger Event with respect to Guarantor; or

 

13.1.17     Contractor is otherwise in material breach of any provision of, or has failed to perform its material obligations under, this Agreement or the Agreement Documents, and such failure continues for thirty (30) Days after written notice from Owner that specifies the damages to Owner that have or will result from such breach (or provide a plan that is acceptable to Owner, in the sole discretion of Owner, to commence a cure within thirty (30) Days after receipt of notice and diligently and continuously pursue a cure, and if such default is capable of cure within ninety (90) Days, then such default shall not be a Contractor Event of Default unless it remains uncured ninety (90) Days from the date of the original written notice from Owner).

 

Section 13.2           Owner Remedies . Upon the occurrence and during the continuation of any Contractor Event of Default hereunder, Owner, in addition to its right to pursue any other remedy given under this Agreement or now or hereafter existing at law or in equity or otherwise and after giving effect to any applicable cure periods, shall have the right to terminate this Agreement by written notice to Contractor and the Guarantors (“Termination for Cause”); provided, however, that Owner shall have no right to terminate this Agreement for any breach or default under this Agreement or the Guaranty that is not a material breach or default. A Termination for Cause shall be effective upon delivery of Owner’s written notice (the “Termination Notice”) with respect thereto. Owner shall, within a reasonable period of time after the Work is finally completed by one or more replacement contractors, determine the total cost to Owner for completing the Work in accordance with the Technical Specifications and the other Requirements of this Agreement, including all sums previously paid or then owed to Contractor pursuant to this Agreement. In contracting with such replacement contractors, Owner shall, to the extent practicable, cause the Work to be completed in accordance with the Agreement Documents and shall employ reasonable efforts to mitigate the costs incurred in connection with completion of the Work. If the Agreement Price is less than the sum of (i) the cost incurred by Owner finally to complete the Work; (ii) all amounts previously paid to Contractor pursuant to this Agreement, Contractor shall pay to Owner on demand the amount of such difference. Any amount owed by Owner to Contractor for the level of completion of the Work shall be retained by Owner until after completion of the Work and applied by Owner to pay any amounts and damages owed by Contractor pursuant to this Section 13.2. Any excess shall be remitted by Contractor within sixty (60) Business Days after the Project is finally completed.

 

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13.2.1      Unless otherwise stated in the notice, upon receipt of notice of Termination for Cause or a Step-In Notice:

 

13.2.1.1           Contractor shall immediately discontinue the Work or the relevant portion of the Work on the date and to the extent specified in the notice;

 

13.2.1.2           Contractor shall place no further orders or subcontracts as to the Work, other than as may be necessary for completion of any such portion of the Work that is not terminated;

 

13.2.1.3           If requested by Owner, Contractor shall make every reasonable effort to obtain cancellation upon terms satisfactory to Owner of all orders and subcontracts to the extent they relate to the performance of the Work terminated;

 

13.2.1.4           As directed by Owner, Contractor shall assist Owner in the maintenance, protection and disposition of materials, supplies, property or the like acquired pursuant to the Agreement; and

 

13.2.1.5           Contractor shall deliver to Owner all Documents, Drawings, plans, specifications, data, estimates, summaries or other material and information whether completed or in process related to the Work.

 

13.2.2      Step-In Rights. During the continuance of a Contractor Event of Default, with or without termination of this Agreement or the exercise of other remedies, Owner shall provide Twelve (12) Days prior written notice (the “Step-In Notice”) to Contractor and Guarantor of its intent to exercise the rights set forth in this Section 13.2.2 (the “Step-In-Rights”) and thereafter take over performance of the Work and assume all of Contractor’s rights and responsibilities under the Turbine Supply Agreement, Prime Subcontract and other specified Subcontracts pursuant to the Turbine Supply Security and Collateral Assignment Agreement, the Turbine Supplier Consent to Assignment, the Prime Subcontract Security and Assignment Agreement, the Prime Subcontractor Consent to Assignment, and any other assignments of Subcontracts and related consents thereto delivered to Owner pursuant to Section 2.21. Owner’s Step-In Rights shall take effect Twelve (12) Days after receipt of the Step-In Notice by Contractor. All costs incurred by Owner in connection with such assumed contracts, as well as all other costs incurred by Owner in completing the Work, shall be deducted from any amounts owed by Owner to Contractor or added to the amount of any claim by Owner against Contractor hereunder, as the case may be.

 

Section 13.3          Owner Default. The occurrence of any one or more of the following events shall constitute an event of default by Owner hereunder (“Owner Event of Default”):

 

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13.3.1      Owner makes a general assignment for the benefit of its creditors, is unable to pay its debts as they become due, or becomes the subject of any voluntary or involuntary bankruptcy, insolvency, arrangement, reorganization or other debtor relief proceeding under any Applicable Laws, now in existence or hereafter becoming effective, and, in the case of any such involuntary proceeding, that is not dismissed or stayed within forty-five (45) Days after it is commenced;

 

13.3.2      Owner fails, for any reason, to make prompt payments required to be made by Owner to Contractor that is not otherwise in dispute;

 

13.3.3      Owner has made a material misrepresentation in this Agreement and fails to cure same within thirty (30) Days after notice from Contractor that specifies the damages to Contractor that have or will result from such misrepresentation;

 

13.3.4      Owner is in material default of the Asset Purchase Agreement and such default is not cured as provided by the Asset Purchase Agreement; or

 

13.3.5      Owner is otherwise in material breach of any provision of, or has failed to perform its material obligations under, the Agreement and Agreement Documents and such failure continues for thirty (30) Days after written notice from Contractor that specifies the damages to Contractor that have or will result from such breach; or provide a plan that is acceptable to Contractor, in the sole discretion of Contractor, to commence a cure within thirty (30) Days after receipt of notice and diligently and continuously pursue a cure, and if such default is capable of cure within ninety (90) Days, then such default shall not be an Owner Event of Default unless it remains uncured ninety (90) Days from the date of the original written notice from Contractor

 

13.3.6      Owner has failed to provide or maintain the Owner LOC as required under Section 4.1.2.

 

Section 13.4           Contractor Rights to Terminate.

 

13.4.1.1           Contractor’s Right to Terminate. Contractor may suspend performance of the Work until the Owner Event of Default is cured or may terminate this Agreement in respect of an Owner Event of Default, upon not less than thirty (30) Days prior written notice to Owner.

 

13.4.1.2           Termination Due to Force Majeure. If (a) Owner wholly suspends the Work on the Project for one hundred eighty (180) consecutive Days due to the occurrence of a Force Majeure Event suffered by Owner or (b) Contractor is entirely prevented from performing the Work for a period of one hundred eighty (180) consecutive Days as a result of the occurrence of a Force Majeure Event, then the affected Party may terminate this Agreement (“Termination Due to Force Majeure”). Upon such termination, Owner shall, except to the extent covered by insurance, pay Contractor (a) payment of all accrued payment obligations due and payable through such date, (b) all reasonable direct costs incurred by Contractor in performance of the Work for which Contractor has not yet been paid by Owner, and all reasonable direct documented costs incurred by Contractor for terminating the Work before Final Completion, including, but not limited to, removing equipment and materials from the Project Site, home office costs associated with terminating contracts and reassignment of personnel, and (c) all reasonable cancellation fees or termination payments required to terminate or cancel Subcontractor’s and Contractor’s contract personnel. The foregoing costs shall not include any costs incurred by Contractor after the date of the event giving rise to such termination that Contractor reasonably could have mitigated. Contractor shall use all reasonable diligent efforts to mitigate the costs described above in this Section 13.4.1.2. Nothing in this Section 13.4.1.2 shall relieve or excuse either Party from its obligations under Article 8 in respect of the occurrence of a Force Majeure Event

 

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Section 13.5         Termination of Asset Purchase Agreement. In the event the Asset Purchase Agreement is terminated in accordance with the terms thereof, this Agreement shall be deemed terminated as of the date of termination of the Asset Purchase Agreement. Each Party shall be relieved of any and all liability to the other Party pursuant to this Agreement upon such termination; provided, however, that any obligation of either Party under Section 13.6.5 shall survive such termination of this Agreement.

 

Section 13.6           Actions Required Following Termination.

 

13.6.1      Discontinuation of Work. Upon termination of this Agreement, Contractor immediately shall discontinue the Work and remove its personnel and equipment from the Project Site, and Owner shall be entitled to take exclusive possession of the Work and all or any part of the Work and materials delivered or en route to the Project Site, for which payment has been made by Owner to Contractor, to the extent that Owner has paid Contractor all amounts hereunder then due and payable from Owner to Contractor, and all amounts due pursuant to Section 13.2, Section 13.3, and Section 13.4. Contractor immediately shall take such steps as are reasonably necessary to preserve and protect Work completed and in progress and to protect materials, equipment and supplies at the Project Site, stored off-site, or in transit.

 

13.6.2      Cancellation and Transfer of Subcontracts and Other Rights. Upon termination of this Agreement, Contractor shall also, upon request by Owner, (a)  to the extent assignable, irrevocably assign and deliver to Owner any and all Subcontracts, purchase orders, bonds and options made by Contractor in performance of the Work and not previously assigned to Owner, pursuant to Section 2.2.1 or otherwise (but in no event shall Owner be liable for any action or default of Contractor occurring prior to such delivery and assignment except to the extent such action or default was caused by Owner, and each contract with each Subcontractor and the Turbine Supplier shall so provide); (b)  provide to Owner without charge and in accordance with this Agreement and the terms of such Subcontracts, all rights to use patented or proprietary materials of Contractor and Subcontractors in completing, operating and maintaining the Work; and (c)  deliver to Owner certified copies of all Agreement Documents and, if the termination occurs at a time when the design of the Infrastructure Facilities is incomplete, originals of all Design Documents in process (except that Contractor may keep for its records copies, and, if sufficient originals exist, an original set, of the Agreement Documents executed by Owner and Design Documents for the WTGs), all other materials relating to the Work which belong to Owner, and all papers and Documents relating to Permits, orders placed, bills and invoices, lien releases and financial management under this Agreement. All deliveries hereunder shall be made free and clear of any liens, security interests or encumbrances, except such as may be created by Owner or permitted by this Agreement. Except as provided herein, no action taken by Owner or Contractor after the termination of this Agreement shall prejudice any other rights or remedies of Owner or Contractor provided by Applicable Laws, the Agreement Documents or otherwise upon such termination. Upon termination of this Agreement solely on account of Section 13.4, Contractor shall be entitled to terminate any Guaranty required by Section 4.7.

 

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13.6.3      Payments to Turbine Supplier. In the event that Turbine Supplier has delivered WTGs to the Project Site and Owner has taken title to such WTGs, then prior to exercising any rights under the Turbine Supply Assignment or the Turbine Supplier Consent to Assignment, Owner shall reimburse Contractor for all previously unreimbursed sums that Contractor has paid to the Turbine Supplier for such WTGs that have been delivered to the Site, minus any amount that Owner is otherwise entitled to offset or withhold in accordance with Section 4.10 or Section 4.12, respectively.

 

13.6.5      Surviving Obligations. Termination or expiration of this Agreement (a)  shall not relieve either Party of its obligations with respect to the confidentiality of the other Party’s information as set forth in Article 17; (b)  shall not relieve either Party of any obligation hereunder which expressly or by implication survives termination hereof; and (c)  except as otherwise provided in any provision of this Agreement expressly limiting the liability of either Party, shall not relieve either Owner or Contractor of any obligations or liabilities for loss or damage to the other Party arising out of or caused by acts or omissions of such Party prior to the effectiveness of such termination or arising out of such termination, and shall not relieve Contractor of its obligations as to portions of the Work or other services hereunder already performed or of obligations assumed by Contractor prior to the date of termination. This Article 13 shall survive the termination or expiration of this Agreement.

 

Article 14
TITLE AND RISK OF LOSS

 

Section 14.1          Title to WTGs, Infrastructure Facilities and the Work. Provided that Owner has made all Milestone Payments due in accordance with this Agreement, (i) Contractor warrants and guarantees that legal title to and ownership of the Work shall be free and clear of any and all liens, claims, security interests or other encumbrances when title thereto passes to Owner, (ii) title to all Infrastructure Facilities and the Work, other than the WTGs, shall pass to Owner upon Project Substantial Completion; (iii) title to the 5% Safe Harbor Turbines shall pass to Owner pursuant to the Asset Purchase Agreement upon Project Closing; and (iv) title to each other WTG shall pass to Owner upon delivery to the Project Site.

 

Section 14.2         Ownership of Work Documents. All Drawings, As-Built Drawings and Documentation, Designs Documents, estimates, data, summaries, materials, information, plans, specifications, calculations, reports and other documents (“Documents”) whether in hard copy or electronic media prepared pursuant to the Agreement shall become the sole and exclusive property of Owner and title thereto shall pass to the Owner upon transmittal to Owner; provided, however, that ownership and rights to use any and all Documents relating to the WTG design and specifications shall be governed exclusively by the Turbine Supply Agreement. Owner reserves the right to reproduce, modify and use in any manner, any and all Documents. Contractor shall, and shall cause its employees, representatives, agents and Subcontractors to execute and deliver any and all forms and instruments necessary or desirable to transfer the Documents such that Owner shall have of record all of its rights, interests, title and ownership in and to the Documents, free and clear of all third party encumbrances and interests.

 

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Section 14.3          Risk of Loss. Notwithstanding passage of title as provided in Section 14.1, Contractor shall bear the risk of loss and damage with respect to the WTGs (including the 5% Safe Harbor Turbines), the related Electrical Works, and all other portions of the Work, or any portion thereof, wherever located, until Project Substantial Completion. Upon such transfer of risk of loss with respect to such item, Contractor shall relinquish and Owner shall assume full and exclusive custody of such property, including responsibility for operation, maintenance, insurance and risk of loss. Notwithstanding the foregoing, if Contractor is obligated by the terms of this Agreement to perform additional Work with respect to the WTGs or the related Electrical Works subsequent to Project Substantial Completion, Contractor shall bear the risk of loss and damage with respect to such additional Work until Contractor’s obligation to perform additional Work is satisfied.

 

Section 14.4         Revenues. Owner shall be entitled to any revenues generated by the Project whether before or after Project Substantial Completion.

 

Article 15
DISPUTE RESOLUTION

 

Section 15.1         Choice of Law. This Agreement shall be construed, interpreted and the rights of the Parties determined in accordance with the Laws of the State of New York without reference to its choice of law provisions other than Section 5-1401 of the General Obligations Law.

 

Section 15.2         Attempt to Resolve Disputes. Upon a Party’s written notification to the other Party of a dispute, which notification must include a written explanation of the dispute and the material particulars of the notifying Party’s position as to the dispute, each Party shall nominate one (1) executive representative with the authority to bind such Party. The nominated representatives shall meet not later than ten (10) Business Days thereafter to attempt in good faith to resolve the dispute and to produce written terms of settlement for the dispute (a “Settlement Agreement”). A Settlement Agreement executed by each executive representative shall serve as conclusive evidence of the resolution of such dispute. If the executive representatives do not produce and execute the Settlement Agreement within forty-five (45) Days after the date of the first meeting or within a longer period agreed to by each executive representative, then, either Party may upon written notice to the other Party, pursue all its rights and remedies provided at law or equity or otherwise in this Agreement.

 

Section 15.3         Forum Selection. The Parties hereto hereby irrevocably submit to the jurisdiction of the federal or state courts located in Hennepin County, Minnesota, over any dispute arising out of or relating to this Agreement or any of the transactions contemplated hereby; and each Party hereby irrevocably agrees that all claims in respect of such dispute or proceeding shall be heard and determined in such court. Each Party hereby irrevocably waives, to the fullest extent permitted by applicable Law, any objection which it may now or hereafter have to the laying of venue of any such dispute brought in such court or any defense of inconvenient forum.

 

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Section 15.4         WAIVER OF JURY TRIAL; ENFORCEMENT PROCEEDINGS. IN ANY LITIGATION ARISING FROM OR RELATED TO THIS AGREEMENT, THE PARTIES HERETO EACH HEREBY KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVE THE RIGHT EACH MAY HAVE TO A TRIAL BY JURY WITH RESPECT TO ANY LITIGATION BASED HEREON, OR ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AGREEMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER ORAL OR WRITTEN) OR ACTIONS OF EITHER PARTY TO THIS AGREEMENT. THIS PROVISION IS A MATERIAL INDUCEMENT FOR OWNER AND CONTRACTOR TO ENTER INTO THIS AGREEMENT. EACH PARTY AGREES THAT FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN ANY OTHER JURISDICTION BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY APPLICABLE LAW.

 

Section 15.5         Service of Process. Each of the Parties hereto hereby consents to process being served by the other Party to this Agreement in any suit, action or proceeding of the nature specified in Section 15.3 by mailing of a copy thereof in accordance with the provisions of Section 17.4 hereof.

 

Section 15.6         Continued Performance. Pending final resolution of any dispute, Owner and Contractor shall continue to fulfill their respective obligations hereunder and Owner shall continue to pay Contractor in accordance with the terms of this Agreement, except to the extent expressly provided in this Agreement.

 

Article 16
REPRESENTATIONS AND WARRANTIES

 

Section 16.1          Contractor Representations. Contractor represents and warrants that:

 

16.1.1     Organization. It is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and is qualified to do business in all jurisdictions in which the nature of the business conducted by it makes such qualification necessary and where failure to so qualify would have a material adverse effect on its ability to perform this Agreement.

 

16.1.2     No Violation of Law; Litigation. It is not in violation of any Applicable Laws, or judgment entered by any Governmental Authority which violations, individually or in the aggregate, would materially and adversely affect its performance of any obligations under this Agreement. Except as Contractor has disclosed in writing to Owner prior to the Effective Date, there are no legal or arbitration proceedings or any proceeding by or before any Governmental Authority, now pending or (to the best knowledge of Contractor) threatened against Contractor which, if adversely determined, could reasonably be expected to have a material adverse effect on the ability of Contractor to perform under this Agreement.

 

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16.1.3     Permits. It is (or will be prior to performing any applicable Work on the Project Site) the holder of all Permits required to permit it to operate or conduct its business now and as contemplated by this Agreement.

 

16.1.4     No Breach. None of the execution and delivery of this Agreement, the consummation of the transactions herein contemplated, or compliance with the terms and provisions hereof, conflicts with or will result in a breach of, or require any consent under, the governing Documents of Contractor, or any Applicable Laws or regulation, order, writ, injunction or decree of any court, or any agreement or instrument to which Contractor is a party or by which it is bound or to which it is subject, or constitute a default under any such agreement or instrument.

 

16.1.5     Corporate Action. It has all necessary power and authority to execute, deliver and perform its obligations under this Agreement; the execution, delivery and performance by Contractor of this Agreement have been duly authorized by all necessary action on its part; and, this Agreement has been duly and validly executed and delivered by Contractor and constitutes the legal, valid and binding obligation of Contractor enforceable in accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency, reorganization or moratorium or other similar laws relating to the enforcement of creditors’ rights generally and by general equitable principles.

 

Section 16.2          Owner Representations. Owner represents and warrants that:

 

16.2.1     Organization. It is a corporation duly organized, validly existing and in good standing under the laws of the State of Minnesota, and is qualified to do business in all jurisdictions in which the nature of the business conducted by it makes such qualification necessary and where failure to so qualify would have a material adverse effect on its ability to perform this Agreement.

 

16.2.2     No Violation of Law; Litigation. It is not in violation of any Applicable Laws or judgment entered by any Governmental Authority, which violations, individually or in the aggregate, would materially and adversely affect its performance of any obligations under this Agreement. Except as Owner has disclosed in writing to Contractor prior to the Effective Date, there are no legal or arbitration proceedings or any proceeding by or before any Governmental Authority, now pending or (to the best knowledge of Owner) threatened against Owner which, if adversely determined, could reasonably be expected to have a material adverse effect on the ability of Owner to perform under this Agreement.

 

16.2.3     No Breach. None of the execution and delivery of this Agreement, the consummation of the transactions herein contemplated, or compliance with the terms and provisions hereof and thereof, conflicts with or will result in a breach of, or require any consent under, the governing Documents of Owner, or any Applicable Laws or regulation, order, writ, injunction or decree of any court, or any agreement or instrument to which Owner is a party or by which it is bound or to which it is subject, or constitute a default under any such agreement or instrument.

 

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16.2.4     Corporate Action. It has all necessary power and authority to execute, deliver and perform its obligations under this Agreement; the execution, delivery and performance by Owner of this Agreement have been duly authorized by all necessary action on its part; and, this Agreement has been duly and validly executed and delivered by Owner and constitutes the legal, valid and binding obligation of Owner enforceable in accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency, reorganization or moratorium or other similar laws relating to the enforcement of creditors’ rights generally and by general equitable principles.

 

16.2.5     Solvency. It is not currently a party to any voluntary or involuntary bankruptcy or reorganization proceeding under Applicable Law, and remains solvent.

 

16.2.6     Sufficient Financial Resources. It has sufficient financial resources to carry out all payment obligations established by and set forth in this Agreement.

 

16.2.7     Financial Condition. Its senior unsecured credit rating is at or above BBB- (or Baa3 in the case of Moody’s) as of the Effective Date.

 

Article 17
MISCELLANEOUS PROVISIONS

 

Section 17.1         Confidentiality. Except as set forth in this Section 17.1, Owner and Contractor shall hold in confidence all information supplied by either Party to the other Party under the terms of this Agreement that is marked or otherwise indicated to be confidential (“Confidential Information”). Each Party shall inform its Affiliates, Subcontractors, suppliers, vendors and employees of its obligations under this Section 17.1 and require such Persons to adhere to the provisions hereof. Notwithstanding the foregoing, Owner and Contractor may disclose the following categories of information or any combination thereof:

 

17.1.1     information which was in the public domain prior to receipt thereof by such Party or which subsequently becomes part of the public domain by publication or otherwise except by a wrongful act of such Party;

 

17.1.2     information that such Party can show was lawfully in its possession prior to receipt thereof from the other Party through no breach of any confidentiality obligation;

 

17.1.3     information received by such Party from a third party having no obligation of confidentiality with respect thereto;

 

17.1.4     information at any time developed independently by such Party providing it is not developed from otherwise confidential information;

 

17.1.5     information disclosed pursuant to and in conformity with Applicable Law or a judicial order or in connection with any legal proceedings described in Article 15; and

 

17.1.6     information required to be disclosed under securities laws applicable to publicly traded companies and their subsidiaries.

 

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In addition, Owner may disclose Confidential Information to any financial institutions expressing interest in providing debt financing or refinancing or other credit support to Owner, and the agent or trustee of any of them; provided, however, that such disclosures shall be subject to the agreement of such Persons to keep such information confidential pursuant to the terms of this Section 17.1. The Parties each acknowledge and agree that the terms of this Agreement shall constitute Confidential Information of the other Party. Notwithstanding the foregoing, either Party may publish Confidential Information regarding this Agreement with the express written consent of the other Party. Neither Party shall release, distribute or disseminate any Confidential Information for publication concerning this Agreement or the participation of the other Party in the transactions contemplated hereby without the prior written consent of the other Party, provided, however, that such limitation on disclosure shall not apply to disclosures or reporting required by a Governmental Authority if the Party seeking disclosure informs the other Party of the need for such disclosure and, if reasonably requested by the other Party, seeks, through a protective order or other appropriate mechanism, to maintain the confidentiality of Confidential Information.

 

Section 17.2         Public Announcements; Press Release. Neither Party shall issue any public announcement or other statement with respect to this Agreement or the transactions contemplated hereby, without the prior consent of the other Party, unless required by Applicable Law or order of a court of competent jurisdiction; provided, however, that a Party shall have the right without obtaining such consent to include public information concerning the Project in such Party’s marketing materials following the initial public announcement of this Agreement by the Parties. In the event of a breach of this Section 17.2, in addition to and not in lieu of any legal or equitable remedies that may otherwise be available, the non-breaching Party may, in its sole discretion, issue public announcements that the non-breaching Party shall deem to be appropriate in its sole discretion to supplement, correct or amplify the announcement or statement made by the breaching Party. Notwithstanding anything in the foregoing provisions of this Section 17.2, the Parties may each make an initial public announcement or statement regarding the execution of this Agreement and the transactions contemplated hereby, without the consent of the other Party, provided that such public announcement or statement shall be limited to statements regarding the size and location of the Project, the projected year for construction and operation of the Project and the parties hereto.

 

Section 17.3         Software and Other Proprietary Material. Owner and Contractor acknowledge and agree that, pursuant to the terms of this Agreement, Owner is being provided and shall have access to certain intellectual property rights, the right to make and use (but not distribute) derivative works (a) owned by Contractor, or (b) used or licensed by Contractor pursuant to Contractor’s agreements with its Subcontractors, including software, trade secrets, patents and other proprietary information relating to the specification, design, construction, installation, operation or maintenance and repair of the Work, as well as certain training processes and the contents of service and maintenance manuals and test and inspection procedures (“Intellectual Property Rights”). Owner and Contractor agree that the Agreement provides Owner and any Affiliate of Owner and their representatives with an irrevocable, permanent, transferable, nonexclusive, royalty-free license to use the Intellectual Property Rights (a) in connection with the Project and (b) solely in connection with the operation, maintenance, repair, modification or alteration of any other power generating facility to be owned, operated, constructed or developed by Owner or any Affiliate of Owner; provided that, Contractor makes no representation or warranty with respect to the Intellectual Property Rights to the extent that such Intellectual Property Rights are used in any facility other than the Project and; provided, further, that Contractor makes no representation that the Intellectual Property Rights are suitable for reuse by Owner or others on any other project and, provided, further, that any such reuse will be at Owner’s sole risk and without liability or legal exposure to Contractor.

 

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Section 17.4         Notice. All notices and other communications required or permitted by this Agreement or by Applicable Law to be served upon or given to a Party by any the other Party shall be in writing signed by the Party giving such notice and shall be deemed duly served, given and received (a)  on the date of service, if served personally or sent by facsimile or email transmission (with appropriate confirmation of receipt) to the Party to whom notice is to be given, (b) on the fourth (4th) Day after mailing, if mailed by first class registered or certified mail, return receipt requested, postage paid, or (c) on the next Day if sent by a nationally recognized courier for next Day service and so addressed and if there is evidence of acceptance by receipt, in each case addressed as follows:

 

 

If to Owner: Otter Tail Power Company
  215 South Cascade Street
  Fergus Falls, Minnesota
  Attention: Harvey McMahon, Manager, Renewable Energy Construction and Operations
  Telephone: (701) 253-4732
  Facsimile: (218) 739-8629
  Email: HMcMahon@otpco.com
   
With a copy to: Otter Tail Power Company
  215 South Cascade Street
  Fergus Falls, MN 56537
  Attention:  Legal Department
  Telephone: (218) 739-8922
  Facsimile: (218) 998-3165
  Email: mbring@otpco.com
   
If to Contractor: EDF-RE US DEVELOPMENT, LLC
  15445 Innovation Drive
  San Diego, California 92128
  Attention: Christina Watts
  Telephone: (858) 521-3512
  Facsimile: (858) 521-3333
  Email: Christina.Watts@edf-re.com
   
with a copy to: EDF Renewable Energy
  15445 Innovation Drive
  San Diego, CA 92128
  Attention:  Joshua Pearson
  Telephone:  (858) 521-3467
  Facsimile:  (858) 521-3333
  Email:  Joshua.Pearson@edf-re.com

 

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The Parties, by like notice in writing, may designate, from time to time, another address or office to which notices shall be delivered pursuant to this Agreement.

 

Section 17.5         No Rights in Third Parties. Except as otherwise expressly provided herein, this Agreement and all rights hereunder are intended for the sole benefit of the Parties and shall not imply or create any rights on the part of, or obligations to, any other Person.

 

Section 17.6         Conflicting Provisions. In the event of any inconsistencies between this Agreement (not including the Exhibits) and the other Agreement Documents, the following order of precedence in the interpretation hereof or resolution of such conflict hereunder shall prevail:

 

17.6.1     duly authorized and executed Scope Change Orders and written amendments to this Agreement executed by both Parties;

 

17.6.2     this Agreement;

 

17.6.3     the Exhibits hereto; and

 

Where an irreconcilable conflict exists among Applicable Laws, this Agreement, the Drawings included in the Design Documents, and the specifications in the Design Documents, the earliest item mentioned in this sentence involving a conflict shall control over any later mentioned item or items subject to such conflict. Notwithstanding the foregoing provisions of this Section 17.6 if a conflict exists within or between parts of the Agreement Documents, or between the Agreement Documents and Applicable Law, or among Applicable Laws themselves, the more stringent or higher quality requirements shall control. All obligations imposed on Contractor and each Subcontractor under the Agreement Documents (other than this Agreement) or under Applicable Laws or Applicable Standards and not expressly imposed or addressed in this Agreement shall be in addition to and supplement the obligations imposed on Contractor under this Agreement, and shall not be construed to create an “irreconcilable conflict”. Where a conflict exists among codes and standards applicable to the Infrastructure Facilities or Contractor’s performance of the Work, the most stringent provision of such codes and standards shall govern.

 

Section 17.7         Entire Agreement. This Agreement contains the entire understanding of the Parties with respect to the subject matter hereof and supersedes all prior agreements and commitments with respect thereto. There are no other oral understandings, terms or conditions and neither Party has relied upon any representation, express or implied, not contained in this Agreement.

 

Section 17.8         Amendments. No amendment or modification of this Agreement shall be valid or binding upon the Parties unless such amendment or modification shall be in writing and duly executed by authorized officers of both Parties.

 

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Section 17.9          [Reserved]

 

Section 17.10         Right of Waiver. Owner, in its sole discretion, shall have the right, but shall have no obligation, to waive, defer or reduce any of the requirements to which Contractor is subject under this Agreement at any time; provided, however, that such waiver is in writing. Any failure of any Party to enforce any of the provisions of this Agreement or to require compliance with any of its terms at any time during the pendency of this Agreement shall in no way affect the validity of this Agreement, or any part hereof, and shall not be deemed a waiver of the right of such Party thereafter to enforce any and each such provision.

 

Section 17.11        Severability. The invalidity of one or more phrases, sentences, clauses, Sections or articles contained in this Agreement shall not affect the validity of the remaining portions of the Agreement so long as the material purposes of this Agreement can be determined and effectuated. In the event that any of the provisions, or portions or applications thereof, of this Agreement are held to be unenforceable or invalid by any court of competent jurisdiction, Owner and Contractor shall negotiate in good faith an equitable adjustment in the provisions of this Agreement with a view toward effecting the purpose of this Agreement.

 

Section 17.12        Assignment. This Agreement or any right or obligation contained herein may be assigned by Owner or Contractor, respectively, to wholly-owned Affiliates of Owner or Contractor; provided, however, that Owner or Contractor, as the case may be, unconditionally guarantees the performance of such Affiliate’s obligations under this Agreement to the reasonable satisfaction of the other Party. This Agreement may be otherwise assigned by the Parties only upon the prior written consent of the other Party, which consent shall not be unreasonably withheld or denied. When duly assigned in accordance with the foregoing, this Agreement shall be binding upon and shall inure to the benefit of the assignee; any other assignment shall be void and without force or effect.

 

Section 17.13        Successors and Assigns. This Agreement shall be binding upon the Parties, their successors and permitted assigns.

 

Section 17.14        No Partnership Created. Nothing contained in this Agreement shall be construed as constituting a joint venture or partnership between Contractor and Owner.

 

Section 17.15       Survival. All provisions of the Agreement Documents that are expressly or by implication to come into or continue in force and effect after the expiration or termination of this Agreement, including Article 7, Article 10, and Article 11 shall remain in effect and be enforceable following such expiration or termination. The representations and warranties of Contractor contained herein or in any other Agreement Document shall survive the execution and delivery hereof and thereof, subject to the limitations set forth herein and therein.

 

Section 17.16        Effectiveness. This Agreement shall be effective on, and binding upon each of the Parties, on the Effective Date; provided that Contractor shall have no obligations hereunder until the Closing Date of the Asset Purchase Agreement and the deemed issuance of the Notice to Proceed simultaneously therewith.

 

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Section 17.17       Further Assurances. Contractor and Owner agree to provide such information, execute and deliver any instruments and Documents and to take such other actions as may be necessary or reasonably requested by the other Party which are not inconsistent with the provisions of this Agreement and which do not involve the assumptions of obligations other than those provided for in this Agreement, in order to give full effect to this Agreement and to carry out the intent of this Agreement.

 

Section 17.18        Captions. The captions contained in this Agreement are for convenience and reference only and in no way define, describe, extend or limit the scope of intent of this Agreement or the intent of any provision contained herein.

 

Section 17.19       Equal Employment Opportunity. The Parties agree that, as applicable, they will abide by the requirements of 41 CFR 60-1.4(a), 41 CFR 60-300.5(a) and 41 CFR 60-741.5(a) and that these laws are incorporated herein by reference. These regulations prohibit discrimination against qualified individuals based on their status as protected veterans or individuals with disabilities, and prohibit discrimination against all individuals based on their race, color, religion, sex, sexual orientation, gender identity, national origin, protected veteran status or disability. These regulations require that Contractor and Subcontractors take affirmative action to employ and advance in employment individuals without regard to race, color, religion, sex, sexual orientation, gender identity, national origin, protected veteran status or disability. The Parties also agree that, as applicable, they will abide by the requirements of Executive Order 13496 (29 CFR Part 471, Appendix A to Subpart A), relating to the notice of employee rights under federal labor laws.

 

Section 17.20       Counterparts. This Agreement may be signed in any number of counterparts which may be delivered electronically and each counterpart shall represent a fully executed original as if signed by both Parties, with all such counterparts together constituting but one and the same instrument.

 

[The next page is the signature page.]

 

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IN WITNESS HEREOF, the Parties have caused this Agreement to be executed by their duly Authorized Representatives as of the date and year first above written.

 

  CONTRACTOR:
   
  EDF-RE US DEVELOPMENT, LLC
     
  BY: EDF RENEWABLE DEVELOPMENT, INC., ITS MANAGING MEMBER
     
  By: /s/ Tristan Grimbert
    Name: Tristan Grimbert
    Title: President and Chief Executive Officer

 

[Signature pages to Turnkey Engineering, Procurement and Construction Services Agreement]

 

 

 

 

IN WITNESS HEREOF, the Parties have caused this Agreement to be executed by their duly Authorized Representatives as of the date and year first above written.

 

  OWNER:
   
  OTTER TAIL POWER COMPANY
     
  By: /s/ Timothy J. Rogelstad
  Name:Timothy J. Rogelstad
  Title: President

 

[Signature pages to Turnkey Engineering, Procurement and Construction Services Agreement]

 

 

 

 EX-10.J14 4 t1700069_ex10-j14.htm EXHIBIT 10-J-14

 

 

Exhibit 10-J-14

 

SUMMARY OF NON-EMPLOYEE DIRECTOR COMPENSATION (2016)

 

Compensation: Non-employee directors shall receive the following remuneration:

 

Director’s Retainer (except Chairman)  $60,000 
Committee Chair Retainer  $14,000 
Chairman of the Board Retainer  $125,000 
Restricted Stock Award Value  $80,000 

 

 

 

Directors may elect to receive their compensation (other than expense reimbursements) in the form of cash, stock or a combination. Directors may elect to defer the receipt of all or part of their cash compensation pursuant to the Deferred Compensation Plan for Directors. The deferral may be in the form of cash or stock units. Cash deferrals receive interest at a rate equal to 1% over the prime commercial rate of U.S. Bank National Association. Deferrals in the form of stock units are credited quarterly with dividend equivalents equal to the dividend rate on Otter Tail Corporation’s common shares and the deferred amount is paid out in common shares.

 

 

 

 EX-12.1 5 t1700069_ex12-1.htm EXHIBIT 12.1

 

 

Exhibit 12.1

 

OTTER TAIL CORPORATION

CALCULATION OF RATIOS OF EARNINGS TO FIXED CHARGES AND PREFERRED DIVIDENDS

 

   Year Ended December 31, 
   2012   2013   2014   2015   2016 
Earnings                    
Pretax income from continuing operations  $66,313,503   $71,363,651   $73,440,180   $80,231,110   $82,118,038 
Plus fixed charges (see below)   34,618,369    30,219,768    32,091,737    33,742,169    34,311,441 
  Total earnings (1)  $100,931,872   $101,583,419   $105,531,917   $113,973,279   $116,429,479 
Fixed Charges                         
Interest charges  $31,057,367   $26,820,365   $29,241,350   $30,817,357   $31,291,356 
Amortization of debt expense, premium and discount   1,501,002    1,155,403    1,095,387    1,065,812    1,089,085 
Estimated interest component of operating leases   2,060,000    2,244,000    1,755,000    1,859,000    1,931,000 
     Total fixed charges (2)  $34,618,369   $30,219,768   $32,091,737   $33,742,169   $34,311,441 
                          
Preferred Dividend Requirement*  $2,101,550   $650,239   $-   $-   $- 
                          
Total Fixed Charges and Preferred Dividend Requirement (3)  $36,719,919   $30,870,007   $32,091,737   $33,742,169   $34,311,441 
                          

Ratio of Earnings to Fixed Charges

(1) Divided by (2)

   2.92    3.36    3.29    3.38    3.39 

Ratio of Earnings to Fixed Charges and Preferred Dividends

(1) Divided by (3)

   2.75    3.29    3.29    3.38    3.39 

 

*  All outstanding cumulative preferred shares were redeemed on March 1, 2013 for $15.7 million, including $0.2 million in call premiums charged to equity and included as preferred dividends paid and as part of our preferred dividend requirement for the year ended December 31, 2013.

 

 

 

 

 EX-21.A 6 t1700069_ex21-a.htm EXHIBIT 21-A

 

 

Exhibit 21-A

 

OTTER TAIL CORPORATION

 

Subsidiaries of the Registrant

February 22, 2017

 

Company State of Organization
   
Otter Tail Power Company Minnesota
Otter Tail Assurance Limited Cayman Islands
Varistar Corporation Minnesota
Northern Pipe Products, Inc. North Dakota
Vinyltech Corporation Arizona
T.O. Plastics, Inc. Minnesota
IMD, Inc. North Dakota
BTD Manufacturing, Inc. Minnesota
Miller Welding & Iron Works, Inc. Minnesota
Shrco, Inc. Minnesota
AEV, Inc. Minnesota

  

 

 EX-23.A 7 t1700069_ex23-a.htm EXHIBIT 23-A

 

 

Exhibit 23-A

 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

We consent to the incorporation by reference in Registration Statement Nos. 333-204041 and 333-204042 on Form S-3, Registration Statement Nos. 333-181362, 333-195337 and 333-204043 on Form S-8 of our report dated February 22, 2017, relating to the consolidated financial statements and financial statement schedule of Otter Tail Corporation and subsidiaries, and the effectiveness of Otter Tail Corporation and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Otter Tail Corporation and subsidiaries for the year ended December 31, 2016.

 

/s/ Deloitte & Touche LLP  
   
Minneapolis, MN  
   
February 22, 2017  

 

 

 

 

 EX-24.A 8 t1700069_ex24-a.htm EXHIBIT 24-A

 

 

Exhibit 24-A

 

POWER OF ATTORNEY

 

 

  

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints CHARLES S. MACFARLANE, Kevin G. Moug, and GEORGE A. KOECK, and each of them, his or her true and lawful attorneys-in-fact and agents, each acting alone, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report on Form 10-K of Otter Tail Corporation for its fiscal year ended December 31, 2016, and any and all amendments to said Annual Report, and to deliver on my behalf said Annual Report and any and all amendments thereto, as each thereof is so signed, for filing with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite or necessary to be done in and about the premises, as fully as to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitutes, may lawfully do or cause to be done by virtue hereof.

 

IN WITNESS WHEREOF, this Power of Attorney has been signed on the 2nd day of February, 2017 by the following persons:

 

/s/ Karen M. Bohn   /s/ John D. Erickson  
Karen M. Bohn   John D. Erickson  
       
/s/ Steven L. Fritze   /s/ Kathryn O. Johnson  
Steven L. Fritze   Kathryn O. Johnson  
       
/s/ Charles S. MacFarlane   /s/ Kevin G. Moug  
Charles S. MacFarlane   Kevin G. Moug  
       
/s/Timothy J. O’Keefe   /s/Nathan I. Partain  
Timothy J. O’Keefe   Nathan I. Partain  
       
/s/ Joyce Nelson Schuette   /s/ James B. Stake  
Joyce Nelson Schuette   James B. Stake  

 

 

 

 EX-31.1 9 t1700069_ex31-1.htm EXHIBIT 31.1

 

Exhibit 31.1

 

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

 

I, Charles S. MacFarlane, certify that:

 

1.          I have reviewed this Annual Report on Form 10-K of Otter Tail Corporation;

 

2.          Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.          Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.          The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

(a)          designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

(b)          designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

(c)          evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

(d)          disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.          The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

(a)          all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

(b)          any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Date: February 22, 2017

 

/s/ Charles S. MacFarlane  
Charles S. MacFarlane  
President and Chief Executive Officer  

 

 

 EX-31.2 10 t1700069_ex31-2.htm EXHIBIT 31.2

 

Exhibit 31.2

 

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

 

I, Kevin G. Moug, certify that:

 

1.          I have reviewed this Annual Report on Form 10-K of Otter Tail Corporation;

 

2.          Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.          Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.          The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

(a)          designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

(b)          designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

(c)          evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

(d)          disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.          The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

(a)          all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

(b)          any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Date: February 22, 2017

 

/s/ Kevin G. Moug  
Kevin G. Moug  
Chief Financial Officer and Senior Vice President  

 

 

 EX-32.1 11 t1700069_ex32-1.htm EXHIBIT 32.1

 

Exhibit 32.1

 

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

 

In connection with the Annual Report of Otter Tail Corporation (the “Company”) on Form 10-K for the period ended December 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles S. MacFarlane, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

 

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

  /s/ Charles S. MacFarlane
  Charles S. MacFarlane
  President and Chief Executive Officer
  February 22, 2017

 

 

 

 EX-32.2 12 t1700069_ex32-2.htm EXHIBIT 32.2

 

Exhibit 32.2

 

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

 

In connection with the Annual Report of Otter Tail Corporation (the “Company”) on Form 10-K for the period ended December 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kevin G. Moug, Chief Financial Officer and Senior Vice President of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

 

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

  /s/ Kevin G. Moug
  Kevin G. Moug
  Chief Financial Officer and Senior Vice President
  February 22, 2017

 

 

 

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See note 2 to consolidated financial statements for further descriptions of the Company&#8217;s business segments. 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This standard allows for the recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. 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OTP and Northern States Power &#8211; MN (NSP MN), a subsidiary of Xcel Energy Inc., jointly developed this project and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. 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OTP jointly developed this project with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. (MDU), and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. 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Direct testimony of the Minnesota Department of Commerce (MNDOC) included a recommendation for an 8.87% allowed rate of return on equity, and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. Hearings before the Administrative Law Judge (ALJ) occurred in October 2016. 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The MPUC is expected to make its final decision in March 2017 and issue its written order in spring 2017.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>2010 General Rate Case</u>&#8212;OTP&#8217;s most recently completed general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. Pursuant to the order, OTP&#8217;s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Minnesota Conservation Improvement Programs</u>&#8212;Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state's energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">The MNDOC may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the Minnesota Conservation Improvement Program (MNCIP) through the use of an annual recovery mechanism approved by the MPUC.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">On September 26, 2014 the MPUC approved OTP&#8217;s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP&#8217;s most recent general rate case.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">OTP recognized a financial incentive for 2014 of $3.0&#160;million due, in part, to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016. Additionally, OTP saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. On July 9, 2015 the MPUC granted approval of OTP&#8217;s 2014 financial incentive of $3.0&#160;million along with an updated surcharge with an effective date of October 1, 2015.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">Based on results from the 2015 MNCIP program year, OTP recognized a financial incentive of $4.2 million. The 2015 MNCIP program resulted in an approximate 39% increase in energy savings compared to 2014 program results. On April 1, 2016 OTP requested approval for recovery of its 2015 MNCIP program costs not included in base rates, a $4.3 million financial incentive and an update to the MNCIP surcharge from the MPUC. On July 19, 2016 the MPUC issued an order approving OTP&#8217;s request with an effective date of October 1, 2016.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">Based on results from the 2016 MNCIP program year, OTP recognized a financial incentive of $5.1 million in 2016. The 2016 program resulted in an approximate 18% increase in energy savings compared to 2015 program results. OTP will request approval for recovery of its 2016 MNCIP program costs not included in base rates, a $5.1 million financial incentive and an update to the MNCIP surcharge from the MPUC by April 1, 2017.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">On May 25, 2016 the MPUC adopted the MNDOC&#8217;s proposed changes to the MNCIP financial incentive. The new model will provide utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <div style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Transmission Cost Recovery Rider</u>&#8212;The Minnesota Public Utilities Act (the MPU Act) provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority&#160;transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility's retail customers, or exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners&#8217; regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The MPU Act also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Finally, under certain circumstances, the MPU Act also authorizes TCR riders to recover the costs associated with distribution planning and investments in distribution facilities to modernize the utility grid. Such TCR riders allow a return on investment at the level approved in a utility&#8217;s last general rate case. 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In a written order issued on March 10, 2014, the MPUC approved OTP&#8217;s 2013 TCR rider update but found capitalized internal costs, costs in excess of CON estimates and a carrying charge ineligible for recovery through the TCR rider. These items were removed from OTP&#8217;s Minnesota TCR rider effective March 1, 2014. OTP is seeking recovery of the capitalized internal costs and costs in excess of CON estimates in its current general rate case filing in Minnesota. In response to the MPUC&#8217;s approval of OTP&#8217;s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC&#8217;s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP&#8217;s compliance filing on June 19, 2014. On February 18, 2015 the MPUC approved OTP&#8217;s 2014 TCR rider annual update with an effective date of March 1, 2015. OTP filed an annual update to its Minnesota TCR rider on September 30, 2015 requesting revenue recovery of approximately $7.8 million. A supplemental filing to the update was made on December 21, 2015 to address an issue surrounding the proration of accumulated deferred income taxes and, in an unrelated adjustment, the TCR rider update revenue request was reduced to $7.2 million. On March&#160;9, 2016 the MPUC issued an order approving OTP&#8217;s annual update to its TCR rider, with an effective date of April 1, 2016.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">OTP filed an update to its TCR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The proposed rate changes went into effect on September 1, 2016. The MPUC has granted extensions to the MNDOC to file initial comments in this docket until February 2, 2017.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">In OTP&#8217;s 2016 general rate case, the MNDOC has argued that the MPUC should require OTP to include in the TCR rider retail rate base 100% of OTP&#8217;s investment in the Big Stone South &#8211; Brookings and Big Stone South &#8211; Ellendale MVP Projects and all revenues received from other utilities under MISO&#8217;s tariffed rates as a credit in its TCR revenue requirement calculations. OTP has opposed this treatment, arguing that the projects are appropriately assigned to the FERC jurisdiction, and the FERC&#8217;s determination of the projects&#8217; revenue requirements should not be altered by forcing the revenues into the retail revenue requirement calculations. In the general rate case proceeding, the ALJ has recommended that the MPUC should affirm OTP&#8217;s treatment. If the MPUC finds that the MNDOC&#8217;s treatment should be followed, it would result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC&#8217;s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <div style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Environmental Cost Recovery (ECR) Rider</u>&#8212;On December 18, 2013 the MPUC granted approval of OTP&#8217;s Minnesota ECR rider for recovery of OTP&#8217;s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements included a return on the project&#8217;s construction work in progress (CWIP) balance at the level approved in OTP&#8217;s 2010 general rate case. The MPUC approved OTP&#8217;s 2014 ECR rider annual update request on November 24, 2014 with an effective date of December 1, 2014. OTP filed its 2015 annual update on July 31, 2015, with a request to keep the 2014 annual update rate in place. On December 21, 2015 OTP filed a supplemental filing with updated financial information. The MPUC issued an order on March 9, 2016 approving OTP&#8217;s request to leave the 2014 annual update rate in place. OTP filed an update to its Minnesota ECR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request, with an effective date of September 1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis and has since granted extensions to the MNDOC to file initial comments in this docket until February 2, 2017. Reply comments were due from OTP on February 13, 2017.&#160;</div> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Reagent Costs and Emission Allowances</u>&#8212;On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP&#8217;s request to revise its FCA rider to include recovery of these costs. These costs are included in OTP&#8217;s 2016 general rate case in Minnesota and are being considered for recovery either through the FCA rider or general rates. These costs are currently being expensed as incurred.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>North Dakota</u></p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>General Rates</u>&#8212;OTP&#8217;s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009. Pursuant to the order, OTP&#8217;s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Renewable Resource Adjustment</u>&#8212;OTP has a North Dakota Renewable Resource Adjustment (NDRRA) which enables OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment. The NDPSC approved OTP&#8217;s 2013 annual update to its NDRRA on March 12, 2014 with an effective date of April 1, 2014, which resulted in a 13.5% reduction in the NDRRA rate. The NDPSC approved OTP&#8217;s 2014 annual update to the NDRRA, including a change in rate design from an amount per kwh consumed to a percentage of a customer&#8217;s bill, on March 25, 2015 with an effective date of April 1, 2015. OTP submitted its 2015 annual update to the NDRRA rider rate on December 31, 2015 with a requested implementation date of April 1, 2016. On February 25, 2016 OTP made a supplemental filing to address the impact of bonus depreciation for income taxes and related deferred tax assets on the NDRRA, as well as an adjustment to the estimated amount of Federal Production Tax Credits used. The NDPSC approved the NDRRA 2015 annual update on June 22, 2016 with an effective date of July 1, 2016. The updated NDRRA reflects a reduction in the return on equity (ROE) component of the rate from 10.75%, approved in OTP&#8217;s most recent general rate case, to 10.50%. OTP submitted its 2016 annual update to the NDRRA rider rate on December 30, 2016, requesting a decrease to the NDRRA rate from 7.573% to 7.005%, with a requested implementation date of April 1, 2017.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Transmission Cost Recovery Rider</u>&#8212;North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case. The NDPSC approved OTP&#8217;s 2014 annual update to its TCR rider rate on December 17, 2014 with an effective date of January 1, 2015. On August 31, 2015 OTP filed its 2015 annual update to its North Dakota TCR rider rate requesting recovery of approximately $10.2 million for 2016 compared with $8.5&#160;million for 2015, including costs assessed by the MISO as well as new costs from the Southwest Power Pool (SPP) that OTP began incurring January 1, 2016. These new costs are associated with OTP&#8217;s load connected to the transmission system of Central Power Electric Cooperative (CPEC). OTP&#8217;s load became subject to SPP transmission-related charges when CPEC transmission assets were added to the SPP. The NDPSC approved OTP&#8217;s 2015 annual update to its TCR rider rate on December 16, 2015, with an effective date of January 1, 2016. On September 1, 2016 OTP filed its annual update to the TCR rider requesting a revenue requirement of $5.7 million, which includes a reduction of $2.6 million for a projected over-collection for 2016. Primary drivers of the decrease from the 2015 updated rider rate include the impact of federal bonus depreciation and unresolved MISO ROE complaint proceedings. OTP filed a supplemental filing on September 14, 2016, requesting that the over-collection balance be spread over the next two years for purposes of reducing the volatility of the rates from year to year. The NDPSC approved the update on December 14, 2016. The new rates went into effect on January 1, 2017.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Environmental Cost Recovery Rider</u>&#8212;On December 18, 2013 the NDPSC approved OTP&#8217;s request for an ECR rider to recover OTP&#8217;s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. The ECR provides for a current return on CWIP and a return on investment at the level approved in OTP&#8217;s most recent general rate case. On March 31, 2014 OTP filed an annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The NDPSC approved OTP&#8217;s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR. This update included a request to increase the ECR rider rate from 7.531% to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective date of July 1, 2015, along with the approval of recovery of OTP&#8217;s North Dakota jurisdictional share of Hoot Lake Plant MATS project costs.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <div style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">On March 31, 2016 OTP filed its annual update to the ECR rider requesting a reduction in the rate from 9.193% to 7.904% of base rates, or a revenue requirement reduction from $12.2 million to $10.4 million, effective July 1, 2016. The rate reduction request was primarily due to the Company&#8217;s 2015 bonus depreciation election for income taxes, which reduces revenue requirements. The filing was approved on June 22, 2016.&#160;</div> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Reagent Costs and Emission Allowances</u>&#8212;On July 31, 2014 OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance costs. On February 25, 2015 the NDPSC approved recovery of these costs through modification of the ECR rider, instead of recovery through the FCA as OTP had proposed. The ECR rider reagent and emissions allowance charge became effective May 1, 2015.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>South Dakota</u></p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>2010 General Rate Case</u>&#8212;OTP&#8217;s most recent general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued on April 21, 2011 and effective with bills rendered on and after June 1, 2011. Pursuant to the order, OTP&#8217;s allowed rate of return on rate base was set at 8.50%.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Transmission Cost Recovery Rider</u>&#8212;South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. The SDPUC approved OTP&#8217;s 2013 annual update on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP&#8217;s 2014 annual update on February 13, 2015 with an effective date of March 1, 2015. OTP filed its 2015 annual update on October 30, 2015 with a proposed effective date of March 1, 2016. A supplemental filing was made on February 3, 2016 to true-up the filing to include the impact of bonus depreciation elected for 2015, the inclusion of a deferred tax asset relating to a net operating loss and the proration of accumulated deferred income taxes. This update included the recovery of new SPP transmission costs OTP began to incur on January 1, 2016. On February 12, 2016 the SDPUC approved OTP&#8217;s annual update to its TCR rider, with an effective date of March 1, 2016. On November 1, 2016 OTP filed the annual update to the South Dakota TCR rider. OTP made a supplemental filing on January&#160;20, 2017 to include updated costs through December 2016 as well as updated forecast information. The proposed effective date of the new rates is March 1, 2017.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Environmental Cost Recovery Rider</u>&#8212;On November 25, 2014 the SDPUC approved OTP&#8217;s ECR rider request to recover OTP&#8217;s South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014. On August 31, 2015 OTP filed its annual update to the South Dakota ECR requesting recovery of approximately $2.7 million in annual revenue. The SDPUC approved the request on October 15, 2015 with an effective date of November 1, 2015. On August 31, 2016 OTP filed its 2016 update to the ECR rider, requesting recovery of approximately $2.3 million in annual revenue. The SDPUC approved the request on October 26, 2016 with an effective date of November 1, 2016. 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font-stretch: normal; -webkit-text-stroke-width: 0px;">Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935, as amended. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. 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MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. 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The complainants sought to reduce the 12.38% ROE used in MISO&#8217;s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. On October 16, 2014 the FERC issued an order finding that the current MISO ROE may be unjust and unreasonable and setting the issue for hearing. Parties, including OTP, sought rehearing of the FERC&#8217;s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the United States Court of Appeals for the District of Columbia (D.C. Circuit). A non-binding decision by the presiding ALJ was issued on December 22, 2015 finding that the MISO transmission owners&#8217; ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP&#8217;s incentive rate filing, OTP&#8217;s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. Parties, including OTP, sought rehearing of the FERC&#8217;s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the D.C. Circuit. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners&#8217; ROE should be 9.7%. 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margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-size-adjust: none; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p><p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-size-adjust: none; font-stretch: normal; -webkit-text-stroke-width: 0px;">Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market&#8217;s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. 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Therefore, the Company cannot estimate OTP&#8217;s exposure at this time from a final order reversing the relevant FERC orders. 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The most significant contingencies impacting the Company&#8217;s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. 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The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of December 31, 2016 will not be material.</div></div> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-size-adjust: none; font-stretch: normal; -webkit-text-stroke-width: 0px;"><b>10. 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The weighted average interest rate paid on debt outstanding under the Otter Tail Corporation Credit Agreement during 2016 was 2.3% compared with 2.0% in 2015. Under the OTP Credit Agreement (as defined below), the maximum amount of debt outstanding in 2016 was $51,885,000 on December 16, 2016 and the average daily balance of debt outstanding during 2016 was $32,576,000. The weighted average interest rate paid on debt outstanding under the OTP Credit Agreement during 2016 was 1.8% compared with 1.5% in 2015. The maximum amount of consolidated short-term debt outstanding in 2016 was $87,211,000 on January 25, 2016 and the average daily balance of consolidated short-term debt outstanding during 2016 was $48,776,000. 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The Company&#8217;s obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of the Company&#8217;s subsidiaries. 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The 2026 Notes were issued on December 13, 2016. The Company&#8217;s obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by its Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). 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The Company is required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if the Company and its Material Subsidiaries sell a &#8220;substantial part&#8221; of its or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes.</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-size-adjust: none; font-stretch: normal; -webkit-text-stroke-width: 0px;">&#160;</p> <p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-size-adjust: none; font-stretch: normal; -webkit-text-stroke-width: 0px;">The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and the Material Subsidiaries that became effective on execution of the 2016 Note Purchase Agreement. 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The Term Loan Agreement provides for an unsecured term loan with an aggregate commitment of $50 million that the Company may use for purposes of funding working capital, capital expenditures and other corporate purposes of the Company and certain of our subsidiaries. Under the Term Loan Agreement, the Company may, on up to two occasions, enter into additional tranches of term loans in minimum increments of $10 million, subject to the consent of the lenders and so long as the aggregate amount of outstanding term loans does not exceed $100 million at any time. Borrowings under the Term Loan Agreement will bear interest at either (1) LIBOR plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve Bank of New York Rate plus 0.50% and (c) LIBOR multiplied by the Statutory Reserve Rate plus 1%. The applicable interest rate will depend on the Company&#8217;s election of whether to make the advance a LIBOR advance. 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color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">The consolidated financial statements of Otter Tail Corporation and its wholly owned subsidiaries (the Company) include the accounts of the following segments: Electric, Manufacturing and Plastics. See note 2 to consolidated financial statements for further descriptions of the Company&#8217;s business segments. All intercompany balances and transactions have been eliminated in consolidation except profits on sales to the regulated electric utility company from nonregulated affiliates, which is in accordance with the requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980,&#160;<i>Regulated Operations</i>&#160;(ASC 980).</div></div> <div><p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;"><u>Regulation and ASC 980</u></p><p style="font: 10pt/normal 'times new roman', times, serif; margin: 0px; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-stretch: normal; -webkit-text-stroke-width: 0px;">The Company&#8217;s regulated electric utility company, Otter Tail Power Company (OTP), accounts for the financial effects of regulation in accordance with ASC 980. This standard allows for the recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. 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The amount of interest capitalized on electric utility plant was $495,000 in 2016, $723,000 in 2015 and $689,000 in 2014. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are charged against the accumulated reserve for estimated removal costs, a regulatory liability. Maintenance, repairs and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated remaining service lives of the properties (5 to 82 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.88% in 2016, 2.61% in 2015 and 2.89% in 2014. 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The cost of additions includes contracted work, direct labor and materials, allocable overheads and capitalized interest. No interest was capitalized on nonelectric plant in 2016, 2015 or 2014. Maintenance and repairs are expensed as incurred. 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With the purchase of BTD-Georgia on September 1, 2015, the Company acquired customer relationships valued at $4,870,000 to be amortized over 20 years and the seller entered into a covenant not to compete valued at $620,000 to be amortized over three years. The final purchase price adjustment agreed to in June 2016 resulted in an $810,000 increase in the fair value of acquired customer relationships and a $30,000 reduction in the fair value of the covenant not to compete. The changes in the value of these intangibles had an insignificant impact on the Company&#8217;s consolidated net income in 2016 related to a change in amortization expense that would have been recorded in 2015 had the adjusted asset values been established on acquisition in 2015. 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Should the Company be required to recognize these contributions as revenue under ASU 2014-09, it could result in a significant increase in reported revenues and expenses. Adoption of ASU&#160;2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard. 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border-bottom-style: double;">14,958</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: center; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-indent: 1pt; padding-left: 1pt;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: center;">&#160;</td></tr><tr style="vertical-align: bottom; 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font-family: 'times new roman', times, serif; font-size: 13.33px; font-style: italic; font-weight: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-variant-ligatures: normal; font-variant-caps: normal; -webkit-text-stroke-width: 0px;"><sup>1</sup>&#160;Corporate cost included in Other Nonelectric Expenses.</td><td style="color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; font-family: 'times new roman', times, serif; font-size: 13.33px; font-style: normal; font-weight: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-variant-ligatures: normal; font-variant-caps: normal; -webkit-text-stroke-width: 0px;">&#160;</td><td style="text-align: left; color: #000000; text-transform: none; text-indent: 0px; letter-spacing: normal; font-family: 'times new roman', times, serif; font-size: 13.33px; font-style: normal; font-weight: normal; word-spacing: 0px; white-space: normal; orphans: 2; widows: 2; font-variant-ligatures: normal; 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padding-bottom: 2px; font-style: italic;">&#160;</td><td style="padding-bottom: 2px; font-style: italic;">&#160;</td><td style="text-align: left; padding-bottom: 2px; font-style: italic;">&#160;</td><td style="text-align: right; padding-bottom: 2px; font-style: italic;">&#160;</td><td style="text-align: left; padding-bottom: 2px; font-style: italic;">&#160;</td><td style="padding-bottom: 2px; font-style: italic;">&#160;</td><td style="text-align: left; padding-bottom: 2px; font-style: italic;">&#160;</td><td style="text-align: right; padding-bottom: 2px; font-style: italic;">&#160;</td><td style="text-align: left; padding-bottom: 2px; font-style: italic;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="text-align: left; font-style: italic;"><sup>2</sup>&#160;&#160;Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; 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Net Amount Recognized</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">(62,571</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">)</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">(48,730</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">)</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="text-align: left;">Accumulated Other Comprehensive (Income) Loss:</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; padding-left: 0.125in;">Unrecognized Prior Service Cost</td><td>&#160;</td><td style="text-align: left;">$</td><td style="text-align: right;">4</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">$</td><td style="text-align: right;">8</td><td style="text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="text-align: left; padding-left: 0.125in; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">Unrecognized Net Actuarial Gain</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">(171</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">)</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">(347</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">)</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; padding-left: 0.25in; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">Accumulated Other Comprehensive Income</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">(167</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">)</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">(339</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">)</td></tr></table></div> <div><table style="font: 10pt/normal 'times new roman', times, serif; width: 100%; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; border-collapse: collapse; orphans: 2; widows: 2; font-size-adjust: none; font-stretch: normal; -webkit-text-stroke-width: 0px;" border="0" cellspacing="0" cellpadding="0"><tr style="vertical-align: bottom;"><td style="font-style: italic; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;" nowrap="nowrap">(in thousands)</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;" colspan="2" nowrap="nowrap">2016</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;" colspan="2" nowrap="nowrap">2015</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; padding-left: 0in;">Regulatory Assets:</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="width: 1148px; text-align: left; padding-left: 0.125in;">Unrecognized Prior Service Cost</td><td style="width: 16px;">&#160;</td><td style="width: 16px; text-align: left;">$</td><td style="width: 157px; text-align: right;">58</td><td style="width: 16px; text-align: left;">&#160;</td><td style="width: 16px;">&#160;</td><td style="width: 15px; text-align: left;">$</td><td style="width: 156px; text-align: right;">75</td><td style="width: 15px; text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; padding-left: 0.125in; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">Unrecognized Actuarial Loss</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">2,890</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">2,936</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="text-align: left; padding-left: 0.25in; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">Total Regulatory Assets</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">2,948</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">3,011</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">Projected Benefit Obligation Liability &#8211; Net Amount Recognized</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">(37,335</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">)</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">(35,811</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">)</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="text-align: left;">Accumulated Other Comprehensive Loss:</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; padding-left: 0.125in;">Unrecognized Prior Service Cost</td><td>&#160;</td><td style="text-align: left;">$</td><td style="text-align: right;">134</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">$</td><td style="text-align: right;">172</td><td style="text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="text-align: left; padding-left: 0.125in; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">Unrecognized Actuarial Loss</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">5,915</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">5,815</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; padding-left: 0.25in; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">Total Accumulated Other Comprehensive Loss</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">6,049</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">5,987</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td></tr></table></div> <div><table align="center" style="font: 10pt/normal 'times new roman', times, serif; width: 90%; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; border-collapse: collapse; orphans: 2; widows: 2; font-size-adjust: none; font-stretch: normal; -webkit-text-stroke-width: 0px;" border="0" cellspacing="0" cellpadding="0"><tr style="vertical-align: bottom;"><td style="text-align: left; font-style: italic; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;" nowrap="nowrap">(in thousands)</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: center; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;" colspan="2" nowrap="nowrap">2016</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: center; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;" colspan="2" nowrap="nowrap">2015</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left;">Regulatory Assets:</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="width: 1032px; text-align: left; padding-left: 0.125in;">Unrecognized Prior Service Cost</td><td style="width: 14px;">&#160;</td><td style="width: 14px; text-align: left;">$</td><td style="width: 141px; text-align: right;">141</td><td style="width: 14px; text-align: left;">&#160;</td><td style="width: 14px;">&#160;</td><td style="width: 14px; text-align: left;">$</td><td style="width: 141px; text-align: right;">329</td><td style="width: 14px; text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; padding-left: 0.125in; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">Unrecognized Actuarial Loss</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">98,039</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">101,974</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="text-align: left; padding-left: 0.25in; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">Total Regulatory Assets</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">98,180</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">102,303</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left;">Accumulated Other Comprehensive Loss:</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">&#160;</td><td style="text-align: right;">&#160;</td><td style="text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="text-align: left; padding-left: 0.125in;">Unrecognized Prior Service Cost</td><td>&#160;</td><td style="text-align: left;">$</td><td style="text-align: right;">12</td><td style="text-align: left;">&#160;</td><td>&#160;</td><td style="text-align: left;">$</td><td style="text-align: right;">16</td><td style="text-align: left;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; padding-left: 0.125in; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">Unrecognized Actuarial Loss</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">406</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">820</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2px; border-bottom-style: solid;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: white;"><td style="text-align: left; padding-left: 0.25in; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">Total Accumulated Other Comprehensive Loss</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">418</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">836</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td></tr><tr style="vertical-align: bottom; background-color: azure;"><td style="text-align: left; padding-left: 0in; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">Noncurrent Liability</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">60,292</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">$</td><td style="text-align: right; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">69,101</td><td style="text-align: left; border-bottom-color: black; border-bottom-width: 2.5pt; border-bottom-style: double;">&#160;</td></tr></table></div> <div><table style="font: 10pt/normal 'times new roman', times, serif; width: 100%; text-transform: none; text-indent: 0px; letter-spacing: normal; word-spacing: 0px; 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The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. 10000000 LIBOR plus 0.90% 1.00 0.60 0.60 1.00 1.00 0.60 1.50 1.00 1.50 1.00 50000000 0.60 <div>Financial Covenants The Company and OTP were in compliance with the financial covenants in these debt agreements as of December 31, 2016. No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies. The Company's and OTP's borrowing agreements are subject to certain financial covenants. Specifically:&#183; Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, the Company may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis) as provided in the agreements.&#183; Under the 2016 Note Purchase Agreement, the Company may not permit its Priority Indebtedness to exceed 10% of its Total Capitalization. The Company had no Priority Indebtedness outstanding as of December 31, 2016.&#183; Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.&#183; Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement.&#183; Under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement. 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Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. Accumulated Other Comprehensive Loss on December 31 is comprised of the following: (in thousands) 2016 2015 2014 Unrealized (Loss) Gain on Marketable Equity Securities: Before Tax $ (29) $ (12) $ 40 Tax Effect 10 4 (14) Unrealized (Loss) Gain on Marketable Equity Securities net-of-tax (19) (8) 26 Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits: Before Tax (6,300) (6,484) (7,815) Tax Effect 2,519 2,594 3,126 Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits net-of-tax (3,781) (3,890) (4,689) Accumulated Other Comprehensive Loss: Before Tax (6,329) (6,496) (7,775) Tax Effect 2,529 2,598 3,112 Net Accumulated Other Comprehensive Loss $ (3,800) $ (3,898) $ (4,663) See accompanying notes to consolidated financial statements. Includes MNCIP costs recovered in base rates. Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff). Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $ 17,382 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 17,382 $ 15,871. Expenses prior to 2016 are not restated to reflect what would have been expensed had the performance-to-date value of the outstanding awards been based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards. Corporate cost included in Other Nonelectric Expenses. Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 15 $ 15 $ 20 Other Nonelectric Expenses 23 23 31 Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 272 $ 310 $ 132 Other Nonelectric Expenses 174 292 (86) Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds. Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund. On December 30, 2016 the Company instructed the pension fund manager to sell the pension fund investment in the SEI Special Situation Collective Investment Trust Fund. 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Document and Entity Information - USD ($)
 12 Months Ended
Dec. 31, 2016
Feb. 10, 2017
Jun. 30, 2016
Document and Entity Information [Abstract]      
Entity Registrant Name Otter Tail Corp    
Entity Central Index Key 0001466593    
Trading Symbol ottr    
Entity Current Reporting Status Yes    
Entity Voluntary Filers No    
Current Fiscal Year End Date --12-31    
Entity Filer Category Large Accelerated Filer    
Entity Well-Known Seasoned Issuer Yes    
Entity Common Stock, Shares Outstanding   39,410,825  
Entity Public Float     $ 1,260,418,253
Document Type 10-K    
Document Period End Date Dec. 31, 2016    
Amendment Flag false    
Document Fiscal Year Focus 2016    
Document Fiscal Period Focus FY    

XML 25 R2.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Balance Sheets - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Current Assets    
Cash and Cash Equivalents
Accounts Receivable:    
Trade (less allowance for doubtful accounts of $1,246 for 2016 and $1,262 for 2015) 68,242 62,974
Other 5,850 9,073
Inventories 83,740 85,416
Unbilled Revenues 20,080 17,869
Income Taxes Receivable 662 4,000
Regulatory Assets 21,297 18,904
Other 8,144 8,453
Total Current Assets 208,015 206,689
Investments 8,417 8,284
Other Assets 34,104 32,784
Goodwill 37,572 39,732
Other Intangibles - Net 14,958 15,673
Regulatory Assets 132,094 127,707
Plant    
Electric Plant in Service 1,860,357 1,820,763
Nonelectric Operations 211,826 201,343
Construction Work in Progress 153,261 79,612
Total Gross Plant 2,225,444 2,101,718
Less Accumulated Depreciation and Amortization 748,219 713,904
Net Plant 1,477,225 1,387,814
Total Assets 1,912,385 1,818,683
Current Liabilities    
Short-Term Debt 42,883 80,672
Current Maturities of Long-Term Debt 33,201 52,422
Accounts Payable 89,350 89,499
Accrued Salaries and Wages 17,497 16,182
Accrued Taxes 16,000 14,827
Other Accrued Liabilities 15,377 15,416
Liabilities of Discontinued Operations 1,363 2,098
Total Current Liabilities 215,671 271,116
Pensions Benefit Liability 97,627 104,912
Other Postretirement Benefits Liability 62,571 48,730
Other Noncurrent Liabilities 21,706 23,854
Commitments and Contingencies (note 9)
Deferred Credits    
Deferred Income Taxes 226,591 207,669
Deferred Tax Credits 22,849 24,506
Regulatory Liabilities 82,433 77,432
Other 7,492 11,595
Total Deferred Credits 339,365 321,202
Capitalization (page 66)    
Long-Term Debt - Net 505,341 443,846
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2016 - 39,348,136 Shares; 2015 - 37,857,186 Shares 196,741 189,286
Premium on Common Shares 337,684 293,610
Retained Earnings 139,479 126,025
Accumulated Other Comprehensive Loss (3,800) (3,898)
Total Common Equity 670,104 605,023
Total Capitalization 1,175,445 1,048,869
Total Liabilities and Equity 1,912,385 1,818,683
Cumulative Preferred Shares    
Capitalization (page 66)    
Cumulative Shares
Cumulative Preference Shares    
Capitalization (page 66)    
Cumulative Shares
XML 26 R3.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Balance Sheets (Parentheticals) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Trade, allowance for doubtful accounts (in dollars) $ 1,246 $ 1,262
Common shares, par value (in dollars per share) $ 5 $ 5
Common shares, authorized 50,000,000 50,000,000
Common shares, outstanding 39,348,136 37,857,186
Cumulative Preferred Shares    
Cumulative shares, authorized 1,500,000 1,500,000
Cumulative shares, without par value (in dollars per share) $ 0 $ 0
Cumulative shares, outstanding 0 0
Cumulative Preference Shares    
Cumulative shares, authorized 1,000,000 1,000,000
Cumulative shares, without par value (in dollars per share) $ 0 $ 0
Cumulative shares, outstanding 0 0
XML 27 R4.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Statements of Income - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Operating Revenues      
Electric $ 427,349 $ 407,039 $ 407,629
Product Sales 376,190 372,765 391,633
Total Operating Revenues 803,539 779,804 799,262
Operating Expenses      
Production Fuel - Electric 54,792 42,744 67,216
Purchased Power - Electric System Use 63,226 78,150 65,848
Electric Operation and Maintenance Expenses 151,225 140,768 141,936
Cost of Products Sold (depreciation included below) 295,222 295,032 308,069
Other Nonelectric Expenses 40,264 40,021 45,981
Depreciation and Amortization 73,445 60,363 58,074
Property Taxes - Electric 14,266 13,512 12,607
Total Operating Expenses 692,440 670,590 699,731
Operating Income 111,099 109,214 99,531
Interest Charges 31,886 31,160 29,648
Other Income 2,905 2,177 3,557
Income Before Income Taxes - Continuing Operations 82,118 80,231 73,440
Income Tax Expense - Continuing Operations 20,081 21,642 16,557
Net Income from Continuing Operations 62,037 58,589 56,883
Discontinued Operations      
Income (Loss) - net of Income Tax Expense (Benefit) of $138 in 2016, ($1,539) in 2015 and $3,952 in 2014 284 (5,404) 6,445
Impairment Loss - net of Income Tax (Benefit) of $0 in 2015 and 2014   (1,000) (5,605)
Gain on Disposition - net of Income Tax Expense of $4,530 in 2015   7,160  
Net Income from Discontinued Operations 284 756 840
Total Net Income $ 62,321 $ 59,345 $ 57,723
Average Number of Common Shares Outstanding - Basic 38,546 37,495 36,514
Average Number of Common Shares Outstanding - Diluted 38,731 37,668 36,753
Basic Earnings Per Common Share:      
Continuing Operations (in dollars per share) $ 1.61 $ 1.56 $ 1.56
Discontinued Operations (in dollars per share) 0.01 0.02 0.02
Earnings Per Share, Basic, Total (in dollars per share) 1.62 1.58 1.58
Diluted Earnings Per Common Share:      
Continuing Operations (in dollars per share) 1.60 1.56 1.55
Discontinued Operations (in dollars per share) 0.01 0.02 0.02
Earnings Per Share, Diluted, Total (in dollars per share) 1.61 1.58 1.57
Dividends Declared Per Common Share (in dollars per share) $ 1.25 $ 1.23 $ 1.21
XML 28 R5.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Statements of Income (Parentheticals) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Statement [Abstract]      
Income tax expense (benefit) on income from discontinued operations $ 138 $ (1,539) $ 3,952
Income tax (benefit) on impairment loss on discontinued operations   0 $ 0
Income tax expense of (loss) gain on disposition of discontinued operations   $ 4,530  
XML 29 R6.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Statements of Comprehensive Income - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Statement Of Income and Comprehensive Income [Abstract]      
Net Income $ 62,321 $ 59,345 $ 57,723
Unrealized Loss on Available-for-Sale Securities:      
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period (3) (3) (19)
Losses Arising During Period (14) (49) (14)
Income Tax Benefit 6 18 12
Change in Unrealized Losses on Available-for-Sale Securities - net-of-tax (11) (34) (21)
Pension and Postretirement Benefit Plans:      
Actuarial (Losses) Gains Net of Regulatory Allocation Adjustment (445) 510 (5,048)
Amortization of Unrecognized Postretirement Benefit Costs (note 11) 628 821 192
Income Tax (Expense) Benefit (74) (532) 1,942
Pension and Postretirement Benefit Plans - net-of-tax 109 799 (2,914)
Total Other Comprehensive Income (Loss) 98 765 (2,935)
Total Comprehensive Income $ 62,419 $ 60,110 $ 54,788
XML 30 R7.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Statements of Common Shareholders' Equity - USD ($)
$ in Thousands
Common Shares
Premium on Common Shares
Retained Earnings
Accumulated Other Comprehensive Income/(Loss)
Total
Balance at Dec. 31, 2013 $ 181,358 $ 255,759 $ 99,441 $ (1,728) [1] $ 534,830
Balance (in shares) at Dec. 31, 2013 36,271,696        
Increase (Decrease) in Stockholders' Equity [Roll Forward]          
Common Stock Issuances, Net of Expenses $ 4,857 21,057     25,914
Common Stock Issuances, Net of Expenses (in shares) 971,286        
Common Stock Retirements $ (125) (465)     (590)
Common Stock Retirements (in shares) (24,929)        
Net Income     57,723   57,723
Other Comprehensive Income (Loss)       (2,935) (2,935)
Tax Benefit - Stock Compensation   302     302
Employee Stock Incentive Plan Expense   1,783     1,783
Common Dividends ( $1.21, $1.23 and $1.25 per share for the year ended December 2014, 2015 and 2016 respectively)     (44,261)   (44,261)
Balance at Dec. 31, 2014 $ 186,090 278,436 112,903 (4,663) [1] 572,766
Balance (in shares) at Dec. 31, 2014 37,218,053        
Increase (Decrease) in Stockholders' Equity [Roll Forward]          
Common Stock Issuances, Net of Expenses $ 3,453 14,715     18,168
Common Stock Issuances, Net of Expenses (in shares) 690,485        
Common Stock Retirements $ (257) (1,339)     (1,596)
Common Stock Retirements (in shares) (51,352)        
Net Income     59,345   59,345
Other Comprehensive Income (Loss)       765 765
Tax Benefit - Stock Compensation   82     82
Employee Stock Incentive Plan Expense   1,716     1,716
Common Dividends ( $1.21, $1.23 and $1.25 per share for the year ended December 2014, 2015 and 2016 respectively)     (46,223)   (46,223)
Balance at Dec. 31, 2015 $ 189,286 293,610 126,025 (3,898) [1] $ 605,023
Balance (in shares) at Dec. 31, 2015 37,857,186       37,857,186
Increase (Decrease) in Stockholders' Equity [Roll Forward]          
Common Stock Issuances, Net of Expenses $ 7,473 38,490     $ 45,963
Common Stock Issuances, Net of Expenses (in shares) 1,494,618        
Common Stock Retirements $ (18) (86)     (104)
Common Stock Retirements (in shares) (3,668)        
Net Income     62,321   62,321
Other Comprehensive Income (Loss)       98 98
Employee Stock Incentive Plan Expense   3,178     3,178
ASU 2016-09 Adoption at Dec. 31, 2016 2,492 (623) 1,869
Increase (Decrease) in Stockholders' Equity [Roll Forward]          
Common Dividends ( $1.21, $1.23 and $1.25 per share for the year ended December 2014, 2015 and 2016 respectively)     (48,244)   (48,244)
Balance at Dec. 31, 2016 $ 196,741 $ 337,684 $ 139,479 $ (3,800) [1] $ 670,104
Balance (in shares) at Dec. 31, 2016 39,348,136       39,348,136
[1] Accumulated Other Comprehensive Loss on December 31 is comprised of the following: (in thousands) 2016 2015 2014 Unrealized (Loss) Gain on Marketable Equity Securities: Before Tax $ (29) $ (12) $ 40 Tax Effect 10 4 (14) Unrealized (Loss) Gain on Marketable Equity Securities net-of-tax (19) (8) 26 Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits: Before Tax (6,300) (6,484) (7,815) Tax Effect 2,519 2,594 3,126 Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits net-of-tax (3,781) (3,890) (4,689) Accumulated Other Comprehensive Loss: Before Tax (6,329) (6,496) (7,775) Tax Effect 2,529 2,598 3,112 Net Accumulated Other Comprehensive Loss $ (3,800) $ (3,898) $ (4,663) See accompanying notes to consolidated financial statements.
XML 31 R8.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Statements of Common Shareholders' Equity (Parentheticals) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]      
Accumulated Other Comprehensive Income (Loss), Before Tax $ (6,329) $ (6,496) $ (7,775)
Accumulated Other Comprehensive Income (Loss), Tax Effect 2,529 2,598 3,112
Accumulated Other Comprehensive Income (Loss), net-of-tax (3,800) (3,898) (4,663)
Unrealized (Loss) Gain on Marketable Equity Securities:      
Accumulated Other Comprehensive Income (Loss) [Line Items]      
Accumulated Other Comprehensive Income (Loss), Before Tax (29) (12) 40
Accumulated Other Comprehensive Income (Loss), Tax Effect 10 4 (14)
Accumulated Other Comprehensive Income (Loss), net-of-tax (19) (8) 26
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits:      
Accumulated Other Comprehensive Income (Loss) [Line Items]      
Accumulated Other Comprehensive Income (Loss), Before Tax (6,300) (6,484) (7,815)
Accumulated Other Comprehensive Income (Loss), Tax Effect 2,519 2,594 3,126
Accumulated Other Comprehensive Income (Loss), net-of-tax $ (3,781) $ (3,890) $ (4,689)
XML 32 R9.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Statements of Common Shareholders' Equity (Parentheticals 1) - $ / shares
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Statement Of Stockholders' Equity [Abstract]      
Dividends Declared Per Common Share (in dollars per share) $ 1.25 $ 1.23 $ 1.21
XML 33 R10.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Statements of Cash Flows - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Cash Flows from Operating Activities      
Net Income $ 62,321 $ 59,345 $ 57,723
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:      
Net Gain from Sale of Discontinued Operations   (7,160)  
Net (Income) Loss from Discontinued Operations (284) 6,404 (840)
Depreciation and Amortization 73,445 60,363 58,074
Deferred Tax Credits (1,657) (1,878) (1,904)
Deferred Income Taxes 19,124 26,027 28,204
Change in Deferred Debits and Other Assets (10,090) 11,407 (50,361)
Discretionary Contribution to Pension Fund (10,000) (10,000) (20,000)
Change in Noncurrent Liabilities and Deferred Credits 14,685 20,524 58,442
Allowance for Equity/Other Funds Used During Construction (857) (1,303) (1,543)
Change in Derivatives Net of Regulatory Deferral   (14,736) 519
Stock Compensation Expense - Equity Awards 3,178 1,716 1,783
Other - Net 7 (80) 601
Cash (Used for) Provided by Current Assets and Current Liabilities:      
Change in Receivables (944) (1,746) (4,647)
Change in Inventories 1,874 1,960 (12,577)
Change in Other Current Assets (2,541) (210) (579)
Change in Payables and Other Current Liabilities 11,941 (15,150) 10,296
Change in Interest Payable and Income Taxes Receivable/Payable 3,339 (3,943) 2,578
Net Cash Provided by Continuing Operations 163,541 131,540 125,769
Net Cash Used in Discontinued Operations (155) (14,000) (13,295)
Net Cash Provided by Operating Activities 163,386 117,540 112,474
Cash Flows from Investing Activities      
Capital Expenditures (161,259) (160,084) (163,582)
Proceeds from Disposal of Noncurrent Assets 4,837 3,590 2,467
Acquisition Purchase Price Cash Received (Paid) 1,500 (30,806)  
Cash Used for Investments and Other Assets (4,402) (6,302) (2,785)
Net Cash Used in Investing Activities - Continuing Operations (159,324) (193,602) (163,900)
Net Proceeds from Sale of Discontinued Operations   39,401  
Net Cash Used in Investing Activities - Discontinued Operations   (1,769) (596)
Net Cash Used in Investing Activities (159,324) (155,970) (164,496)
Cash Flows from Financing Activities      
Change in Checks Written in Excess of Cash (3,363) 2,857 1,236
Net Short-Term (Repayments) Borrowings (37,789) 69,818 (40,341)
Proceeds from Issuance of Common Stock 44,435 14,233 26,259
Common Stock Issuance Expenses (562) (451) (673)
Payments for Retirement of Capital Stock (104) (1,596) (590)
Proceeds from Issuance of Long-Term Debt 130,000   150,000
Short-Term and Long-Term Debt Issuance Expenses (888) (312) (856)
Payments for Retirement of Long-Term Debt (87,547) (212) (41,088)
Dividends Paid and Other Distributions (48,244) (46,223) (44,261)
Net Cash (Used in) Provided by Financing Activities - Continuing Operations (4,062) 38,114 49,686
Net Cash Provided by Financing Activities - Discontinued Operations   316 1,178
Net Cash (Used in) Provided by Financing Activities (4,062) 38,430 50,864
Net Change in Cash and Cash Equivalents - Discontinued Operations (849)
Net Change in Cash and Cash Equivalents (2,007)
Cash and Cash Equivalents at Beginning of Period 2,007
Cash and Cash Equivalents at End of Period
XML 34 R11.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Statements of Capitalization - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Schedule of Capitalization [Line Items]    
Short-Term Debt $ 42,883 $ 80,672
Long-Term Debt 540,942 498,489
Less: Current Maturities - Otter Tail Corporation 33,201 52,422
Unamortized Debt Discount - Otter Tail Corporation 2,400 2,221
Total Long-Term Debt 505,341 443,846
Total Common Shareholders' Equity 670,104 605,023
Total Capitalization 1,175,445 1,048,869
Cumulative Preferred Shares    
Schedule of Capitalization [Line Items]    
Cumulative Shares
Cumulative Preference Shares    
Schedule of Capitalization [Line Items]    
Cumulative Shares
9.000% Notes, due December 15, 2016    
Schedule of Capitalization [Line Items]    
Long-Term Debt   52,330
North Dakota Development Note, 3.95%, due April 1, 2018    
Schedule of Capitalization [Line Items]    
Long-Term Debt 106 182
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021    
Schedule of Capitalization [Line Items]    
Long-Term Debt 836 977
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017    
Schedule of Capitalization [Line Items]    
Long-Term Debt 33,000 33,000
Senior Unsecured Notes 4.63%, due December 1, 2021    
Schedule of Capitalization [Line Items]    
Long-Term Debt 140,000 140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022    
Schedule of Capitalization [Line Items]    
Long-Term Debt 30,000 30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027    
Schedule of Capitalization [Line Items]    
Long-Term Debt 42,000 42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029    
Schedule of Capitalization [Line Items]    
Long-Term Debt 60,000 60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037    
Schedule of Capitalization [Line Items]    
Long-Term Debt 50,000 50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044    
Schedule of Capitalization [Line Items]    
Long-Term Debt 90,000 90,000
Otter Tail Corporation    
Schedule of Capitalization [Line Items]    
Short-Term Debt   59,666
Long-Term Debt 95,942 53,489
Less: Current Maturities - Otter Tail Corporation 231 52,422
Unamortized Debt Discount - Otter Tail Corporation 539 122
Total Long-Term Debt 95,172 945
Total Capitalization 765,276 605,968
Otter Tail Corporation | Otter Tail Corporation Credit Agreement    
Schedule of Capitalization [Line Items]    
Short-Term Debt 59,666
Otter Tail Corporation | Otter Tail Power Company Credit Agreement    
Schedule of Capitalization [Line Items]    
Short-Term Debt 42,883 21,006
Otter Tail Corporation | 9.000% Notes, due December 15, 2016    
Schedule of Capitalization [Line Items]    
Long-Term Debt 52,330
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018    
Schedule of Capitalization [Line Items]    
Long-Term Debt 15,000
Otter Tail Corporation | 3.55% Guaranteed Senior Notes, due December 15, 2026    
Schedule of Capitalization [Line Items]    
Long-Term Debt 80,000
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018    
Schedule of Capitalization [Line Items]    
Long-Term Debt 106 182
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021    
Schedule of Capitalization [Line Items]    
Long-Term Debt 836 977
Otter Tail Power Company    
Schedule of Capitalization [Line Items]    
Short-Term Debt 42,883 21,006
Long-Term Debt 445,000 445,000
Less: Current Maturities - Otter Tail Corporation 32,970
Unamortized Debt Discount - Otter Tail Corporation 1,861 2,099
Total Long-Term Debt 410,169 442,901
Total Capitalization 1,123,168  
Otter Tail Power Company | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017    
Schedule of Capitalization [Line Items]    
Long-Term Debt 33,000 33,000
Otter Tail Power Company | Senior Unsecured Notes 4.63%, due December 1, 2021    
Schedule of Capitalization [Line Items]    
Long-Term Debt 140,000 140,000
Otter Tail Power Company | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022    
Schedule of Capitalization [Line Items]    
Long-Term Debt 30,000 30,000
Otter Tail Power Company | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027    
Schedule of Capitalization [Line Items]    
Long-Term Debt 42,000 42,000
Otter Tail Power Company | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029    
Schedule of Capitalization [Line Items]    
Long-Term Debt 60,000 60,000
Otter Tail Power Company | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037    
Schedule of Capitalization [Line Items]    
Long-Term Debt 50,000 50,000
Otter Tail Power Company | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044    
Schedule of Capitalization [Line Items]    
Long-Term Debt $ 90,000 $ 90,000
XML 35 R12.htm IDEA: XBRL DOCUMENT v3.6.0.2
Consolidated Statements of Capitalization (Parentheticals) - $ / shares
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
9.000% Notes, due December 15, 2016    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate   9.00%
Long-Term Debt, Due Date   Dec. 15, 2016
North Dakota Development Note, 3.95%, due April 1, 2018    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 3.95% 3.95%
Long-Term Debt, Due Date Apr. 01, 2018 Apr. 01, 2018
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 2.54% 2.54%
Long-Term Debt, Due Date Mar. 18, 2021 Mar. 18, 2021
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 5.95% 5.95%
Long-Term Debt, Due Date Aug. 20, 2017 Aug. 20, 2017
Senior Unsecured Notes 4.63%, due December 1, 2021    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 4.63% 4.63%
Long-Term Debt, Due Date Dec. 01, 2021 Dec. 01, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 6.15% 6.15%
Long-Term Debt, Due Date Aug. 20, 2022 Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 6.37% 6.37%
Long-Term Debt, Due Date Aug. 20, 2027 Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 4.68% 4.68%
Long-Term Debt, Due Date Feb. 27, 2029 Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 6.47% 6.47%
Long-Term Debt, Due Date Aug. 20, 2037 Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 5.47% 5.47%
Long-Term Debt, Due Date Feb. 27, 2044 Feb. 27, 2044
Cumulative Preferred Shares    
Schedule of Capitalization [Line Items]    
Cumulative shares, without par value (in dollars per share) $ 0 $ 0
Cumulative shares, authorized 1,500,000 1,500,000
Cumulative shares, outstanding 0 0
Cumulative Preference Shares    
Schedule of Capitalization [Line Items]    
Cumulative shares, without par value (in dollars per share) $ 0 $ 0
Cumulative shares, authorized 1,000,000 1,000,000
Cumulative shares, outstanding 0 0
OTTER TAIL CORPORATION | 9.000% Notes, due December 15, 2016    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 9.00% 9.00%
Long-Term Debt, Due Date Dec. 15, 2016 Dec. 15, 2016
OTTER TAIL CORPORATION | Term Loan, LIBOR plus 0.90%, due February 5, 2018    
Schedule of Capitalization [Line Items]    
Description of variable rate basis LIBOR plus 0.90% LIBOR plus 0.90%
Long-Term Debt, Interest Rate 0.90% 0.90%
Long-Term Debt, Due Date Feb. 05, 2018 Feb. 05, 2018
OTTER TAIL CORPORATION | 3.55% Guaranteed Senior Notes, due December 15, 2026    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 3.55% 3.55%
Long-Term Debt, Due Date Dec. 15, 2026 Dec. 15, 2026
OTTER TAIL CORPORATION | North Dakota Development Note, 3.95%, due April 1, 2018    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 3.95% 3.95%
Long-Term Debt, Due Date Apr. 01, 2018 Apr. 01, 2018
OTTER TAIL CORPORATION | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 2.54% 2.54%
Long-Term Debt, Due Date Mar. 18, 2021 Mar. 18, 2021
Otter Tail Power Company | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 5.95% 5.95%
Long-Term Debt, Due Date Aug. 20, 2017 Aug. 20, 2017
Otter Tail Power Company | Senior Unsecured Notes 4.63%, due December 1, 2021    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 4.63% 4.63%
Long-Term Debt, Due Date Dec. 01, 2021 Dec. 01, 2021
Otter Tail Power Company | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 6.15% 6.15%
Long-Term Debt, Due Date Aug. 20, 2022 Aug. 20, 2022
Otter Tail Power Company | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 6.37% 6.37%
Long-Term Debt, Due Date Aug. 20, 2027 Aug. 20, 2027
Otter Tail Power Company | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 4.68% 4.68%
Long-Term Debt, Due Date Feb. 27, 2029 Feb. 27, 2029
Otter Tail Power Company | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 6.47% 6.47%
Long-Term Debt, Due Date Aug. 20, 2037 Aug. 20, 2037
Otter Tail Power Company | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044    
Schedule of Capitalization [Line Items]    
Long-Term Debt, Interest Rate 5.47% 5.47%
Long-Term Debt, Due Date Feb. 27, 2044 Feb. 27, 2044
XML 36 R13.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2016
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

 

Principles of Consolidation

The consolidated financial statements of Otter Tail Corporation and its wholly owned subsidiaries (the Company) include the accounts of the following segments: Electric, Manufacturing and Plastics. See note 2 to consolidated financial statements for further descriptions of the Company’s business segments. All intercompany balances and transactions have been eliminated in consolidation except profits on sales to the regulated electric utility company from nonregulated affiliates, which is in accordance with the requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, Regulated Operations (ASC 980).

 

Regulation and ASC 980

The Company’s regulated electric utility company, Otter Tail Power Company (OTP), accounts for the financial effects of regulation in accordance with ASC 980. This standard allows for the recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. See note 4 to consolidated financial statements for further discussion.

 

OTP is subject to various state and federal agency regulations. The accounting policies followed by this business are subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company’s nonelectric businesses.

 

Plant, Retirements and Depreciation

Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction. The amount of interest capitalized on electric utility plant was $495,000 in 2016, $723,000 in 2015 and $689,000 in 2014. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are charged against the accumulated reserve for estimated removal costs, a regulatory liability. Maintenance, repairs and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated remaining service lives of the properties (5 to 82 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.88% in 2016, 2.61% in 2015 and 2.89% in 2014. Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates.

 

Property and equipment of nonelectric operations are carried at historical cost or at the then-current replacement cost if acquired in a business combination, and are depreciated on a straight-line basis over the assets’ estimated useful lives (3 to 40 years). The cost of additions includes contracted work, direct labor and materials, allocable overheads and capitalized interest. No interest was capitalized on nonelectric plant in 2016, 2015 or 2014. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.

 

Recoverability of Long-Lived Assets

The Company reviews its long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. The Company determines potential impairment by comparing the carrying amount of the assets with net cash flows expected to be provided by operating activities of the business or related assets. If the sum of the expected future net cash flows is less than the carrying amount of the assets, the Company would recognize an impairment loss. Such an impairment loss would be measured as the amount by which the carrying amount exceeds the fair value of the asset, where fair value is based on the discounted cash flows expected to be generated by the asset.

 

Jointly Owned Facilities

OTP is a joint owner in two coal-fired steam-powered electric generation plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station near Beulah, North Dakota. OTP is also a joint owner, with other regional utilities, in three major in-service transmission lines and two additional major transmission lines under construction. The following table provides OTP’s ownership percentages and amounts included in the Company’s December 31, 2016 and 2015 consolidated balance sheets for OTP’s share of jointly owned assets in each of these jointly owned facilities:

 

Jointly Owned Facilities (dollars in thousands)   OTP
Ownership
Percentage		     Electric Plant
in Service		     Construction
Work in
Progress		     Accumulated
Depreciation		     Net Plant  
December 31, 2016                                        
Big Stone Plant     53.9 %   $ 328,809     $ 23     $ (65,665 )   $ 263,167  
Coyote Station     35.0 %     176,315       113       (101,499 )     74,929  
Fargo-Monticello 345 kV line     14.2 %     78,298       —       (3,511 )     74,787  
Brookings-Southeast Twin Cities 345 kV line1     4.8 %     26,406       —       (924 )     25,482  
Bemidji-Grand Rapids 230 kV line     14.8 %     16,331       —       (1,573 )     14,758  
Big Stone South to Brookings 345 kV line1     50.0 %     —       45,050       —       45,050  
Big Stone South to Ellendale 345 kV line1     50.0 %     —       49,160       —       49,160  
December 31, 2015                                        
Big Stone Plant     53.9 %   $ 327,474     $ (305 )   $ (57,641 )   $ 269,528  
Coyote Station     35.0 %     165,497       7,405       (103,822 )     69,080  
Fargo-Monticello 345 kV line     14.2 %     78,272       —       (2,213 )     76,059  
Brookings-Southeast Twin Cities 345 kV line1     4.8 %     26,189       —       (486 )     25,703  
Bemidji-Grand Rapids 230 kV line     14.8 %     16,331       —       (1,233 )     15,098  
Big Stone South to Brookings 345 kV line1     50.0 %     —       14,210       —       14,210  
Big Stone South to Ellendale 345 kV line1     50.0 %     —       8,335       —       8,335  
1 Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).

 

The Company’s share of direct revenue and expenses of the jointly owned facilities is included in operating revenue and expenses in the consolidated statements of income.

 

Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.

 

If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. Coyote Station started taking delivery of coal and paying for coal and accumulated development fees and capital charges under the LSA in May 2016. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of December 31, 2016 could be as high as $60.6 million, OTP’s 35% share of unrecovered costs.

 

Income Taxes

Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect in the periods when the temporary differences reverse. The Company amortizes investment tax credits over the estimated lives of related property. The Company records income taxes in accordance with ASC Topic 740, Income Taxes, and has recognized in its consolidated financial statements the tax effects of all tax positions that are “more-likely-than-not” to be sustained on audit based solely on the technical merits of those positions as of the balance sheet date. The term “more-likely-than-not” means a likelihood of more than 50%. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes. See note 14 to consolidated financial statements regarding the Company’s accounting for uncertain tax positions.

 

The Company also is required to assess the realizability of its deferred tax assets, taking into consideration the Company’s forecast of future taxable income, the reversal of other existing temporary differences, available net operating loss carryforwards and available tax planning strategies that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, valuation allowances against the Company’s deferred tax assets. To the extent facts and circumstances change in the future, adjustments to the valuation allowance may be required.

 

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, the price is fixed or determinable and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as OTP’s 2015 forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with ASC Topic 815, Derivatives and Hedging (ASC 815). Gains and losses on forward energy contracts subject to regulatory treatment, if any, have been deferred and recognized on a net basis in revenue in the period realized.

 

For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

 

Customer electricity use is metered and bills are rendered monthly. Revenue is accrued for electricity consumed but not yet billed. Rate schedules applicable to substantially all customers include a fuel clause adjustment, under which the rates are adjusted to reflect changes in average cost of fuels and purchased power, and a surcharge for recovery of conservation-related expenses. Revenue is recognized for fuel and purchased power costs incurred in excess of amounts recovered in base rates but not yet billed through the fuel clause adjustment, for conservation program incentives and bonuses earned but not yet billed and for renewable resource, transmission-related and environmental incurred costs and investment returns approved for recovery through riders.

 

Revenues on wholesale electricity sales from Company-owned generating units are recognized when energy is delivered. For shared use of transmission facilities with certain regional transmission cooperatives, revenues are estimated. Bills are rendered based on anticipated usage and settlements are made later based on actual usage. Estimated revenues may be adjusted prior to settlement, or at the time of settlement, to reflect actual usage.

 

Under ASC 815, OTP accounts for forward energy contracts as derivatives subject to mark-to-market accounting unless those contracts meet the definition of a capacity contract or are not subject to unplanned netting, then OTP accounts for the contracts under the normal purchases and sales exception to mark-to-market accounting.

 

Manufacturing and Plastics operating revenues are recorded when products are shipped.

 

Warranty Reserves

Certain products sold by the Company’s manufacturing and plastics companies carry product warranties for one year after the shipment date. These companies’ standard product warranty terms generally include post-sales support and repairs or replacement of a product at no additional charge for a specified period of time. While these companies engage in extensive product quality programs and processes, including actively monitoring and evaluating the quality of their component suppliers, they base their estimated warranty obligations on warranty terms, ongoing product failure rates, repair costs, product call rates, average cost per call, and current period product shipments. The Company’s manufacturing and plastics companies have not incurred any significant warranty costs over the last three fiscal years in continuing operations.

 

Shipping and Handling Costs

The Company includes revenues received for shipping and handling in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of goods sold.

 

Use of Estimates

The Company uses estimates based on the best information available in recording transactions and balances resulting from business operations. As better information becomes available (or actual amounts are known), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

 

Cash Equivalents

The Company considers all highly liquid debt instruments purchased with maturity of 90 days or less to be cash equivalents.

 

Investments

The following table provides a breakdown of the Company’s investments at December 31:

 

(in thousands)   2016     2015  
Cost Method:                
Economic Development Loan Pools   $ 54     $ 81  
Other     115       2,088  
Equity Method Partnerships     23       22  
Marketable Securities Classified as Available-for-Sale     8,225       8,093  
Total Investments   $ 8,417     $ 10,284  
Less: Aevenia, Inc. (AEV, Inc.) Escrow Funds Reported Under Other Current Assets     —       (1,500 )
Foley Company (Foley) Escrow Funds Reported Under Other Current Assets     —       (500 )
Investments   $ 8,417     $ 8,284  

 

The Company’s marketable securities classified as available-for-sale are held for insurance purposes and are reflected at their fair values on December 31, 2016. See further discussion below.

 

Agreements Subject to Legally Enforceable Netting Arrangements

The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.

 

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:

 

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).

 

Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

 

Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.

 

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2016 and December 31, 2015:

 

December 31, 2016 (in thousands)   Level 1     Level 2     Level 3  
Assets:                        
Investments:                        
Corporate Debt Securities – Held by Captive Insurance Company           $ 5,280          
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company             2,945          
Other Assets:                        
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan   $ 849                  
Total Assets   $ 849     $ 8,225          

 

December 31, 2015 (in thousands)   Level 1     Level 2     Level 3  
Assets:                        
Current Assets – Other:                        
Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions   $ 2,000                  
Investments:                        
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company           $ 4,235          
Corporate Debt Securities – Held by Captive Insurance Company             3,858          
Other Assets:                        
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan     196                  
Total Assets   $ 2,196     $ 8,093          
Liabilities:                        
Other Accrued Liabilities:                        
Derivative Liabilities – Forward Gasoline Purchase Contracts           $ 199          
Total Liabilities           $ 199          

 

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

 

Forward Gasoline Purchase Contracts –These contracts were priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods. As of December 31, 2016 OTP held, and currently holds, no RBOB contracts.

 

Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

 

Inventories

Electric segment inventories are reported at average cost. The Manufacturing and Plastics segments’ inventories are stated at the lower of average cost or market. Inventories consist of the following at December 31:

 

(in thousands)   2016     2015  
Finished Goods   $ 27,755     $ 25,971  
Work in Process     11,754       12,821  
Raw Material, Fuel and Supplies     44,231       46,624  
Total Inventories   $ 83,740     $ 85,416  

 

Goodwill and Other Intangible Assets

The Company accounts for goodwill and other intangible assets in accordance with the requirements of ASC Topic 350, Intangibles—Goodwill and Other, measuring its goodwill for impairment annually in the fourth quarter, and more often when events indicate the assets may be impaired. The Company does qualitative assessments of its reporting units with recorded goodwill to determine if it is more likely than not that the fair value of the reporting unit exceeds its book value. The Company also does quantitative assessments of its reporting units with recorded goodwill to determine the fair value of the reporting unit.

 

In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued operations. See note 16 to consolidated financial statements.

 

On September 1, 2015 Miller Welding & Iron Works, Inc. (BTD-Illinois), a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing, Inc. (Impulse) of Dawsonville, Georgia. The acquired business operates under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference in the fair value of assets acquired and the price paid for Impulse resulted in an initial estimate of acquired goodwill of $8.2 million. A final determination of the purchase price was agreed to in June 2016 resulting in a $2.2 million reduction in acquired goodwill in June 2016. See note 2 to the Company’s consolidated financial statements for more information.

 

The following tables summarize changes to goodwill by business segment during 2016 and 2015:

 

(in thousands)   Gross Balance
December 31, 2015		     Accumulated
Impairments		     Balance (net of
impairments)
December 31, 2015		     Adjustments to
Goodwill in
2016		     Balance (net of
impairments)
December 31, 2016		  
Manufacturing   $ 20,430     $ —     $ 20,430     $ (2,160 )   $ 18,270  
Plastics     19,302       —       19,302       —       19,302  
Total   $ 39,732     $ —     $ 39,732     $ (2,160 )   $ 37,572  
                                         
(in thousands)   Gross Balance
December 31, 2014		     Accumulated
Impairments		     Balance
(net of impairments)
December 31, 2014		     Adjustments
and Additions
to Goodwill
in 2015		     Balance
(net of impairments)
December 31, 2015		  
Manufacturing   $ 12,186     $ —     $ 12,186     $ 8,244     $ 20,430  
Plastics     19,302       —       19,302       —       19,302  
Total   $ 31,488     $ —     $ 31,488     $ 8,244     $ 39,732  

 

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. With the purchase of BTD-Georgia on September 1, 2015, the Company acquired customer relationships valued at $4,870,000 to be amortized over 20 years and the seller entered into a covenant not to compete valued at $620,000 to be amortized over three years. The final purchase price adjustment agreed to in June 2016 resulted in an $810,000 increase in the fair value of acquired customer relationships and a $30,000 reduction in the fair value of the covenant not to compete. The changes in the value of these intangibles had an insignificant impact on the Company’s consolidated net income in 2016 related to a change in amortization expense that would have been recorded in 2015 had the adjusted asset values been established on acquisition in 2015. See note 2 to the Company’s consolidated financial statements for more information.

 

The following table summarizes the components of the Company’s intangible assets at December 31, 2016 and December 31, 2015:

 

December 31, 2016 (in thousands)   Gross Carrying
Amount		     Accumulated
Amortization		     Net Carrying
Amount		     Remaining
Amortization
Periods
Amortizable Intangible Assets:                            
Customer Relationships   $ 22,491     $ 7,861     $ 14,630     36-224 months
Covenant not to Compete     590       262       328     20 months
Total   $ 23,081     $ 8,123     $ 14,958      
                             
December 31, 2015 (in thousands)                            
Amortizable Intangible Assets:                            
Customer Relationships   $ 21,681     $ 6,714     $ 14,967     48-236 months
Covenant not to Compete     620       69       551     32 months
Other Intangible Assets     639       543       96     9 months
Emission Allowances     59       NA       59     Expensed as used
Total   $ 22,999     $ 7,326     $ 15,673      

 

The amortization expense for these intangible assets was:

 

(in thousands)   2016     2015     2014  
Amortization Expense – Intangible Assets   $ 1,436     $ 1,127     $ 977  

 

The estimated annual amortization expense for these intangible assets for the next five years is:

 

(in thousands)   2017     2018     2019     2020     2021  
Estimated Amortization Expense – Intangible Assets   $ 1,330     $ 1,264     $ 1,133     $ 1,099     $ 1,099  

 

Supplemental Disclosures of Cash Flow Information

 

    As of December 31,  
(in thousands)   2016     2015  
Noncash Investing Activities:                
Transactions Related to Capital Additions not Settled in Cash   $ 13,533     $ 20,371  

 

(in thousands)   2016     2015     2014  
Cash Paid (Received) During the Year for:                        
Interest (net of amount capitalized)   $ 31,269     $ 30,512     $ 26,364  
Income Taxes   $ (1,291 )   $ 7,322     $ 145  

 

New Accounting Standards

 

Accounting Standards Update (ASU) 2014-09—In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

 

Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. As of December 31, 2016 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is evaluating transition options. Based on review of the Company’s revenue streams, the Company does not anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU 2014-09, with the exception of the treatment of contributions in aid of construction in the Electric segment on which consensus treatment has not been determined and guidance has not been provided. Currently, the Company reduces its investment in fixed assets for the amount of these contributions. Should the Company be required to recognize these contributions as revenue under ASU 2014-09, it could result in a significant increase in reported revenues and expenses. Adoption of ASU 2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard. The Company does not plan to adopt the updated guidance prior to January 1, 2018.

 

ASU 2015-03—In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03), which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015 and must be applied retrospectively to balance sheets presented for periods prior to adoption. The Company adopted the updated standards in ASU 2015-03 in the first quarter of 2016. In conjunction with implementing this update, the Company is reclassifying the remaining balance of unamortized line of credit issuance costs from the deferred debit section of its consolidated balance sheet to other assets, eliminating the deferred debits section of its consolidated balance sheet and displaying long-term regulatory assets as a separate line item on its consolidated balance sheet. The effects of applying the guidance in ASU 2015-03 retrospectively to the Company’s December 31, 2015 consolidated balance sheet and statement of capitalization and of the associated reclassification of unamortized line of credit issuance costs are shown in the following table:

 

(in thousands)   December 31, 2015
Previously Stated		     Adjustments     December 31, 2015
Adjusted		  
Other Assets   $ 31,108     $ 1,676     $ 32,784  
Unamortized Debt Expense     3,897       (3,897 )     —  
Total Assets     1,820,904       (2,221 )     1,818,683  
                         
Current Liabilities                        
Current Maturities of Long-Term Debt     52,544       (122 )     52,422  
Total Current Liabilities     271,238       (122 )     271,116  
Capitalization                        
Long-Term Debt—Net     445,945       (2,099 )     443,846  
Total Capitalization     1,050,968       (2,099 )     1,048,869  
Total Liabilities and Equity     1,820,904       (2,221 )     1,818,683  

 

ASU 2015-11—In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires that inventories be measured at the lower of cost or net realizable value instead of the lower of cost or market value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The standards update is effective prospectively for fiscal years and interim periods beginning after December 15, 2016, with early adoption permitted. The Company does not expect the adoption of the updated standard to have a material impact on its consolidated financial statements.

 

ASU 2015-16—In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16), which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in ASU 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in ASU 2015-16 are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date, with earlier application permitted for financial statements that have not been issued. The Company elected to adopt the updated standard in the fourth quarter of 2015 in order to apply the updates to its recent acquisition of BTD-Georgia. Adoption of the updated standard did not have a material impact on the Company’s consolidated financial statements. The early adoption of the standard alleviated the need for prior period adjustments of income related to the BTD-Georgia acquisition purchase price adjustment recorded in June 2016. See note 2 to the Company’s consolidated financial statements for more information.

 

ASU 2016-02—In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 is a comprehensive amendment of the ASC, creating Topic 842, which will supersede the current requirements under ASC Topic 840 on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic 842 affects any entity that enters into a lease, with some specified scope exemptions. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. The Company is currently reviewing ASU 2016-02, identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and evaluating transition options. The Company does not currently plan to apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019.

 

ASU 2016-09— In March 2016, the FASB issued ASU No. 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which is intended to improve and simplify accounting and reporting requirements related to stock-based compensation programs. The amendments in ASU 2016-09 change how companies account for certain aspects of share-based payments to employees, including: (1) changing award classifications from liability to equity as a result of an increase in the permitted level of share withholding to cover income taxes to satisfy statutory income tax withholding requirements on the awards, (2) recognizing excess tax benefits as an adjustment to income tax expense when the awards vest rather than directly adjusting stockholders' equity, and (3) introducing an accounting policy election that permits reporting entities to elect to account for forfeitures as they occur. The amendments in ASU 2016-09 are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted.

 

In the fourth quarter of 2016, the Company elected to early adopt the updates in ASU 2016-09. The withholding provisions in the award agreements applicable to the Company’s outstanding performance awards granted to executive officers in 2014, 2015 and 2016 allow for withholding up to the maximum statutory tax rates in the applicable jurisdictions. The updates in ASU 2016-09 result in these awards being classified as equity awards rather than liability awards, requiring the amount of expense recognized for these awards to be based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards. The reporting-date fair values of the 2014 and 2015 awards outstanding on December 31, 2015 were less than the grant-date fair values of the awards. On adoption of the updates in ASU 2016-09 in the fourth quarter of 2016, the difference in expense that would have been recognized related to the outstanding 2014 and 2015 awards in 2014 and 2015 had the awards been classified as equity awards instead of liability awards results in a cumulative-effect net-of-tax adjustment to retained earnings of $623,000, with related adjustments to unvested restricted stock liability, deferred tax and miscellaneous paid-in capital accounts, effective as of January 1, 2016, as illustrated below:

 

Balance Sheet Account Affected, Effective January 1, 2016   Debit     Credit  
Adjustment to Retained Earnings   $ 623,000          
Long-Term Incentive Payable   $ 1,453,000          
Deferred Taxes   $ 416,000          
Miscellaneous Paid-In Capital           $ 2,492,000  

 

The impact of adopting the updates in ASU 2016-09 effective January 1, 2016 on 2016 interim reporting periods was not material.
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Business Combinations, Dispositions and Segment Information
 12 Months Ended
Dec. 31, 2016
Business Combinations, Dispositions and Segment Information [Abstract]  
Business Combinations, Dispositions and Segment Information

2. Business Combinations, Dispositions and Segment Information

 

Business Combinations

On September 1, 2015 BTD-Illinois, a wholly owned subsidiary of BTD, acquired the assets of Impulse of Dawsonville, Georgia for $30.8 million in cash. A post-closing reduction in the purchase price of $1.5 million was agreed to in June 2016 resulting in an adjusted purchase price of $29.3 million. The acquired business, operating under the name BTD-Georgia, is a full-service metal fabricator located 30 miles north of Atlanta, Georgia, which offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers. In addition to serving some of BTD’s existing customers from a location closer to the customers’ manufacturing facilities, this acquisition provides opportunities for growth in new and existing markets for BTD with complementing production capabilities that expand the capacity of services offered by BTD. Pro forma results of operations have not been presented for this acquisition because the effect of the acquisition was not material to the Company. 

 

Below is condensed balance sheet information disclosing the final allocation of the purchase price assigned to each major asset and liability category of BTD-Georgia:

 

(in thousands)      
Assets:        
Current Assets   $ 4,906  
Goodwill     6,083  
Other Intangible Assets     6,270  
Other Amortizable Assets     1,380  
Fixed Assets     13,649  
Total Assets   $ 32,288  
Liabilities:        
Current Liabilities   $ 2,971  
Lease Obligation     11  
Total Liabilities   $ 2,982  
Cash Paid   $ 29,306  

 

In the fourth quarter of 2015, the Company elected to early adopt ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which requires that an acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The purchase price adjustment agreed to in June 2016 resulted in a $2.2 million reduction to the value of acquired goodwill, a $0.8 million increase in the fair value of acquired customer relationships and a $0.1 million increase in acquired liabilities. The changes in the value of customer relationships had an immaterial impact on the Company’s consolidated net income in 2016 related to a change in amortization expense that would have been recorded in 2015 had the adjusted asset values been established on acquisition in 2015.

 

The Company acquired no new businesses in 2016 or 2014.

 

In execution of the Company’s announced strategy of realigning its business portfolio to reduce its risk profile and dedicate a greater portion of its resources toward electric utility operations, the Company sold several of its holdings in recent years. On December 31, 2014 the Company was in the process of negotiating the sales of Foley, its mechanical and prime contractor on industrial projects, and AEV, Inc., its electrical design and construction services company, which resulted in the removal of its Construction segment from continuing operations. The sale of Foley closed on April 30, 2015 and the sale of the assets of AEV, Inc. closed on February 28, 2015.

 

The results of operations of the Company’s recently disposed businesses are reported as discontinued operations in the Company’s consolidated financial statements as of and for the years ended December 31, 2016, 2015 and 2014, and are summarized in note 16 to consolidated financial statements.

 

Segment Information

The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company’s business structure currently includes the following three segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.

 

 

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907. 

 

Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.

 

Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States.

 

OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

 

No single customer accounted for over 10% of the Company’s consolidated revenues in 2016, 2015 and 2014. All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.6% of sales in 2016, 97.1% of sales in 2015 and 95.9% of sales in 2014.

 

The Company evaluates the performance of its business segments and allocates resources to them based on segment net income contribution and return on total invested capital. Information on continuing operations for the business segments for 2016, 2015 and 2014 is presented in the following table:

 

(in thousands)   2016     2015     2014  
Operating Revenue                        
Electric   $ 427,383     $ 407,131     $ 407,743  
Manufacturing     221,289       215,011       219,583  
Plastics     154,901       157,758       172,050  
Intersegment Eliminations     (34 )     (96 )     (114 )
Total   $ 803,539     $ 779,804     $ 799,262  
Cost of Products Sold                        
Manufacturing   $ 171,732     $ 171,956     $ 169,033  
Plastics     123,496       123,085       139,081  
Intersegment Eliminations     (6 )     (9 )     (45 )
Total   $ 295,222     $ 295,032     $ 308,069  
Other Nonelectric Expenses                        
Manufacturing   $ 21,994     $ 21,115     $ 23,340  
Plastics     9,402       9,850       9,292  
Corporate     8,896       9,143       13,418  
Intersegment Eliminations     (28 )     (87 )     (69 )
Total   $ 40,264     $ 40,021     $ 45,981  
Depreciation and Amortization                        
Electric   $ 53,743     $ 44,786     $ 44,076  
Manufacturing     15,794       11,853       10,518  
Plastics     3,861       3,552       3,364  
Corporate     47       172       116  
Total   $ 73,445     $ 60,363     $ 58,074  
Operating Income (Loss)                        
Electric   $ 90,131     $ 87,171     $ 76,060  
Manufacturing     11,769       10,086       16,692  
Plastics     18,142       21,272       20,313  
Corporate     (8,943 )     (9,315 )     (13,534 )
Total   $ 111,099     $ 109,214     $ 99,531  
 
(in thousands)   2016     2015     2014  
Interest Charges                        
Electric   $ 25,069     $ 24,371     $ 23,322  
Manufacturing     3,859       3,560       3,243  
Plastics     1,034       1,026       1,043  
Corporate and Intersegment Eliminations     1,924       2,203       2,040  
Total   $ 31,886     $ 31,160     $ 29,648  
Income Tax Expense (Benefit) – Continuing Operations                        
Electric   $ 16,366     $ 16,067     $ 11,029  
Manufacturing     2,276       2,299       4,117  
Plastics     6,538       8,187       7,301  
Corporate     (5,099 )     (4,911 )     (5,890 )
Total   $ 20,081     $ 21,642     $ 16,557  
Net Income (Loss)                        
Electric   $ 49,829     $ 48,370     $ 43,684  
Manufacturing     5,694       4,247       9,361  
Plastics     10,628       12,108       12,085  
Corporate     (4,114 )     (6,136 )     (8,247 )
Discontinued Operations     284       756       840  
Total   $ 62,321     $ 59,345     $ 57,723  
Capital Expenditures                        
Electric   $ 149,648     $ 135,572     $ 148,719  
Manufacturing     8,429       20,295       11,252  
Plastics     3,085       4,206       3,567  
Corporate     97       11       44  
Total   $ 161,259     $ 160,084     $ 163,582  
Identifiable Assets                        
Electric   $ 1,622,231     $ 1,520,887     $ 1,438,791  
Manufacturing     166,525       173,860       128,608  
Plastics     84,592       81,624       86,650  
Corporate     39,037       42,312       36,508  
Assets of Discontinued Operations     —       —       47,559  
Total   $ 1,912,385     $ 1,818,683     $ 1,738,116  
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Rate and Regulatory Matters
 12 Months Ended
Dec. 31, 2016
Rate And Regulatory Matters [Abstract]  
Rate and Regulatory Matters

3. Rate and Regulatory Matters

 

Below are descriptions of OTP’s major capital expenditure projects and use of reagents and emission allowances that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2016, 2015 and 2014.

 

Major Capital Expenditure Projects

 

The Big Stone South – Brookings MVP and CapX2020 Project—This 345 kiloVolt (kV) transmission line, currently under construction, will extend approximately 70 miles between a substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Northern States Power – MN (NSP MN), a subsidiary of Xcel Energy Inc., jointly developed this project and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. Construction began on this line in the third quarter of 2015 and the line is expected to be in service in fall 2017. 

 

The Big Stone South – Ellendale MVP—This is a 345 kV transmission line that will extend 163 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. (MDU), and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019.

 

Capacity Expansion 2020 (CapX2020) Transmission Line Projects—CapX2020 is a joint initiative of eleven investor-owned, cooperative, and municipal utilities in Minnesota and the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service.

 

Fargo–Monticello 345 kV CapX2020 Project (the Fargo Project)—OTP has invested approximately $81 million and has a 14.2% ownership interest in the jointly-owned assets of this 240-mile transmission line, and owns 100% of certain assets of the project. The final phase of this project was energized on April 2, 2015. 
 
Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project)—OTP has invested approximately $26 million and has a 4.8% ownership interest in this 250-mile transmission line. The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011. The final segments of this line were energized on March 26, 2015.

 

Big Stone Plant Air Quality Control System (AQCS)— OTP completed construction and testing of the Big Stone Plant AQCS in the fourth quarter of 2015 and placed the AQCS into commercial operation on December 29, 2015. OTP’s capitalized cost of the project, excluding allowance for funds used during construction, was approximately $200 million.

 

Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.

 

Reagent Costs

 

OTP’s systemwide costs for reagents are expected to increase to approximately $2.2 million annually through May 2021 when Hoot Lake Plant is expected to be retired. The Minnesota, North Dakota and South Dakota share of costs are approximately 50%, 40% and 10%, respectively. Reagent costs for the Big Stone Plant AQCS and Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) were initially incurred in 2015 when projects went into service.

 

Minnesota

 

2016 General Rate Case—On February 16, 2016 OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested an allowed rate of return on rate base of 8.07% and an allowed rate of return on equity of 10.4% based on an equity ratio of 52.5% of total capital. On April 14, 2016 the MPUC issued an order approving an interim rate increase of 9.56% to the base rate portion of customers’ bills effective April 16, 2016, as modified and subject to refund. The request and interim rate information is detailed in the table below:

 

($ in thousands)   Annualized or
Test Year		     Actual Through
December 31, 2016		  
Revenue Increase Requested   $ 19,296          
Increase Percentage Requested     9.80 %        
Jurisdictional Rate Base   $ 483,000          
Interim Revenue Increase (subject to refund)   $ 16,816     $ 10,976  

 

The major components of the requested rate increase are summarized below:

 

Revenue Requirement Deficiency Cost Factors (in thousands)   2016 Test Year
Allocation		  
Increased Rate Base   $ 10,000  
Increased Expenses     7,700  
Other     1,596  
Total Requested Revenue Increase   $ 19,296  
Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset     (2,480 )
Approved Interim Revenue Increase (subject to refund)   $ 16,816  
 

The deadline for submission of intervenor direct testimony was August 16, 2016. Direct testimony of the Minnesota Department of Commerce (MNDOC) included a recommendation for an 8.87% allowed rate of return on equity, and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. Hearings before the Administrative Law Judge (ALJ) occurred in October 2016. On January 5, 2017 the ALJ issued his report which included a recommendation for a 9.54% allowed rate of return on equity.

 

Based on OTP’s modifications to its original request and other expected outcomes in the aforementioned rate case, OTP has recorded an estimated interim rate refund of $3.6 million as of December 31, 2016. Oral arguments before the MPUC are expected to occur in late February 2017. The MPUC is expected to make its final decision in March 2017 and issue its written order in spring 2017.

 

2010 General Rate Case—OTP’s most recently completed general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%.

 

Minnesota Conservation Improvement Programs—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state's energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota.

 

The MNDOC may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the Minnesota Conservation Improvement Program (MNCIP) through the use of an annual recovery mechanism approved by the MPUC.

 

On September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case.

 

OTP recognized a financial incentive for 2014 of $3.0 million due, in part, to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016. Additionally, OTP saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million along with an updated surcharge with an effective date of October 1, 2015.

 

Based on results from the 2015 MNCIP program year, OTP recognized a financial incentive of $4.2 million. The 2015 MNCIP program resulted in an approximate 39% increase in energy savings compared to 2014 program results. On April 1, 2016 OTP requested approval for recovery of its 2015 MNCIP program costs not included in base rates, a $4.3 million financial incentive and an update to the MNCIP surcharge from the MPUC. On July 19, 2016 the MPUC issued an order approving OTP’s request with an effective date of October 1, 2016.

 

Based on results from the 2016 MNCIP program year, OTP recognized a financial incentive of $5.1 million in 2016. The 2016 program resulted in an approximate 18% increase in energy savings compared to 2015 program results. OTP will request approval for recovery of its 2016 MNCIP program costs not included in base rates, a $5.1 million financial incentive and an update to the MNCIP surcharge from the MPUC by April 1, 2017.

 

On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes to the MNCIP financial incentive. The new model will provide utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism.

 

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act (the MPU Act) provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility's retail customers, or exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The MPU Act also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Finally, under certain circumstances, the MPU Act also authorizes TCR riders to recover the costs associated with distribution planning and investments in distribution facilities to modernize the utility grid. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule.

 

MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers.

 

OTP filed an annual update to its Minnesota TCR rider on February 7, 2013 to include three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but found capitalized internal costs, costs in excess of CON estimates and a carrying charge ineligible for recovery through the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP is seeking recovery of the capitalized internal costs and costs in excess of CON estimates in its current general rate case filing in Minnesota. In response to the MPUC’s approval of OTP’s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. OTP filed an annual update to its Minnesota TCR rider on September 30, 2015 requesting revenue recovery of approximately $7.8 million. A supplemental filing to the update was made on December 21, 2015 to address an issue surrounding the proration of accumulated deferred income taxes and, in an unrelated adjustment, the TCR rider update revenue request was reduced to $7.2 million. On March 9, 2016 the MPUC issued an order approving OTP’s annual update to its TCR rider, with an effective date of April 1, 2016.

 

OTP filed an update to its TCR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The proposed rate changes went into effect on September 1, 2016. The MPUC has granted extensions to the MNDOC to file initial comments in this docket until February 2, 2017.

 

In OTP’s 2016 general rate case, the MNDOC has argued that the MPUC should require OTP to include in the TCR rider retail rate base 100% of OTP’s investment in the Big Stone South – Brookings and Big Stone South – Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. OTP has opposed this treatment, arguing that the projects are appropriately assigned to the FERC jurisdiction, and the FERC’s determination of the projects’ revenue requirements should not be altered by forcing the revenues into the retail revenue requirement calculations. In the general rate case proceeding, the ALJ has recommended that the MPUC should affirm OTP’s treatment. If the MPUC finds that the MNDOC’s treatment should be followed, it would result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time.

 

Environmental Cost Recovery (ECR) Rider—On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements included a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. The MPUC approved OTP’s 2014 ECR rider annual update request on November 24, 2014 with an effective date of December 1, 2014. OTP filed its 2015 annual update on July 31, 2015, with a request to keep the 2014 annual update rate in place. On December 21, 2015 OTP filed a supplemental filing with updated financial information. The MPUC issued an order on March 9, 2016 approving OTP’s request to leave the 2014 annual update rate in place. OTP filed an update to its Minnesota ECR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request, with an effective date of September 1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis and has since granted extensions to the MNDOC to file initial comments in this docket until February 2, 2017. Reply comments were due from OTP on February 13, 2017. 

 

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery of these costs. These costs are included in OTP’s 2016 general rate case in Minnesota and are being considered for recovery either through the FCA rider or general rates. These costs are currently being expensed as incurred.

 

North Dakota

 

General Rates—OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.

 

Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment (NDRRA) which enables OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment. The NDPSC approved OTP’s 2013 annual update to its NDRRA on March 12, 2014 with an effective date of April 1, 2014, which resulted in a 13.5% reduction in the NDRRA rate. The NDPSC approved OTP’s 2014 annual update to the NDRRA, including a change in rate design from an amount per kwh consumed to a percentage of a customer’s bill, on March 25, 2015 with an effective date of April 1, 2015. OTP submitted its 2015 annual update to the NDRRA rider rate on December 31, 2015 with a requested implementation date of April 1, 2016. On February 25, 2016 OTP made a supplemental filing to address the impact of bonus depreciation for income taxes and related deferred tax assets on the NDRRA, as well as an adjustment to the estimated amount of Federal Production Tax Credits used. The NDPSC approved the NDRRA 2015 annual update on June 22, 2016 with an effective date of July 1, 2016. The updated NDRRA reflects a reduction in the return on equity (ROE) component of the rate from 10.75%, approved in OTP’s most recent general rate case, to 10.50%. OTP submitted its 2016 annual update to the NDRRA rider rate on December 30, 2016, requesting a decrease to the NDRRA rate from 7.573% to 7.005%, with a requested implementation date of April 1, 2017.

 

Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case. The NDPSC approved OTP’s 2014 annual update to its TCR rider rate on December 17, 2014 with an effective date of January 1, 2015. On August 31, 2015 OTP filed its 2015 annual update to its North Dakota TCR rider rate requesting recovery of approximately $10.2 million for 2016 compared with $8.5 million for 2015, including costs assessed by the MISO as well as new costs from the Southwest Power Pool (SPP) that OTP began incurring January 1, 2016. These new costs are associated with OTP’s load connected to the transmission system of Central Power Electric Cooperative (CPEC). OTP’s load became subject to SPP transmission-related charges when CPEC transmission assets were added to the SPP. The NDPSC approved OTP’s 2015 annual update to its TCR rider rate on December 16, 2015, with an effective date of January 1, 2016. On September 1, 2016 OTP filed its annual update to the TCR rider requesting a revenue requirement of $5.7 million, which includes a reduction of $2.6 million for a projected over-collection for 2016. Primary drivers of the decrease from the 2015 updated rider rate include the impact of federal bonus depreciation and unresolved MISO ROE complaint proceedings. OTP filed a supplemental filing on September 14, 2016, requesting that the over-collection balance be spread over the next two years for purposes of reducing the volatility of the rates from year to year. The NDPSC approved the update on December 14, 2016. The new rates went into effect on January 1, 2017.

 

Environmental Cost Recovery Rider—On December 18, 2013 the NDPSC approved OTP’s request for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. The ECR provides for a current return on CWIP and a return on investment at the level approved in OTP’s most recent general rate case. On March 31, 2014 OTP filed an annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR. This update included a request to increase the ECR rider rate from 7.531% to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective date of July 1, 2015, along with the approval of recovery of OTP’s North Dakota jurisdictional share of Hoot Lake Plant MATS project costs.

 

On March 31, 2016 OTP filed its annual update to the ECR rider requesting a reduction in the rate from 9.193% to 7.904% of base rates, or a revenue requirement reduction from $12.2 million to $10.4 million, effective July 1, 2016. The rate reduction request was primarily due to the Company’s 2015 bonus depreciation election for income taxes, which reduces revenue requirements. The filing was approved on June 22, 2016. 

 

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance costs. On February 25, 2015 the NDPSC approved recovery of these costs through modification of the ECR rider, instead of recovery through the FCA as OTP had proposed. The ECR rider reagent and emissions allowance charge became effective May 1, 2015.

 

South Dakota

 

2010 General Rate Case—OTP’s most recent general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued on April 21, 2011 and effective with bills rendered on and after June 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.50%.

 

Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. The SDPUC approved OTP’s 2013 annual update on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP’s 2014 annual update on February 13, 2015 with an effective date of March 1, 2015. OTP filed its 2015 annual update on October 30, 2015 with a proposed effective date of March 1, 2016. A supplemental filing was made on February 3, 2016 to true-up the filing to include the impact of bonus depreciation elected for 2015, the inclusion of a deferred tax asset relating to a net operating loss and the proration of accumulated deferred income taxes. This update included the recovery of new SPP transmission costs OTP began to incur on January 1, 2016. On February 12, 2016 the SDPUC approved OTP’s annual update to its TCR rider, with an effective date of March 1, 2016. On November 1, 2016 OTP filed the annual update to the South Dakota TCR rider. OTP made a supplemental filing on January 20, 2017 to include updated costs through December 2016 as well as updated forecast information. The proposed effective date of the new rates is March 1, 2017.

 

Environmental Cost Recovery Rider—On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover OTP’s South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014. On August 31, 2015 OTP filed its annual update to the South Dakota ECR requesting recovery of approximately $2.7 million in annual revenue. The SDPUC approved the request on October 15, 2015 with an effective date of November 1, 2015. On August 31, 2016 OTP filed its 2016 update to the ECR rider, requesting recovery of approximately $2.3 million in annual revenue. The SDPUC approved the request on October 26, 2016 with an effective date of November 1, 2016. The lower revenue requirement is a result of the implementation of federal bonus depreciation taken on the Big Stone Plant AQCS.

 

Reagent Costs and Emission Allowances—On August 1, 2014 OTP filed a request with the SDPUC to revise its FCA rider in South Dakota to include recovery of reagent and emission allowance costs. On September 16, 2014 the SDPUC approved OTP’s request to include recovery of these costs in its South Dakota FCA rider.

 

Revenues Recorded under Rate Riders

 

The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the years ended December 31:

 

Rate Rider (in thousands)   2016     2015     2014  
Minnesota                        
Conservation Improvement Program Costs and Incentives1   $ 12,920     $ 10,724     $ 7,757  
Environmental Cost Recovery     12,443       10,238       6,891  
Transmission Cost Recovery     5,795       5,202       6,275  
North Dakota                        
Environmental Cost Recovery     11,089       9,502       5,872  
Renewable Resource Adjustment     7,800       8,409       7,484  
Transmission Cost Recovery     7,694       6,609       5,794  
South Dakota                        
Environmental Cost Recovery     2,538       1,967       234  
Transmission Cost Recovery     1,820       1,290       1,207  
Conservation Improvement Program Costs and Incentives     468       583       435  

1Includes MNCIP costs recovered in base rates. 

 

FERC

 

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935, as amended. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.

 

Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing.

 

Effective January 1, 2012 the FERC authorized OTP to recover 100% of prudently incurred CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission Expansion Plan: the Big Stone South–Brookings MVP and the Big Stone South–Ellendale MVP.

 

On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. On October 16, 2014 the FERC issued an order finding that the current MISO ROE may be unjust and unreasonable and setting the issue for hearing. Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the United States Court of Appeals for the District of Columbia (D.C. Circuit). A non-binding decision by the presiding ALJ was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%.

 

On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.

 

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12, 2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the D.C. Circuit. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. The FERC is expected to issue its order not earlier than spring 2017.

 

Based on a potential reduction by the FERC in the ROE component of the MISO Tariff, OTP recorded reductions in revenue of $1.6 million in 2016 and $1.1 million in 2015 and has a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE.
XML 39 R16.htm IDEA: XBRL DOCUMENT v3.6.0.2
Regulatory Assets and Liabilities
 12 Months Ended
Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]  
Regulatory Assets and Liabilities

4. Regulatory Assets and Liabilities

 

As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC 980. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

 

  December 31, 2016  Remaining
Recovery/
(in thousands) Current  Long-Term  Total  Refund Period
Regulatory Assets:              
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 $6,443  $108,267  $114,710  see below
Deferred Marked-to-Market Losses1  4,063   6,467   10,530  48 months
Conservation Improvement Program Costs and Incentives2  4,836   5,158   9,994  21 months
Accumulated ARO Accretion/Depreciation Adjustment1  —   6,153   6,153  asset lives
Big Stone II Unrecovered Project Costs – Minnesota1  778   2,087   2,865  52 months
North Dakota Renewable Resource Rider Accrued Revenues2  1,319   482   1,801  15 months
Recoverable Fuel and Purchased Power Costs1  1,798   —   1,798  12 months
Debt Reacquisition Premiums1  325   1,214   1,539  189 months
Minnesota Deferred Rate Case Expenses Subject to Recovery1  1,082   —   1,082  12 months
Deferred Income Taxes1  —   1,014   1,014  asset lives
Big Stone II Unrecovered Project Costs – South Dakota2  100   543   643  77 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2  —   568   568  24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2  333   —   333  12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2  73   141   214  14 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2  113   —   113  12 months
Minnesota Renewable Resource Rider Accrued Revenues2  34   —   34  9 months
Total Regulatory Assets $21,297  $132,094  $153,391   
Regulatory Liabilities:              
Accumulated Reserve for Estimated Removal Costs – Net of Salvage $—  $80,404  $80,404  asset lives
North Dakota Transmission Cost Recovery Rider Accrued Refund  1,381   782   2,163  24 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota  711   208   919  16 months
Deferred Income Taxes  —   818   818  asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund  757   —   757  12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund  285   —   285  12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund  139   —   139  12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up  —   132   132  24 months
Other  21   89   110  204 months
Total Regulatory Liabilities $3,294  $82,433  $85,727   
Net Regulatory Asset Position $18,003   49,661  $67,664   

1Costs subject to recovery without a rate of return.

2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. 

 

  December 31, 2015  Remaining
Recovery/
(in thousands) Current  Long-Term  Total  Refund Period
Regulatory Assets:              
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 $7,439  $99,293  $106,732  see below
Deferred Marked-to-Market Losses1  4,063   10,530   14,593  60 months
Conservation Improvement Program Costs and Incentives2  4,411   4,266   8,677  18 months
Accumulated ARO Accretion/Depreciation Adjustment1  —   5,672   5,672  asset lives
Big Stone II Unrecovered Project Costs – Minnesota1  942   2,620   3,562  84 months
North Dakota Renewable Resource Rider Accrued Revenues2  —   1,266   1,266  15 months
Debt Reacquisition Premiums1  351   1,539   1,890  201 months
Minnesota Deferred Rate Case Expenses Subject to Recovery1  291   —   291  12 months
Deferred Income Taxes1  —   1,455   1,455  asset lives
Big Stone II Unrecovered Project Costs – South Dakota2  100   643   743  89 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2  698   355   1,053  24 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues2  576   —   576  12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2  33   —   33  12 months
Minnesota Renewable Resource Rider Accrued Revenues2  —   68   68  see below
Total Regulatory Assets $18,904  $127,707  $146,611   
Regulatory Liabilities:              
Accumulated Reserve for Estimated Removal Costs – Net of Salvage $—  $74,948  $74,948  asset lives
Refundable Fuel Clause Adjustment Revenues  1,834   —   1,834  12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund  132   —   132  12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota  —   1,279   1,279  see below
Deferred Income Taxes  —   1,110   1,110  asset lives
South Dakota Environmental Cost Recovery Rider Accrued Refund  185   —   185  12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund  777   —   777  12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion  5   95   100  216 months
North Dakota Environmental Cost Recovery Rider Accrued Refund  321   —   321  12 months
North Dakota Renewable Resource Rider Accrued Refund  68   —   68  12 months
Total Regulatory Liabilities $3,322  $77,432  $80,754   
Net Regulatory Asset Position $15,582  $50,275  $65,857   

1Costs subject to recovery without a rate of return.

2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

 

The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

 

All Deferred Marked-to-Market Losses recorded as of December 31, 2016 relate to forward purchases of energy scheduled for delivery through December 2020.

 

Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.

 

The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.

 

Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project.

 

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of December 31, 2016. 

 

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 189 months.

 

Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota currently being recovered over a 24-month period beginning with the establishment of interim rates in April 2016.

 

The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes.

 

Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project.

 

The North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of December 31, 2016.

 

MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.

 

The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to South Dakota customers as of December 31, 2016.

 

The North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that have not been billed to North Dakota customers as of December 31, 2016.

 

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP’s request to set the rider rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered over an 18-month period beginning with the establishment of interim rates in April 2016.

 

The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.

 

The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of December 31, 2016.

 

Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund over a 24-month period beginning with the establishment of interim rates in April 2016.

 

The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of December 31, 2016.

 

The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of December 31, 2016.

 

The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of December 31, 2016.

 

If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of guidance under ASC 980 ceases.
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Open Contract Positions Subject to Legally Enforceable Netting Arrangements
 12 Months Ended
Dec. 31, 2016
Open Contract Positions Subject To Legally Enforceable Netting Arrangements [Abstract]  
Open Contract Positions Subject to Legally Enforceable Netting Arrangements

5. Open Contract Positions Subject to Legally Enforceable Netting Arrangements

 

OTP has certain derivative contracts that are designated as normal purchases and carried at historical cost in the accompanying balance sheet. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The following table shows the current fair value of these forward contract positions subject to legally enforceable netting arrangements as of December 31:

 

(in thousands)   2016     2015  
Derivatives in Gain Positions Subject to Legally Enforceable Netting Arrangements   $ —     $ —  
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements     (17,382 )     (16,070 )
 Net Balance Subject to Legally Enforceable Netting Arrangements   $ (17,382 )   $ (16,070 )

 

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of December 31:

 

(in thousands)   2016     2015  
Loss Contracts Covered by Deposited Funds or Letters of Credit   $ —     $ 199  
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1     17,382       15,871  
Total Loss Contracts based on Current Market Values   $ 17,382     $ 16,070  
1Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.                
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade   $ 17,382     $ 15,871  
Offsetting Gains with Counterparties under Master Netting Agreements     —       —  
Reporting Date Deposit Requirement if Credit Risk Feature Triggered   $ 17,382     $ 15,871  
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Common Shares and Earnings Per Share
 12 Months Ended
Dec. 31, 2016
Stockholders Equity and Earnings Per Share [Abstract]  
Common Shares and Earnings Per Share

6. Common Shares and Earnings per Share

 

Shelf Registration

The Company’s shelf registration statement filed with the Securities and Exchange Commission on May 11, 2015, under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on May 11, 2018.

 

Common Share Distribution Agreement

On May 11, 2015, the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it may offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of $75 million.

 

Under the Distribution Agreement, the Company will designate the minimum price and maximum number of shares to be sold through JPMS on any given trading day or over a specified period of trading days, and JPMS will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. Sales of the shares, if any, will be made by means of ordinary brokers’ transactions on the NASDAQ Global Select Market at market prices or as otherwise agreed with JPMS. The Company may also agree to sell shares to JPMS, as principal for its own account, on terms agreed by the Company and JPMS in a separate agreement at the time of sale. The Company is not obligated to sell and JPMS is not obligated to buy or sell any of the shares under the Distribution Agreement. The shares, if issued, will be issued pursuant to the Company’s existing shelf registration statement.

 

2016 Common Stock Activity

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2015 through December 31, 2016:

 

Common Shares Outstanding, December 31, 2015     37,857,186  
Issuances:        
At-the-Market Offering     1,014,115  
Automatic Dividend Reinvestment and Share Purchase Plan:        
Dividends Reinvested     163,010  
Cash Invested     115,801  
Vesting of Executive Stock Performance Awards     54,700  
Employee Stock Purchase Plan:        
Cash Invested     53,875  
Dividends Reinvested     23,713  
Employee Stock Ownership Plan     23,837  
Restricted Stock Issued to Directors     23,200  
Vesting of Restricted Stock Units     21,825  
Directors Deferred Compensation     542  
Retirements:        
Shares Withheld for Individual Income Tax Requirements     (3,668 )
Common Shares Outstanding, December 31, 2016     39,348,136  

 

2014 Stock Incentive Plan

The 2014 Stock Incentive Plan (2014 Incentive Plan), which was approved by the Company’s shareholders in April 2014, provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, and other stock and stock-based awards. A total of 1,900,000 common shares were authorized for granting stock awards under the 2014 Incentive Plan, of which 1,356,811 were available for issuance as of December 31, 2016. The 2014 Incentive Plan terminates on December 13, 2023.

 

Employee Stock Purchase Plan

The 1999 Employee Stock Purchase Plan (Purchase Plan) allows eligible employees to purchase the Company’s common shares at 85% of the market price at the end of each six-month purchase period. For purchase periods beginning after January 1, 2017, the purchase price will be 100% of the market price at the end of each six-month purchase period. On April 16, 2012, the Company’s shareholders approved an amendment to the Purchase Plan, increasing the number of shares available under the Purchase Plan from 900,000 common shares to 1,400,000 common shares and making certain other changes to the terms of the Purchase Plan. Of the 1,400,000 common shares authorized to be issued under the Purchase Plan, 384,159 were available for purchase as of December 31, 2016. At the discretion of the Company, shares purchased under the Purchase Plan can be either new issue shares or shares purchased in the open market. To provide shares for purchases for the Purchase Plan, 53,875 common shares were issued in 2016, 42,253 common shares were issued in 2015 and 39,222 common shares were issued in 2014. The shares to be purchased by employees participating in the Purchase Plan were not material to the calculation of diluted earnings per share during the investment period.

 

Dividend Reinvestment and Share Purchase Plan

The Company’s shelf registration statement filed with the SEC on May 11, 2015, as amended on October 13, 2015, provides for the issuance of up to 1,500,000 common shares under the Company's Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. New common shares issued under the Plan totaled 278,811 in 2016 and 302,519 in 2015, leaving 918,670 common shares available for issuance under the Plan as of December 31, 2016.

 

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income with no adjustments in 2016, 2015 and 2014. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation:

 

    2016     2015     2014  
Weighted Average Common Shares Outstanding – Basic     38,546,459       37,494,986       36,514,397  
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:                        
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance     118,644       100,194       135,480  
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees     45,712       36,180       27,540  
Nonvested Restricted Shares     16,778       22,848       49,998  
Shares Expected to be Issued Under the Deferred Compensation Program for Directors     3,417       13,488       24,048  
Potentially Dilutive Stock Options     —       330       1,096  
Total Dilutive Shares     184,551       173,040       238,162  
Weighted Average Common Shares Outstanding – Diluted     38,731,010       37,668,026       36,752,559  

 

The effect of dilutive shares on earnings per share for the years ended December 31, 2016, 2015 and 2014, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in any period.
XML 42 R19.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments
 12 Months Ended
Dec. 31, 2016
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]  
Share-Based Payments

7. Share-Based Payments

 

Purchase Plan

Through December 31, 2016, the Purchase Plan allowed employees through payroll withholding to purchase shares of the Company’s common stock at a 15% discount from the average market price on the last day of a six month investment period. Under ASC Topic 718, Compensation—Stock Compensation (ASC 718), the Company is required to record compensation expense related to the 15% discount. The 15% discount resulted in compensation expense of $173,000 in 2016, $184,000 in 2015 and $175,000 in 2014. For purchase periods beginning after January 1, 2017, the purchase price will be 100% of the market price at the end of each six-month purchase period.

 

Stock Options Granted Under the 1999 Incentive Plan

The Company granted 2,041,500 options for the purchase of the Company’s common stock under the 1999 Stock Incentive Plan (1999 Incentive Plan). The exercise price of the options granted was the average market price of the Company’s common stock on the grant date. Under ASC 718 accounting requirements, compensation expense is recorded based on the estimated fair value of the options on their grant date using a fair-value option pricing model. Under ASC 718 accounting requirements, the fair value of the options granted has been recorded as compensation expense over the requisite service period (the vesting period of the options). The estimated fair value of all options granted under the 1999 Incentive Plan was based on the Black-Scholes option pricing model. There were no options outstanding as of December 31, 2016 or December 31, 2015.

 

Presented below is a summary of the stock options activity:

 

Stock Option Activity   2016     2015     2014  
    Options     Average
Exercise
Price		     Options     Average
Exercise
Price		     Options     Average
Exercise
Price		  
Outstanding, Beginning of Year     —               12,750     $ 24.93       34,700     $ 25.69  
Exercised     —               10,250       24.93       20,800       26.11  
Forfeited or Expired     —               2,500       24.93       1,150       26.495  
Outstanding, End of Year     —               —               12,750       24.93  
Exercisable, End of Year     —               —               12,750       24.93  
Cash Received for Options Exercised                           $ 256,000             $ 543,000  
Intrinsic Value of Options Exercised                           $ 75,000             $ 89,000  

 

Restricted Stock Granted to Directors

Under the 1999 Incentive Plan and the 2014 Incentive Plan, restricted shares of the Company’s common stock have been granted to members of the Company’s board of directors as a form of compensation. Under ASC 718 accounting requirements, compensation expense related to restricted shares is based on the fair value of the restricted shares on their grant dates. On April 11, 2016, 23,200 shares of restricted stock were granted to the Company’s nonemployee directors. The grant-date fair value of each share of restricted stock granted on April 11, 2016 was $28.66 per share, the average of the high and low market price on the date of grant. The restricted shares granted in 2016 vest 25% per year on April 8 of each year in the period 2017 through 2020 and are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreement.

 

Presented below is a summary of the status of directors’ restricted stock awards for the years ended December 31:

 

Directors’ Restricted Stock Awards   2016     2015     2014  
    Shares     Weighted
Average
Grant-Date
Fair Value		     Shares     Weighted
Average
Grant-Date
Fair Value		     Shares     Weighted
Average
Grant-Date
Fair Value		  
Nonvested, Beginning of Year     38,217     $ 29.78       38,050     $ 27.47       42,483     $ 25.03  
Granted     23,200       28.66       15,200       31.775       16,800       29.41  
Vested     15,083       28.28       15,033       25.96       21,233       24.11  
Forfeited     —               —               —          
Nonvested, End of Year     46,334       29.71       38,217       29.78       38,050       27.47  
Compensation Expense Recognized           $ 491,000             $ 417,000             $ 416,000  
Fair Value of Shares Vested in Year           $ 427,000             $ 390,000             $ 512,000  
 

Restricted Stock Granted to Employees

Under the 1999 Incentive Plan and 2014 Incentive Plan, restricted shares of the Company’s common stock have been granted to employees as a form of compensation. Under ASC 718 accounting requirements, compensation expense related to restricted shares is based on the fair value of the restricted shares on their grant dates. No shares of restricted stock were granted to employees in 2016 or 2015.

 

Presented below is a summary of the status of employees’ restricted stock awards for the years ended December 31:

 

Employees’ Restricted Stock Awards   2016     2015     2014  
    Shares     Weighted 
Average 
Grant-Date
Fair Value		     Shares     Weighted
Average
Grant-Date
Fair Value		     Shares     Weighted
Average
Grant-Date
Fair Value		  
Nonvested, Beginning of Year     13,581     $ 28.56       45,280     $ 27.46       48,315     $ 25.04  
Granted     —               —               26,700       29.41  
Vested     6,401       27.25       31,699       27.09       25,360       24.80  
Forfeited     —               —               4,375       28.03  
Nonvested, End of Year     7,180       29.72       13,581       28.56       45,280       27.46  
Compensation Expense Recognized           $ 96,000             $ 359,000             $ 998,000  
Fair Value of Awards Vested           $ 174,000             $ 859,000             $ 629,000  

 

Restricted Stock Units Granted to Executive Officers

On February 4, 2016, 22,000 restricted stock units under the 2014 Incentive Plan were granted to the Company’s executive officers. The grant-date fair value of each restricted stock unit was $28.915 per share, the average of the high and low market price on the date of grant. The restricted stock units granted to executive officers in 2016 vest 25% per year on February 6 of each year in the period 2017 through 2020 and are eligible to receive dividend equivalent payments on all unvested awards over the awards’ respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases.

 

Presented below is a summary of the status of restricted stock unit awards granted to executive officers for the years ended December 31:

 

Executives’ Restricted Stock Unit Awards   2016     2015  
    Restricted
Stock
Units		     Weighted
Average
Grant-Date
Fair Value		     Restricted
Stock
Units		     Weighted
Average
Grant-Date
Fair Value		  
Nonvested, Beginning of Year     24,300     $ 31.682       —          
Granted     22,000       28.915       29,100     $ 31.681  
Vested     4,475       31.69       4,800       31.675  
Forfeited     —               —        
Nonvested, End of Year     41,825       30.23       24,300       31.682  
Compensation Expense Recognized           $ 446,000             $ 452,000  
Fair Value of Awards Vested           $ 142,000             $ 152,000  

 

Restricted Stock Units Granted to Employees

In 2016 the following restricted stock unit awards under the 2014 Incentive Plan were granted to key employees of the Company who are not executive officers:

 

    Grant Date   Units
Granted		     Grant-Date
Fair Value
per Award		  
Restricted Stock Units Vesting 100% on April 8, 2020   April 11, 2016     15,800     $ 24.00  
Restricted Stock Units Vesting 100% on April 8, 2020   September 21, 2016     1,420     $ 30.59  
 

The grant-date fair value of each restricted stock unit was based on the average of the high and low market price of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion over the four-year vesting period. Under the terms of the restricted stock unit award agreements, all outstanding (unvested) restricted stock units held by a retiring grantee vest immediately on normal retirement.

 

Presented below is a summary of the status of employees’ restricted stock unit awards for the years ended December 31:

 

Employees’ Restricted Stock Unit Awards   2016     2015     2014  
    Restricted
Stock
Units		     Weighted
Average
Grant-Date
Fair Value		     Restricted
Stock
Units		     Weighted
Average
Grant-Date
Fair Value		     Restricted
Stock
Units		     Weighted
Average
Grant-Date
Fair Value		  
Nonvested, Beginning of Year     46,600     $ 23.75       45,900     $ 21.82       56,180     $ 19.79  
Granted     17,220       24.54       15,650       25.89       11,800       24.95  
Reinstated     —               —               75       30.81  
Vested     12,250       19.03       12,250       19.46       14,305       18.05  
Forfeited     4,200       24.51       2,700       22.84       7,850       18.90  
Nonvested, End of Year     47,370       25.19       46,600       23.75       45,900       21.82  
Compensation Expense Recognized           $ 307,000             $ 304,000             $ 194,000  
Fair Value of Awards Vested           $ 233,000             $ 238,000             $ 258,000  

 

Stock Performance Awards granted to Executive Officers

Stock performance award agreements have been granted under the 1999 Incentive Plan and the 2014 Incentive Plan for the Company’s executive officers. Under these agreements, the officers could be awarded shares of the Company’s common stock based on the Company’s total shareholder return relative to that of its peer group of companies in the Edison Electric Institute (EEI) Index over a three-year period beginning on January 1 of the year the awards are granted. Awards granted in 2016 and 2015 also included a performance incentive based on the Company’s average 3-year adjusted return on equity relative to a targeted average 3-year adjusted return on equity. The number of shares earned, if any, will be awarded and issued at the end of each three-year performance measurement period. The participants have no voting or dividend rights under these award agreements until the shares are issued at the end of the performance measurement period.

 

On February 4, 2016 performance share awards were granted to the Company’s executive officers under the 2014 Incentive Plan for the 2016-2018 performance measurement period. Under the 2016 performance share award agreements the aggregate award for performance at target is 81,500 shares. For target performance the Company’s executive officers would earn an aggregate of 54,333 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2016 through December 31, 2018. The Company’s executive officers would also earn an aggregate of 27,167 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 122,250 common shares.

 

Under the 2016 performance award agreements, payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to executive employment agreements with the Company is to be made at the target amount at the date of any such event. The vesting of these performance award agreements is accelerated and paid at target in the event of a change in control, disability or death (and upon retirement at or after age 62 for certain officers who are parties to executive employment agreements with the Company).

 

Through December 31, 2015, the income tax withholding terms applicable to outstanding performance awards dictated that the awards be classified and accounted for as liability awards, in accordance with the requirements of ASC 718, with compensation measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date. In the fourth quarter of 2016, the Company elected to early adopt the updates in ASU 2016-09, resulting in the outstanding 2015 and 2016 performance awards being now classified as equity awards. See note 1 for additional information on the impact of the adoption of ASU 2016-09.

 

The table below provides a summary of stock performance awards granted and amounts expensed related to the stock performance awards:

 

Performance
Period		   Maximum
Shares Subject
 To Award		     Target
Shares		     Expense Recognized
in the Year Ended December 31,1		     Earned
Shares		  
                2016     2015     2014        
2016-2018     122,250       81,500     $ 798,000                          
2015-2017     126,450       84,300       535,000     $ 943,000                  
2014-2016     159,450       106,300       332,000       (64,000 )   $ 1,422,000       121,491  
2013-2015     90,600       45,300       —       (445,000 )     458,000       22,500  
2012-2014     148,400       74,200       —       —       142,000       89,991  
Total                   $ 1,665,000     $ 434,000     $ 2,022,000       233,982  

1Expenses prior to 2016 are not restated to reflect what would have been expensed had the performance-to-date value of the outstanding awards been based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards.

 

Stock-based payment expense recognized in 2016 and 2015 for the 2016-2018 and 2015-2017 performance awards reflects the accelerated recognition of expense for outstanding and unvested awards of executives who are eligible for retirement and whose awards vest on normal retirement, as defined in the performance award agreements, prior to the vesting dates of the awards.

 

The earned shares shown in the table above for the 2014-2016 performance period include shares received in 2017 by participants in the plan, based on the Company achieving a total shareholder return ranking of 19 out of 43 companies in the EEI Index and a resulting payout at 114.29% of target. The earned shares also include shares for a portion of the award that vested on normal retirement of the Company’s former CEO on July 1, 2015 that were issued in 2016 following the 180 day deferral period required under the Internal Revenue Code at a value of $26.35 per share or $848,000.

 

The earned shares shown in the table above for the 2013-2015 performance period reflect shares that vested on normal retirement of the Company’s former CEO on July 1, 2015 that were issued in 2016 following the 180 day deferral period required under the Internal Revenue Code at a value of $26.35 per share or $593,000.

 

The earned shares shown in the table above for the 2012-2014 performance period reflect shares received in 2015 by active participants in the plan on December 31, 2014, based on the Company achieving a total shareholder return ranking of 21 out of 48 companies in the EEI Index and a resulting payout at 121.28% of target.

 

In connection with the resignation of executive officers in May 2014 and March 2012, the following unvested stock performance awards were forfeited: 8,900 granted in 2014, 4,900 granted in 2013, and 6,600 granted in 2012.

 

As of December 31, 2016 the total remaining unrecognized amount of compensation expense related to stock-based compensation for all of the Company’s stock-based payment programs was approximately $4.0 million (before income taxes), which will be amortized over a weighted average period of 2.2 years.
XML 43 R20.htm IDEA: XBRL DOCUMENT v3.6.0.2
Retained Earnings and Dividend Restriction
 12 Months Ended
Dec. 31, 2016
Retained Earnings Note Disclosure [Abstract]  
Retained Earnings and Dividend Restriction

8. Retained Earnings and Dividend Restriction

 

The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

 

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of December 31, 2016 the Company was in compliance with these financial covenants. See note 10 to consolidated financial statements for further information on the covenants.

 

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.

 

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.5% and 58.1% based on OTP’s 2016 capital structure petition approved by order of the MPUC on August 2, 2016. As of December 31, 2016 OTP’s equity-to-total-capitalization ratio including short-term debt was 52.9% and its net assets restricted from distribution totaled approximately $440,000,000. Total capitalization for OTP cannot currently exceed $1,123,168,000.
XML 44 R21.htm IDEA: XBRL DOCUMENT v3.6.0.2
Commitments and Contingencies of Continuing Operations
 12 Months Ended
Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies of Continuing Operations

9. Commitments and Contingencies of Continuing Operations

 

Construction and Other Purchase Commitments

At December 31, 2016 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $84.8 million.

 

Electric Utility Capacity and Energy Requirements and Coal Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2040. OTP has commitments under contracts providing for the purchase of a significant portion of its current coal requirements. Current coal purchase agreements for Big Stone Plant and Coyote Station expire in 2017 and 2040, respectively. In January 2016, OTP entered into an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant for the period of January 1, 2016 through December 31, 2023. OTP has no fixed minimum purchase requirements under the agreement but all of Hoot Lake Plant’s coal requirements for the period covered must be purchased under this agreement. The dollar amounts of OTP’s estimated purchase requirements under this agreement are excluded from the table below because OTP has not committed to any minimum level of purchases under the agreement. Fuel clause adjustment mechanisms lessen the risk of loss from market price changes because they provide for recovery of most fuel costs. See table below for schedule of commitments.

 

Operating Leases

OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. Rent expense from continuing operations was $7,565,000, $6,447,000 and $10,165,000 for 2016, 2015 and 2014, respectively.

 

The amounts of the Company’s construction program and other commitments and commitments under capacity and energy agreements, coal and coal delivery contracts and operating leases for continuing operations as of December 31, 2016, are as follows:

 

  Construction
Program and Other		  Capacity and
Energy		  Coal
Purchase		  Operating Leases 
(in thousands) Commitments  Requirements  Commitments  OTP  Nonelectric  Total 
2017 $74,328  $23,711  $30,699  $2,374  $4,760  $7,134 
2018  7,139   24,356   21,563   1,513   4,129   5,642 
2019  3,331   24,925   22,102   1,237   2,598   3,835 
2020  —   24,844   22,331   1,251   2,259   3,510 
2021  —   12,988   22,840   1,103   1,996   3,099 
Beyond 2021  —   166,137   550,719   9,396   7,320   16,716 
Total $84,798  $276,961  $670,254  $16,874  $23,062  $39,936 
 

Contingencies

Based on the reduction by the FERC in the ROE component of the MISO Tariff, OTP has a $2.7 million liability on its balance sheet as of December 31, 2016 representing OTP’s best estimate of its current refund obligation related to amounts collected under the MISO Tariff, net of amounts that would be subject to recovery under state jurisdictional TCR riders.

 

Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders and the FERC’s decision to resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. These consolidated cases are currently held in abeyance while the parties engage in mediation before the D.C. Circuit. OTP is an intervenor in these cases and a participant in mediation. The scope of the issues that will be subject to appeal at the D.C. Circuit have not yet been finalized. In addition, MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders. Although the Company cannot estimate OTP’s exposure at this time, a final order reversing the relevant FERC orders could have a material adverse effect on the Company’s results of operations.

 

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $1.0 million, excluding any liability for RSG charges for which an estimate cannot be made at this time.

 

In 2014 the Environmental Protection Agency (EPA) published proposed standards of performance for carbon dioxide (CO2) emissions from new fossil fuel-fired power plants, proposed CO2 emission guidelines for existing fossil fuel-fired power plants and proposed CO2 standards of performance for CO2 emissions from reconstructed and modified fossil fuel-fired power plants under section 111 of the Clean Air Act. The EPA published final rules for each of these proposals on October 23, 2015. All of these rules have been challenged on legal grounds and are currently pending before the D.C. Circuit. On February 9, 2016 the U.S. Supreme Court granted a stay of the CO2 emission guidelines for existing fossil fuel-fired power plants, pending disposition of petitions for review in the D.C. Circuit and, if a petition for a writ of certiorari seeking review by the U.S. Supreme Court were granted, any final Supreme Court determination. The D.C. Circuit heard oral argument on challenges to the CO2 emission guidelines on September 27, 2016 before the full court, and a decision will likely be rendered in the first half of 2017. In addition, members of Congress and the new administration have been very critical of the Clean Power Plan (CPP) and may take actions that could impact the rule or the litigation. Therefore, while the CPP remains stayed, there is uncertainty regarding the future of the rule. The final outcome of this rulemaking process could have an adverse impact on the Company’s business and results of operations.

 

Other

The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of December 31, 2016 will not be material.
XML 45 R22.htm IDEA: XBRL DOCUMENT v3.6.0.2
Short-Term and Long-Term Borrowings
 12 Months Ended
Dec. 31, 2016
Debt Disclosure [Abstract]  
Short-Term and Long-Term Borrowings

10. Short-Term and Long-Term Borrowings

 

Short-Term Debt

 

The following table presents the status of the Company’s lines of credit as of December 31, 2016 and December 31, 2015:

 

(in thousands)   Line Limit     In Use on
December 31,
2016		     Restricted due to
Outstanding
Letters of Credit		     Available on
December 31,
2016		     Available on
December 31,
2015		  
Otter Tail Corporation Credit Agreement   $ 130,000     $ —     $ —     $ 130,000     $ 90,334  
OTP Credit Agreement     170,000       42,883       50       127,067       148,694  
Total   $ 300,000     $ 42,883     $ 50     $ 257,067     $ 239,028  

 

Under the Otter Tail Corporation Credit Agreement (as defined below), the maximum amount of debt outstanding in 2016 was $63,757,000 on January 4, 2016 and the average daily balance of debt outstanding during 2016 was $16,200,000. The weighted average interest rate paid on debt outstanding under the Otter Tail Corporation Credit Agreement during 2016 was 2.3% compared with 2.0% in 2015. Under the OTP Credit Agreement (as defined below), the maximum amount of debt outstanding in 2016 was $51,885,000 on December 16, 2016 and the average daily balance of debt outstanding during 2016 was $32,576,000. The weighted average interest rate paid on debt outstanding under the OTP Credit Agreement during 2016 was 1.8% compared with 1.5% in 2015. The maximum amount of consolidated short-term debt outstanding in 2016 was $87,211,000 on January 25, 2016 and the average daily balance of consolidated short-term debt outstanding during 2016 was $48,776,000. The weighted average interest rate on consolidated short-term debt outstanding on December 31, 2016 was 1.9%.

 

On October 29, 2012 the Company entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $130 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On October 31, 2016 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021 and the unsecured revolving credit facility was reduced from $150 million to $130 million. The Company can draw on this credit facility to refinance certain indebtedness and support its operations and the operations of its subsidiaries. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 1.75%, subject to adjustment based on the Company’s senior unsecured credit ratings. The Company is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The Otter Tail Corporation Credit Agreement contains a number of restrictions on the Company and the businesses of its wholly owned subsidiary, Varistar Corporation (Varistar) and its subsidiaries, including restrictions on the Company’s and Varistar’s ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s credit ratings. The Company’s obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of the Company’s subsidiaries. Outstanding letters of credit issued by the Company under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million.

 

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 31, 2016 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party. 

 

Long-Term Debt Issuances and Retirements

 

2016 Note Purchase Agreement

On September 23, 2016 the Company entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which the Company agreed to issue to the purchasers, in a private placement transaction, $80 million aggregate principal amount of our 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes). The 2026 Notes were issued on December 13, 2016. The Company’s obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by its Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). The proceeds from the issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our 9.000% Senior Notes due December 15, 2016, and to pay down a portion of the $50 million in funds borrowed in February 2016 under the Company’s term loan agreement.

 

The Company may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. The Company is required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if the Company and its Material Subsidiaries sell a “substantial part” of its or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes.

 

The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and the Material Subsidiaries that became effective on execution of the 2016 Note Purchase Agreement. These include restrictions on the Company’s and the Material Subsidiaries’ abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or pay dividends on the Company’s and the Material Subsidiaries’ shares of capital stock, and make investments. The 2016 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2016 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s or the Material Subsidiaries’ credit ratings.

 

Term Loan Agreement

On February 5, 2016 the Company entered into a Term Loan Agreement (the Term Loan Agreement) with the Banks named therein, JPMorgan Chase Bank, N.A., as administrative agent, and JPMS, as Lead Arranger and Book Runner. The Term Loan Agreement provides for an unsecured term loan with an aggregate commitment of $50 million that the Company may use for purposes of funding working capital, capital expenditures and other corporate purposes of the Company and certain of our subsidiaries. Under the Term Loan Agreement, the Company may, on up to two occasions, enter into additional tranches of term loans in minimum increments of $10 million, subject to the consent of the lenders and so long as the aggregate amount of outstanding term loans does not exceed $100 million at any time. Borrowings under the Term Loan Agreement will bear interest at either (1) LIBOR plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve Bank of New York Rate plus 0.50% and (c) LIBOR multiplied by the Statutory Reserve Rate plus 1%. The applicable interest rate will depend on the Company’s election of whether to make the advance a LIBOR advance. The Term Loan Agreement terminates on February 5, 2018.

 

On February 5, 2016 the Company borrowed $50 million under the Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points and used the proceeds to pay down borrowings under the Otter Tail Corporation Credit Agreement that were used to fund the expansion of BTD’s Minnesota facilities in 2015 and to fund the September 1, 2015 acquisition of BTD-Georgia.

 

The Term Loan Agreement contains a number of restrictions on the Company, Varistar and certain subsidiaries of Varistar, including restrictions on its and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The Term Loan Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The Term Loan Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s credit ratings. The Company’s obligations under the Term Loan Agreement are guaranteed by Varistar and certain of its subsidiaries. 

 

2013 Note Purchase Agreement

On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) pursuant to which OTP has agreed to issue to the purchasers named therein, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). The Notes were issued on February 27, 2014. OTP used a portion of the proceeds of the Notes to retire early a $40.9 million term loan then outstanding and to repay OTP’s short-term debt outstanding on February 27, 2014. The remaining proceeds of the Notes were used to pay fees and expenses related to the issuance of the Notes and for other general purposes, including construction program expenditures.

 

The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states OTP must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP.

 

The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement, provided that no default or event of default has occurred and is continuing.

 

2007 and 2011 Note Purchase Agreements

On December 1, 2011, OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011 (the 2011 Note Purchase Agreement). OTP also has outstanding its $155 million senior unsecured notes issued in four series consisting of $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, due 2017; $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement).

 

The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.” 
 

Shelf Registration

On May 11, 2015 the Company filed a shelf registration statement with the SEC under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 11, 2018.

 

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of December 31, 2016 and December 31, 2015:

 

December 31, 2016 (in thousands)   OTP     Otter Tail 
Corporation		     Otter Tail 
Corporation 
Consolidated		  
Short-Term Debt   $ 42,883     $ —     $ 42,883  
Long-Term Debt:                        
Term Loan, LIBOR plus 0.90%, due February 5, 2018           $ 15,000     $ 15,000  
3.55% Guaranteed Senior Notes, due December 15, 2026             80,000       80,000  
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017   $ 33,000               33,000  
Senior Unsecured Notes 4.63%, due December 1, 2021     140,000               140,000  
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022     30,000               30,000  
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027     42,000               42,000  
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029     60,000               60,000  
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037     50,000               50,000  
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044     90,000               90,000  
North Dakota Development Note, 3.95%, due April 1, 2018             106       106  
PACE Note, 2.54%, due March 18, 2021             836       836  
Total   $ 445,000     $ 95,942     $ 540,942  
Less:   Current Maturities net of Unamortized Debt Issuance Costs     32,970       231       33,201  
Unamortized Long-Term Debt Issuance Costs     1,861       539       2,400  
Total Long-Term Debt net of Unamortized Debt Issuance Costs   $ 410,169     $ 95,172     $ 505,341  
Total Short-Term and Long-Term Debt (with current maturities)   $ 486,022     $ 95,403     $ 581,425  

 

December 31, 2015 (in thousands)   OTP   Otter Tail 
Corporation		   Otter Tail 
Corporation 
Consolidated
Short-Term Debt   $ 21,006     $ 59,666     $ 80,672  
Long-Term Debt:                        
9.000% Notes, due December 15, 2016           $ 52,330     $ 52,330  
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017   $ 33,000               33,000  
Senior Unsecured Notes 4.63%, due December 1, 2021     140,000               140,000  
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022     30,000               30,000  
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027     42,000               42,000  
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029     60,000               60,000  
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037     50,000               50,000  
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044     90,000               90,000  
North Dakota Development Note, 3.95%, due April 1, 2018             182       182  
PACE Note, 2.54%, due March 18, 2021             977       977  
Total   $ 445,000     $ 53,489     $ 498,489  
Less:   Current Maturities net of Unamortized Debt Issuance Costs             52,422       52,422  
 Unamortized Long-Term Debt Issuance Costs     2,099       122       2,221  
Total Long-Term Debt net of Unamortized Debt Issuance Costs   $ 442,901     $ 945     $ 443,846  
Total Short-Term and Long-Term Debt (with current maturities)   $ 463,907     $ 113,033     $ 576,940  

 

The aggregate amounts of maturities on bonds outstanding and other long-term obligations at December 31, 2016 for each of the next five years are:

 

(in thousands)   2017     2018     2019     2020     2021  
Aggregate Amounts of Debt Maturities   $ 33,231     $ 15,187     $ 172     $ 185     $ 140,171  
 

Financial Covenants

The Company and OTP were in compliance with the financial covenants in these debt agreements as of December 31, 2016.

 

No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

 

The Company’s and OTP’s borrowing agreements are subject to certain financial covenants. Specifically:

 

· Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, the Company may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis) as provided in the agreements.
     
· Under the 2016 Note Purchase Agreement, the Company may not permit its Priority Indebtedness to exceed 10% of its Total Capitalization. The Company had no Priority Indebtedness outstanding as of December 31, 2016.
     
· Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.
     
· Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement.
     
· Under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement. OTP had no Priority Indebtedness outstanding as of December 31, 2016.
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Pension Plan and Other Postretirement Benefits
 12 Months Ended
Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]  
Pension Plan and Other Postretirement Benefits

11. Pension Plan and Other Postretirement Benefits

 

For valuation of the Company’s pension and other postretirement benefit plans’ projected benefit obligations as of December 31, 2016, the Company adopted updated and modified mortality tables and an updated and modified mortality improvement scale that projects lower mortality improvements in the future for plan participants. The adoption of the updated and modified mortality tables and mortality improvement scale in 2016 decreased the Company’s pension and other postretirement benefit obligations from projected benefit obligations that would have been rendered using the mortality tables the Company had been using since 2014. Although the adoption of the updated and modified tables and improvement scale will have the effect of decreasing the estimated and recognized cost of future benefit payments in the near term, the ultimate cost recognized will be determined by the actual level and duration of future benefit payments.

 

Pension Plan

The Company's noncontributory funded pension plan covers substantially all corporate employees and OTP nonunion employees hired prior to September 1, 2006, and all union employees of OTP hired prior to November 1, 2013, excluding Coyote Station employees. Coyote Station employees hired before January 1, 2009 are covered under the plan. The plan provides 100% vesting after five vesting years of service and for retirement compensation at age 65, with reduced compensation in cases of retirement prior to age 62. The Company reserves the right to discontinue the plan but no change or discontinuance may affect the pensions theretofore vested.

 

The pension plan has a trustee who is responsible for pension payments to retirees and a separate pension fund manager responsible for managing the plan's assets. An independent actuary assists the Company in performing the necessary actuarial valuations for the plan.

 

The plan assets consist of common stock and bonds of public companies, U.S. government securities, cash and cash equivalents and alternative investments. None of the plan assets are invested in common stock or debt securities of the Company.

 

The following table lists components of net periodic pension benefit cost for the year ended December 31:

 

(in thousands)   2016     2015     2014  
Service Cost–Benefit Earned During the Period   $ 5,518     $ 6,059     $ 4,666  
Interest Cost on Projected Benefit Obligation     14,195       13,344       13,111  
Expected Return on Assets     (19,454 )     (18,383 )     (16,743 )
Amortization of Prior Service Cost:                        
From Regulatory Asset     189       188       257  
From Other Comprehensive Income1     5       5       7  
Amortization of Net Actuarial Loss:                        
From Regulatory Asset     5,153       6,676       3,400  
From Other Comprehensive Income1     127       171       83  
Net Periodic Pension Cost   $ 5,733     $ 8,060     $ 4,781  
1Corporate cost included in Other Nonelectric Expenses.                        

 

Weighted average assumptions used to determine net periodic pension cost for the year ended December 31:

 

    2016     2015     2014  
Discount Rate     4.76 %     4.35 %     5.30 %
Long-Term Rate of Return on Plan Assets     7.75 %     7.75 %     7.75 %
Rate of Increase in Future Compensation Level     3.13 %     3.13 %     3.13 %

 

The following table presents amounts recognized in the consolidated balance sheets as of December 31:

 

(in thousands)   2016     2015  
Regulatory Assets:                
Unrecognized Prior Service Cost   $ 141     $ 329  
Unrecognized Actuarial Loss     98,039       101,974  
Total Regulatory Assets   $ 98,180     $ 102,303  
Accumulated Other Comprehensive Loss:                
Unrecognized Prior Service Cost   $ 12     $ 16  
Unrecognized Actuarial Loss     406       820  
Total Accumulated Other Comprehensive Loss   $ 418     $ 836  
Noncurrent Liability   $ 60,292     $ 69,101  

 

Funded status as of December 31:

 

(in thousands)   2016     2015  
Accumulated Benefit Obligation   $ (281,414 )   $ (268,387 )
Projected Benefit Obligation   $ (314,637 )   $ (302,740 )
Fair Value of Plan Assets     254,345       233,639  
  Funded Status   $ (60,292 )   $ (69,101 )

 

The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s benefit obligations over the two-year period ended December 31, 2016:

 

(in thousands)   2016     2015  
Reconciliation of Fair Value of Plan Assets:                
Fair Value of Plan Assets at January 1   $ 233,639     $ 244,589  
Actual Return on Plan Assets     23,794       (9,160 )
Discretionary Company Contributions     10,000       10,000  
Benefit Payments     (13,088 )     (11,790 )
Fair Value of Plan Assets at December 31   $ 254,345     $ 233,639  
Estimated Asset Return     10.1 %     (3.7 )%
Reconciliation of Projected Benefit Obligation:                
Projected Benefit Obligation at January 1   $ 302,740     $ 311,650  
Service Cost     5,518       6,059  
Interest Cost     14,195       13,344  
Benefit Payments     (13,088 )     (11,790 )
Actuarial Loss (Gain)     5,272       (16,523 )
Projected Benefit Obligation at December 31   $ 314,637     $ 302,740  

 

Weighted average assumptions used to determine benefit obligations at December 31:

 

    2016     2015  
Discount Rate     4.60 %     4.76 %
Rate of Increase in Future Compensation Level     3.00 %     3.13 %

 

The assumed rate of return on pension fund assets used for the determination of 2017 net periodic pension cost is 7.50%. The assumed long-term rate of return on plan assets is based primarily on asset category studies using historical market return and volatility data with forward looking estimates based on existing financial market conditions and forecasts of capital markets. Modest excess return expectations versus some market indices are incorporated into the return projections based on the actively managed structure of the investment programs and their records of achieving such returns historically. The Company reviews its rate of return on plan asset assumptions annually. The assumptions are largely based on the asset category rate-of-return assumptions developed annually with the Company’s pension plan investment advisors, as well as input from actuaries who work with the pension plan.

 

Market-related value of plan assets—The Company’s expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets.

 

The Company bases actuarial determination of pension plan expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a five-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

 

Measurement Dates: 2016 2015
Net Periodic Pension Cost January 1, 2016 January 1, 2015
End of Year Benefit Obligations January 1, 2016 projected to 
December 31, 2016		 January 1, 2015 projected to 
December 31, 2015
Market Value of Assets December 31, 2016 December 31, 2015

 

The estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic pension cost in 2017 are:

 

(in thousands)   2017  
Decrease in Regulatory Assets:        
Amortization of Unrecognized Prior Service Cost   $ 120  
Amortization of Unrecognized Actuarial Loss     5,090  
Decrease in Accumulated Other Comprehensive Loss:        
Amortization of Unrecognized Prior Service Cost     3  
Amortization of Unrecognized Actuarial Loss     125  
Total Estimated Amortization   $ 5,338  

 

Cash flows—The Company had no minimum funding requirement as of December 31, 2016 and will continue to evaluate if discretionary plan contributions will be made in 2017.

 

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid out from plan assets:

 

(in thousands)   2017     2018     2019     2020     2021     Years
2022-2026		  
    $ 13,413     $ 14,140     $ 14,806     $ 15,564     $ 16,335     $ 92,083  

 

The following objectives guide the investment strategy of the Company’s pension plan (the Plan):

 

· The assets of the Plan will be invested in accordance with all applicable laws in a manner consistent with fiduciary standards including Employee Retirement Income Security Act standards (if applicable). Specifically:
o The safeguards and diversity that a prudent investor would adhere to must be present in the investment program.
o All transactions undertaken on behalf of the Plan must be in the best interest of plan participants and their beneficiaries.
· The primary objective of the Plan is to provide a source of retirement income for its participants and beneficiaries.
· The near-term primary financial objective of the Plan is to improve the funded status of the Plan.
· A secondary financial objective is to minimize pension funding and expense volatility where possible.

 

The asset allocation strategy developed by the Company’s Retirement Plans Administration Committee (the Committee) is based on the current needs of the Plan and the objectives listed above. An asset/liability review is conducted annually or as often as necessary to assess the impact of various asset allocations on funded status and other financial variables. The current needs of the Plan, the overall investment objectives above, the investment preferences and risk tolerance of the Committee and the desired degree of diversification suggest the need for an investment allocation including multiple asset classes.

 

The asset allocation in the table below contains guideline percentages, at market value, of the total Plan invested in various asset classes. The Permitted Range is a guide and will at times not reflect the actual asset allocation as this will be dictated by market conditions, the independent actions of the Committee and/or Investment Managers and required cash flows to and from the Plan. The Permitted Range anticipates this fluctuation and provides flexibility for the Investment Managers’ portfolios to vary around the target without the need for immediate rebalancing. The Investment Manager will proactively monitor the asset allocation and will direct the purchases and sales to remain within the stated ranges.

 

The policy of the Plan is to invest assets in accordance with the allocations shown below:

 

    Permitted Range
Asset Class / PBO Funded Status   < 100% PBO   100% PBO   105% PBO   >=110% PBO
Equity   30% - 65%   25% - 60%   20% - 55%   15% - 50%
Investment Grade Fixed Income   35% - 75%   40% - 80%   45% - 85%   50% - 90%
Below Investment Grade Fixed Income*     0% - 15%    0% - 15%    0% - 15%    0% - 15%
Other**     0% - 20%    0% - 20%    0% - 20%    0% - 20%
* Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds. 
** Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund. 

 

The Company’s pension plan asset allocations at December 31, 2016 and 2015, by asset category are as follows:

 

Asset Allocation   2016     2015  
Large Capitalization Equity Securities     21.4 %     21.2 %
International Equity Securities     22.0 %     21.6 %
Small and Mid-Capitalization Equity Securities     9.0 %     8.1 %
SEI Dynamic Asset Allocation Fund     5.4 %     5.6 %
Equity Securities     57.8 %     56.5 %
Fixed-Income Securities and Cash     34.3 %     35.8 %
Other – SEI Energy Debt Collective Fund     4.1 %     3.6 %
Other – SEI Special Situation Collective Investment Trust     3.8 %     4.1 %
      100.0 %     100.0 %

 

The following table presents the Company’s pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy and assets measured using the NAV practical expedient to fair valuation as of December 31:

 

(in thousands)   2016     2015  
Assets in Level 1 of the Fair Value Hierarchy   $ 234,303     $ 215,676  
SEI Energy Debt Collective Fund at NAV     10,441       8,342  
SEI Special Situation Collective Investment Trust Fund at NAV (1)     9,601       9,621  
Total Assets   $ 254,345     $ 233,639  

(1)On December 30, 2016 the Company instructed the pension fund manager to sell the pension fund investment in the SEI Special Situation Collective Investment Trust Fund. The cash value of the investment on settlement of the sale in January 2017 was $9,679,000.

 

Fair Value Measurements of Pension Fund Assets

ASC 715, Compensation – Retirement Benefits, requires disclosures about pension plan assets identified by the three levels of the fair value hierarchy established by ASC 820-10-35.

 

The following table presents, the Company’s pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy as of December 31:

 

(in thousands)   2016     2015  
Large Capitalization Equity Securities Mutual Fund   $ 54,483     $ 49,513  
International Equity Securities Mutual Funds     55,916       50,504  
Small and Mid-Capitalization Equity Securities Mutual Fund     23,011       18,823  
SEI Dynamic Asset Allocation Mutual Fund     13,622       13,004  
Fixed Income Securities Mutual Funds     87,268       83,830  
Cash Management – Money Market Fund     3       2  
Total Assets   $ 234,303     $ 215,676  

 

The investments held by the SEI Special Situation Collective Investment Trust on December 31, 2016 and 2015 consisted of investments primarily in hedge funds that pursue alternative strategies, private equity funds and hybrid funds, as well as investments directly in other securities and financial instruments, with the objective of achieving high returns balanced against an appropriate level of volatility and market exposure over a full market cycle. The NAV of the SEI Special Situations Collective Investment Trust is determined by using the fair value of the portfolio as of the close of business at the end of the year. The fair value of the fund is calculated independently by the fund’s administrator and is reviewed by the Company.

 

The investments held by the SEI Energy Debt Collective Fund on December 31, 2016 and 2015 consist mainly of below investment grade high yielding bonds and loans of U.S. energy companies which trade at a discount to fair value. Redemptions are allowed semi-annually with a 95-day notice period, subject to fund director consent and certain gate, holdback and suspension restrictions. Subscriptions are allowed monthly with a three-year lock up on subscriptions. The Company invested $10.0 million in the SEI Energy Debt Fund in July 2015. The fund’s assets are valued in accordance with valuations reported by the fund’s sub-advisor or the fund’s underlying investments or other independent third party sources, although SEI in its discretion may use other valuation methods, subject to compliance with ERISA (as applicable). The fund’s assets are valued as of the close of business on the last business day of each calendar month and are available 30 days after the end of a calendar quarter. On an annual basis, as determined by the investment manager in its sole discretion, an independent valuation agent is retained to provide a valuation of the illiquid assets of the fund and of any other asset of the fund, as determined by the investment manager in its sole discretion. The Company reviews and verifies the reasonableness of the year-end valuations.

 

Executive Survivor and Supplemental Retirement Plan (ESSRP)

The ESSRP is an unfunded, nonqualified benefit plan for executive officers and certain key management employees. The ESSRP provides defined benefit payments to these employees on their retirements for life or to their beneficiaries on their deaths for a 15-year postretirement period. Life insurance carried on certain plan participants is payable to the Company on the employee's death. There are no plan assets in this nonqualified benefit plan due to the nature of the plan.

 

The following table lists components of net periodic pension benefit cost for the year ended December 31:

 

(in thousands)   2016       2015       2014  
Service Cost–Benefit Earned During the Period   $ 252     $ 189     $ 51  
Interest Cost on Projected Benefit Obligation     1,667       1,523       1,520  
Amortization of Prior Service Cost:                        
From Regulatory Asset     16       16       22  
From Other Comprehensive Income1     38       38       51  
Amortization of Net Actuarial Loss:                        
From Regulatory Asset     293       334       142  
From Other Comprehensive Income2     446       602       46  
Net Periodic Pension Cost   $ 2,712     $ 2,702     $ 1,832  
1  Amortization of Prior Service Costs from Other Comprehensive Income Charged to:                        
Electric Operation and Maintenance Expenses   $ 15     $ 15     $ 20  
Other Nonelectric Expenses     23       23       31  
                         
2  Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:                        
Electric Operation and Maintenance Expenses   $ 272     $ 310     $ 132  
Other Nonelectric Expenses     174       292       (86 )

 

Weighted average assumptions used to determine net periodic pension cost for the year ended December 31:

 

    2016     2015     2014  
Discount Rate     4.76 %     4.35 %     5.30 %
Rate of Increase in Future Compensation Level     3.13 %     3.15 %     3.18 %

 

The following table presents amounts recognized in the consolidated balance sheets as of December 31:

 

(in thousands)   2016     2015  
Regulatory Assets:                
Unrecognized Prior Service Cost   $ 58     $ 75  
Unrecognized Actuarial Loss     2,890       2,936  
Total Regulatory Assets   $ 2,948     $ 3,011  
Projected Benefit Obligation Liability – Net Amount Recognized   $ (37,335 )   $ (35,811 )
Accumulated Other Comprehensive Loss:                
Unrecognized Prior Service Cost   $ 134     $ 172  
Unrecognized Actuarial Loss     5,915       5,815  
Total Accumulated Other Comprehensive Loss   $ 6,049     $ 5,987  

 

The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations over the two-year period ended December 31, 2016 and a statement of the funded status as of December 31 of both years:

 

(in thousands)   2016     2015  
Reconciliation of Fair Value of Plan Assets:                
Fair Value of Plan Assets at January 1   $ —     $ —  
Actual Return on Plan Assets     —       —  
Employer Contributions     1,188       1,119  
Benefit Payments     (1,188 )     (1,119 )
Fair Value of Plan Assets at December 31   $ —     $ —  
Reconciliation of Projected Benefit Obligation:                
Projected Benefit Obligation at January 1   $ 35,811     $ 35,650  
Service Cost     252       189  
Interest Cost     1,667       1,523  
Benefit Payments     (1,188 )     (1,119 )
Plan Amendments     —       —  
Actuarial Loss (Gain)     793       (432 )
Projected Benefit Obligation at December 31   $ 37,335     $ 35,811  

 

Weighted average assumptions used to determine benefit obligations at December 31:

 

    2016     2015  
Discount Rate     4.60 %     4.76 %
Rate of Increase in Future Compensation Level     3.00 %     3.13 %

 

The estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic pension cost for the ESSRP in 2017 are:

 

(in thousands)   2017  
Decrease in Regulatory Assets:        
Amortization of Unrecognized Prior Service Cost   $ 16  
Amortization of Unrecognized Actuarial Loss     285  
Decrease in Accumulated Other Comprehensive Loss:        
Amortization of Unrecognized Prior Service Cost     38  
Amortization of Unrecognized Actuarial Loss     440  
Total Estimated Amortization   $ 779  

 

Cash flows—The ESSRP is unfunded and has no assets; contributions are equal to the benefits paid to plan participants. The following benefit payments, which reflect future service, as appropriate, are expected to be paid:

 

    Years  
(in thousands)   2017     2018     2019     2020     2021     2022-2026  
    $ 1,253     $ 1,487     $ 1,562     $ 1,544     $ 1,754     $ 12,700  

 

Other Postretirement Benefits

The Company provides a portion of health insurance and life insurance benefits for retired OTP and corporate employees. Substantially all of the Company's electric utility and corporate employees may become eligible for health insurance benefits if they reach age 55 and have 10 years of service. There are no plan assets. The following table lists components of net periodic postretirement benefit cost for the year ended December 31:

 

(in thousands)   2016     2015     2014  
Service Cost–Benefit Earned During the Period   $ 1,301     $ 1,297     $ 1,055  
Interest Cost on Projected Benefit Obligation     2,503       2,097       2,200  
Amortization of Prior Service Cost                        
From Regulatory Asset     134       205       205  
From Other Comprehensive Income1     3       5       5  
Amortization of Net Actuarial Loss                        
From Regulatory Asset     379       —       —  
From Other Comprehensive Income1     9       —       —  
  Net Periodic Postretirement Benefit Cost   $ 4,329     $ 3,604     $ 3,465  
Effect of Medicare Part D Subsidy   $ (923 )   $ (1,487 )   $ (948 )
1 Corporate cost included in Other Nonelectric Expenses.                        

 

Weighted average assumptions used to determine net periodic postretirement benefit cost for the year ended December 31:

 

    2016     2015     2014  
Discount Rate     4.57 %     4.20 %     5.10 %

 

The following table presents amounts recognized in the consolidated balance sheets as of December 31:

 

(in thousands)   2016     2015  
Regulatory Asset:                
Unrecognized Prior Service Cost   $ (4 )   $ 129  
Unrecognized Net Actuarial Loss     13,586       1,289  
Net Regulatory Asset   $ 13,582     $ 1,418  
Projected Benefit Obligation Liability – Net Amount Recognized   $ (62,571 )   $ (48,730 )
Accumulated Other Comprehensive (Income) Loss:                
Unrecognized Prior Service Cost   $ 4     $ 8  
Unrecognized Net Actuarial Gain     (171 )     (347 )
Accumulated Other Comprehensive Income   $ (167 )   $ (339 )

 

The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations and accrued postretirement benefit cost over the two-year period ended December 31, 2016:

 

(in thousands)   2016     2015  
Reconciliation of Fair Value of Plan Assets:                
Fair Value of Plan Assets at January 1   $ —     $ —  
Actual Return on Plan Assets     —       —  
Company Contributions     2,825       2,365  
Benefit Payments (Net of Medicare Part D Subsidy)     (5,908 )     (5,324 )
Participant Premium Payments     3,083       2,959  
Fair Value of Plan Assets at December 31   $ —     $ —  
Reconciliation of Projected Benefit Obligation:                
Projected Benefit Obligation at January 1   $ 48,730     $ 53,638  
Service Cost (Net of Medicare Part D Subsidy)     1,301       1,297  
Interest Cost (Net of Medicare Part D Subsidy)     2,503       2,097  
Benefit Payments (Net of Medicare Part D Subsidy)     (5,908 )     (5,324 )
Participant Premium Payments     3,083       2,959  
Actuarial Loss (Gain)     12,862       (5,937 )
Projected Benefit Obligation at December 31   $ 62,571     $ 48,730  
Reconciliation of Accrued Postretirement Cost:                
Accrued Postretirement Cost at January 1   $ (47,652 )   $ (46,413 )
Expense     (4,329 )     (3,604 )
Net Company Contribution     2,825       2,365  
Accrued Postretirement Cost at December 31   $ (49,156 )   $ (47,652 )

 

Weighted average assumptions used to determine benefit obligations at December 31:

 

    2016     2015  
Discount Rate     4.46 %     4.57 %

 

Assumed healthcare cost-trend rates as of December 31:

    2016     2015  
Healthcare Cost-Trend Rate Assumed for Next Year Pre-65     6.01 %     6.16 %
Healthcare Cost-Trend Rate Assumed for Next Year Post-65     6.23 %     6.43 %
Rate to Which the Cost-Trend Rate is Assumed to Decline     4.50 %     4.50 %
Year the Rate Reaches the Ultimate Trend Rate     2038       2038  

 

Assumed healthcare cost-trend rates have a significant effect on the amounts reported for healthcare plans. A one-percentage-point change in assumed healthcare cost-trend rates for 2016 would have the following effects:

(in thousands)   1 Point 
Increase		     1 Point
Decrease		  
Effect on the Postretirement Benefit Obligation   $ 7,151     $ (7,492 )
Effect on Total of Service and Interest Cost   $ 653     $ (519 )
Effect on Expense   $ 1,454     $ (907 )

  

Measurement Dates: 2016 2015
Net Periodic Postretirement Benefit Cost January 1, 2016 January 1, 2015
     
End of Year Benefit Obligations January 1, 2016 projected to 
December 31, 2016		 January 1, 2015 projected to 
December 31, 2015

 

The estimated net amounts of unrecognized prior service cost to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic postretirement benefit cost in 2017 are:

 

(in thousands)   2017  
Decrease in Regulatory Assets:        
Amortization of Unrecognized Prior Service Cost   $ —  
Amortization of Unrecognized Actuarial Loss     932  
Decrease in Accumulated Other Comprehensive Loss:        
Amortization of Unrecognized Prior Service Cost     —  
Amortization of Unrecognized Actuarial Loss     23  
Total Estimated Amortization   $ 955  

 

Cash flows—The Company expects to contribute $3.5 million net of expected employee contributions for the payment of retiree medical benefits and Medicare Part D subsidy receipts in 2017. The Company expects to receive a Medicare Part D subsidy from the Federal government of approximately $416,000 in 2017. The following benefit payments, which reflect expected future service, as appropriate, net of expected Medicare Part D subsidy receipts and participant premium payments, are expected to be paid:

 

    Years  
(in thousands)   2017     2018     2019     2020     2021     2022-2026  
     $ 3,512     $ 3,669     $ 3,828     $ 3,912     $ 4,046     $ 20,377  

 

401K Plan

The Company sponsors a 401K plan for the benefit of all corporate and subsidiary company employees. Contributions made to these plans by the Company and its subsidiary companies included in continuing operations totaled $3,877,000 for 2016, $3,602,000 for 2015 and $3,171,000 for 2014.

 

Employee Stock Ownership Plan

The Company has a stock ownership plan for the benefit of all its electric utility employees. Contributions made by the Company were $647,000 for 2016, $674,000 for 2015 and $696,000 for 2014.
XML 47 R24.htm IDEA: XBRL DOCUMENT v3.6.0.2
Fair Value of Financial Instruments
 12 Months Ended
Dec. 31, 2016
Fair Value Disclosures [Abstract]  
Fair Value of Financial Instruments

12. Fair Value of Financial Instruments

 

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

 

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of December 31, 2016 and December 31, 2015 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, for the respective entities, which approximate market rates.

 

Long-Term Debt including Current Maturities—The fair value of the Company's and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.

 

  December 31, 2016  December 31, 2015 
(in thousands) Carrying 
Amount		  Fair Value  Carrying 
Amount		  Fair Value 
Cash and Cash Equivalents $—  $—  $—  $— 
Short-Term Debt  (42,883)  (42,883)  (80,672)  (80,672)
Long-Term Debt including Current Maturities  (538,542)  (583,835)  (496,268)  (561,245)
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Property, Plant and Equipment
 12 Months Ended
Dec. 31, 2016
Property, Plant and Equipment [Abstract]  
Property, Plant and Equipment

13. Property, Plant and Equipment

 

(in thousands) December 31,
2016		  December 31,
2015		 
Electric Plant in Service        
Production $891,330  $879,121 
Transmission  410,679   391,941 
Distribution  466,285   451,820 
General  92,063   97,881 
Electric Plant in Service  1,860,357   1,820,763 
Construction Work in Progress  149,997   64,117 
Total Gross Electric Plant  2,010,354   1,884,880 
Less Accumulated Depreciation and Amortization  622,657   592,001 
Net Electric Plant $1,387,697  $1,292,879 
Nonelectric Operations Plant        
Equipment $155,809  $155,715 
Buildings and Leasehold Improvements  51,323   41,149 
Land  4,694   4,479 
Nonelectric Operations Plant  211,826   201,343 
Construction Work in Progress  3,264   15,495 
Total Gross Nonelectric Plant  215,090   216,838 
Less Accumulated Depreciation and Amortization  125,562   121,903 
Net Nonelectric Operations Plant $89,528  $94,935 
Net Plant $1,477,225  $1,387,814 

 

The estimated service lives for rate-regulated properties is 5 to 82 years. For nonelectric property the estimated useful lives are from 3 to 40 years.

 

  Service Life Range 
(years) Low  High 
Electric Fixed Assets:        
Production Plant  9   82 
Transmission Plant  42   70 
Distribution Plant  5   68 
General Plant  5   50 
Nonelectric Fixed Assets:        
Equipment  3   12 
Buildings and Leasehold Improvements  7   40 
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Income Taxes
 12 Months Ended
Dec. 31, 2016
Income Tax Disclosure [Abstract]  
Income Taxes

14. Income Taxes

 

The total income tax expense differs from the amount computed by applying the federal income tax rate (35% in 2016, 2015 and 2014) to net income before total income tax expense for the following reasons:

 

(in thousands)   2016     2015     2014  
Tax Computed at Federal Statutory Rate – Continuing Operations   $ 28,741     $ 28,081     $ 25,704  
Increases (Decreases) in Tax from:                        
Federal PTCs     (7,175 )     (6,962 )     (7,517 )
State Income Taxes Net of Federal Income Tax Expense     2,848       4,945       1,993  
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes     (850 )     (850 )     (849 )
Corporate-owned Life Insurance     (680 )     (167 )     (354 )
Dividend Received/Paid Deduction     (537 )     (560 )     (622 )
Section 199 Domestic Production Activities Deduction     (482 )     —       (1,026 )
Investment Tax Credit Amortization     (350 )     (571 )     (597 )
Allowance for Funds Used During Construction – Equity     (280 )     (426 )     (505 )
Differences Reversing in Excess of Federal Rates     77       (1,143 )     (106 )
Permanent and Other Differences     (1,231 )     (705 )     436  
Total Income Tax Expense – Continuing Operations   $ 20,081     $ 21,642     $ 16,557  
Income Tax Expense – Discontinued Operations – U.S.     138       2,991       3,952  
Income Tax Expense – Continuing and Discontinued Operations   $ 20,219     $ 24,633     $ 20,509  
Overall Effective Federal, State and Foreign Income Tax Rate     24.5 %     29.3 %     26.2 %
Income Tax Expense From Continuing Operations Includes the Following:                        
Current Federal Income Taxes   $ 1,070     $ 211     $ 124  
Current State Income Taxes     1,211       1       5  
Deferred Federal Income Taxes     23,586       23,050       21,044  
Deferred State Income Taxes     2,589       6,763       4,347  
Federal PTCs     (7,175 )     (6,962 )     (7,517 )
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes     (850 )     (850 )     (849 )
Investment Tax Credit Amortization     (350 )     (571 )     (597 )
Total   $ 20,081     $ 21,642     $ 16,557  
Total Income Before Income Taxes – Continuing and Discontinued Operations   $ 82,540     $ 83,978     $ 78,232  

 

 

The Company's deferred tax assets and liabilities were composed of the following on December 31:

 

(in thousands)   2016     2015  
Deferred Tax Assets                
Benefit Liabilities   $ 44,381     $ 41,788  
Federal PTCs     43,433       39,505  
Retirement Benefits Liabilities     38,390       41,958  
North Dakota Wind Tax Credits     32,962       32,962  
Cost of Removal     31,636       29,463  
Differences Related to Property     9,876       10,177  
Net Operating Loss Carryforward     3,865       22,824  
Vacation Accrual     2,725       2,500  
Investment Tax Credits     818       1,109  
Other     7,793       7,617  
Total Deferred Tax Assets   $ 215,879     $ 229,903  
Deferred Tax Liabilities                
Differences Related to Property   $ (371,761 )   $ (366,234 )
Retirement Benefits Regulatory Asset     (38,390 )     (41,958 )
Excess Tax over Book Pension     (15,509 )     (13,775 )
North Dakota Wind Tax Credits     (3,654 )     (3,179 )
Impact of State Net Operating Losses on Federal Taxes     (1,352 )     (1,596 )
Other     (11,804 )     (10,830 )
 Total Deferred Tax Liabilities   $ (442,470 )   $ (437,572 )
 Deferred Income Taxes   $ (226,591 )   $ (207,669 )

 

Federal PTCs are earned as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs increased 3.6% in 2016 compared with 2015. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

 

Schedule of expiration of tax credits and tax net operating losses available as of December 31, 2016:

 

(in thousands)   Amount     2017     2027-36  
United States                        
Federal Net Operating Losses   $ —     $ —     $ —  
Federal Tax Credits     46,435       —       46,435  
State Net Operating Losses     3,865       —       3,865  
State Tax Credits     33,993       389       33,604  

 

The carryforward period on a portion of the North Dakota wind tax credits from the Langdon wind project is five years. OTP has adjusted its deferred tax assets and deferred tax credits by $0.4 million for potential unused North Dakota wind tax credits related to the Langdon wind project.

 

The following table summarizes the activity related to our unrecognized tax benefits:

 

(in thousands)   2016     2015     2014  
Balance on January 1   $ 468     $ 222     $ 4,239  
Increases Related to Tax Positions for Prior Years     406       236       120  
Decreases Related to Tax Positions for Prior Years     —       —       (4,142 )
Increases Related to Tax Positions for Current Year     114       10       5  
Uncertain Positions Resolved During Year     (97 )     —       —  
Balance on December 31   $ 891     $ 468     $ 222  

 

The balance of unrecognized tax benefits as of December 31, 2016 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of December 31, 2016 is not expected to change significantly within the next 12 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in our consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of December 31, 2016.

 

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of December 31, 2016, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2013 for federal and Minnesota and North Dakota state income taxes.
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Asset Retirement Obligations (AROs)
 12 Months Ended
Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations (AROs)

15. Asset Retirement Obligations (AROs)

 

The Company’s AROs are related to OTP’s coal-fired generation plants and its 92 wind turbines located in North Dakota. The AROs include items such as site restoration, closure of ash pits, and removal of certain structures, generators, asbestos and storage tanks. The Company has legal obligations associated with the retirement of a variety of other long-lived tangible assets used in electric operations where the estimated settlement costs are individually and collectively immaterial. The Company has no assets legally restricted for the settlement of any of its AROs.

 

On December 19, 2014 the EPA’s rule regulating coal combustion residuals (CCR) went into effect. The final rule regulates CCR as a non-hazardous solid waste under Subtitle D of the Resource Conservation and Recovery Act. In the second quarter of 2015, subsequent to publication of the CCR rule, OTP completed an assessment of its ash handling and storage facilities at Hoot Lake Plant, Coyote Station and Big Stone Plant and determined that it had no immediate obligation under the rules to close or modify any existing ash handling facilities or storage sites but has discontinued the use of one pit at Coyote Station to avoid the potential for future obligations related to this site under the CCR rule. Additionally, OTP identified a slag sluice pond and slag stockpile area at Big Stone Plant that will need to be reclaimed at a future date to comply with the CCR rule. OTP established an ARO liability of approximately $0.5 million for its share of the estimated future costs to reclaim this site. Although identified as a new ARO resulting from the issuance of the CCR rule, the slag sluice pond and slag stockpile are currently in use, so the cost of the new ARO was capitalized. Therefore, the establishment of the ARO will have no impact on current year consolidated operating expenses but will result in an offsetting charge to the removal cost component of the accumulated provision for depreciation on the Company’s consolidated balance sheet. Future reclamation costs, when incurred, will be charged against, and reduce, the accumulated ARO liability.
 

OTP recorded no new AROs in 2016.

 

Reconciliations of carrying amounts of the present value of the Company’s legal AROs, capitalized asset retirement costs and related accumulated depreciation and a summary of settlement activity for the years ended December 31, 2016 and 2015 are presented in the following table:

 

(in thousands) 2016  2015 
Asset Retirement Obligations        
Beginning Balance $8,084  $7,721 
New Obligations Recognized  —   451 
Adjustments Due to Revisions in Cash Flow Estimates  (103)  (424)
Accrued Accretion  360   336 
Settlements  —   — 
Ending Balance $8,341  $8,084 
Asset Retirement Costs Capitalized        
Beginning Balance $3,086  $3,059 
New Obligations Recognized  —   451 
Adjustments Due to Revisions in Cash Flow Estimates  (103)  (424)
Settlements  —   — 
Ending Balance $2,983  $3,086 
Accumulated Depreciation – Asset Retirement Costs Capitalized        
Beginning Balance $673  $527 
New Obligations Recognized  —   — 
Adjustments Due to Revisions in Cash Flow Estimates  —   — 
Depreciation Expense  122   146 
Settlements  —   — 
Ending Balance $795  $673 
Settlements  None   None 
Original Capitalized Asset Retirement Cost – Retired $—  $— 
Accumulated Depreciation  —   — 
         
Asset Retirement Obligation $—  $— 
Settlement Cost  —   — 
Gain on Settlement – Deferred Under Regulatory Accounting $—  $— 
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Discontinued Operations
 12 Months Ended
Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]  
Discontinued Operations

16. Discontinued Operations

 

On April 30, 2015 the Company sold Foley for $12.0 million in cash, plus $6.3 million in adjustments for working capital and other related items received in October 2015, less $1.0 million in selling expenses. On February 28, 2015 the Company sold the assets of AEV, Inc. for $22.3 million in cash, plus $0.6 million in adjustments for working capital and fixed assets received in October 2015, less $0.8 million in selling expenses. Foley and AEV, Inc. were formerly included in the Company’s Construction segment.

 

On February 8, 2013 the Company completed the sale of substantially all the assets of its dock and boatlift company, formerly included in our Manufacturing segment. On November 30, 2012 the Company completed the sale of the assets of our wind tower manufacturing business. This business was the only remaining entity in the Company’s former Wind Energy segment.

 

The Company’s Wind Energy and Construction segments were eliminated as a result of the sales of its wind tower manufacturing business, Foley and AEV, Inc. The financial position, results of operations and cash flows of Foley, AEV, Inc., the Company’s wind tower manufacturing business and its dock and boatlift company are reported as discontinued operations in the Company’s consolidated financial statements.

 

 

Following are summary presentations of the results of discontinued operations for the years ended December 31, 2016, 2015 and 2014:

 

    For the Year Ended December 31, 2016  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower 
Business		     Dock and 
Boatlift 
Business		     Intercompany 
Transactions 
Adjustment		     Total  
Operating Expenses   $ 250     $ —     $ (757 )   $ 85     $ —     $ (422 )
Income Tax (Benefit) Expense     (136 )     5       303       (34 )     —       138  
Net (Loss) Income   $ (114 )   $ (5 )   $ 454     $ (51 )   $ —     $ 284  

 

    For the Year Ended December 31, 2015  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower 
Business		     Dock and 
Boatlift 
Business		     Intercompany 
Transactions 
Adjustment		     Total  
Operating Revenues   $ 21,625     $ 2,998     $ —     $ —     $ —     $ 24,623  
Operating Expenses     26,839       4,532       (462 )     966       (240 )     31,635  
Asset Impairment Charge     1,000       —       —       —       —       1,000  
Interest Expense     177       27       —       —       (204 )     —  
Other Income (Deductions)     (42 )     2       111       —       (2 )     69  
Income Tax (Benefit) Expense     (921 )     (638 )     229       (386 )     177       (1,539 )
Net (Loss) Income from Operations     (5,512 )     (921 )     344       (580 )     265       (6,404 )
(Loss) Gain on Disposition Before Taxes     (204 )     11,894       —       —       —       11,690  
Income Tax (Benefit) Expense on Disposition     (227 )     4,757       —       —       —       4,530  
Net Gain on Disposition     23       7,137       —       —       —       7,160  
Net (Loss) Income   $ (5,489 )   $ 6,216     $ 344     $ (580 )   $ 265     $ 756  

 

    For the Year Ended December 31, 2014  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower
Business		     Dock and 
Boatlift 
Business		     Intercompany 
Transactions
Adjustment		     Total  
Operating Revenues   $ 105,333     $ 44,527     $ —     $ —     $ —     $ 149,860  
Operating Expenses     100,826       40,297       19       (180 )     (960 )     140,002  
Asset Impairment Charge     5,605       —       —       —       —       5,605  
Interest Expense     510       184       —       —       (694 )     —  
Other (Deductions) Income     (38 )     304       —       277       (4 )     539  
Income Tax Expense (Benefit)     1,388       1,729       (8 )     183       660       3,952  
Net (Loss) Income   $ (3,034 )   $ 2,621     $ (11 )   $ 274     $ 990     $ 840  

 

Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts were recognized on a percentage-of-completion basis. The method used to determine the progress of completion was based on the ratio of costs incurred to total estimated costs on construction projects. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in pretax charges of $4.4 million in 2015.

 

In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued operations.

 

 

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of December 31, 2016 and December 31, 2015:

 

    December 31, 2016  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower 
Business		     Dock and 
Boatlift
Business		     Total  
Current Liabilities   $ —     $ —     $ 589     $ 774     $ 1,363  
Liabilities of Discontinued Operations   $ —     $ —     $ 589     $ 774     $ 1,363  

 

    December 31, 2015  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower 
Business		     Dock and 
Boatlift 
Business		     Total  
Current Liabilities   $ —     $ —     $ 1,299     $ 799     $ 2,098  
Liabilities of Discontinued Operations   $ —     $ —     $ 1,299     $ 799     $ 2,098  

 

Included in current liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow:

 

(in thousands)   2016     2015  
Warranty Reserve Balance, January 1   $ 2,103     $ 2,527  
Additional Provision for Warranties Made During the Year     —       —  
Settlements Made During the Year     (24 )     (124 )
Decrease in Warranty Estimates for Prior Years     (710 )     (300 )
Warranty Reserve Balance, December 31   $ 1,369     $ 2,103  

 

The warranty reserve balances as of December 31, 2016 relate entirely to products produced by the Company’s former wind tower and dock and boatlift manufacturing companies. Certain products sold by the companies carried one to fifteen year warranties. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies.

 

Expenses associated with remediation activities of these companies could be substantial. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated net income and financial condition.
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Subsequent Events
 12 Months Ended
Dec. 31, 2016
Subsequent Events [Abstract]  
Subsequent Events

17. Subsequent Events

 

Stock Incentive Awards

On February 2, 2017 the following stock incentive awards were granted to officers under the 2014 Incentive Plan:

 

Award Shares/Units 
Granted		  Weighted 
Average 
Grant-Date
Fair Value 
per Award		  Vesting 
Restricted Stock Units Granted  15,900  $37.65   25% per year through February 6, 2021 
Stock Performance Awards Granted  59,500  $31.00   December 31, 2019 

 

The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant. 

 

Under the performance share awards the aggregate award for performance at target is 59,500 shares. For target performance the participants would earn an aggregate of 39,667 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2017 through December 31, 2019, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2017 and the average closing price for the 20 trading days immediately preceding January 1, 2020. The participants would also earn an aggregate of 19,833 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 89,250 common shares. There are no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance measurement period. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718, and will be measured over the performance period based on the grant-date fair value of the award.

 

Under the 2017 Performance Award Agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to Executive Employment Agreements with the Company is to be made at target at the date of any such event.

 

The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.
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SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
 12 Months Ended
Dec. 31, 2016
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]  
CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

 
OTTER TAIL CORPORATION (PARENT COMPANY)
Condensed Balance Sheets, December 31
(in thousands)   2016     2015  
ASSETS                
Current Assets                
Cash and Cash Equivalents   $ 6,218     $ —  
Accounts Receivable     12       38  
Accounts Receivable from Subsidiaries     1,706       2,311  
Interest Receivable from Subsidiaries     141       175  
Income Taxes Receivable     662       4,000  
Notes Receivable from Subsidiaries     1,671       5,645  
Other     936       1,096  
Total Current Assets     11,346       13,265  
Investments in Subsidiaries     692,723       713,344  
Notes Receivable from Subsidiaries     79,843       72,560  
Deferred Income Taxes     35,387       37,406  
Other Assets     29,079       26,957  
Total Assets   $ 848,378     $ 863,532  
                 
LIABILITIES AND EQUITY                
                 
Current Liabilities                
Short-Term Debt   $ —     $ 59,666  
Current Maturities of Long-Term Debt     231       52,422  
Accounts Payable to Subsidiaries     5,958       5,959  
Notes Payable to Subsidiaries     38,519       99,467  
Other     5,838       6,035  
Total Current Liabilities     50,546       223,549  
                 
Other Noncurrent Liabilities     32,556       34,015  
Commitments and Contingencies                
Capitalization                
Long-Term Debt, Net of Current Maturities     95,172       945  
Common Shareholder Equity     670,104       605,023  
Total Capitalization     765,276       605,968  
Total Liabilities and Equity   $ 848,378     $ 863,532  
See accompanying notes to condensed financial statements.                

 

 

OTTER TAIL CORPORATION (PARENT COMPANY)
Condensed Statements of Income—For the Years Ended December 31
(in thousands)   2016     2015     2014  
                   
Operating Loss                        
Revenue   $ —     $ —     $ —  
Operating Expenses     9,689       10,188       12,593  
Operating Loss     (9,689 )     (10,188 )     (12,593 )
                         
Other Income (Expense)                        
Equity Income in Earnings of Subsidiaries     67,047       66,067       64,926  
Interest Charges     (6,817 )     (6,786 )     (6,326 )
Interest Charges to Subsidiaries     (173 )     (193 )     (117 )
Interest Income from Subsidiaries     4,897       4,786       4,980  
Other Income     1,621       421       1,379  
Total Other Income     66,575       64,295       64,842  
                         
Income Before Income Taxes     56,886       54,107       52,249  
Income Tax Benefit     (5,435 )     (5,238 )     (5,474 )
Net Income   $ 62,321     $ 59,345     $ 57,723  
See accompanying notes to condensed financial statements.                        

 

OTTER TAIL CORPORATION (PARENT COMPANY)
Condensed Statements of Cash Flows—For the Years Ended December 31
(in thousands)   2016     2015     2014  
Cash Flows from Operating Activities                        
                         
Net Cash Provided by Operating Activities   $ 83,296     $ 53,958     $ 47,697  
                         
Cash Flows from Investing Activities                        
Return of Capital (Investment in Subsidiaries)     9,912       (88,079 )     (44,000 )
Debt Issued to Subsidiaries     (3,309 )     (12,592 )     (7,662 )
Cash Provided by (Used in) Investing Activities     106       (11 )     (44 )
Net Cash Provided by (Used in) Investing Activities     6,709       (100,682 )     (51,706 )
                         
Cash Flows from Financing Activities                        
Change in Checks Written in Excess of Cash     (428 )     213       215  
Net Short-Term (Repayments) Borrowings     (59,666 )     48,812       10,854  
(Repayments to) Borrowings from Subsidiaries     (60,948 )     32,249       4,656  
Proceeds from Issuance of Common Stock     44,435       14,233       26,259  
Common Stock Issuance Expenses     (562 )     (451 )     (673 )
Payments for Retirement of Capital Stock     (104 )     (1,596 )     (590 )
Proceeds from the Issuance of Long-Term Debt     130,000       —       —  
Short-Term and Long-Term Debt Issuance Expenses     (723 )     (312 )     (170 )
Payments for Retirement of Long-Term Debt     (87,547 )     (201 )     (188 )
Dividends Paid and Other Distributions     (48,244 )     (46,223 )     (44,261 )
Net Cash (Used in) Provided by Financing Activities     (83,787 )     46,724       (3,898 )
Net Change in Cash and Cash Equivalents     6,218       —       (7,907 )
Cash and Cash Equivalents at Beginning of Period     —       —       7,907  
Cash and Cash Equivalents at End of Period   $ 6,218     $ —     $ —  
See accompanying notes to condensed financial statements.                        

 

Otter Tail Corporation (Parent Company)

Notes to Condensed Financial Statements

For the years ended December 31, 2016, 2015 and 2014

 

Incorporated by reference are Otter Tail Corporation’s consolidated statements of comprehensive income and common shareholders’ equity in Part II, Item 8.

 

Basis of Presentation

 

The condensed financial information of Otter Tail Corporation is presented to comply with Rule 12-04 of Regulation S-X. The unconsolidated condensed financial statements do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read with the consolidated financial statements and related notes included in this Annual Report on Form 10-K.

 

Otter Tail Corporation’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income (loss) from operations of the subsidiaries is reported on a net basis as equity income (loss) in earnings of subsidiaries.

 

Related Party Transactions

 

As of December 31, 2016: 
(in thousands)		   Accounts 
Receivable		     Interest 
Receivable		     Current 
Notes 
Receivable		     Long-Term 
Notes 
Receivable		     Accounts 
Payable		     Current 
Notes 
Payable		  
Otter Tail Power Company   $ 1,572     $ —     $ —     $ —     $ 10     $ —  
Vinyltech Corporation     3       20       —       11,500       —       15,951  
Northern Pipe Products, Inc.     —       10       —       5,943       —       6,560  
BTD Manufacturing, Inc.     —       92       —       52,000       —       2,342  
Wind Tower Business     —       —       1,441       —       —       —  
Dock and Boatlift Business     —       —       230       —       —       —  
T.O. Plastics, Inc.     —       19       —       10,400       —       12,378  
Varistar Corporation     60       —       —       —       5,948       1,288  
Otter Tail Assurance Limited     71       —       —       —       —       —  
    $ 1,706     $ 141     $ 1,671     $ 79,843     $ 5,958     $ 38,519  

 

As of December 31, 2015: 
(in thousands)		   Accounts 
Receivable		     Interest 
Receivable		     Current 
Notes 
Receivable		     Long-Term 
Notes 
Receivable		     Accounts 
Payable		     Current 
Notes 
Payable		  
Otter Tail Power Company   $ 1,928     $ —     $ —     $ —     $ 11     $ —  
Vinyltech Corporation     —       32       —       8,500       —       14,844  
Northern Pipe Products, Inc.     —       8       —       3,160       —       7,088  
BTD Manufacturing, Inc.     13       107       3,924       53,500       —       —  
Wind Tower Business     —       —       1,444       —       —       —  
Dock and Boatlift Business     —       —       277       —       —       —  
T.O. Plastics, Inc.     —       28       —       7,400       —       6,405  
Varistar Corporation     60       —       —       —       5,948       71,130  
Otter Tail Assurance Limited     310       —       —       —       —       —  
    $ 2,311     $ 175     $ 5,645     $ 72,560     $ 5,959     $ 99,467  

 

Dividends

 

Dividends paid to Otter Tail Corporation (the Parent) from its subsidiaries were as follows:

 

(in thousands)   2016     2015     2014  
Cash Dividends Paid to Parent by Subsidiaries   $ 77,779     $ 46,188     $ 44,261  

 

See Otter Tail Corporation’s notes to consolidated financial statements in Part II, Item 8 for other disclosures.

 

Other schedules are omitted because of the absence of the conditions under which they are required, because the amounts are insignificant or because the information required is included in the financial statements or the notes thereto.
XML 54 R31.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2016
Accounting Policies [Abstract]  
Principles of Consolidation

Principles of Consolidation

The consolidated financial statements of Otter Tail Corporation and its wholly owned subsidiaries (the Company) include the accounts of the following segments: Electric, Manufacturing and Plastics. See note 2 to consolidated financial statements for further descriptions of the Company’s business segments. All intercompany balances and transactions have been eliminated in consolidation except profits on sales to the regulated electric utility company from nonregulated affiliates, which is in accordance with the requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, Regulated Operations (ASC 980).
Regulation and ASC 980

Regulation and ASC 980

The Company’s regulated electric utility company, Otter Tail Power Company (OTP), accounts for the financial effects of regulation in accordance with ASC 980. This standard allows for the recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. See note 4 to consolidated financial statements for further discussion.

 

OTP is subject to various state and federal agency regulations. The accounting policies followed by this business are subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company’s nonelectric businesses.
Plant, Retirements and Depreciation

Plant, Retirements and Depreciation

Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction. The amount of interest capitalized on electric utility plant was $495,000 in 2016, $723,000 in 2015 and $689,000 in 2014. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are charged against the accumulated reserve for estimated removal costs, a regulatory liability. Maintenance, repairs and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated remaining service lives of the properties (5 to 82 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.88% in 2016, 2.61% in 2015 and 2.89% in 2014. Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates.

 

Property and equipment of nonelectric operations are carried at historical cost or at the then-current replacement cost if acquired in a business combination, and are depreciated on a straight-line basis over the assets’ estimated useful lives (3 to 40 years). The cost of additions includes contracted work, direct labor and materials, allocable overheads and capitalized interest. No interest was capitalized on nonelectric plant in 2016, 2015 or 2014. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.
Recoverability of Long-Lived Assets

Recoverability of Long-Lived Assets

The Company reviews its long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. The Company determines potential impairment by comparing the carrying amount of the assets with net cash flows expected to be provided by operating activities of the business or related assets. If the sum of the expected future net cash flows is less than the carrying amount of the assets, the Company would recognize an impairment loss. Such an impairment loss would be measured as the amount by which the carrying amount exceeds the fair value of the asset, where fair value is based on the discounted cash flows expected to be generated by the asset.
Jointly Owned Facilities

Jointly Owned Facilities

OTP is a joint owner in two coal-fired steam-powered electric generation plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station near Beulah, North Dakota. OTP is also a joint owner, with other regional utilities, in three major in-service transmission lines and two additional major transmission lines under construction. The following table provides OTP’s ownership percentages and amounts included in the Company’s December 31, 2016 and 2015 consolidated balance sheets for OTP’s share of jointly owned assets in each of these jointly owned facilities:

 

Jointly Owned Facilities (dollars in thousands) OTP
Ownership
Percentage		  Electric Plant
in Service		  Construction
Work in
Progress		  Accumulated
Depreciation		  Net Plant 
December 31, 2016                    
Big Stone Plant  53.9% $328,809  $23  $(65,665) $263,167 
Coyote Station  35.0%  176,315   113   (101,499)  74,929 
Fargo-Monticello 345 kV line  14.2%  78,298   —   (3,511)  74,787 
Brookings-Southeast Twin Cities 345 kV line1  4.8%  26,406   —   (924)  25,482 
Bemidji-Grand Rapids 230 kV line  14.8%  16,331   —   (1,573)  14,758 
Big Stone South to Brookings 345 kV line1  50.0%  —   45,050   —   45,050 
Big Stone South to Ellendale 345 kV line1  50.0%  —   49,160   —   49,160 
December 31, 2015                    
Big Stone Plant  53.9% $327,474  $(305) $(57,641) $269,528 
Coyote Station  35.0%  165,497   7,405   (103,822)  69,080 
Fargo-Monticello 345 kV line  14.2%  78,272   —   (2,213)  76,059 
Brookings-Southeast Twin Cities 345 kV line1  4.8%  26,189   —   (486)  25,703 
Bemidji-Grand Rapids 230 kV line  14.8%  16,331   —   (1,233)  15,098 
Big Stone South to Brookings 345 kV line1  50.0%  —   14,210   —   14,210 
Big Stone South to Ellendale 345 kV line1  50.0%  —   8,335   —   8,335 
1Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).

 

The Company’s share of direct revenue and expenses of the jointly owned facilities is included in operating revenue and expenses in the consolidated statements of income.
Coyote Station Lignite Supply Agreement - Variable Interest Entity

Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.

 

If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. Coyote Station started taking delivery of coal and paying for coal and accumulated development fees and capital charges under the LSA in May 2016. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of December 31, 2016 could be as high as $60.6 million, OTP’s 35% share of unrecovered costs.
Income Taxes

Income Taxes

Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect in the periods when the temporary differences reverse. The Company amortizes investment tax credits over the estimated lives of related property. The Company records income taxes in accordance with ASC Topic 740, Income Taxes, and has recognized in its consolidated financial statements the tax effects of all tax positions that are “more-likely-than-not” to be sustained on audit based solely on the technical merits of those positions as of the balance sheet date. The term “more-likely-than-not” means a likelihood of more than 50%. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes. See note 14 to consolidated financial statements regarding the Company’s accounting for uncertain tax positions.

 

The Company also is required to assess the realizability of its deferred tax assets, taking into consideration the Company’s forecast of future taxable income, the reversal of other existing temporary differences, available net operating loss carryforwards and available tax planning strategies that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, valuation allowances against the Company’s deferred tax assets. To the extent facts and circumstances change in the future, adjustments to the valuation allowance may be required.
Revenue Recognition

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, the price is fixed or determinable and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as OTP’s 2015 forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with ASC Topic 815, Derivatives and Hedging (ASC 815). Gains and losses on forward energy contracts subject to regulatory treatment, if any, have been deferred and recognized on a net basis in revenue in the period realized.

 

For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

 

Customer electricity use is metered and bills are rendered monthly. Revenue is accrued for electricity consumed but not yet billed. Rate schedules applicable to substantially all customers include a fuel clause adjustment, under which the rates are adjusted to reflect changes in average cost of fuels and purchased power, and a surcharge for recovery of conservation-related expenses. Revenue is recognized for fuel and purchased power costs incurred in excess of amounts recovered in base rates but not yet billed through the fuel clause adjustment, for conservation program incentives and bonuses earned but not yet billed and for renewable resource, transmission-related and environmental incurred costs and investment returns approved for recovery through riders.

 

Revenues on wholesale electricity sales from Company-owned generating units are recognized when energy is delivered. For shared use of transmission facilities with certain regional transmission cooperatives, revenues are estimated. Bills are rendered based on anticipated usage and settlements are made later based on actual usage. Estimated revenues may be adjusted prior to settlement, or at the time of settlement, to reflect actual usage.

 

Under ASC 815, OTP accounts for forward energy contracts as derivatives subject to mark-to-market accounting unless those contracts meet the definition of a capacity contract or are not subject to unplanned netting, then OTP accounts for the contracts under the normal purchases and sales exception to mark-to-market accounting.

 

Manufacturing and Plastics operating revenues are recorded when products are shipped.
Warranty Reserves

Warranty Reserves

Certain products sold by the Company’s manufacturing and plastics companies carry product warranties for one year after the shipment date. These companies’ standard product warranty terms generally include post-sales support and repairs or replacement of a product at no additional charge for a specified period of time. While these companies engage in extensive product quality programs and processes, including actively monitoring and evaluating the quality of their component suppliers, they base their estimated warranty obligations on warranty terms, ongoing product failure rates, repair costs, product call rates, average cost per call, and current period product shipments. The Company’s manufacturing and plastics companies have not incurred any significant warranty costs over the last three fiscal years in continuing operations.
Shipping and Handling Costs

Shipping and Handling Costs

The Company includes revenues received for shipping and handling in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of goods sold.
Use of Estimates

Use of Estimates

The Company uses estimates based on the best information available in recording transactions and balances resulting from business operations. As better information becomes available (or actual amounts are known), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Cash Equivalents

Cash Equivalents

The Company considers all highly liquid debt instruments purchased with maturity of 90 days or less to be cash equivalents.
Investments

Investments

The following table provides a breakdown of the Company’s investments at December 31:

 

(in thousands) 2016  2015 
Cost Method:        
Economic Development Loan Pools $54  $81 
Other  115   2,088 
Equity Method Partnerships  23   22 
Marketable Securities Classified as Available-for-Sale  8,225   8,093 
Total Investments $8,417  $10,284 
Less: Aevenia, Inc. (AEV, Inc.) Escrow Funds Reported Under Other Current Assets  —   (1,500)
Foley Company (Foley) Escrow Funds Reported Under Other Current Assets  —   (500)
Investments $8,417  $8,284 

 

The Company’s marketable securities classified as available-for-sale are held for insurance purposes and are reflected at their fair values on December 31, 2016. See further discussion below.
Agreements Subject to Legally Enforceable Netting Arrangements

Agreements Subject to Legally Enforceable Netting Arrangements

The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.
Fair Value Measurements

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:

 

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).

 

Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

 

Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts. 

 

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2016 and December 31, 2015:

 

December 31, 2016 (in thousands) Level 1  Level 2  Level 3 
Assets:            
Investments:            
Corporate Debt Securities – Held by Captive Insurance Company     $5,280     
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company      2,945     
Other Assets:            
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $849         
Total Assets $849  $8,225     

 

December 31, 2015 (in thousands) Level 1  Level 2  Level 3 
Assets:            
Current Assets – Other:            
Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $2,000         
Investments:            
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company     $4,235     
Corporate Debt Securities – Held by Captive Insurance Company      3,858     
Other Assets:            
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan  196         
Total Assets $2,196  $8,093     
Liabilities:            
Other Accrued Liabilities:            
Derivative Liabilities – Forward Gasoline Purchase Contracts     $199     
Total Liabilities     $199     

 

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

 

Forward Gasoline Purchase Contracts –These contracts were priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods. As of December 31, 2016 OTP held, and currently holds, no RBOB contracts.

 

Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.
Inventories

Inventories

Electric segment inventories are reported at average cost. The Manufacturing and Plastics segments’ inventories are stated at the lower of average cost or market. Inventories consist of the following at December 31:

 

(in thousands) 2016  2015 
Finished Goods $27,755  $25,971 
Work in Process  11,754   12,821 
Raw Material, Fuel and Supplies  44,231   46,624 
Total Inventories $83,740  $85,416 
Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

The Company accounts for goodwill and other intangible assets in accordance with the requirements of ASC Topic 350, Intangibles—Goodwill and Other, measuring its goodwill for impairment annually in the fourth quarter, and more often when events indicate the assets may be impaired. The Company does qualitative assessments of its reporting units with recorded goodwill to determine if it is more likely than not that the fair value of the reporting unit exceeds its book value. The Company also does quantitative assessments of its reporting units with recorded goodwill to determine the fair value of the reporting unit.

 

In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued operations. See note 16 to consolidated financial statements.

 

On September 1, 2015 Miller Welding & Iron Works, Inc. (BTD-Illinois), a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing, Inc. (Impulse) of Dawsonville, Georgia. The acquired business operates under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference in the fair value of assets acquired and the price paid for Impulse resulted in an initial estimate of acquired goodwill of $8.2 million. A final determination of the purchase price was agreed to in June 2016 resulting in a $2.2 million reduction in acquired goodwill in June 2016. See note 2 to the Company’s consolidated financial statements for more information.

 

The following tables summarize changes to goodwill by business segment during 2016 and 2015:

 

(in thousands) Gross Balance
December 31, 2015		  Accumulated
Impairments		  Balance (net of
impairments)
December 31, 2015		  Adjustments to
Goodwill in
2016		  Balance (net of
impairments)
December 31, 2016		 
Manufacturing $20,430  $—  $20,430  $(2,160) $18,270 
Plastics  19,302   —   19,302   —   19,302 
Total $39,732  $—  $39,732  $(2,160) $37,572 
                     
(in thousands) Gross Balance
December 31, 2014		  Accumulated
Impairments		  Balance
(net of impairments)
December 31, 2014		  Adjustments
and Additions
to Goodwill
in 2015		  Balance
(net of impairments)
December 31, 2015		 
Manufacturing $12,186  $—  $12,186  $8,244  $20,430 
Plastics  19,302   —   19,302   —   19,302 
Total $31,488  $—  $31,488  $8,244  $39,732 

 

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. With the purchase of BTD-Georgia on September 1, 2015, the Company acquired customer relationships valued at $4,870,000 to be amortized over 20 years and the seller entered into a covenant not to compete valued at $620,000 to be amortized over three years. The final purchase price adjustment agreed to in June 2016 resulted in an $810,000 increase in the fair value of acquired customer relationships and a $30,000 reduction in the fair value of the covenant not to compete. The changes in the value of these intangibles had an insignificant impact on the Company’s consolidated net income in 2016 related to a change in amortization expense that would have been recorded in 2015 had the adjusted asset values been established on acquisition in 2015. See note 2 to the Company’s consolidated financial statements for more information. 

 

The following table summarizes the components of the Company’s intangible assets at December 31, 2016 and December 31, 2015:

 

December 31, 2016 (in thousands) Gross Carrying
Amount		  Accumulated
Amortization		  Net Carrying
Amount		  Remaining
Amortization
Periods
Amortizable Intangible Assets:              
Customer Relationships $22,491  $7,861  $14,630  36-224 months
Covenant not to Compete  590   262   328  20 months
Total $23,081  $8,123  $14,958   
               
December 31, 2015 (in thousands)              
Amortizable Intangible Assets:              
Customer Relationships $21,681  $6,714  $14,967  48-236 months
Covenant not to Compete  620   69   551  32 months
Other Intangible Assets  639   543   96  9 months
Emission Allowances  59   NA   59  Expensed as used
Total $22,999  $7,326  $15,673   

 

The amortization expense for these intangible assets was:

 

(in thousands) 2016  2015  2014 
Amortization Expense – Intangible Assets $1,436  $1,127  $977 

 

The estimated annual amortization expense for these intangible assets for the next five years is:

 

(in thousands) 2017  2018  2019  2020  2021 
Estimated Amortization Expense – Intangible Assets $1,330  $1,264  $1,133  $1,099  $1,099 
Supplemental Disclosures of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

 

  As of December 31, 
(in thousands) 2016  2015 
Noncash Investing Activities:        
Transactions Related to Capital Additions not Settled in Cash $13,533  $20,371 

 

(in thousands) 2016  2015  2014 
Cash Paid (Received) During the Year for:            
Interest (net of amount capitalized) $31,269  $30,512  $26,364 
Income Taxes $(1,291) $7,322  $145 
New Accounting Standards

New Accounting Standards

 

Accounting Standards Update (ASU) 2014-09—In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

 

Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. As of December 31, 2016 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is evaluating transition options. Based on review of the Company’s revenue streams, the Company does not anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU 2014-09, with the exception of the treatment of contributions in aid of construction in the Electric segment on which consensus treatment has not been determined and guidance has not been provided. Currently, the Company reduces its investment in fixed assets for the amount of these contributions. Should the Company be required to recognize these contributions as revenue under ASU 2014-09, it could result in a significant increase in reported revenues and expenses. Adoption of ASU 2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard. The Company does not plan to adopt the updated guidance prior to January 1, 2018.

 

ASU 2015-03—In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03), which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015 and must be applied retrospectively to balance sheets presented for periods prior to adoption. The Company adopted the updated standards in ASU 2015-03 in the first quarter of 2016. In conjunction with implementing this update, the Company is reclassifying the remaining balance of unamortized line of credit issuance costs from the deferred debit section of its consolidated balance sheet to other assets, eliminating the deferred debits section of its consolidated balance sheet and displaying long-term regulatory assets as a separate line item on its consolidated balance sheet. The effects of applying the guidance in ASU 2015-03 retrospectively to the Company’s December 31, 2015 consolidated balance sheet and statement of capitalization and of the associated reclassification of unamortized line of credit issuance costs are shown in the following table:

 

(in thousands) December 31, 2015
Previously Stated		  Adjustments  December 31, 2015
Adjusted		 
Other Assets $31,108  $1,676  $32,784 
Unamortized Debt Expense  3,897   (3,897)  — 
Total Assets  1,820,904   (2,221)  1,818,683 
             
Current Liabilities            
Current Maturities of Long-Term Debt  52,544   (122)  52,422 
Total Current Liabilities  271,238   (122)  271,116 
Capitalization            
Long-Term Debt—Net  445,945   (2,099)  443,846 
Total Capitalization  1,050,968   (2,099)  1,048,869 
Total Liabilities and Equity  1,820,904   (2,221)  1,818,683 

 

ASU 2015-11—In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires that inventories be measured at the lower of cost or net realizable value instead of the lower of cost or market value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The standards update is effective prospectively for fiscal years and interim periods beginning after December 15, 2016, with early adoption permitted. The Company does not expect the adoption of the updated standard to have a material impact on its consolidated financial statements.

 

ASU 2015-16—In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16), which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in ASU 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in ASU 2015-16 are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date, with earlier application permitted for financial statements that have not been issued. The Company elected to adopt the updated standard in the fourth quarter of 2015 in order to apply the updates to its recent acquisition of BTD-Georgia. Adoption of the updated standard did not have a material impact on the Company’s consolidated financial statements. The early adoption of the standard alleviated the need for prior period adjustments of income related to the BTD-Georgia acquisition purchase price adjustment recorded in June 2016. See note 2 to the Company’s consolidated financial statements for more information.

 

ASU 2016-02—In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 is a comprehensive amendment of the ASC, creating Topic 842, which will supersede the current requirements under ASC Topic 840 on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic 842 affects any entity that enters into a lease, with some specified scope exemptions. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. The Company is currently reviewing ASU 2016-02, identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and evaluating transition options. The Company does not currently plan to apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019.

 

ASU 2016-09— In March 2016, the FASB issued ASU No. 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which is intended to improve and simplify accounting and reporting requirements related to stock-based compensation programs. The amendments in ASU 2016-09 change how companies account for certain aspects of share-based payments to employees, including: (1) changing award classifications from liability to equity as a result of an increase in the permitted level of share withholding to cover income taxes to satisfy statutory income tax withholding requirements on the awards, (2) recognizing excess tax benefits as an adjustment to income tax expense when the awards vest rather than directly adjusting stockholders' equity, and (3) introducing an accounting policy election that permits reporting entities to elect to account for forfeitures as they occur. The amendments in ASU 2016-09 are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted.

 

In the fourth quarter of 2016, the Company elected to early adopt the updates in ASU 2016-09. The withholding provisions in the award agreements applicable to the Company’s outstanding performance awards granted to executive officers in 2014, 2015 and 2016 allow for withholding up to the maximum statutory tax rates in the applicable jurisdictions. The updates in ASU 2016-09 result in these awards being classified as equity awards rather than liability awards, requiring the amount of expense recognized for these awards to be based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards. The reporting-date fair values of the 2014 and 2015 awards outstanding on December 31, 2015 were less than the grant-date fair values of the awards. On adoption of the updates in ASU 2016-09 in the fourth quarter of 2016, the difference in expense that would have been recognized related to the outstanding 2014 and 2015 awards in 2014 and 2015 had the awards been classified as equity awards instead of liability awards results in a cumulative-effect net-of-tax adjustment to retained earnings of $623,000, with related adjustments to unvested restricted stock liability, deferred tax and miscellaneous paid-in capital accounts, effective as of January 1, 2016, as illustrated below:

 

Balance Sheet Account Affected, Effective January 1, 2016 Debit  Credit 
Adjustment to Retained Earnings $623,000     
Long-Term Incentive Payable $1,453,000     
Deferred Taxes $416,000     
Miscellaneous Paid-In Capital     $2,492,000 

 

The impact of adopting the updates in ASU 2016-09 effective January 1, 2016 on 2016 interim reporting periods was not material.
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Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2016
Accounting Policies [Abstract]  
Schedule for ownership share of jointly owned facilities
Jointly Owned Facilities (dollars in thousands) OTP
Ownership
Percentage		  Electric Plant
in Service		  Construction
Work in
Progress		  Accumulated
Depreciation		  Net Plant 
December 31, 2016                    
Big Stone Plant  53.9% $328,809  $23  $(65,665) $263,167 
Coyote Station  35.0%  176,315   113   (101,499)  74,929 
Fargo-Monticello 345 kV line  14.2%  78,298   —   (3,511)  74,787 
Brookings-Southeast Twin Cities 345 kV line1  4.8%  26,406   —   (924)  25,482 
Bemidji-Grand Rapids 230 kV line  14.8%  16,331   —   (1,573)  14,758 
Big Stone South to Brookings 345 kV line1  50.0%  —   45,050   —   45,050 
Big Stone South to Ellendale 345 kV line1  50.0%  —   49,160   —   49,160 
December 31, 2015                    
Big Stone Plant  53.9% $327,474  $(305) $(57,641) $269,528 
Coyote Station  35.0%  165,497   7,405   (103,822)  69,080 
Fargo-Monticello 345 kV line  14.2%  78,272   —   (2,213)  76,059 
Brookings-Southeast Twin Cities 345 kV line1  4.8%  26,189   —   (486)  25,703 
Bemidji-Grand Rapids 230 kV line  14.8%  16,331   —   (1,233)  15,098 
Big Stone South to Brookings 345 kV line1  50.0%  —   14,210   —   14,210 
Big Stone South to Ellendale 345 kV line1  50.0%  —   8,335   —   8,335 
1Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).
Schedule of breakdown of Investments
(in thousands) 2016  2015 
Cost Method:        
Economic Development Loan Pools $54  $81 
Other  115   2,088 
Equity Method Partnerships  23   22 
Marketable Securities Classified as Available-for-Sale  8,225   8,093 
Total Investments $8,417  $10,284 
Less: Aevenia, Inc. (AEV, Inc.) Escrow Funds Reported Under Other Current Assets  —   (1,500)
Foley Company (Foley) Escrow Funds Reported Under Other Current Assets  —   (500)
Investments $8,417  $8,284 
Schedule of assets and liabilities that are measured at fair value on a recurring basis
December 31, 2016 (in thousands) Level 1  Level 2  Level 3 
Assets:            
Investments:            
Corporate Debt Securities – Held by Captive Insurance Company     $5,280     
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company      2,945     
Other Assets:            
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $849         
Total Assets $849  $8,225     

 

December 31, 2015 (in thousands) Level 1  Level 2  Level 3 
Assets:            
Current Assets – Other:            
Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $2,000         
Investments:            
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company     $4,235     
Corporate Debt Securities – Held by Captive Insurance Company      3,858     
Other Assets:            
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan  196         
Total Assets $2,196  $8,093     
Liabilities:            
Other Accrued Liabilities:            
Derivative Liabilities – Forward Gasoline Purchase Contracts     $199     
Total Liabilities     $199     
Schedule of inventories
(in thousands) 2016  2015 
Finished Goods $27,755  $25,971 
Work in Process  11,754   12,821 
Raw Material, Fuel and Supplies  44,231   46,624 
Total Inventories $83,740  $85,416 
Schedule of changes to goodwill by business segment
(in thousands) Gross Balance
December 31, 2015		  Accumulated
Impairments		  Balance (net of
impairments)
December 31, 2015		  Adjustments to
Goodwill in
2016		  Balance (net of
impairments)
December 31, 2016		 
Manufacturing $20,430  $—  $20,430  $(2,160) $18,270 
Plastics  19,302   —   19,302   —   19,302 
Total $39,732  $—  $39,732  $(2,160) $37,572 
                     
(in thousands) Gross Balance
December 31, 2014		  Accumulated
Impairments		  Balance
(net of impairments)
December 31, 2014		  Adjustments
and Additions
to Goodwill
in 2015		  Balance
(net of impairments)
December 31, 2015		 
Manufacturing $12,186  $—  $12,186  $8,244  $20,430 
Plastics  19,302   —   19,302   —   19,302 
Total $31,488  $—  $31,488  $8,244  $39,732 
Schedule of components of intangible assets
December 31, 2016 (in thousands) Gross Carrying
Amount		  Accumulated
Amortization		  Net Carrying
Amount		  Remaining
Amortization
Periods
Amortizable Intangible Assets:              
Customer Relationships $22,491  $7,861  $14,630  36-224 months
Covenant not to Compete  590   262   328  20 months
Total $23,081  $8,123  $14,958   
               
December 31, 2015 (in thousands)              
Amortizable Intangible Assets:              
Customer Relationships $21,681  $6,714  $14,967  48-236 months
Covenant not to Compete  620   69   551  32 months
Other Intangible Assets  639   543   96  9 months
Emission Allowances  59   NA   59  Expensed as used
Total $22,999  $7,326  $15,673   
Schedule of amortization expense for intangible assets
(in thousands) 2016  2015  2014 
Amortization Expense – Intangible Assets $1,436  $1,127  $977 
Schedule of estimated annual amortization expense for intangible assets
(in thousands) 2017  2018  2019  2020  2021 
Estimated Amortization Expense – Intangible Assets $1,330  $1,264  $1,133  $1,099  $1,099 
Schedule of supplemental disclosure of cash flow information
  As of December 31, 
(in thousands) 2016  2015 
Noncash Investing Activities:        
Transactions Related to Capital Additions not Settled in Cash $13,533  $20,371 

 

(in thousands) 2016  2015  2014 
Cash Paid (Received) During the Year for:            
Interest (net of amount capitalized) $31,269  $30,512  $26,364 
Income Taxes $(1,291) $7,322  $145 
Schedule of effects of applying the guidance and reclassification of unamortized line of credit issuance costs
(in thousands) December 31, 2015
Previously Stated		  Adjustments  December 31, 2015
Adjusted		 
Other Assets $31,108  $1,676  $32,784 
Unamortized Debt Expense  3,897   (3,897)  — 
Total Assets  1,820,904   (2,221)  1,818,683 
             
Current Liabilities            
Current Maturities of Long-Term Debt  52,544   (122)  52,422 
Total Current Liabilities  271,238   (122)  271,116 
Capitalization            
Long-Term Debt—Net  445,945   (2,099)  443,846 
Total Capitalization  1,050,968   (2,099)  1,048,869 
Total Liabilities and Equity  1,820,904   (2,221)  1,818,683 
Schedule of related adjustments to unvested restricted stock liability, deferred tax and miscellaneous paid-in capital accounts
Balance Sheet Account Affected, Effective January 1, 2016 Debit  Credit 
Adjustment to Retained Earnings $623,000     
Long-Term Incentive Payable $1,453,000     
Deferred Taxes $416,000     
Miscellaneous Paid-In Capital     $2,492,000 
XML 56 R33.htm IDEA: XBRL DOCUMENT v3.6.0.2
Business Combinations, Dispositions and Segment Information (Tables)
 12 Months Ended
Dec. 31, 2016
Business Combinations, Dispositions and Segment Information [Abstract]  
Schedule of business combination disclosing the preliminary allocation of purchase price to each major asset and liability
(in thousands)   
Assets:    
Current Assets $4,906 
Goodwill  6,083 
Other Intangible Assets  6,270 
Other Amortizable Assets  1,380 
Fixed Assets  13,649 
Total Assets $32,288 
Liabilities:    
Current Liabilities $2,971 
Lease Obligation  11 
Total Liabilities $2,982 
Cash Paid $29,306 
Schedule of information by business segments
(in thousands) 2016  2015  2014 
Operating Revenue            
Electric $427,383  $407,131  $407,743 
Manufacturing  221,289   215,011   219,583 
Plastics  154,901   157,758   172,050 
Intersegment Eliminations  (34)  (96)  (114)
Total $803,539  $779,804  $799,262 
Cost of Products Sold            
Manufacturing $171,732  $171,956  $169,033 
Plastics  123,496   123,085   139,081 
Intersegment Eliminations  (6)  (9)  (45)
Total $295,222  $295,032  $308,069 
Other Nonelectric Expenses            
Manufacturing $21,994  $21,115  $23,340 
Plastics  9,402   9,850   9,292 
Corporate  8,896   9,143   13,418 
Intersegment Eliminations  (28)  (87)  (69)
Total $40,264  $40,021  $45,981 
Depreciation and Amortization            
Electric $53,743  $44,786  $44,076 
Manufacturing  15,794   11,853   10,518 
Plastics  3,861   3,552   3,364 
Corporate  47   172   116 
Total $73,445  $60,363  $58,074 
Operating Income (Loss)            
Electric $90,131  $87,171  $76,060 
Manufacturing  11,769   10,086   16,692 
Plastics  18,142   21,272   20,313 
Corporate  (8,943)  (9,315)  (13,534)
Total $111,099  $109,214  $99,531 
 
(in thousands) 2016  2015  2014 
Interest Charges            
Electric $25,069  $24,371  $23,322 
Manufacturing  3,859   3,560   3,243 
Plastics  1,034   1,026   1,043 
Corporate and Intersegment Eliminations  1,924   2,203   2,040 
Total $31,886  $31,160  $29,648 
Income Tax Expense (Benefit) – Continuing Operations            
Electric $16,366  $16,067  $11,029 
Manufacturing  2,276   2,299   4,117 
Plastics  6,538   8,187   7,301 
Corporate  (5,099)  (4,911)  (5,890)
Total $20,081  $21,642  $16,557 
Net Income (Loss)            
Electric $49,829  $48,370  $43,684 
Manufacturing  5,694   4,247   9,361 
Plastics  10,628   12,108   12,085 
Corporate  (4,114)  (6,136)  (8,247)
Discontinued Operations  284   756   840 
Total $62,321  $59,345  $57,723 
Capital Expenditures            
Electric $149,648  $135,572  $148,719 
Manufacturing  8,429   20,295   11,252 
Plastics  3,085   4,206   3,567 
Corporate  97   11   44 
Total $161,259  $160,084  $163,582 
Identifiable Assets            
Electric $1,622,231  $1,520,887  $1,438,791 
Manufacturing  166,525   173,860   128,608 
Plastics  84,592   81,624   86,650 
Corporate  39,037   42,312   36,508 
Assets of Discontinued Operations  —   —   47,559 
Total $1,912,385  $1,818,683  $1,738,116 
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Rate and Regulatory Matters (Tables)
 12 Months Ended
Dec. 31, 2016
Rate And Regulatory Matters [Abstract]  
Schedule of request and interim rate information

The request and interim rate information is detailed in the table below:

 

($ in thousands) Annualized or
Test Year		  Actual Through
December 31, 2016		 
Revenue Increase Requested $19,296     
Increase Percentage Requested  9.80%    
Jurisdictional Rate Base $483,000     
Interim Revenue Increase (subject to refund) $16,816  $10,976 

 

The major components of the requested rate increase are summarized below:

 

Revenue Requirement Deficiency Cost Factors (in thousands) 2016 Test Year
Allocation		 
Increased Rate Base $10,000 
Increased Expenses  7,700 
Other  1,596 
Total Requested Revenue Increase $19,296 
Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset  (2,480)
Approved Interim Revenue Increase (subject to refund) $16,816 
Schedule of revenues recorded under rate riders
Rate Rider (in thousands)   2016     2015     2014  
Minnesota                        
Conservation Improvement Program Costs and Incentives1   $ 12,920     $ 10,724     $ 7,757  
Environmental Cost Recovery     12,443       10,238       6,891  
Transmission Cost Recovery     5,795       5,202       6,275  
North Dakota                        
Environmental Cost Recovery     11,089       9,502       5,872  
Renewable Resource Adjustment     7,800       8,409       7,484  
Transmission Cost Recovery     7,694       6,609       5,794  
South Dakota                        
Environmental Cost Recovery     2,538       1,967       234  
Transmission Cost Recovery     1,820       1,290       1,207  
Conservation Improvement Program Costs and Incentives     468       583       435  

1Includes MNCIP costs recovered in base rates.
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Regulatory Assets and Liabilities (Tables)
 12 Months Ended
Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]  
Schedule of amount of regulatory assets and liabilities
  December 31, 2016  Remaining
Recovery/
(in thousands) Current  Long-Term  Total  Refund Period
Regulatory Assets:              
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 $6,443  $108,267  $114,710  see below
Deferred Marked-to-Market Losses1  4,063   6,467   10,530  48 months
Conservation Improvement Program Costs and Incentives2  4,836   5,158   9,994  21 months
Accumulated ARO Accretion/Depreciation Adjustment1  —   6,153   6,153  asset lives
Big Stone II Unrecovered Project Costs – Minnesota1  778   2,087   2,865  52 months
North Dakota Renewable Resource Rider Accrued Revenues2  1,319   482   1,801  15 months
Recoverable Fuel and Purchased Power Costs1  1,798   —   1,798  12 months
Debt Reacquisition Premiums1  325   1,214   1,539  189 months
Minnesota Deferred Rate Case Expenses Subject to Recovery1  1,082   —   1,082  12 months
Deferred Income Taxes1  —   1,014   1,014  asset lives
Big Stone II Unrecovered Project Costs – South Dakota2  100   543   643  77 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2  —   568   568  24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2  333   —   333  12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2  73   141   214  14 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2  113   —   113  12 months
Minnesota Renewable Resource Rider Accrued Revenues2  34   —   34  9 months
Total Regulatory Assets $21,297  $132,094  $153,391   
Regulatory Liabilities:              
Accumulated Reserve for Estimated Removal Costs – Net of Salvage $—  $80,404  $80,404  asset lives
North Dakota Transmission Cost Recovery Rider Accrued Refund  1,381   782   2,163  24 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota  711   208   919  16 months
Deferred Income Taxes  —   818   818  asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund  757   —   757  12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund  285   —   285  12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund  139   —   139  12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up  —   132   132  24 months
Other  21   89   110  204 months
Total Regulatory Liabilities $3,294  $82,433  $85,727   
Net Regulatory Asset Position $18,003   49,661  $67,664   

1Costs subject to recovery without a rate of return.

2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. 

 

  December 31, 2015  Remaining
Recovery/
(in thousands) Current  Long-Term  Total  Refund Period
Regulatory Assets:              
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 $7,439  $99,293  $106,732  see below
Deferred Marked-to-Market Losses1  4,063   10,530   14,593  60 months
Conservation Improvement Program Costs and Incentives2  4,411   4,266   8,677  18 months
Accumulated ARO Accretion/Depreciation Adjustment1  —   5,672   5,672  asset lives
Big Stone II Unrecovered Project Costs – Minnesota1  942   2,620   3,562  84 months
North Dakota Renewable Resource Rider Accrued Revenues2  —   1,266   1,266  15 months
Debt Reacquisition Premiums1  351   1,539   1,890  201 months
Minnesota Deferred Rate Case Expenses Subject to Recovery1  291   —   291  12 months
Deferred Income Taxes1  —   1,455   1,455  asset lives
Big Stone II Unrecovered Project Costs – South Dakota2  100   643   743  89 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2  698   355   1,053  24 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues2  576   —   576  12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2  33   —   33  12 months
Minnesota Renewable Resource Rider Accrued Revenues2  —   68   68  see below
Total Regulatory Assets $18,904  $127,707  $146,611   
Regulatory Liabilities:              
Accumulated Reserve for Estimated Removal Costs – Net of Salvage $—  $74,948  $74,948  asset lives
Refundable Fuel Clause Adjustment Revenues  1,834   —   1,834  12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund  132   —   132  12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota  —   1,279   1,279  see below
Deferred Income Taxes  —   1,110   1,110  asset lives
South Dakota Environmental Cost Recovery Rider Accrued Refund  185   —   185  12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund  777   —   777  12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion  5   95   100  216 months
North Dakota Environmental Cost Recovery Rider Accrued Refund  321   —   321  12 months
North Dakota Renewable Resource Rider Accrued Refund  68   —   68  12 months
Total Regulatory Liabilities $3,322  $77,432  $80,754   
Net Regulatory Asset Position $15,582  $50,275  $65,857   

1Costs subject to recovery without a rate of return.

2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
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Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Tables)
 12 Months Ended
Dec. 31, 2016
Open Contract Positions Subject To Legally Enforceable Netting Arrangements [Abstract]  
Schedule of current fair value of these forward contract positions subject to legally enforceable netting arrangements
(in thousands) 2016  2015 
Derivatives in Gain Positions Subject to Legally Enforceable Netting Arrangements $—  $— 
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements  (17,382)  (16,070)
 Net Balance Subject to Legally Enforceable Netting Arrangements $(17,382) $(16,070)
Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions
(in thousands) 2016  2015 
Loss Contracts Covered by Deposited Funds or Letters of Credit $—  $199 
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1  17,382   15,871 
Total Loss Contracts based on Current Market Values $17,382  $16,070 
1Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.        
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $17,382  $15,871 
Offsetting Gains with Counterparties under Master Netting Agreements  —   — 
Reporting Date Deposit Requirement if Credit Risk Feature Triggered $17,382  $15,871 
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Common Shares and Earnings Per Share (Tables)
 12 Months Ended
Dec. 31, 2016
Stockholders Equity and Earnings Per Share [Abstract]  
Schedule of reconciliation of Company's common shares outstanding
Common Shares Outstanding, December 31, 2015  37,857,186 
Issuances:    
At-the-Market Offering  1,014,115 
Automatic Dividend Reinvestment and Share Purchase Plan:    
Dividends Reinvested  163,010 
Cash Invested  115,801 
Vesting of Executive Stock Performance Awards  54,700 
Employee Stock Purchase Plan:    
Cash Invested  53,875 
Dividends Reinvested  23,713 
Employee Stock Ownership Plan  23,837 
Restricted Stock Issued to Directors  23,200 
Vesting of Restricted Stock Units  21,825 
Directors Deferred Compensation  542 
Retirements:    
Shares Withheld for Individual Income Tax Requirements  (3,668)
Common Shares Outstanding, December 31, 2016  39,348,136 
Schedule of outstanding stock options excluded from the calculation of diluted earnings per share
  2016  2015  2014 
Weighted Average Common Shares Outstanding – Basic  38,546,459   37,494,986   36,514,397 
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:            
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance  118,644   100,194   135,480 
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees  45,712   36,180   27,540 
Nonvested Restricted Shares  16,778   22,848   49,998 
Shares Expected to be Issued Under the Deferred Compensation Program for Directors  3,417   13,488   24,048 
Potentially Dilutive Stock Options  —   330   1,096 
Total Dilutive Shares  184,551   173,040   238,162 
Weighted Average Common Shares Outstanding – Diluted  38,731,010   37,668,026   36,752,559 
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Share-Based Payments (Tables)
 12 Months Ended
Dec. 31, 2016
Schedule of stock options activity
Stock Option Activity 2016  2015  2014 
  Options  Average
Exercise
Price		  Options  Average
Exercise
Price		  Options  Average
Exercise
Price		 
Outstanding, Beginning of Year  —       12,750  $24.93   34,700  $25.69 
Exercised  —       10,250   24.93   20,800   26.11 
Forfeited or Expired  —       2,500   24.93   1,150   26.495 
Outstanding, End of Year  —       —       12,750   24.93 
Exercisable, End of Year  —       —       12,750   24.93 
Cash Received for Options Exercised             $256,000      $543,000 
Intrinsic Value of Options Exercised             $75,000      $89,000 
Schedule of the status of directors' restricted stock awards
Directors’ Restricted Stock Awards 2016  2015  2014 
  Shares  Weighted
Average
Grant-Date
Fair Value		  Shares  Weighted
Average
Grant-Date
Fair Value		  Shares  Weighted
Average
Grant-Date
Fair Value		 
Nonvested, Beginning of Year  38,217  $29.78   38,050  $27.47   42,483  $25.03 
Granted  23,200   28.66   15,200   31.775   16,800   29.41 
Vested  15,083   28.28   15,033   25.96   21,233   24.11 
Forfeited  —       —       —     
Nonvested, End of Year  46,334   29.71   38,217   29.78   38,050   27.47 
Compensation Expense Recognized     $491,000      $417,000      $416,000 
Fair Value of Shares Vested in Year     $427,000      $390,000      $512,000 
Schedule of status of employees' restricted stock awards
Employees’ Restricted Stock Awards   2016     2015     2014  
    Shares     Weighted 
Average 
Grant-Date
Fair Value		     Shares     Weighted
Average
Grant-Date
Fair Value		     Shares     Weighted
Average
Grant-Date
Fair Value		  
Nonvested, Beginning of Year     13,581     $ 28.56       45,280     $ 27.46       48,315     $ 25.04  
Granted     —               —               26,700       29.41  
Vested     6,401       27.25       31,699       27.09       25,360       24.80  
Forfeited     —               —               4,375       28.03  
Nonvested, End of Year     7,180       29.72       13,581       28.56       45,280       27.46  
Compensation Expense Recognized           $ 96,000             $ 359,000             $ 998,000  
Fair Value of Awards Vested           $ 174,000             $ 859,000             $ 629,000  
Schedule of status of employees' restricted stock unit awards
Employees’ Restricted Stock Unit Awards 2016  2015  2014 
  Restricted
Stock
Units		  Weighted
Average
Grant-Date
Fair Value		  Restricted
Stock
Units		  Weighted
Average
Grant-Date
Fair Value		  Restricted
Stock
Units		  Weighted
Average
Grant-Date
Fair Value		 
Nonvested, Beginning of Year  46,600  $23.75   45,900  $21.82   56,180  $19.79 
Granted  17,220   24.54   15,650   25.89   11,800   24.95 
Reinstated  —       —       75   30.81 
Vested  12,250   19.03   12,250   19.46   14,305   18.05 
Forfeited  4,200   24.51   2,700   22.84   7,850   18.90 
Nonvested, End of Year  47,370   25.19   46,600   23.75   45,900   21.82 
Compensation Expense Recognized     $307,000      $304,000      $194,000 
Fair Value of Awards Vested     $233,000      $238,000      $258,000 
Schedule of stock performance awards granted and amounts expensed related to the stock performance awards
Performance
Period		 Maximum
Shares Subject
 To Award		  Target
Shares		  Expense Recognized
in the Year Ended December 31,1		  Earned
Shares		 
        2016  2015  2014    
2016-2018  122,250   81,500  $798,000             
2015-2017  126,450   84,300   535,000  $943,000         
2014-2016  159,450   106,300   332,000   (64,000) $1,422,000   121,491 
2013-2015  90,600   45,300   —   (445,000)  458,000   22,500 
2012-2014  148,400   74,200   —   —   142,000   89,991 
Total         $1,665,000  $434,000  $2,022,000   233,982 

1Expenses prior to 2016 are not restated to reflect what would have been expensed had the performance-to-date value of the outstanding awards been based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards.
Executive Officers  
Schedule of status of employees' restricted stock awards
Executives’ Restricted Stock Unit Awards   2016     2015  
    Restricted
Stock
Units		     Weighted
Average
Grant-Date
Fair Value		     Restricted
Stock
Units		     Weighted
Average
Grant-Date
Fair Value		  
Nonvested, Beginning of Year     24,300     $ 31.682       —          
Granted     22,000       28.915       29,100     $ 31.681  
Vested     4,475       31.69       4,800       31.675  
Forfeited     —               —        
Nonvested, End of Year     41,825       30.23       24,300       31.682  
Compensation Expense Recognized           $ 446,000             $ 452,000  
Fair Value of Awards Vested           $ 142,000             $ 152,000  
Key Employees  
Schedule of status of employees' restricted stock unit awards
  Grant Date Units
Granted		  Grant-Date
Fair Value
per Award		 
Restricted Stock Units Vesting 100% on April 8, 2020 April 11, 2016  15,800  $24.00 
Restricted Stock Units Vesting 100% on April 8, 2020 September 21, 2016  1,420  $30.59 
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Commitments and Contingencies of Continuing Operations (Tables)
 12 Months Ended
Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]  
Schedule of amounts of commitments under construction programs, capacity and energy agreements, coal and coal delivery contracts and operating leases
  Construction
Program and Other		  Capacity and
Energy		  Coal
Purchase		  Operating Leases 
(in thousands) Commitments  Requirements  Commitments  OTP  Nonelectric  Total 
2017 $74,328  $23,711  $30,699  $2,374  $4,760  $7,134 
2018  7,139   24,356   21,563   1,513   4,129   5,642 
2019  3,331   24,925   22,102   1,237   2,598   3,835 
2020  —   24,844   22,331   1,251   2,259   3,510 
2021  —   12,988   22,840   1,103   1,996   3,099 
Beyond 2021  —   166,137   550,719   9,396   7,320   16,716 
Total $84,798  $276,961  $670,254  $16,874  $23,062  $39,936 
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Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Tables)
 12 Months Ended
Dec. 31, 2016
Debt Disclosure [Abstract]  
Schedule of lines of credit
(in thousands) Line Limit  In Use on
December 31,
2016		  Restricted due to
Outstanding
Letters of Credit		  Available on
December 31,
2016		  Available on
December 31,
2015		 
Otter Tail Corporation Credit Agreement $130,000  $—  $—  $130,000  $90,334 
OTP Credit Agreement  170,000   42,883   50   127,067   148,694 
Total $300,000  $42,883  $50  $257,067  $239,028 
Schedule of short-term and long-term debt outstanding
December 31, 2016 (in thousands) OTP  Otter Tail 
Corporation		  Otter Tail 
Corporation 
Consolidated		 
Short-Term Debt $42,883  $—  $42,883 
Long-Term Debt:            
Term Loan, LIBOR plus 0.90%, due February 5, 2018     $15,000  $15,000 
3.55% Guaranteed Senior Notes, due December 15, 2026      80,000   80,000 
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 $33,000       33,000 
Senior Unsecured Notes 4.63%, due December 1, 2021  140,000       140,000 
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022  30,000       30,000 
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027  42,000       42,000 
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029  60,000       60,000 
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037  50,000       50,000 
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044  90,000       90,000 
North Dakota Development Note, 3.95%, due April 1, 2018      106   106 
PACE Note, 2.54%, due March 18, 2021      836   836 
Total $445,000  $95,942  $540,942 
Less:   Current Maturities net of Unamortized Debt Issuance Costs  32,970   231   33,201 
Unamortized Long-Term Debt Issuance Costs  1,861   539   2,400 
Total Long-Term Debt net of Unamortized Debt Issuance Costs $410,169  $95,172  $505,341 
Total Short-Term and Long-Term Debt (with current maturities) $486,022  $95,403  $581,425 

 

December 31, 2015 (in thousands) OTP Otter Tail 
Corporation		 Otter Tail 
Corporation 
Consolidated
Short-Term Debt $21,006  $59,666  $80,672 
Long-Term Debt:            
9.000% Notes, due December 15, 2016     $52,330  $52,330 
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 $33,000       33,000 
Senior Unsecured Notes 4.63%, due December 1, 2021  140,000       140,000 
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022  30,000       30,000 
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027  42,000       42,000 
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029  60,000       60,000 
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037  50,000       50,000 
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044  90,000       90,000 
North Dakota Development Note, 3.95%, due April 1, 2018      182   182 
PACE Note, 2.54%, due March 18, 2021      977   977 
Total $445,000  $53,489  $498,489 
Less:   Current Maturities net of Unamortized Debt Issuance Costs      52,422   52,422 
 Unamortized Long-Term Debt Issuance Costs  2,099   122   2,221 
Total Long-Term Debt net of Unamortized Debt Issuance Costs $442,901  $945  $443,846 
Total Short-Term and Long-Term Debt (with current maturities) $463,907  $113,033  $576,940 
Schedule of aggregate amounts of maturities on bonds outstanding and other long-term obligations
(in thousands) 2017  2018  2019  2020  2021 
Aggregate Amounts of Debt Maturities $33,231  $15,187  $172  $185  $140,171 
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Pension Plan and Other Postretirement Benefits (Tables)
 12 Months Ended
Dec. 31, 2016
Pension Plan  
Schedule of components of net periodic benefit cost
(in thousands) 2016  2015  2014 
Service Cost–Benefit Earned During the Period $5,518  $6,059  $4,666 
Interest Cost on Projected Benefit Obligation  14,195   13,344   13,111 
Expected Return on Assets  (19,454)  (18,383)  (16,743)
Amortization of Prior Service Cost:            
From Regulatory Asset  189   188   257 
From Other Comprehensive Income1  5   5   7 
Amortization of Net Actuarial Loss:            
From Regulatory Asset  5,153   6,676   3,400 
From Other Comprehensive Income1  127   171   83 
Net Periodic Pension Cost $5,733  $8,060  $4,781 
1Corporate cost included in Other Nonelectric Expenses.
Schedule of weighted-average assumptions used to determine net periodic benefit cost
  2016  2015  2014 
Discount Rate  4.76%  4.35%  5.30%
Long-Term Rate of Return on Plan Assets  7.75%  7.75%  7.75%
Rate of Increase in Future Compensation Level  3.13%  3.13%  3.13%
Schedule of amounts recognized in consolidated balance sheets
(in thousands) 2016  2015 
Regulatory Assets:        
Unrecognized Prior Service Cost $141  $329 
Unrecognized Actuarial Loss  98,039   101,974 
Total Regulatory Assets $98,180  $102,303 
Accumulated Other Comprehensive Loss:        
Unrecognized Prior Service Cost $12  $16 
Unrecognized Actuarial Loss  406   820 
Total Accumulated Other Comprehensive Loss $418  $836 
Noncurrent Liability $60,292  $69,101 
Schedule of funded status
(in thousands) 2016  2015 
Accumulated Benefit Obligation $(281,414) $(268,387)
Projected Benefit Obligation $(314,637) $(302,740)
Fair Value of Plan Assets  254,345   233,639 
  Funded Status $(60,292) $(69,101)
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations
(in thousands) 2016  2015 
Reconciliation of Fair Value of Plan Assets:        
Fair Value of Plan Assets at January 1 $233,639  $244,589 
Actual Return on Plan Assets  23,794   (9,160)
Discretionary Company Contributions  10,000   10,000 
Benefit Payments  (13,088)  (11,790)
Fair Value of Plan Assets at December 31 $254,345  $233,639 
Estimated Asset Return  10.1%  (3.7)%
Reconciliation of Projected Benefit Obligation:        
Projected Benefit Obligation at January 1 $302,740  $311,650 
Service Cost  5,518   6,059 
Interest Cost  14,195   13,344 
Benefit Payments  (13,088)  (11,790)
Actuarial Loss (Gain)  5,272   (16,523)
Projected Benefit Obligation at December 31 $314,637  $302,740 
Schedule of weighted average assumptions used to determine benefit obligations
  2016  2015 
Discount Rate  4.60%  4.76%
Rate of Increase in Future Compensation Level  3.00%  3.13%
Schedule of measurement dates
Measurement Dates:20162015
Net Periodic Pension CostJanuary 1, 2016January 1, 2015
End of Year Benefit ObligationsJanuary 1, 2016 projected to 
December 31, 2016		January 1, 2015 projected to 
December 31, 2015
Market Value of AssetsDecember 31, 2016December 31, 2015
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized
(in thousands) 2017 
Decrease in Regulatory Assets:    
Amortization of Unrecognized Prior Service Cost $120 
Amortization of Unrecognized Actuarial Loss  5,090 
Decrease in Accumulated Other Comprehensive Loss:    
Amortization of Unrecognized Prior Service Cost  3 
Amortization of Unrecognized Actuarial Loss  125 
Total Estimated Amortization $5,338 
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets
(in thousands) 2017  2018  2019  2020  2021  Years
2022-2026		 
  $13,413  $14,140  $14,806  $15,564  $16,335  $92,083 
Schedule of allocation targets and tactical ranges reflecting investment policy statement approved by BAC
  Permitted Range
Asset Class / PBO Funded Status < 100% PBO 100% PBO 105% PBO >=110% PBO
Equity 30% - 65% 25% - 60% 20% - 55% 15% - 50%
Investment Grade Fixed Income 35% - 75% 40% - 80% 45% - 85% 50% - 90%
Below Investment Grade Fixed Income*   0% - 15%  0% - 15%  0% - 15%  0% - 15%
Other**   0% - 20%  0% - 20%  0% - 20%  0% - 20%
* Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds. 
** Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund. 
Schedule Of pension plan asset allocations by asset category
Asset Allocation 2016  2015 
Large Capitalization Equity Securities  21.4%  21.2%
International Equity Securities  22.0%  21.6%
Small and Mid-Capitalization Equity Securities  9.0%  8.1%
SEI Dynamic Asset Allocation Fund  5.4%  5.6%
Equity Securities  57.8%  56.5%
Fixed-Income Securities and Cash  34.3%  35.8%
Other – SEI Energy Debt Collective Fund  4.1%  3.6%
Other – SEI Special Situation Collective Investment Trust  3.8%  4.1%
   100.0%  100.0%
Schedule of pension fund assets measured at fair value
(in thousands)   2016     2015  
Assets in Level 1 of the Fair Value Hierarchy   $ 234,303     $ 215,676  
SEI Energy Debt Collective Fund at NAV     10,441       8,342  
SEI Special Situation Collective Investment Trust Fund at NAV (1)     9,601       9,621  
Total Assets   $ 254,345     $ 233,639  

(1)On December 30, 2016 the Company instructed the pension fund manager to sell the pension fund investment in the SEI Special Situation Collective Investment Trust Fund. The cash value of the investment on settlement of the sale in January 2017 was $9,679,000.
Schedule of pension fund assets measured at fair value including level 1 fair value hierarchy
(in thousands) 2016  2015 
Large Capitalization Equity Securities Mutual Fund $54,483  $49,513 
International Equity Securities Mutual Funds  55,916   50,504 
Small and Mid-Capitalization Equity Securities Mutual Fund  23,011   18,823 
SEI Dynamic Asset Allocation Mutual Fund  13,622   13,004 
Fixed Income Securities Mutual Funds  87,268   83,830 
Cash Management – Money Market Fund  3   2 
Total Assets $234,303  $215,676 
Executive Survivor and Supplemental Retirement Plan (ESSRP)  
Schedule of components of net periodic benefit cost
(in thousands) 2016   2015   2014 
Service Cost–Benefit Earned During the Period $252  $189  $51 
Interest Cost on Projected Benefit Obligation  1,667   1,523   1,520 
Amortization of Prior Service Cost:            
From Regulatory Asset  16   16   22 
From Other Comprehensive Income1  38   38   51 
Amortization of Net Actuarial Loss:            
From Regulatory Asset  293   334   142 
From Other Comprehensive Income2  446   602   46 
Net Periodic Pension Cost $2,712  $2,702  $1,832 
1  Amortization of Prior Service Costs from Other Comprehensive Income Charged to:            
Electric Operation and Maintenance Expenses $15  $15  $20 
Other Nonelectric Expenses  23   23   31 
             
2  Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:            
Electric Operation and Maintenance Expenses $272  $310  $132 
Other Nonelectric Expenses  174   292   (86)
Schedule of weighted-average assumptions used to determine net periodic benefit cost
  2016  2015  2014 
Discount Rate  4.76%  4.35%  5.30%
Rate of Increase in Future Compensation Level  3.13%  3.15%  3.18%
Schedule of amounts recognized in consolidated balance sheets
(in thousands) 2016  2015 
Regulatory Assets:        
Unrecognized Prior Service Cost $58  $75 
Unrecognized Actuarial Loss  2,890   2,936 
Total Regulatory Assets $2,948  $3,011 
Projected Benefit Obligation Liability – Net Amount Recognized $(37,335) $(35,811)
Accumulated Other Comprehensive Loss:        
Unrecognized Prior Service Cost $134  $172 
Unrecognized Actuarial Loss  5,915   5,815 
Total Accumulated Other Comprehensive Loss $6,049  $5,987 
Schedule of reconciliation of changes in fair value of plan assets and plan's benefit obligations
(in thousands) 2016  2015 
Reconciliation of Fair Value of Plan Assets:        
Fair Value of Plan Assets at January 1 $—  $— 
Actual Return on Plan Assets  —   — 
Employer Contributions  1,188   1,119 
Benefit Payments  (1,188)  (1,119)
Fair Value of Plan Assets at December 31 $—  $— 
Reconciliation of Projected Benefit Obligation:        
Projected Benefit Obligation at January 1 $35,811  $35,650 
Service Cost  252   189 
Interest Cost  1,667   1,523 
Benefit Payments  (1,188)  (1,119)
Plan Amendments  —   — 
Actuarial Loss (Gain)  793   (432)
Projected Benefit Obligation at December 31 $37,335  $35,811 
Schedule of weighted average assumptions used to determine benefit obligations
  2016  2015 
Discount Rate  4.60%  4.76%
Rate of Increase in Future Compensation Level  3.00%  3.13%
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized
(in thousands) 2017 
Decrease in Regulatory Assets:    
Amortization of Unrecognized Prior Service Cost $16 
Amortization of Unrecognized Actuarial Loss  285 
Decrease in Accumulated Other Comprehensive Loss:    
Amortization of Unrecognized Prior Service Cost  38 
Amortization of Unrecognized Actuarial Loss  440 
Total Estimated Amortization $779 
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets
  Years 
(in thousands) 2017  2018  2019  2020  2021  2022-2026 
  $1,253  $1,487  $1,562  $1,544  $1,754  $12,700 
Other Postretirement Benefits  
Schedule of components of net periodic benefit cost
(in thousands) 2016  2015  2014 
Service Cost–Benefit Earned During the Period $1,301  $1,297  $1,055 
Interest Cost on Projected Benefit Obligation  2,503   2,097   2,200 
Amortization of Prior Service Cost            
From Regulatory Asset  134   205   205 
From Other Comprehensive Income1  3   5   5 
Amortization of Net Actuarial Loss            
From Regulatory Asset  379   —   — 
From Other Comprehensive Income1  9   —   — 
  Net Periodic Postretirement Benefit Cost $4,329  $3,604  $3,465 
Effect of Medicare Part D Subsidy $(923) $(1,487) $(948)
1 Corporate cost included in Other Nonelectric Expenses.  
Schedule of weighted-average assumptions used to determine net periodic benefit cost
  2016  2015  2014 
Discount Rate  4.57%  4.20%  5.10%
Schedule of amounts recognized in consolidated balance sheets
(in thousands) 2016  2015 
Regulatory Asset:        
Unrecognized Prior Service Cost $(4) $129 
Unrecognized Net Actuarial Loss  13,586   1,289 
Net Regulatory Asset $13,582  $1,418 
Projected Benefit Obligation Liability – Net Amount Recognized $(62,571) $(48,730)
Accumulated Other Comprehensive (Income) Loss:        
Unrecognized Prior Service Cost $4  $8 
Unrecognized Net Actuarial Gain  (171)  (347)
Accumulated Other Comprehensive Income $(167) $(339)
Schedule of funded status
(in thousands) 2016  2015 
Reconciliation of Fair Value of Plan Assets:        
Fair Value of Plan Assets at January 1 $—  $— 
Actual Return on Plan Assets  —   — 
Company Contributions  2,825   2,365 
Benefit Payments (Net of Medicare Part D Subsidy)  (5,908)  (5,324)
Participant Premium Payments  3,083   2,959 
Fair Value of Plan Assets at December 31 $—  $— 
Reconciliation of Projected Benefit Obligation:        
Projected Benefit Obligation at January 1 $48,730  $53,638 
Service Cost (Net of Medicare Part D Subsidy)  1,301   1,297 
Interest Cost (Net of Medicare Part D Subsidy)  2,503   2,097 
Benefit Payments (Net of Medicare Part D Subsidy)  (5,908)  (5,324)
Participant Premium Payments  3,083   2,959 
Actuarial Loss (Gain)  12,862   (5,937)
Projected Benefit Obligation at December 31 $62,571  $48,730 
Reconciliation of Accrued Postretirement Cost:        
Accrued Postretirement Cost at January 1 $(47,652) $(46,413)
Expense  (4,329)  (3,604)
Net Company Contribution  2,825   2,365 
Accrued Postretirement Cost at December 31 $(49,156) $(47,652)
Schedule of weighted average assumptions used to determine benefit obligations
  2016  2015 
Discount Rate  4.46%  4.57%
Schedule of healthcare cost-trend rates
  2016  2015 
Healthcare Cost-Trend Rate Assumed for Next Year Pre-65  6.01%  6.16%
Healthcare Cost-Trend Rate Assumed for Next Year Post-65  6.23%  6.43%
Rate to Which the Cost-Trend Rate is Assumed to Decline  4.50%  4.50%
Year the Rate Reaches the Ultimate Trend Rate  2038   2038 
Schedule of effects of one percentage change in assumed healthcare cost-trend rates
(in thousands) 1 Point 
Increase		  1 Point
Decrease		 
Effect on the Postretirement Benefit Obligation $7,151  $(7,492)
Effect on Total of Service and Interest Cost $653  $(519)
Effect on Expense $1,454  $(907)
Schedule of measurement dates
Measurement Dates:20162015
Net Periodic Postretirement Benefit CostJanuary 1, 2016January 1, 2015
   
End of Year Benefit ObligationsJanuary 1, 2016 projected to 
December 31, 2016		January 1, 2015 projected to 
December 31, 2015
Schedule of estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized
(in thousands) 2017 
Decrease in Regulatory Assets:    
Amortization of Unrecognized Prior Service Cost $— 
Amortization of Unrecognized Actuarial Loss  932 
Decrease in Accumulated Other Comprehensive Loss:    
Amortization of Unrecognized Prior Service Cost  — 
Amortization of Unrecognized Actuarial Loss  23 
Total Estimated Amortization $955 
Schedule of benefit payments, which reflect expected future service, as appropriate, expected to be paid out from plan assets
  Years 
(in thousands) 2017  2018  2019  2020  2021  2022-2026 
   $3,512  $3,669  $3,828  $3,912  $4,046  $20,377 
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Fair Value of Financial Instruments (Tables)
 12 Months Ended
Dec. 31, 2016
Fair Value Disclosures [Abstract]  
Schedule of long-term debt including current maturities
  December 31, 2016  December 31, 2015 
(in thousands) Carrying 
Amount		  Fair Value  Carrying 
Amount		  Fair Value 
Cash and Cash Equivalents $—  $—  $—  $— 
Short-Term Debt  (42,883)  (42,883)  (80,672)  (80,672)
Long-Term Debt including Current Maturities  (538,542)  (583,835)  (496,268)  (561,245)
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Property, Plant and Equipment (Tables)
 12 Months Ended
Dec. 31, 2016
Property, Plant and Equipment [Abstract]  
Schedule of property, plant and equipment
(in thousands) December 31,
2016		  December 31,
2015		 
Electric Plant in Service        
Production $891,330  $879,121 
Transmission  410,679   391,941 
Distribution  466,285   451,820 
General  92,063   97,881 
Electric Plant in Service  1,860,357   1,820,763 
Construction Work in Progress  149,997   64,117 
Total Gross Electric Plant  2,010,354   1,884,880 
Less Accumulated Depreciation and Amortization  622,657   592,001 
Net Electric Plant $1,387,697  $1,292,879 
Nonelectric Operations Plant        
Equipment $155,809  $155,715 
Buildings and Leasehold Improvements  51,323   41,149 
Land  4,694   4,479 
Nonelectric Operations Plant  211,826   201,343 
Construction Work in Progress  3,264   15,495 
Total Gross Nonelectric Plant  215,090   216,838 
Less Accumulated Depreciation and Amortization  125,562   121,903 
Net Nonelectric Operations Plant $89,528  $94,935 
Net Plant $1,477,225  $1,387,814 
Schedule of estimated service lives for properties
  Service Life Range 
(years) Low  High 
Electric Fixed Assets:        
Production Plant  9   82 
Transmission Plant  42   70 
Distribution Plant  5   68 
General Plant  5   50 
Nonelectric Fixed Assets:        
Equipment  3   12 
Buildings and Leasehold Improvements  7   40 
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Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2016
Income Tax Disclosure [Abstract]  
Schedule of income from continuing operations before income taxes and income tax expense
(in thousands) 2016  2015  2014 
Tax Computed at Federal Statutory Rate – Continuing Operations $28,741  $28,081  $25,704 
Increases (Decreases) in Tax from:            
Federal PTCs  (7,175)  (6,962)  (7,517)
State Income Taxes Net of Federal Income Tax Expense  2,848   4,945   1,993 
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes  (850)  (850)  (849)
Corporate-owned Life Insurance  (680)  (167)  (354)
Dividend Received/Paid Deduction  (537)  (560)  (622)
Section 199 Domestic Production Activities Deduction  (482)  —   (1,026)
Investment Tax Credit Amortization  (350)  (571)  (597)
Allowance for Funds Used During Construction – Equity  (280)  (426)  (505)
Differences Reversing in Excess of Federal Rates  77   (1,143)  (106)
Permanent and Other Differences  (1,231)  (705)  436 
Total Income Tax Expense – Continuing Operations $20,081  $21,642  $16,557 
Income Tax Expense – Discontinued Operations – U.S.  138   2,991   3,952 
Income Tax Expense – Continuing and Discontinued Operations $20,219  $24,633  $20,509 
Overall Effective Federal, State and Foreign Income Tax Rate  24.5%  29.3%  26.2%
Income Tax Expense From Continuing Operations Includes the Following:            
Current Federal Income Taxes $1,070  $211  $124 
Current State Income Taxes  1,211   1   5 
Deferred Federal Income Taxes  23,586   23,050   21,044 
Deferred State Income Taxes  2,589   6,763   4,347 
Federal PTCs  (7,175)  (6,962)  (7,517)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes  (850)  (850)  (849)
Investment Tax Credit Amortization  (350)  (571)  (597)
Total $20,081  $21,642  $16,557 
Total Income Before Income Taxes – Continuing and Discontinued Operations $82,540  $83,978  $78,232 
Schedule of deferred tax assets and liabilities

 

(in thousands)   2016     2015  
Deferred Tax Assets                
Benefit Liabilities   $ 44,381     $ 41,788  
Federal PTCs     43,433       39,505  
Retirement Benefits Liabilities     38,390       41,958  
North Dakota Wind Tax Credits     32,962       32,962  
Cost of Removal     31,636       29,463  
Differences Related to Property     9,876       10,177  
Net Operating Loss Carryforward     3,865       22,824  
Vacation Accrual     2,725       2,500  
Investment Tax Credits     818       1,109  
Other     7,793       7,617  
Total Deferred Tax Assets   $ 215,879     $ 229,903  
Deferred Tax Liabilities                
Differences Related to Property   $ (371,761 )   $ (366,234 )
Retirement Benefits Regulatory Asset     (38,390 )     (41,958 )
Excess Tax over Book Pension     (15,509 )     (13,775 )
North Dakota Wind Tax Credits     (3,654 )     (3,179 )
Impact of State Net Operating Losses on Federal Taxes     (1,352 )     (1,596 )
Other     (11,804 )     (10,830 )
 Total Deferred Tax Liabilities   $ (442,470 )   $ (437,572 )
 Deferred Income Taxes   $ (226,591 )   $ (207,669 )
Schedule of tax credits and tax net operating losses available
(in thousands) Amount  2017  2027-36 
United States            
Federal Net Operating Losses $—  $—  $— 
Federal Tax Credits  46,435   —   46,435 
State Net Operating Losses  3,865   —   3,865 
State Tax Credits  33,993   389   33,604 
Schedule of activity related to unrecognized tax benefits
(in thousands) 2016  2015  2014 
Balance on January 1 $468  $222  $4,239 
Increases Related to Tax Positions for Prior Years  406   236   120 
Decreases Related to Tax Positions for Prior Years  —   —   (4,142)
Increases Related to Tax Positions for Current Year  114   10   5 
Uncertain Positions Resolved During Year  (97)  —   — 
Balance on December 31 $891  $468  $222 
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Asset Retirement Obligations (AROs) (Tables)
 12 Months Ended
Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of reconciliations of carrying amounts of present value of legal AROs, capitalized asset retirement costs and related accumulated depreciation and summary of settlement activity
(in thousands) 2016  2015 
Asset Retirement Obligations        
Beginning Balance $8,084  $7,721 
New Obligations Recognized  —   451 
Adjustments Due to Revisions in Cash Flow Estimates  (103)  (424)
Accrued Accretion  360   336 
Settlements  —   — 
Ending Balance $8,341  $8,084 
Asset Retirement Costs Capitalized        
Beginning Balance $3,086  $3,059 
New Obligations Recognized  —   451 
Adjustments Due to Revisions in Cash Flow Estimates  (103)  (424)
Settlements  —   — 
Ending Balance $2,983  $3,086 
Accumulated Depreciation – Asset Retirement Costs Capitalized        
Beginning Balance $673  $527 
New Obligations Recognized  —   — 
Adjustments Due to Revisions in Cash Flow Estimates  —   — 
Depreciation Expense  122   146 
Settlements  —   — 
Ending Balance $795  $673 
Settlements  None   None 
Original Capitalized Asset Retirement Cost – Retired $—  $— 
Accumulated Depreciation  —   — 
         
Asset Retirement Obligation $—  $— 
Settlement Cost  —   — 
Gain on Settlement – Deferred Under Regulatory Accounting $—  $— 
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Discontinued Operations (Tables)
 12 Months Ended
Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]  
Schedule of Income and Gains and Losses from Disposition of Discontinued Operations and Schedule of Major Components of Assets and Liabilities of Discontinued Operations
For the Year Ended December 31, 2016  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower 
Business		     Dock and 
Boatlift 
Business		     Intercompany 
Transactions 
Adjustment		     Total  
Operating Expenses   $ 250     $ —     $ (757 )   $ 85     $ —     $ (422 )
Income Tax (Benefit) Expense     (136 )     5       303       (34 )     —       138  
Net (Loss) Income   $ (114 )   $ (5 )   $ 454     $ (51 )   $ —     $ 284  

 

    For the Year Ended December 31, 2015  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower 
Business		     Dock and 
Boatlift 
Business		     Intercompany 
Transactions 
Adjustment		     Total  
Operating Revenues   $ 21,625     $ 2,998     $ —     $ —     $ —     $ 24,623  
Operating Expenses     26,839       4,532       (462 )     966       (240 )     31,635  
Asset Impairment Charge     1,000       —       —       —       —       1,000  
Interest Expense     177       27       —       —       (204 )     —  
Other Income (Deductions)     (42 )     2       111       —       (2 )     69  
Income Tax (Benefit) Expense     (921 )     (638 )     229       (386 )     177       (1,539 )
Net (Loss) Income from Operations     (5,512 )     (921 )     344       (580 )     265       (6,404 )
(Loss) Gain on Disposition Before Taxes     (204 )     11,894       —       —       —       11,690  
Income Tax (Benefit) Expense on Disposition     (227 )     4,757       —       —       —       4,530  
Net Gain on Disposition     23       7,137       —       —       —       7,160  
Net (Loss) Income   $ (5,489 )   $ 6,216     $ 344     $ (580 )   $ 265     $ 756  

 

    For the Year Ended December 31, 2014  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower
Business		     Dock and 
Boatlift 
Business		     Intercompany 
Transactions
Adjustment		     Total  
Operating Revenues   $ 105,333     $ 44,527     $ —     $ —     $ —     $ 149,860  
Operating Expenses     100,826       40,297       19       (180 )     (960 )     140,002  
Asset Impairment Charge     5,605       —       —       —       —       5,605  
Interest Expense     510       184       —       —       (694 )     —  
Other (Deductions) Income     (38 )     304       —       277       (4 )     539  
Income Tax Expense (Benefit)     1,388       1,729       (8 )     183       660       3,952  
Net (Loss) Income   $ (3,034 )   $ 2,621     $ (11 )   $ 274     $ 990     $ 840  

 

    December 31, 2016  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower 
Business		     Dock and 
Boatlift
Business		     Total  
Current Liabilities   $ —     $ —     $ 589     $ 774     $ 1,363  
Liabilities of Discontinued Operations   $ —     $ —     $ 589     $ 774     $ 1,363  

 

    December 31, 2015  
(in thousands)   Foley     AEV, Inc.     Wind 
Tower 
Business		     Dock and 
Boatlift 
Business		     Total  
Current Liabilities   $ —     $ —     $ 1,299     $ 799     $ 2,098  
Liabilities of Discontinued Operations   $ —     $ —     $ 1,299     $ 799     $ 2,098  

 
Schedule of warranty reserves
(in thousands) 2016  2015 
Warranty Reserve Balance, January 1 $2,103  $2,527 
Additional Provision for Warranties Made During the Year  —   — 
Settlements Made During the Year  (24)  (124)
Decrease in Warranty Estimates for Prior Years  (710)  (300)
Warranty Reserve Balance, December 31 $1,369  $2,103 
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Subsequent Events (Tables)
 12 Months Ended
Dec. 31, 2016
Subsequent Events [Abstract]  
Schedule of stock incentive awards under the 2014 Stock Incentive Plan
Award Shares/Units 
Granted		  Weighted 
Average 
Grant-Date
Fair Value 
per Award		  Vesting 
Restricted Stock Units Granted  15,900  $37.65   25% per year through February 6, 2021 
Stock Performance Awards Granted  59,500  $31.00   December 31, 2019 
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Summary of Significant Accounting Policies - OTP's Ownership Interests in Jointly Owned Facilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Big Stone Plant    
Jointly Owned Utility Plant Interests [Line Items]    
Electric Plant in Service $ 328,809 $ 327,474
Construction Work in Progress 23 (305)
Accumulated Depreciation (65,665) (57,641)
Net Plant 263,167 269,528
Coyote Station    
Jointly Owned Utility Plant Interests [Line Items]    
Electric Plant in Service 176,315 165,497
Construction Work in Progress 113 7,405
Accumulated Depreciation (101,499) (103,822)
Net Plant 74,929 69,080
Fargo-Monticello 345 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Electric Plant in Service 78,298 78,272
Construction Work in Progress
Accumulated Depreciation (3,511) (2,213)
Net Plant 74,787 76,059
Brookings-Southeast Twin Cities 345 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Electric Plant in Service [1] 26,406 26,189
Construction Work in Progress [1]
Accumulated Depreciation [1] (924) (486)
Net Plant [1] 25,482 25,703
Bemidji-Grand Rapids 230 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Electric Plant in Service 16,331 16,331
Construction Work in Progress
Accumulated Depreciation (1,573) (1,233)
Net Plant 14,758 15,098
Big Stone South to Brookings 345 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Electric Plant in Service [1]
Construction Work in Progress [1] 45,050 14,210
Accumulated Depreciation [1]
Net Plant [1] 45,050 14,210
Big Stone South to Ellendale 345 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Electric Plant in Service [1]
Construction Work in Progress [1] 49,160 8,335
Accumulated Depreciation [1]
Net Plant [1] $ 49,160 $ 8,335
Otter Tail Power Company | Big Stone Plant    
Jointly Owned Utility Plant Interests [Line Items]    
Ownership Percentage 53.90% 53.90%
Otter Tail Power Company | Coyote Station    
Jointly Owned Utility Plant Interests [Line Items]    
Ownership Percentage 35.00% 35.00%
Otter Tail Power Company | Fargo-Monticello 345 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Ownership Percentage 14.20% 14.20%
Otter Tail Power Company | Brookings-Southeast Twin Cities 345 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Ownership Percentage [1] 4.80% 4.80%
Otter Tail Power Company | Bemidji-Grand Rapids 230 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Ownership Percentage 14.80% 14.80%
Otter Tail Power Company | Big Stone South to Brookings 345 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Ownership Percentage [1] 50.00% 50.00%
Otter Tail Power Company | Big Stone South to Ellendale 345 kV line    
Jointly Owned Utility Plant Interests [Line Items]    
Ownership Percentage [1] 50.00% 50.00%
[1] Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).
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Summary of Significant Accounting Policies - Breakdown of Investments (Details 1) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Schedule of Investments [Line Items]    
Marketable Securities Classified as Available-for-Sale $ 8,225 $ 8,093
Total Investments 8,417 10,284
Investments 8,417 8,284
AEV, Inc.    
Schedule of Investments [Line Items]    
Escrow Funds Reported Under Other Current Assets (1,500)
Foley Company    
Schedule of Investments [Line Items]    
Escrow Funds Reported Under Other Current Assets (500)
Economic Development Loan Pools    
Schedule of Investments [Line Items]    
Cost Method 54 81
Other    
Schedule of Investments [Line Items]    
Cost Method 115 2,088
Equity Method Partnerships    
Schedule of Investments [Line Items]    
Equity Method $ 23 $ 22
XML 73 R50.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details 2) - Fair Value, Measurements, Recurring - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Level 1    
Assets:    
Total Assets $ 849 $ 2,196
Level 1 | Money Market Escrow Accounts - AEV, Inc. and Foley Company Sales    
Assets:    
Current Assets - Other   2,000
Level 1 | Money Market and Mutual Funds    
Assets:    
Other Assets - Nonqualified Retirement Savings Plan 849 196
Level 2    
Assets:    
Total Assets 8,225 8,093
Liabilities    
Total Liabilities   199
Level 2 | Forward Gasoline Purchase Contracts    
Liabilities    
Other Accrued Liabilities - Derivative Liabilities   199
Level 2 | Corporate Debt Securities    
Assets:    
Investments Held by Captive Insurance Company 5,280 3,858
Level 2 | Government-Backed and Government-Sponsored Enterprises' Debt Securities - Held by Captive Insurance Company    
Assets:    
Investments Held by Captive Insurance Company $ 2,945 $ 4,235
XML 74 R51.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Inventories (Details 3) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Accounting Policies [Abstract]    
Finished Goods $ 27,755 $ 25,971
Work in Process 11,754 12,821
Raw Material, Fuel and Supplies 44,231 46,624
Total Inventories $ 83,740 $ 85,416
XML 75 R52.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details 4) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Goodwill [Roll Forward]    
Gross Balance $ 39,732 $ 31,488
Accumulated Impairments  
Balance (net of impairments) 39,732 31,488
Adjustments and Additions to Goodwill (2,160) 8,244
Balance (net of impairments) 37,572 39,732
Manufacturing    
Goodwill [Roll Forward]    
Gross Balance 20,430 12,186
Accumulated Impairments  
Balance (net of impairments) 20,430 12,186
Adjustments and Additions to Goodwill (2,160) 8,244
Balance (net of impairments) 18,270 20,430
Plastics    
Goodwill [Roll Forward]    
Gross Balance 19,302 19,302
Accumulated Impairments  
Balance (net of impairments) 19,302 19,302
Adjustments and Additions to Goodwill
Balance (net of impairments) $ 19,302 $ 19,302
XML 76 R53.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Components of Intangible Assets (Details 5) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Amortizable Intangible Assets:    
Amortized Intangible Assets, Gross Carrying Amount $ 23,081 $ 22,999
Amortized Intangible Assets, Accumulated Amortization 8,123 7,326
Amortized Intangible Assets, Net Carrying Amount 14,958 15,673
Customer Relationships    
Amortizable Intangible Assets:    
Amortized Intangible Assets, Gross Carrying Amount 22,491 21,681
Amortized Intangible Assets, Accumulated Amortization 7,861 6,714
Amortized Intangible Assets, Net Carrying Amount $ 14,630 $ 14,967
Customer Relationships | Minimum    
Amortizable Intangible Assets:    
Remaining Amortization Periods 36 months 48 months
Customer Relationships | Maximum    
Amortizable Intangible Assets:    
Remaining Amortization Periods 224 months 236 months
Covenant not to Compete    
Amortizable Intangible Assets:    
Amortized Intangible Assets, Gross Carrying Amount $ 590 $ 620
Amortized Intangible Assets, Accumulated Amortization 262 69
Amortized Intangible Assets, Net Carrying Amount $ 328 $ 551
Remaining Amortization Periods 20 months 32 months
Other Intangible Assets    
Amortizable Intangible Assets:    
Amortized Intangible Assets, Gross Carrying Amount   $ 639
Amortized Intangible Assets, Accumulated Amortization   543
Amortized Intangible Assets, Net Carrying Amount   $ 96
Remaining Amortization Periods   9 months
Emission Allowances    
Amortizable Intangible Assets:    
Amortized Intangible Assets, Gross Carrying Amount   $ 59
Amortized Intangible Assets, Net Carrying Amount   $ 59
XML 77 R54.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details 6) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Accounting Policies [Abstract]      
Amortization Expense - Intangible Assets $ 1,436 $ 1,127 $ 977
XML 78 R55.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Estimated Amortization Expense for Intangible Assets (Details 7)
$ in Thousands
Dec. 31, 2016
USD ($)
Estimated Amortization Expense - Intangible Assets  
2017 $ 1,330
2018 1,264
2019 1,133
2020 1,099
2021 $ 1,099
XML 79 R56.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information of Noncash Investing Activities (Details 8) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Noncash Investing Activities:    
Transactions Related to Capital Additions not Settled in Cash $ 13,533 $ 20,371
XML 80 R57.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information Of Cash Paid During Year (Details 9) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Cash Paid (Received) During the Year for:      
Interest (net of amount capitalized) $ 31,269 $ 30,512 $ 26,364
Income Taxes $ (1,291) $ 7,322 $ 145
XML 81 R58.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Effect of applying the guidance in ASU 2015-17 retrospectively to consolidated balance sheet (Details 10) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Assets [Abstract]      
Other Assets $ 34,104 $ 32,784  
Total Assets 1,912,385 1,818,683 $ 1,738,116
Current Liabilities      
Current Maturities of Long-Term Debt 33,201 52,422  
Total Current Liabilities 215,671 271,116  
Capitalization      
Long-Term Debt - Net 505,341 443,846  
Total Capitalization 1,175,445 1,048,869  
Total Liabilities and Equity $ 1,912,385 1,818,683  
Previously Stated      
Assets [Abstract]      
Other Assets   31,108  
Unamortized Debt Expense   3,897  
Total Assets   1,820,904  
Current Liabilities      
Current Maturities of Long-Term Debt   52,544  
Total Current Liabilities   271,238  
Capitalization      
Long-Term Debt - Net   445,945  
Total Capitalization   1,050,968  
Total Liabilities and Equity   1,820,904  
Adjustments      
Assets [Abstract]      
Other Assets   1,676  
Unamortized Debt Expense   (3,897)  
Total Assets   (2,221)  
Current Liabilities      
Current Maturities of Long-Term Debt   (122)  
Total Current Liabilities   (122)  
Capitalization      
Long-Term Debt - Net   (2,099)  
Total Capitalization   (2,099)  
Total Liabilities and Equity   $ (2,221)  
XML 82 R59.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies - Balance Sheet Account Affected, Effective January 1, 2016 (Details 11)
Dec. 31, 2016
USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]  
Balance Sheet Account Affected, Effective January 1, 2016 $ 1,869,000
Adjustment to Retained Earnings  
New Accounting Pronouncements or Change in Accounting Principle [Line Items]  
Balance Sheet Account Affected, Effective January 1, 2016 (623,000)
Long-Term Incentive Payable  
New Accounting Pronouncements or Change in Accounting Principle [Line Items]  
Balance Sheet Account Affected, Effective January 1, 2016 (1,453,000)
Deferred Taxes  
New Accounting Pronouncements or Change in Accounting Principle [Line Items]  
Balance Sheet Account Affected, Effective January 1, 2016 (416,000)
Miscellaneous Paid-In Capital  
New Accounting Pronouncements or Change in Accounting Principle [Line Items]  
Balance Sheet Account Affected, Effective January 1, 2016 $ 2,492,000
XML 83 R60.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies (Detail Textuals) - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Electric Plant      
Significant Accounting Policies [Line Items]      
Interest capitalized on a plant $ 495,000 $ 723,000 $ 689,000
Provisions for utility depreciation 2.88% 2.61% 2.89%
Electric Plant | Minimum      
Significant Accounting Policies [Line Items]      
Estimated useful lives of Property and equipment 5 Years    
Electric Plant | Maximum      
Significant Accounting Policies [Line Items]      
Estimated useful lives of Property and equipment 82 Years    
Nonelectric Plant | Minimum      
Significant Accounting Policies [Line Items]      
Estimated useful lives of Property and equipment 3 years    
Nonelectric Plant | Maximum      
Significant Accounting Policies [Line Items]      
Estimated useful lives of Property and equipment 40 years    
XML 84 R61.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies (Detail Textuals 1) - Coyote Creek Mining Company, L.L.C. (CCMC) - Lignite Sales Agreement - Otter Tail Power Company
$ in Millions
 12 Months Ended
Dec. 31, 2016
USD ($)
Significant Accounting Policies [Line Items]  
Percentage of development period costs, development fees and capital charge incurred by CCMC 35.00%
Amount of development period costs, development fees and capital charges incurred by CCMC $ 60.6
XML 85 R62.htm IDEA: XBRL DOCUMENT v3.6.0.2
Summary of Significant Accounting Policies (Detail Textuals 2) - USD ($)
 1 Months Ended 3 Months Ended 12 Months Ended
Sep. 01, 2015
Jun. 30, 2016
Mar. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Dec. 31, 2015
Significant Accounting Policies [Line Items]            
Goodwill       $ 31,488,000 $ 37,572,000 $ 39,732,000
Reduction in acquired goodwill         (2,160,000) $ 8,244,000
Cumulative-effect net-of-tax adjustment to retained earnings         1,869,000  
Adjustment to Retained Earnings            
Significant Accounting Policies [Line Items]            
Cumulative-effect net-of-tax adjustment to retained earnings         $ (623,000)  
Impulse Manufacturing Inc | Customer Relationships            
Significant Accounting Policies [Line Items]            
Value of intangible assets acquired $ 4,870,000          
Amortization period 20 years          
Increase (decrease) in the fair value of asset acquired   $ 810,000        
Impulse Manufacturing Inc | Covenant not to Compete            
Significant Accounting Policies [Line Items]            
Value of intangible assets acquired $ 620,000          
Amortization period 3 years          
Increase (decrease) in the fair value of asset acquired   (30,000)        
Foley Company            
Significant Accounting Policies [Line Items]            
Goodwill impairment charge     $ 1,000,000 $ 5,600,000    
Miller Welding & Iron Works, Inc. (BTD-Illinois) | Impulse Manufacturing Inc            
Significant Accounting Policies [Line Items]            
Goodwill $ 8,200,000          
Reduction in acquired goodwill   $ 2,200,000        
XML 86 R63.htm IDEA: XBRL DOCUMENT v3.6.0.2
Business Combinations, Dispositions and Segment Information (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Sep. 01, 2015
Dec. 31, 2014
Assets:        
Goodwill $ 37,572 $ 39,732   $ 31,488
BTD-Georgia        
Assets:        
Current Assets     $ 4,906  
Goodwill     6,083  
Other Intangible Assets     6,270  
Other Amortizable Assets     1,380  
Fixed Assets     13,649  
Total Assets     32,288  
Liabilities:        
Current Liabilities     2,971  
Lease Obligation     11  
Total Liabilities     2,982  
Cash Paid     $ 29,306  
XML 87 R64.htm IDEA: XBRL DOCUMENT v3.6.0.2
Business Combinations, Dispositions and Segment Information - Information on Continuing Operations for Business Segments (Details 1) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Segment Reporting Information [Line Items]      
Operating Revenue $ 803,539 $ 779,804 $ 799,262
Cost of Products Sold 295,222 295,032 308,069
Other Nonelectric Expenses 40,264 40,021 45,981
Depreciation and Amortization 73,445 60,363 58,074
Operating Income (Loss) 111,099 109,214 99,531
Interest Charges 31,886 31,160 29,648
Income Tax Expense (Benefit) - Continuing Operations 20,081 21,642 16,557
Net Income (Loss) 62,321 59,345 57,723
Capital Expenditures 161,259 160,084 163,582
Identifiable Assets 1,912,385 1,818,683 1,738,116
Discontinued Operations      
Segment Reporting Information [Line Items]      
Net Income (Loss) 284 756 840
Identifiable Assets 47,559
Intersegment Eliminations      
Segment Reporting Information [Line Items]      
Operating Revenue (34) (96) (114)
Cost of Products Sold (6) (9) (45)
Other Nonelectric Expenses (28) (87) (69)
Corporate      
Segment Reporting Information [Line Items]      
Other Nonelectric Expenses 8,896 9,143 13,418
Depreciation and Amortization 47 172 116
Operating Income (Loss) (8,943) (9,315) (13,534)
Interest Charges 1,924 2,203 2,040
Income Tax Expense (Benefit) - Continuing Operations (5,099) (4,911) (5,890)
Net Income (Loss) (4,114) (6,136) (8,247)
Capital Expenditures 97 11 44
Identifiable Assets 39,037 42,312 36,508
Electric | Operating Segments      
Segment Reporting Information [Line Items]      
Operating Revenue 427,383 407,131 407,743
Depreciation and Amortization 53,743 44,786 44,076
Operating Income (Loss) 90,131 87,171 76,060
Interest Charges 25,069 24,371 23,322
Income Tax Expense (Benefit) - Continuing Operations 16,366 16,067 11,029
Net Income (Loss) 49,829 48,370 43,684
Capital Expenditures 149,648 135,572 148,719
Identifiable Assets 1,622,231 1,520,887 1,438,791
Manufacturing | Operating Segments      
Segment Reporting Information [Line Items]      
Operating Revenue 221,289 215,011 219,583
Cost of Products Sold 171,732 171,956 169,033
Other Nonelectric Expenses 21,994 21,115 23,340
Depreciation and Amortization 15,794 11,853 10,518
Operating Income (Loss) 11,769 10,086 16,692
Interest Charges 3,859 3,560 3,243
Income Tax Expense (Benefit) - Continuing Operations 2,276 2,299 4,117
Net Income (Loss) 5,694 4,247 9,361
Capital Expenditures 8,429 20,295 11,252
Identifiable Assets 166,525 173,860 128,608
Plastics | Operating Segments      
Segment Reporting Information [Line Items]      
Operating Revenue 154,901 157,758 172,050
Cost of Products Sold 123,496 123,085 139,081
Other Nonelectric Expenses 9,402 9,850 9,292
Depreciation and Amortization 3,861 3,552 3,364
Operating Income (Loss) 18,142 21,272 20,313
Interest Charges 1,034 1,026 1,043
Income Tax Expense (Benefit) - Continuing Operations 6,538 8,187 7,301
Net Income (Loss) 10,628 12,108 12,085
Capital Expenditures 3,085 4,206 3,567
Identifiable Assets $ 84,592 $ 81,624 $ 86,650
XML 88 R65.htm IDEA: XBRL DOCUMENT v3.6.0.2
Business Combinations, Dispositions and Segment Information (Detail Textuals) - USD ($)
$ in Thousands
 1 Months Ended 12 Months Ended
Sep. 01, 2015
Jun. 30, 2016
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Business Acquisition [Line Items]          
Cash     $ (1,500) $ 30,806  
Revenues recorded     803,539 779,804 $ 799,262
Net loss     $ 62,321 $ 59,345 $ 57,723
BTD-Georgia          
Business Acquisition [Line Items]          
Cash $ 30,800 $ 29,300      
Post closing reduction in purchase price $ 1,500        
Reduction in goodwill   2,200      
Amount of increase in customer relationships   800      
Amount of increase in liabilities   $ 100      
XML 89 R66.htm IDEA: XBRL DOCUMENT v3.6.0.2
Business Combinations, Dispositions and Segment Information (Detail Textuals 1) - Segment
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Segment Reporting Information [Line Items]      
Number of segments 3    
Operating revenues | United States      
Segment Reporting Information [Line Items]      
Percentage of sales revenue 98.60% 97.10% 95.90%
XML 90 R67.htm IDEA: XBRL DOCUMENT v3.6.0.2
Rate and Regulatory Matters (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
USD ($)
Annualized or Test Year  
Regulatory Matters [Line Items]  
Revenue Increase Requested $ 19,296
Increase Percentage Requested 9.80%
Jurisdictional Rate Base $ 483,000
Interim Revenue Increase (subject to refund) 16,816
Actual Through December 31, 2016  
Regulatory Matters [Line Items]  
Interim Revenue Increase (subject to refund) $ 10,976
XML 91 R68.htm IDEA: XBRL DOCUMENT v3.6.0.2
Rate and Regulatory Matters (Details 1) - 2016 Test Year Allocation
$ in Thousands
 12 Months Ended
Dec. 31, 2016
USD ($)
Revenue Requirement Deficiency Cost Factors  
Total Requested Revenue Increase $ 19,296
Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset (2,480)
Approved Interim Revenue Increase (subject to refund) 16,816
Increased Rate Base  
Revenue Requirement Deficiency Cost Factors  
Total Requested Revenue Increase 10,000
Increased Expenses  
Revenue Requirement Deficiency Cost Factors  
Total Requested Revenue Increase 7,700
Other  
Revenue Requirement Deficiency Cost Factors  
Total Requested Revenue Increase $ 1,596
XML 92 R69.htm IDEA: XBRL DOCUMENT v3.6.0.2
Rate and Regulatory Matters (Details 2) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Regulatory Matters [Line Items]      
Revenue $ 803,539 $ 779,804 $ 799,262
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives      
Regulatory Matters [Line Items]      
Revenue [1] 12,920 10,724 7,757
Otter Tail Power Company | Minnesota | Environmental Cost Recovery      
Regulatory Matters [Line Items]      
Revenue 12,443 10,238 6,891
Otter Tail Power Company | Minnesota | Transmission Cost Recovery      
Regulatory Matters [Line Items]      
Revenue 5,795 5,202 6,275
Otter Tail Power Company | North Dakota | Environmental Cost Recovery      
Regulatory Matters [Line Items]      
Revenue 11,089 9,502 5,872
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment      
Regulatory Matters [Line Items]      
Revenue 7,800 8,409 7,484
Otter Tail Power Company | North Dakota | Transmission Cost Recovery      
Regulatory Matters [Line Items]      
Revenue 7,694 6,609 5,794
Otter Tail Power Company | South Dakota | Conservation Improvement Program Costs and Incentives      
Regulatory Matters [Line Items]      
Revenue 468 583 435
Otter Tail Power Company | South Dakota | Environmental Cost Recovery      
Regulatory Matters [Line Items]      
Revenue 2,538 1,967 234
Otter Tail Power Company | South Dakota | Transmission Cost Recovery      
Regulatory Matters [Line Items]      
Revenue $ 1,820 $ 1,290 $ 1,207
[1] Includes MNCIP costs recovered in base rates.
XML 93 R70.htm IDEA: XBRL DOCUMENT v3.6.0.2
Rate and Regulatory Matters (Detail Textuals) - Otter Tail Power Company
$ in Millions
 12 Months Ended
Dec. 31, 2016
USD ($)
kV
mi
Dec. 31, 2011
USD ($)
kV
mi
Regulatory Matters [Line Items]    
Increase In reagent costs and emission allowances | $ $ 2.2  
Big Stone South - Brookings MVP    
Regulatory Matters [Line Items]    
Expanded capacity of projects | kV   345
Extended distance of transmission line | mi   70
Capacity Expansion 2020 | Brookings Project    
Regulatory Matters [Line Items]    
Investment to acquire ownership interest | $   $ 26.0
Percentage of ownership interest acquired in transmission line   4.80%
Expanded capacity of projects | kV   345
Distance of transmission line | mi   250
Capacity Expansion 2020 | Fargo Project    
Regulatory Matters [Line Items]    
Investment to acquire ownership interest | $ $ 81.0  
Percentage of ownership interest acquired in transmission line 14.20%  
Expanded capacity of projects | kV 345  
Distance of transmission line | mi 240  
Percentage of certain assets of project 100.00%  
Big Stone AQCS Project BART - compliant AQCS    
Regulatory Matters [Line Items]    
Capitalized projected cost | $ $ 200.0  
Federal Energy Regulatory Commission | Big Stone South - Ellendale MVP    
Regulatory Matters [Line Items]    
Expanded capacity of projects | kV   345
Extended distance of transmission line | mi   163
Minnesota Public Utilities Commission    
Regulatory Matters [Line Items]    
Percentage of reagent costs and emission allowances shared 50.00%  
North Dakota Public Service Commission    
Regulatory Matters [Line Items]    
Percentage of reagent costs and emission allowances shared 40.00%  
South Dakota Public Utilities Commission    
Regulatory Matters [Line Items]    
Percentage of reagent costs and emission allowances shared 10.00%  
XML 94 R71.htm IDEA: XBRL DOCUMENT v3.6.0.2
Rate and Regulatory Matters (Detail Textuals 1)
$ in Millions
 1 Months Ended 12 Months Ended
Feb. 16, 2016
Dec. 21, 2015
USD ($)
Sep. 30, 2015
USD ($)
Apr. 25, 2011
USD ($)
Dec. 31, 2016
USD ($)
Dec. 31, 2015
USD ($)
Dec. 31, 2014
USD ($)
$ / kWh
Aug. 16, 2016
May 25, 2016
Apr. 14, 2016
Apr. 01, 2016
USD ($)
Jul. 09, 2015
USD ($)
Sep. 26, 2014
USD ($)
Otter Tail Power Company | 2016 General Rate Case                          
Regulatory Matters [Line Items]                          
Estimated interim rate refund         $ 3.6                
Otter Tail Power Company | 2016 General Rate Case | Rebuttal testimony                          
Regulatory Matters [Line Items]                          
Percentage of allowed rate of return on equity               10.05%          
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program                          
Regulatory Matters [Line Items]                          
Financial incentives recognized during period         5.1 $ 4.2 $ 3.0            
Decrease in estimation of kilowatt-hours for financial incentives | $ / kWh             2,000,000            
Amount of financial incentive requested         $ 5.1           $ 4.3    
Percentage increase in energy savings         18.00% 39.00%              
Incentives net benefit, 2017                 13.50%        
Incentives net benefit, 2018                 12.00%        
Incentives net benefit, 2019                 10.00%        
Assumed savings of utility                 1.70%        
Percentage of reduction in financial incentive                 50.00%        
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Minimum                          
Regulatory Matters [Line Items]                          
Percentage of operating revenue from service to be invested in energy conservation in Minnesota         1.50%                
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013                          
Regulatory Matters [Line Items]                          
Financial incentive request approved                         $ 4.0
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013 To 2015                          
Regulatory Matters [Line Items]                          
Lower estimated incentives | $ / kWh             0.09            
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014 To 2016                          
Regulatory Matters [Line Items]                          
Lower estimated incentives | $ / kWh             0.07            
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014                          
Regulatory Matters [Line Items]                          
Financial incentive request approved                       $ 3.0  
Otter Tail Power Company | Minnesota Public Utilities Commission | Transmission Cost Recovery Rider                          
Regulatory Matters [Line Items]                          
Seeking revenue recovery   $ 7.2 $ 7.8                    
Otter Tail Power Company | Minnesota Public Utilities Commission | 2010 General Rate Case                          
Regulatory Matters [Line Items]                          
General rate revenue increase approved       $ 5.0                  
Percentage of increase in base rate revenue approved by rate authority       1.60%                  
Public utilities allowed rate of return on rate base prior to approval of increase in base rate       8.33%                  
Allowed rate of return on rate base       8.61%                  
Public utilities allowed rate of return on equity prior to approval of increase in base rate       10.43%                  
Allowed rate of return on equity       10.74%                  
Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case                          
Regulatory Matters [Line Items]                          
Allowed rate of return on rate base 8.07%                        
Allowed rate of return on equity 10.40%                        
Percentage of capital 52.50%                        
Increase to base rate portion of customer bills                   9.56%      
Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case | Transmission Cost Recovery Rider                          
Regulatory Matters [Line Items]                          
Allowed rate of return on rate base         100.00%                
MNDOC | 2016 General Rate Case | Direct testimony                          
Regulatory Matters [Line Items]                          
Percentage of allowed rate of return on equity               8.87%          
MNDOC | 2016 General Rate Case | Rebuttal testimony                          
Regulatory Matters [Line Items]                          
Percentage of allowed rate of return on equity               8.66%          
OAG | 2016 General Rate Case | Direct testimony                          
Regulatory Matters [Line Items]                          
Percentage of allowed rate of return on equity               6.96%          
OAG | 2016 General Rate Case | Rebuttal testimony                          
Regulatory Matters [Line Items]                          
Percentage of allowed rate of return on equity               7.14%          
ALJ | 2016 General Rate Case                          
Regulatory Matters [Line Items]                          
Percentage of allowed rate of return on equity               9.54%          
XML 95 R72.htm IDEA: XBRL DOCUMENT v3.6.0.2
Rate and Regulatory Matters (Detail Textuals 2) - Otter Tail Power Company - North Dakota Public Service Commission - USD ($)
$ in Millions
 1 Months Ended
Mar. 12, 2014
Apr. 01, 2017
Dec. 30, 2016
Sep. 01, 2016
Mar. 31, 2016
Aug. 31, 2015
Jul. 01, 2015
Mar. 31, 2015
Mar. 31, 2014
Nov. 25, 2009
Renewable Resource Cost Recovery Rider                    
Regulatory Matters [Line Items]                    
Percentage of reduction in the NDRRA 13.50%                  
Percentage of ECR rider rate     7.005%              
Allowed rate of return on equity 10.50%                  
Renewable Resource Cost Recovery Rider | Subsequent Event                    
Regulatory Matters [Line Items]                    
Percentage of ECR rider rate previously in effect   7.573%                
Transmission Cost Recovery Rider                    
Regulatory Matters [Line Items]                    
Jurisdictional Capital And Operating Costs Recovery           $ 8.5        
Transmission Cost Recovery Rider | Fiscal Year 2016                    
Regulatory Matters [Line Items]                    
Jurisdictional Capital And Operating Costs Recovery           $ 10.2        
Revenue requirement       $ 5.7            
Reduction of projected over collection       $ 2.6            
Environmental Cost Recovery Rider                    
Regulatory Matters [Line Items]                    
Percentage of ECR rider rate         7.904%   9.193% 7.531% 4.319%  
Revenue requirement         $ 10.4   $ 12.2      
General Rate Case                    
Regulatory Matters [Line Items]                    
General rate revenue increase approved                   $ 3.6
Percentage of increase in base rate revenue approved by MPUC                   3.00%
Allowed rate of return on rate base                   8.62%
Allowed rate of return on equity                   10.75%
XML 96 R73.htm IDEA: XBRL DOCUMENT v3.6.0.2
Rate and Regulatory Matters (Detail Textuals 3) - USD ($)
 1 Months Ended 12 Months Ended
Feb. 12, 2015
Nov. 06, 2014
Nov. 12, 2013
Sep. 28, 2016
Aug. 31, 2016
Dec. 22, 2015
Aug. 31, 2015
Apr. 21, 2011
Dec. 31, 2016
Dec. 31, 2015
Sep. 19, 2016
Jan. 31, 2012
Regulatory Matters [Line Items]                        
Regulatory liabilities                 $ 85,727,000 $ 80,754,000    
Otter Tail Power Company | South Dakota Public Utilities Commission | Environmental Cost Recovery Rider                        
Regulatory Matters [Line Items]                        
Annual Revenue Requesting Recovery         $ 2,300,000   $ 2,700,000          
Otter Tail Power Company | South Dakota Public Utilities Commission | 2010 General Rate Case                        
Regulatory Matters [Line Items]                        
Revenue increase approved by rate authority               $ 643,000        
Percentage of increase in base rate revenue approved by MPUC               2.32%        
Allowed rate of return on rate base               8.50%        
Otter Tail Power Company | Federal Energy Regulatory Commission                        
Regulatory Matters [Line Items]                        
Percentage of prudently incurred costs of construction work in progress, authorized for recovery by formula transmission rate                       100.00%
Proposed reduced return on equity used in transmission rates 8.67%   9.15%                  
Current return on equity used in transmission rates     12.38%     10.32%            
Additional Incentive Basis Point   50-basis points                    
Expected percentage of return on equity       10.82%             9.70%  
Expected percentage of return on equity description       ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder)                
Reductions in revenue                 1,600,000 $ 1,100,000    
Regulatory liabilities                 $ 2,700,000      
XML 97 R74.htm IDEA: XBRL DOCUMENT v3.6.0.2
Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current $ 21,297 $ 18,904
Regulatory Liabilities - Current 3,294 3,322
Net Regulatory Asset Position - Current 18,003 15,582
Regulatory Assets - Long-Term 132,094 127,707
Regulatory Liabilities - Long-Term 82,433 77,432
Net Regulatory Asset Position - Long-Term 49,661 50,275
Regulatory Assets - Total 153,391 146,611
Regulatory Liabilities - Total 85,727 80,754
Net Regulatory Asset Position 67,664 65,857
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [1] 6,443 7,439
Regulatory Assets - Long-Term [1] 108,267 99,293
Regulatory Assets - Total [1] $ 114,710 $ 106,732
Regulatory Assets - Remaining Recovery/Refund Period [1] see below see below
Deferred Marked-to-Market Losses    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [1] $ 4,063 $ 4,063
Regulatory Assets - Long-Term [1] 6,467 10,530
Regulatory Assets - Total [1] $ 10,530 $ 14,593
Regulatory Assets - Remaining Recovery/Refund Period [1] 48 months 60 months
Conservation Improvement Program Costs and Incentives    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [2] $ 4,836 $ 4,411
Regulatory Assets - Long-Term [2] 5,158 4,266
Regulatory Assets - Total [2] $ 9,994 $ 8,677
Regulatory Assets - Remaining Recovery/Refund Period [2] 21 months 18 months
Accumulated ARO Accretion/Depreciation Adjustment    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [1]
Regulatory Assets - Long-Term [1] 6,153 5,672
Regulatory Assets - Total [1] $ 6,153 $ 5,672
Regulatory Assets - Remaining Recovery/Refund Period [1] asset lives asset lives
Big Stone II Unrecovered Project Costs - Minnesota    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [1] $ 778 $ 942
Regulatory Assets - Long-Term [1] 2,087 2,620
Regulatory Assets - Total [1] $ 2,865 $ 3,562
Regulatory Assets - Remaining Recovery/Refund Period [1] 52 months 84 months
North Dakota Renewable Resource Rider Accrued Revenues    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [2] $ 1,319
Regulatory Assets - Long-Term [2] 482 1,266
Regulatory Assets - Total [2] $ 1,801 $ 1,266
Regulatory Assets - Remaining Recovery/Refund Period [2] 15 months 15 months
Recoverable Fuel and Purchased Power Costs    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [1] $ 1,798  
Regulatory Assets - Long-Term [1]  
Regulatory Assets - Total [1] $ 1,798  
Regulatory Assets - Remaining Recovery/Refund Period [1] 12 months  
Debt Reacquisition Premiums    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [1] $ 325 $ 351
Regulatory Assets - Long-Term [1] 1,214 1,539
Regulatory Assets - Total [1] $ 1,539 $ 1,890
Regulatory Assets - Remaining Recovery/Refund Period [1] 189 months 201 months
Minnesota Deferred Rate Case Expenses Subject to Recovery    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [1] $ 1,082 $ 291
Regulatory Assets - Long-Term [1]
Regulatory Assets - Total [1] $ 1,082 $ 291
Regulatory Assets - Remaining Recovery/Refund Period [1] 12 months 12 months
Deferred Income Taxes    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [1]
Regulatory Liabilities - Current
Regulatory Assets - Long-Term [1] 1,014 1,455
Regulatory Liabilities - Long-Term 818 1,110
Regulatory Assets - Total [1] 1,014 1,455
Regulatory Liabilities - Total $ 818 $ 1,110
Regulatory Assets - Remaining Recovery/Refund Period [1] asset lives asset lives
Regulatory Liabilities - Remaining Recovery/Refund Period asset lives asset lives
Big Stone II Unrecovered Project Costs - South Dakota    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [2] $ 100 $ 100
Regulatory Assets - Long-Term [2] 543 643
Regulatory Assets - Total [2] $ 643 $ 743
Regulatory Assets - Remaining Recovery/Refund Period 77 months 89 months [2]
North Dakota Transmission Cost Recovery Rider Accrued Revenues    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [2]  
Regulatory Assets - Long-Term [2] 568  
Regulatory Assets - Total [2] $ 568  
Regulatory Assets - Remaining Recovery/Refund Period 24 months  
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [2] $ 333 $ 698
Regulatory Liabilities - Current  
Regulatory Assets - Long-Term [2] 355
Regulatory Liabilities - Long-Term 132  
Regulatory Assets - Total [2] 333 $ 1,053
Regulatory Liabilities - Total $ 132  
Regulatory Assets - Remaining Recovery/Refund Period [2] 12 months 24 months
Regulatory Liabilities - Remaining Recovery/Refund Period 24 months  
South Dakota Transmission Cost Recovery Rider Accrued Revenues    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [2] $ 73 $ 33
Regulatory Assets - Long-Term [2] 141
Regulatory Assets - Total [2] $ 214 $ 33
Regulatory Assets - Remaining Recovery/Refund Period [2] 14 months 12 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [2] $ 113  
Regulatory Assets - Long-Term [2]  
Regulatory Assets - Total [2] $ 113  
Regulatory Assets - Remaining Recovery/Refund Period [2] 12 months  
Regulatory Liabilities - Remaining Recovery/Refund Period   12 months
Minnesota Renewable Resource Rider Accrued Revenues    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [2] $ 34
Regulatory Assets - Long-Term [2] 68
Regulatory Assets - Total [2] $ 34 $ 68
Regulatory Assets - Remaining Recovery/Refund Period [2] 9 months  
Regulatory Assets - Remaining Recovery/Refund Period [2]   see below
Accumulated Reserve for Estimated Removal Costs - Net of Salvage    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current
Regulatory Liabilities - Long-Term 80,404 74,948
Regulatory Liabilities - Total $ 80,404 $ 74,948
Regulatory Liabilities - Remaining Recovery/Refund Period asset lives asset lives
Revenue for Rate Case Expenses Subject to Refund - Minnesota    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current $ 711
Regulatory Liabilities - Long-Term 208 1,279
Regulatory Liabilities - Total $ 919 $ 1,279
Regulatory Liabilities - Remaining Recovery/Refund Period 16 months  
Regulatory Liabilities - Remaining Recovery/Refund Period   see below
Deferred Gain on Sale of Utility Property - Minnesota Portion    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current   $ 5
Regulatory Liabilities - Long-Term   95
Regulatory Liabilities - Total   $ 100
Regulatory Liabilities - Remaining Recovery/Refund Period   216 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Assets - Current [2]   $ 576
Regulatory Assets - Long-Term [2]  
Regulatory Assets - Total [2]   $ 576
Regulatory Assets - Remaining Recovery/Refund Period [2]   12 months
Refundable Fuel Clause Adjustment Revenues    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current   $ 1,834
Regulatory Liabilities - Long-Term  
Regulatory Liabilities - Total   $ 1,834
Regulatory Liabilities - Remaining Recovery/Refund Period   12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current $ 139 $ 777
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total $ 139 $ 777
Regulatory Liabilities - Remaining Recovery/Refund Period 12 months 12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current $ 285 $ 185
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total $ 285 $ 185
Regulatory Liabilities - Remaining Recovery/Refund Period 12 months 12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current $ 1,381 $ 132
Regulatory Liabilities - Long-Term 782
Regulatory Liabilities - Total $ 2,163 $ 132
Regulatory Assets - Remaining Recovery/Refund Period [1] 12 months  
Regulatory Liabilities - Remaining Recovery/Refund Period 24 months 12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current   $ 321
Regulatory Liabilities - Long-Term  
Regulatory Liabilities - Total   $ 321
Regulatory Liabilities - Remaining Recovery/Refund Period   12 months
North Dakota Renewable Resource Rider Accrued Refund    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current   $ 68
Regulatory Liabilities - Long-Term  
Regulatory Liabilities - Total   $ 68
Regulatory Liabilities - Remaining Recovery/Refund Period   12 months
Other    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current $ 21  
Regulatory Liabilities - Long-Term 89  
Regulatory Liabilities - Total $ 110  
Regulatory Liabilities - Remaining Recovery/Refund Period 204 months  
Minnesota Transmission Cost Recovery Rider Accrued Refund    
Schedule of Regulatory Assets and Liabilities [Line Items]    
Regulatory Liabilities - Current $ 757  
Regulatory Liabilities - Long-Term  
Regulatory Liabilities - Total $ 757  
Regulatory Liabilities - Remaining Recovery/Refund Period 12 months  
[1] Costs subject to recovery without a rate of return.
[2] Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
XML 98 R75.htm IDEA: XBRL DOCUMENT v3.6.0.2
Regulatory Assets and Liabilities (Detail Textuals)
 12 Months Ended
Dec. 31, 2016
Debt Reacquisition Premiums  
Schedule of Regulatory Assets and Liabilities [Line Items]  
Regulatory assets - long term, remaining recovery/refund period 189 months
XML 99 R76.htm IDEA: XBRL DOCUMENT v3.6.0.2
Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Details) - Legally enforceable netting arrangements - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]    
Derivatives in Gain Positions Subject to Legally Enforceable Netting Arrangements
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements (17,382) (16,070)
Net Balance Subject to Legally Enforceable Netting Arrangements $ (17,382) $ (16,070)
XML 100 R77.htm IDEA: XBRL DOCUMENT v3.6.0.2
Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Details 1) - Otter Tail Power Company - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Credit Derivatives [Line Items]    
Loss Contracts Covered by Deposited Funds or Letters of Credit $ 199
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade [1] 17,382 15,871
Total Loss Contracts based on Current Market Values $ 17,382 $ 16,070
[1] Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $ 17,382 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 17,382 $ 15,871.
XML 101 R78.htm IDEA: XBRL DOCUMENT v3.6.0.2
Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Parentheticals) (Details 1) - Otter Tail Power Company - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Credit Derivatives [Line Items]    
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade [1] $ 17,382 $ 15,871
Offsetting Gains with Counterparties under Master Netting Agreements
Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 17,382 $ 15,871
[1] Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $ 17,382 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 17,382 $ 15,871.
XML 102 R79.htm IDEA: XBRL DOCUMENT v3.6.0.2
Common Shares and Earnings Per Share - Reconciliation of Common Shares Outstanding (Details)
 12 Months Ended
Dec. 31, 2016
shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]  
Balance (in shares) 37,857,186
Issuances:  
At-the-Market Offering 1,014,115
Automatic Dividend Reinvestment and Share Purchase Plan:  
Dividends Reinvested 163,010
Cash Invested 115,801
Vesting of Executive Stock Performance Awards 54,700
Employee Stock Purchase Plan:  
Cash Invested 53,875
Dividends Reinvested 23,713
Employee Stock Ownership Plan 23,837
Restricted Stock Issued to Directors 23,200
Vesting of Restricted Stock Units 21,825
Directors Deferred Compensation 542
Retirements:  
Shares Withheld for Individual Income Tax Requirements (3,668)
Balance (in shares) 39,348,136
XML 103 R80.htm IDEA: XBRL DOCUMENT v3.6.0.2
Common Shares and Earnings Per Share (Details 1) - shares
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]      
Weighted Average Common Shares Outstanding - Basic 38,546,000 37,495,000 36,514,000
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:      
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance 118,644 100,194 135,480
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 45,712 36,180 27,540
Nonvested Restricted Shares 16,778 22,848 49,998
Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,417 13,488 24,048
Potentially Dilutive Stock Options 330 1,096
Total Dilutive Shares 184,551 173,040 238,162
Weighted Average Common Shares Outstanding - Diluted 38,731,000 37,668,000 36,753,000
XML 104 R81.htm IDEA: XBRL DOCUMENT v3.6.0.2
Common Shares and Earnings Per Share (Detail Textuals) - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended
Jan. 01, 2017
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
May 11, 2015
Stockholders Equity Note [Line Items]          
Common shares issued for cash   53,875      
Maximum per share differences between basic and diluted earnings per share in total or from continuing or discontinued operations   $ 0.01 $ 0.01 $ 0.01  
Subsequent Event          
Stockholders Equity Note [Line Items]          
Percentage of market price for eligible employees to purchase shares at the end of each six month purchase period 100.00%        
1999 Employee Stock Purchase Plan          
Stockholders Equity Note [Line Items]          
Percentage of market price for eligible employees to purchase shares at the end of each six month purchase period   85.00%      
Common shares authorized for granting stock awards   1,400,000      
Common shares available for grant   384,159      
Common shares issued for cash   53,875 42,253 39,222  
1999 Employee Stock Purchase Plan | Previously Reported          
Stockholders Equity Note [Line Items]          
Common shares authorized for granting stock awards   900,000      
Dividend Reinvestment and Share Purchase Plan          
Stockholders Equity Note [Line Items]          
Common shares available for grant   918,670      
Common shares issued for cash   278,811 302,519    
Shelf registration for issuance of common shares         1,500,000
2014 Stock Incentive Plan          
Stockholders Equity Note [Line Items]          
Common shares authorized for granting stock awards   1,900,000      
Common shares available for grant   1,356,811      
Distribution Agreement | J.P. Morgan Securities LLC (JPMS)          
Stockholders Equity Note [Line Items]          
Agreement with distribution agent for offer and sale of shares, aggregate sales price         $ 75
XML 105 R82.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments - Summary of Stock Options Activity (Details) - Stock options - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Options      
Outstanding, Beginning of Year 12,750 34,700
Exercised 10,250 20,800
Forfeited or Expired 2,500 1,150
Outstanding, End of Year 12,750
Exercisable, End of Year 12,750
Average Exercise Price      
Outstanding, Beginning of Year   $ 24.93 $ 25.69
Exercised   24.93 26.11
Forfeited or Expired   $ 24.93 26.495
Outstanding, End of Year     24.93
Exercisable, End of Year     $ 24.93
Cash Received for Options Exercised   $ 256,000 $ 543,000
Intrinsic Value of Options Exercised   $ 75,000 $ 89,000
XML 106 R83.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments - Summary of Status of Directors' Restricted Stock Awards (Details 1) - Director - Restricted Stock - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Shares      
Nonvested, Beginning of Year 38,217 38,050 42,483
Granted 23,200 15,200 16,800
Vested 15,083 15,033 21,233
Forfeited
Nonvested, End of Year 46,334 38,217 38,050
Weighted Average Grant-Date Fair Value      
Nonvested, Beginning of Year $ 29.78 $ 27.47 $ 25.03
Granted 28.66 31.775 29.41
Vested 28.28 25.96 24.11
Forfeited    
Nonvested, End of Year $ 29.71 $ 29.78 $ 27.47
Compensation Expense Recognized $ 491,000 $ 417,000 $ 416,000
Fair Value of Shares Vested in Year $ 427,000 $ 390,000 $ 512,000
XML 107 R84.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments - Summary of Status of Employees' Restricted Stock Awards (Details 2) - Employee - Restricted Stock - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Shares      
Nonvested, Beginning of Year 13,581 45,280 48,315
Granted 26,700
Awards Vested 6,401 31,699 25,360
Forfeited 4,375
Nonvested, End of Year 7,180 13,581 45,280
Weighted Average Grant-Date Fair Value      
Nonvested, Beginning of Year $ 28.56 $ 27.46 $ 25.04
Granted 29.41
Awards Vested 27.25 27.09 24.80
Forfeited     28.03
Nonvested, End of Year $ 29.72 $ 28.56 $ 27.46
Compensation Expense Recognized $ 96,000 $ 359,000 $ 998,000
Fair Value of Awards Vested $ 174,000 $ 859,000 $ 629,000
XML 108 R85.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments - Summary of Status of Executive Restricted Stock Awards (Details 3) - Executives - Restricted Stock - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Restricted Stock Units    
Nonvested, Beginning of Year 24,300
Granted 22,000 29,100
Vested 4,475 4,800
Forfeited
Nonvested, End of Year 41,825 24,300
Weighted Average Grant-Date Fair Value    
Nonvested, Beginning of Year $ 31.682  
Granted 28.915 $ 31.681
Vested 31.69 31.675
Nonvested, End of Year $ 30.23 $ 31.682
Compensation Expense Recognized $ 446,000 $ 452,000
Fair Value of Awards Vested $ 142,000 $ 152,000
XML 109 R86.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments - Summary of restricted stock unit awards granted and vested to executive officers (Details 4) - Restricted Stock Units (RSU) - Employee - $ / shares
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]      
Units Granted 17,220 15,650 11,800
Grant-Date Fair Value per Award $ 24.54 $ 25.89 $ 24.95
2014 Stock Incentive Plan | Vesting 100% on April 8, 2020 | Granted on April 11, 2016      
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]      
Units Granted 15,800    
Grant-Date Fair Value per Award $ 24.00    
Vesting percentage 100.00%    
2014 Stock Incentive Plan | Vesting 100% on April 8, 2020 | Granted on September 21, 2016      
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]      
Units Granted 1,420    
Grant-Date Fair Value per Award $ 30.59    
Vesting percentage 100.00%    
XML 110 R87.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments - Summary of Status of Employees' Restricted Stock Unit Awards (Details 5) - Restricted Stock Units (RSU) - Employee - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Restricted Stock Units      
Nonvested, Beginning of Year 46,600 45,900 56,180
Granted 17,220 15,650 11,800
Reinstated 75
Vested 12,250 12,250 14,305
Forfeited 4,200 2,700 7,850
Nonvested, End of Year 47,370 46,600 45,900
Weighted Average Grant-Date Fair Value      
Nonvested, Beginning of Year $ 23.75 $ 21.82 $ 19.79
Granted 24.54 25.89 24.95
Reinstated     30.81
Vested 19.03 19.46 18.05
Forfeited 24.51 22.84 18.90
Nonvested, End of Year $ 25.19 $ 23.75 $ 21.82
Compensation Expense Recognized $ 307,000 $ 304,000 $ 194,000
Fair Value of Awards Vested $ 233,000 $ 238,000 $ 258,000
XML 111 R88.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments - Summary of Stock Performance Awards Granted and Amounts Expensed (Details 6) - Executive Officers - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Expense Recognized [1] $ 1,665,000 $ 434,000 $ 2,022,000
Earned Shares 233,982    
Performance Period 2016 To 2018      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share Awards Granted 122,250    
Shares Used To Estimate Expense 81,500    
Expense Recognized [1] $ 798,000    
Performance Period 2015 To 2017      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share Awards Granted 126,450    
Shares Used To Estimate Expense 84,300    
Expense Recognized [1] $ 535,000 943,000  
Performance Period 2014 To 2016      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share Awards Granted 159,450    
Shares Used To Estimate Expense 106,300    
Expense Recognized [1] $ 332,000 (64,000) 1,422,000
Earned Shares 121,491    
Performance Period 2013 To 2015      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share Awards Granted 90,600    
Shares Used To Estimate Expense 45,300    
Expense Recognized [1] (445,000) 458,000
Earned Shares 22,500    
Performance Period 2012 To 2014      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share Awards Granted 148,400    
Shares Used To Estimate Expense 74,200    
Expense Recognized [1] $ 142,000
Earned Shares 89,991    
[1] Expenses prior to 2016 are not restated to reflect what would have been expensed had the performance-to-date value of the outstanding awards been based on the grant-date fair value of the awards rather than the reporting-date fair value of the awards.
XML 112 R89.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments (Detail Textuals) - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Employee Stock Purchase Plan      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Discount from average market price to purchase shares 15.00%    
Investment period 6 months    
Stock compensation expense $ 173,000 $ 184,000 $ 175,000
1999 Stock Incentive Plan      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Number of options to purchase common stock 2,041,500    
XML 113 R90.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments (Detail Textuals 1) - Restricted Stock - $ / shares
 12 Months Ended
Feb. 04, 2016
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Director        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Shares/UnitsGranted   23,200 15,200 16,800
Forfeited  
Vesting percentage   25.00%    
Grant-Date Fair Value per Award   $ 28.66 $ 31.775 $ 29.41
Executive Officers | 2014 Stock Incentive Plan        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Shares/UnitsGranted 22,000      
Vesting percentage 25.00%      
Grant-Date Fair Value per Award $ 28.915      
XML 114 R91.htm IDEA: XBRL DOCUMENT v3.6.0.2
Share-Based Payments (Detail Textuals 2) - USD ($)
 12 Months Ended
Feb. 04, 2016
Dec. 31, 2016
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Unrecognized amount of compensation expense related to stock-based compensation   $ 4,000,000      
Weighted-average period of amortization   2 years 2 months 12 days      
Chief Executive Officer | Performance Period 2014 To 2016          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Issue price per share of earned shares issued $ 26.35        
Value of earned shares issued $ 848,000        
Payout target percentage 114.29%        
Chief Executive Officer | Performance Period 2012 To 2014          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Payout target percentage 121.28%        
Executive Officers | Performance Period 2015 To 2017          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted   126,450      
Executive Officers | Performance Period 2014 To 2016          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted   159,450      
Executive Officers | Performance Period 2013 To 2015          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted   90,600      
Issue price per share of earned shares issued $ 26.35        
Value of earned shares issued $ 593,000        
Executive Officers | Performance Period 2012 To 2014          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted   148,400      
Executive Officers | Performance Period 2016 To 2018          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted   122,250      
2014 Stock Incentive Plan          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted   1,900,000      
2014 Stock Incentive Plan | Stock Performance Awards | Executive Officers          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted 81,500        
Basis for achieving performance target, description Common shares for achieving the target set for the Company's 3-year average adjusted return on equity        
2014 Stock Incentive Plan | Stock Performance Awards | Executive Officers | Maximum          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Actual payment percentage of target amount 150.00%        
2014 Stock Incentive Plan | Stock Performance Awards | Executive Officers | Performance Target One          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted 54,333        
Basis for achieving performance target, description
Common shares based on the Company's total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2016 through December 31, 2018.
        
2014 Stock Incentive Plan | Stock Performance Awards | Executive Officers | Performance Target Two          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted 27,167        
Basis for achieving performance target, description
Common shares for achieving the target set for the Company's 3-year average adjusted return on equity.
        
2014 Stock Incentive Plan | Restricted Stock Units (RSU) | Executive Officers          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share Awards Granted     8,900 4,900 6,600
XML 115 R92.htm IDEA: XBRL DOCUMENT v3.6.0.2
Retained Earnings and Dividend Restriction (Detail Textuals) - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Retained Earnings Restriction [Line Items]    
Total Capitalization $ 1,175,445,000 $ 1,048,869,000
OTP    
Retained Earnings Restriction [Line Items]    
Equity to total capitalization ratio 52.90%  
Net assets restricted from distribution $ 440,000,000  
Total Capitalization $ 1,123,168,000  
OTP | Minimum    
Retained Earnings Restriction [Line Items]    
Required equity to total capitalization ratio to limit dividend payment 47.50%  
OTP | Maximum    
Retained Earnings Restriction [Line Items]    
Required equity to total capitalization ratio to limit dividend payment 58.10%  
XML 116 R93.htm IDEA: XBRL DOCUMENT v3.6.0.2
Commitments and Contingencies of Continuing Operations - Amounts of Commitments under Construction Programs, Capacity and Energy Requirements, Coal and Coal Delivery Contracts and Operating Leases (Details)
$ in Thousands
Dec. 31, 2016
USD ($)
Operating Leases  
2017 $ 7,134
2018 5,642
2019 3,835
2020 3,510
2021 3,099
Beyond 2021 16,716
Total 39,936
OTP  
Operating Leases  
2017 2,374
2018 1,513
2019 1,237
2020 1,251
2021 1,103
Beyond 2021 9,396
Total 16,874
OTP | Construction Program and Other Commitments  
Purchase Commitments  
2017 74,328
2018 7,139
2019 3,331
2020
2021
Beyond 2021
Total 84,798
OTP | Capacity and Energy Requirements  
Purchase Commitments  
2017 23,711
2018 24,356
2019 24,925
2020 24,844
2021 12,988
Beyond 2021 166,137
Total 276,961
OTP | Coal Purchase Commitments  
Purchase Commitments  
2017 30,699
2018 21,563
2019 22,102
2020 22,331
2021 22,840
Beyond 2021 550,719
Total 670,254
Nonelectric  
Operating Leases  
2017 4,760
2018 4,129
2019 2,598
2020 2,259
2021 1,996
Beyond 2021 7,320
Total $ 23,062
XML 117 R94.htm IDEA: XBRL DOCUMENT v3.6.0.2
Commitments and Contingencies of Continuing Operations (Detail Textuals) - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Commitments and Contingencies Disclosure [Line Items]      
Rent expense from continuing operations $ 7,565,000 $ 6,447,000 $ 10,165,000
Loss contingency, range of possible loss, maximum 1,000,000    
OTP | Construction Programs and Other Commitments      
Commitments and Contingencies Disclosure [Line Items]      
Commitment under contracts aggregate amount $ 84,800,000    
OTP | Capacity and Energy Requirements      
Commitments and Contingencies Disclosure [Line Items]      
Contracts expiration year 2017 and 2040    
OTP | Federal Energy Regulatory Commission      
Commitments and Contingencies Disclosure [Line Items]      
Estimated liability of refund obligation $ 2,700,000    
XML 118 R95.htm IDEA: XBRL DOCUMENT v3.6.0.2
Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Status of Lines of Credit (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Line of Credit Facility [Line Items]    
Line Limit $ 300,000  
In Use 42,883  
Restricted due to Outstanding Letters of Credit 50  
Available 257,067 $ 239,028
Otter Tail Corporation Credit Agreement    
Line of Credit Facility [Line Items]    
Line Limit 130,000  
In Use  
Restricted due to Outstanding Letters of Credit  
Available 130,000 90,334
OTP Credit Agreement    
Line of Credit Facility [Line Items]    
Line Limit 170,000  
In Use 42,883  
Restricted due to Outstanding Letters of Credit 50  
Available $ 127,067 $ 148,694
XML 119 R96.htm IDEA: XBRL DOCUMENT v3.6.0.2
Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Breakdown of Assignment of Company's Consolidated Short-Term and Long-Term Debt Outstanding (Details 1) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]    
Short-Term Debt $ 42,883 $ 80,672
Long-Term Debt 540,942 498,489
Less: Current Maturities - Otter Tail Corporation 33,201 52,422
Unamortized Long-Term Debt Issuance Costs 2,400 2,221
Total Long-Term Debt net of Unamortized Debt Issuance Costs 505,341 443,846
Total Short-Term and Long-Term Debt (with current maturities) 581,425 576,940
Term Loan, LIBOR plus 0.90%, due February 5, 2018    
Debt Instrument [Line Items]    
Long-Term Debt 15,000  
3.55% Guaranteed Senior Notes, due December 15, 2026    
Debt Instrument [Line Items]    
Long-Term Debt 80,000  
9.000% Notes, due December 15, 2016    
Debt Instrument [Line Items]    
Long-Term Debt   52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017    
Debt Instrument [Line Items]    
Long-Term Debt 33,000 33,000
Senior Unsecured Notes 4.63%, due December 1, 2021    
Debt Instrument [Line Items]    
Long-Term Debt 140,000 140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022    
Debt Instrument [Line Items]    
Long-Term Debt 30,000 30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027    
Debt Instrument [Line Items]    
Long-Term Debt 42,000 42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029    
Debt Instrument [Line Items]    
Long-Term Debt 60,000 60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037    
Debt Instrument [Line Items]    
Long-Term Debt 50,000 50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044    
Debt Instrument [Line Items]    
Long-Term Debt 90,000 90,000
North Dakota Development Note, 3.95%, due April 1, 2018    
Debt Instrument [Line Items]    
Long-Term Debt 106 182
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021    
Debt Instrument [Line Items]    
Long-Term Debt 836 977
OTP    
Debt Instrument [Line Items]    
Short-Term Debt 42,883 21,006
Long-Term Debt 445,000 445,000
Less: Current Maturities - Otter Tail Corporation 32,970
Unamortized Long-Term Debt Issuance Costs 1,861 2,099
Total Long-Term Debt net of Unamortized Debt Issuance Costs 410,169 442,901
Total Short-Term and Long-Term Debt (with current maturities) 486,022 463,907
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017    
Debt Instrument [Line Items]    
Long-Term Debt 33,000 33,000
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021    
Debt Instrument [Line Items]    
Long-Term Debt 140,000 140,000
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022    
Debt Instrument [Line Items]    
Long-Term Debt 30,000 30,000
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027    
Debt Instrument [Line Items]    
Long-Term Debt 42,000 42,000
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029    
Debt Instrument [Line Items]    
Long-Term Debt 60,000 60,000
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037    
Debt Instrument [Line Items]    
Long-Term Debt 50,000 50,000
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044    
Debt Instrument [Line Items]    
Long-Term Debt 90,000 90,000
OTTER TAIL CORPORATION    
Debt Instrument [Line Items]    
Short-Term Debt   59,666
Long-Term Debt 95,942 53,489
Less: Current Maturities - Otter Tail Corporation 231 52,422
Unamortized Long-Term Debt Issuance Costs 539 122
Total Long-Term Debt net of Unamortized Debt Issuance Costs 95,172 945
Total Short-Term and Long-Term Debt (with current maturities) 95,403 113,033
OTTER TAIL CORPORATION | Term Loan, LIBOR plus 0.90%, due February 5, 2018    
Debt Instrument [Line Items]    
Long-Term Debt 15,000  
OTTER TAIL CORPORATION | 3.55% Guaranteed Senior Notes, due December 15, 2026    
Debt Instrument [Line Items]    
Long-Term Debt 80,000  
OTTER TAIL CORPORATION | 9.000% Notes, due December 15, 2016    
Debt Instrument [Line Items]    
Long-Term Debt 52,330
OTTER TAIL CORPORATION | North Dakota Development Note, 3.95%, due April 1, 2018    
Debt Instrument [Line Items]    
Long-Term Debt 106 182
OTTER TAIL CORPORATION | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021    
Debt Instrument [Line Items]    
Long-Term Debt $ 836 $ 977
XML 120 R97.htm IDEA: XBRL DOCUMENT v3.6.0.2
Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Breakdown of Assignment of Company's Consolidated Short-Term and Long-Term Debt Outstanding (Parentheticals) (Details 1)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Term Loan, LIBOR plus 0.90%, due February 5, 2018    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 0.90%  
Long-Term Debt, Due Date Feb. 05, 2018  
3.55% Guaranteed Senior Notes, due December 15, 2026    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 3.55%  
Long-Term Debt, Due Date Dec. 15, 2026  
9.000% Notes, due December 15, 2016    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate   9.00%
Long-Term Debt, Due Date   Dec. 15, 2016
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 5.95% 5.95%
Long-Term Debt, Due Date Aug. 20, 2017 Aug. 20, 2017
Senior Unsecured Notes 4.63%, due December 1, 2021    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 4.63% 4.63%
Long-Term Debt, Due Date Dec. 01, 2021 Dec. 01, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 6.15% 6.15%
Long-Term Debt, Due Date Aug. 20, 2022 Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 6.37% 6.37%
Long-Term Debt, Due Date Aug. 20, 2027 Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 4.68% 4.68%
Long-Term Debt, Due Date Feb. 27, 2029 Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 6.47% 6.47%
Long-Term Debt, Due Date Aug. 20, 2037 Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 5.47% 5.47%
Long-Term Debt, Due Date Feb. 27, 2044 Feb. 27, 2044
North Dakota Development Note, 3.95%, due April 1, 2018    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 3.95% 3.95%
Long-Term Debt, Due Date Apr. 01, 2018 Apr. 01, 2018
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 2.54% 2.54%
Long-Term Debt, Due Date Mar. 18, 2021 Mar. 18, 2021
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 5.95% 5.95%
Long-Term Debt, Due Date Aug. 20, 2017 Aug. 20, 2017
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 4.63% 4.63%
Long-Term Debt, Due Date Dec. 01, 2021 Dec. 01, 2021
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 6.15% 6.15%
Long-Term Debt, Due Date Aug. 20, 2022 Aug. 20, 2022
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 6.37% 6.37%
Long-Term Debt, Due Date Aug. 20, 2027 Aug. 20, 2027
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 4.68% 4.68%
Long-Term Debt, Due Date Feb. 27, 2029 Feb. 27, 2029
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 6.47% 6.47%
Long-Term Debt, Due Date Aug. 20, 2037 Aug. 20, 2037
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 5.47% 5.47%
Long-Term Debt, Due Date Feb. 27, 2044 Feb. 27, 2044
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 0.90%  
Long-Term Debt, Due Date Feb. 05, 2018  
Otter Tail Corporation | 3.55% Guaranteed Senior Notes, due December 15, 2026    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 3.55%  
Long-Term Debt, Due Date Dec. 15, 2026  
Otter Tail Corporation | 9.000% Notes, due December 15, 2016    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 9.00% 9.00%
Long-Term Debt, Due Date Dec. 15, 2016 Dec. 15, 2016
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 3.95% 3.95%
Long-Term Debt, Due Date Apr. 01, 2018 Apr. 01, 2018
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021    
Debt Instrument [Line Items]    
Long-Term Debt, Interest Rate 2.54% 2.54%
Long-Term Debt, Due Date Mar. 18, 2021 Mar. 18, 2021
XML 121 R98.htm IDEA: XBRL DOCUMENT v3.6.0.2
Short-Term and Long-Term Borrowings and Preferred Stock Redemption - Aggregate Amounts of Maturities on Bonds Outstanding and Other Long-Term Obligations (Details 2)
$ in Thousands
Dec. 31, 2016
USD ($)
Debt Disclosure [Abstract]  
Aggregate amounts of debt maturities in 2017 $ 33,231
Aggregate amounts of debt maturities in 2018 15,187
Aggregate amounts of debt maturities in 2019 172
Aggregate amounts of debt maturities in 2020 185
Aggregate amounts of debt maturities in 2021 $ 140,171
XML 122 R99.htm IDEA: XBRL DOCUMENT v3.6.0.2
Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals) - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Oct. 29, 2012
Line of Credit Facility [Line Items]      
Maximum amount of debt outstanding $ 87,211,000    
Average daily balance of debt outstanding $ 48,776,000    
Weighted average interest rate paid on short-term debt 1.90%    
Line Limit $ 300,000,000    
Otter Tail Corporation Credit Agreement      
Line of Credit Facility [Line Items]      
Maximum amount of debt outstanding 63,757,000    
Average daily balance of debt outstanding $ 16,200,000    
Weighted average interest rate paid on short-term debt 2.30% 2.00%  
Line Limit $ 130,000,000    
Line of credit facility, description of variable rate basis LIBOR    
Line of credit facility, basis spread on variable rate 1.75%    
Otter Tail Corporation Credit Agreement | Unsecured revolving credit facility      
Line of Credit Facility [Line Items]      
Line Limit     $ 150,000,000
Line of credit facility, maximum borrowing capacity, subject to conditions     250,000,000
Reduced line of credit facility, borrowing capacity     40,000,000
OTP Credit Agreement      
Line of Credit Facility [Line Items]      
Maximum amount of debt outstanding $ 51,885,000    
Average daily balance of debt outstanding $ 32,576,000    
Weighted average interest rate paid on short-term debt 1.80% 1.50%  
Line Limit $ 170,000,000    
Line of credit facility, maximum amount of letters of credit outstanding at any time $ 50,000,000    
Line of credit facility, description of variable rate basis LIBOR    
Line of credit facility, basis spread on variable rate 1.25%    
OTP Credit Agreement | Revolving credit facility      
Line of Credit Facility [Line Items]      
Line Limit     170,000,000
Line of credit facility, maximum borrowing capacity, subject to conditions     $ 250,000,000
XML 123 R100.htm IDEA: XBRL DOCUMENT v3.6.0.2
Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 1) - USD ($)
 12 Months Ended
Dec. 31, 2016
Sep. 23, 2016
Dec. 31, 2015
9.000% Notes, due December 15, 2016      
Debt Instrument [Line Items]      
Debt instrument, interest rate     9.00%
3.55% Guaranteed Senior Notes, due December 15, 2026      
Debt Instrument [Line Items]      
Debt instrument, interest rate 3.55%    
2016 Note Purchase Agreement      
Debt Instrument [Line Items]      
Debt instrument description of prepayment The Company may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount.    
2016 Note Purchase Agreement | 9.000% Notes, due December 15, 2016      
Debt Instrument [Line Items]      
Repayments of Debt $ 52,330,000    
2016 Note Purchase Agreement | 3.55% Guaranteed Senior Notes, due December 15, 2026      
Debt Instrument [Line Items]      
Original debt issued, principal amount   $ 80,000,000  
Debt instrument, interest rate   3.55%  
Unsecured Term Loan | 2016 Note Purchase Agreement | February 2016 term loan agreement      
Debt Instrument [Line Items]      
Repayments of Debt $ 50,000,000    
XML 124 R101.htm IDEA: XBRL DOCUMENT v3.6.0.2
Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 2) - USD ($)
 12 Months Ended
Feb. 05, 2016
Dec. 31, 2016
Debt Instrument [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity   $ 300,000,000
Maximum amount of debt outstanding   $ 87,211,000
Term Loan Agreement | JPMorgan    
Debt Instrument [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity $ 50,000,000  
Minimum increments tranches of term loans 10,000,000  
Maximum amount of debt outstanding $ 100,000,000  
Interest rate base LIBOR plus 0.90%  
Borrowed amount $ 50,000,000  
Term Loan Agreement | JPMorgan | LIBOR    
Debt Instrument [Line Items]    
Debt Instrument, Description of Variable Rate Basis LIBOR  
Debt Instrument, Basis Spread on Variable Rate 0.90%  
Term Loan Agreement | JPMorgan | Prime Rate    
Debt Instrument [Line Items]    
Debt Instrument, Description of Variable Rate Basis Prime Rate  
Term Loan Agreement | JPMorgan | Federal Reserve Bank of New York Rate    
Debt Instrument [Line Items]    
Debt Instrument, Description of Variable Rate Basis Federal Reserve Bank of New York Rate  
Debt Instrument, Basis Spread on Variable Rate 0.50%  
Term Loan Agreement | JPMorgan | Statutory Reserve Rate    
Debt Instrument [Line Items]    
Debt Instrument, Description of Variable Rate Basis LIBOR multiplied by the Statutory Reserve Rate  
Debt Instrument, Basis Spread on Variable Rate 1.00%  
XML 125 R102.htm IDEA: XBRL DOCUMENT v3.6.0.2
Short-Term and Long-Term Borrowings and Preferred Stock Redemption (Detail Textuals 3) - USD ($)
$ in Millions
 12 Months Ended
Aug. 14, 2013
Dec. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]      
Financial covenants of debt  
Financial Covenants The Company and OTP were in compliance with the financial covenants in these debt agreements as of December 31, 2016. No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies. The Company's and OTP's borrowing agreements are subject to certain financial covenants. Specifically:· Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, the Company may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis) as provided in the agreements.· Under the 2016 Note Purchase Agreement, the Company may not permit its Priority Indebtedness to exceed 10% of its Total Capitalization. The Company had no Priority Indebtedness outstanding as of December 31, 2016.· Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.· Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement.· Under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement. OTP had no Priority Indebtedness outstanding as of December 31, 2016.
  
Senior Unsecured Notes 4.63%, due December 1, 2021      
Debt Instrument [Line Items]      
Debt instrument, interest rate   4.63% 4.63%
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017      
Debt Instrument [Line Items]      
Debt instrument, interest rate   5.95% 5.95%
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022      
Debt Instrument [Line Items]      
Debt instrument, interest rate   6.15% 6.15%
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027      
Debt Instrument [Line Items]      
Debt instrument, interest rate   6.37% 6.37%
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037      
Debt Instrument [Line Items]      
Debt instrument, interest rate   6.47% 6.47%
Note Purchase Agreement 2013      
Debt Instrument [Line Items]      
Interest bearing debt, maximum percentage of total capitalization   60.00%  
Priority debt to total capitalization   20.00%  
2007 and 2011 Note Purchase Agreements      
Debt Instrument [Line Items]      
Priority debt to total capitalization   20.00%  
2007 and 2011 Note Purchase Agreements | Minimum      
Debt Instrument [Line Items]      
Debt to total capitalization ratio   0.60  
Interest and dividend coverage ratio   1.00  
2007 and 2011 Note Purchase Agreements | Maximum      
Debt Instrument [Line Items]      
Debt to total capitalization ratio   1.00  
Interest and dividend coverage ratio   1.50  
Otter Tail Corporation Credit Agreement | Minimum      
Debt Instrument [Line Items]      
Debt to total capitalization ratio   0.60  
Interest and dividend coverage ratio   1.00  
Otter Tail Corporation Credit Agreement | Maximum      
Debt Instrument [Line Items]      
Debt to total capitalization ratio   1.00  
Interest and dividend coverage ratio   1.50  
2016 Note Purchase Agreement      
Debt Instrument [Line Items]      
Debt instrument description of prepayment   The Company may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount.  
Priority debt to total capitalization   10.00%  
OTP Credit Agreement | Minimum      
Debt Instrument [Line Items]      
Debt to total capitalization ratio   0.60  
OTP Credit Agreement | Maximum      
Debt Instrument [Line Items]      
Debt to total capitalization ratio   1.00  
Otter Tail Power Company | Senior Unsecured Notes 4.63%, due December 1, 2021      
Debt Instrument [Line Items]      
Debt instrument, interest rate   4.63% 4.63%
Otter Tail Power Company | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017      
Debt Instrument [Line Items]      
Debt instrument, interest rate   5.95% 5.95%
Otter Tail Power Company | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022      
Debt Instrument [Line Items]      
Debt instrument, interest rate   6.15% 6.15%
Otter Tail Power Company | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027      
Debt Instrument [Line Items]      
Debt instrument, interest rate   6.37% 6.37%
Otter Tail Power Company | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037      
Debt Instrument [Line Items]      
Debt instrument, interest rate   6.47% 6.47%
Otter Tail Power Company | Note Purchase Agreement 2013      
Debt Instrument [Line Items]      
Debt instrument description of prepayment   The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount.  
Otter Tail Power Company | Note Purchase Agreement 2013 | Series A Senior Unsecured Notes due on February 27, 2029      
Debt Instrument [Line Items]      
Aggregate principal amount of note $ 60.0    
Debt instrument, interest rate 4.68%    
Otter Tail Power Company | Note Purchase Agreement 2013 | Series B Senior Unsecured Notes due on February 27, 2044      
Debt Instrument [Line Items]      
Aggregate principal amount of note $ 90.0    
Debt instrument, interest rate 5.47%    
Portion of proceeds used to retire outstanding term loan $ 40.9    
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 4.63%, due December 1, 2021      
Debt Instrument [Line Items]      
Aggregate principal amount of note   $ 140.0  
Debt instrument, interest rate   4.63%  
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017      
Debt Instrument [Line Items]      
Aggregate principal amount of note   $ 33.0  
Debt instrument, interest rate   5.95%  
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022      
Debt Instrument [Line Items]      
Aggregate principal amount of note   $ 30.0  
Debt instrument, interest rate   6.15%  
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027      
Debt Instrument [Line Items]      
Aggregate principal amount of note   $ 42.0  
Debt instrument, interest rate   6.37%  
Otter Tail Power Company | Note Purchase Agreement 2011 | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037      
Debt Instrument [Line Items]      
Aggregate principal amount of note   $ 50.0  
Debt instrument, interest rate   6.47%  
Otter Tail Power Company | Note Purchase Agreement 2011 | Unsecured Senior Notes      
Debt Instrument [Line Items]      
Aggregate principal amount of note   $ 155.0  
Otter Tail Power Company | 2007 and 2011 Note Purchase Agreements      
Debt Instrument [Line Items]      
Debt instrument description of prepayment   The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount.  
XML 126 R103.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Service Cost-Benefit Earned During the Period $ 5,518 $ 6,059 $ 4,666
Interest Cost on Projected Benefit Obligation 14,195 13,344 13,111
Expected Return on Assets (19,454) (18,383) (16,743)
Amortization of Prior Service Cost:      
From Regulatory Asset 189 188 257
From Other Comprehensive Income [1] 5 5 7
Amortization of Net Actuarial Loss:      
From Regulatory Asset 5,153 6,676 3,400
From Other Comprehensive Income [1] 127 171 83
Net Periodic Cost 5,733 8,060 4,781
Executive Survivor and Supplemental Retirement Plan (ESSRP)      
Defined Benefit Plan Disclosure [Line Items]      
Service Cost-Benefit Earned During the Period 252 189 51
Interest Cost on Projected Benefit Obligation 1,667 1,523 1,520
Amortization of Prior Service Cost:      
From Regulatory Asset 16 16 22
From Other Comprehensive Income [2] 38 38 51
Amortization of Net Actuarial Loss:      
From Regulatory Asset 293 334 142
From Other Comprehensive Income [3] 446 602 46
Net Periodic Cost 2,712 2,702 1,832
Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Service Cost (Net of Medicare Part D Subsidy) 1,301 1,297 1,055
Interest Cost (Net of Medicare Part D Subsidy) 2,503 2,097 2,200
Amortization of Prior Service Cost:      
From Regulatory Asset 134 205 205
From Other Comprehensive Income [1] 3 5 5
Amortization of Net Actuarial Loss:      
From Regulatory Asset 379
From Other Comprehensive Income [1] 9
Net Periodic Cost 4,329 3,604 3,465
Effect of Medicare Part D Subsidy $ (923) $ (1,487) $ (948)
[1] Corporate cost included in Other Nonelectric Expenses.
[2] Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 15 $ 15 $ 20 Other Nonelectric Expenses 23 23 31
[3] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 272 $ 310 $ 132 Other Nonelectric Expenses 174 292 (86)
XML 127 R104.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Parentheticals) (Details) - Executive Survivor and Supplemental Retirement Plan (ESSRP) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]      
Amortization of Prior Service Costs from Other Comprehensive Income [1] $ 38 $ 38 $ 51
Amortization of Net Actuarial Loss from Other Comprehensive Income [2] 446 602 46
Electric Operation and Maintenance Expenses      
Defined Benefit Plan Disclosure [Line Items]      
Amortization of Prior Service Costs from Other Comprehensive Income 15 15 20
Amortization of Net Actuarial Loss from Other Comprehensive Income 272 310 132
Other Nonelectric Expenses      
Defined Benefit Plan Disclosure [Line Items]      
Amortization of Prior Service Costs from Other Comprehensive Income 23 23 31
Amortization of Net Actuarial Loss from Other Comprehensive Income $ 174 $ 292 $ (86)
[1] Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 15 $ 15 $ 20 Other Nonelectric Expenses 23 23 31
[2] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and MaintenanceExpenses $ 272 $ 310 $ 132 Other Nonelectric Expenses 174 292 (86)
XML 128 R105.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost (Details 1)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Discount Rate 4.76% 4.35% 5.30%
Long-Term Rate of Return on Plan Assets 7.75% 7.75% 7.75%
Rate of Increase in Future Compensation Level 3.13% 3.13% 3.13%
Executive Survivor and Supplemental Retirement Plan (ESSRP)      
Defined Benefit Plan Disclosure [Line Items]      
Discount Rate 4.76% 4.35% 5.30%
Rate of Increase in Future Compensation Level 3.13% 3.15% 3.18%
Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Discount Rate 4.57% 4.20% 5.10%
XML 129 R106.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Amounts Recognized in Consolidated Balance Sheets (Details 2) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Pension Plan      
Regulatory Assets:      
Unrecognized Prior Service Cost $ 141 $ 329  
Unrecognized Actuarial Loss 98,039 101,974  
Total Regulatory Assets 98,180 102,303  
Projected Benefit Obligation Liability - Net Amount Recognized (314,637) (302,740) $ (311,650)
Accumulated Other Comprehensive Loss:      
Unrecognized Prior Service Cost 12 16  
Unrecognized Actuarial Loss (Gain) 406 820  
Total Accumulated Other Comprehensive Loss 418 836  
Noncurrent Liability 60,292 69,101  
Executive Survivor and Supplemental Retirement Plan (ESSRP)      
Regulatory Assets:      
Unrecognized Prior Service Cost 58 75  
Unrecognized Actuarial Loss 2,890 2,936  
Total Regulatory Assets 2,948 3,011  
Projected Benefit Obligation Liability - Net Amount Recognized (37,335) (35,811) (35,650)
Accumulated Other Comprehensive Loss:      
Unrecognized Prior Service Cost 134 172  
Unrecognized Actuarial Loss (Gain) 5,915 5,815  
Total Accumulated Other Comprehensive Loss 6,049 5,987  
Other Postretirement Benefits      
Regulatory Assets:      
Unrecognized Prior Service Cost (4) 129  
Unrecognized Actuarial Loss 13,586 1,289  
Total Regulatory Assets 13,582 1,418  
Projected Benefit Obligation Liability - Net Amount Recognized (62,571) (48,730) $ (53,638)
Accumulated Other Comprehensive Loss:      
Unrecognized Prior Service Cost 4 8  
Unrecognized Actuarial Loss (Gain) (171) (347)  
Total Accumulated Other Comprehensive Loss $ (167) $ (339)  
XML 130 R107.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Funded Status (Details 3) - Pension Plan - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]      
Accumulated Benefit Obligation $ (281,414) $ (268,387)  
Projected Benefit Obligation (314,637) (302,740) $ (311,650)
Fair Value of Plan Assets 254,345 233,639 $ 244,589
Funded Status $ (60,292) $ (69,101)  
XML 131 R108.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Reconciliation of Changes in Fair Value of Plan Assets and Plan's Benefit Obligations (Details 4) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Pension Plan      
Reconciliation of Fair Value of Plan Assets:      
Fair Value of Plan Assets at January 1 $ 233,639 $ 244,589  
Actual Return on Plan Assets 23,794 (9,160)  
Discretionary Company Contributions 10,000 10,000  
Benefit Payments (13,088) (11,790)  
Fair Value of Plan Assets at December 31 $ 254,345 $ 233,639 $ 244,589
Estimated Asset Return 10.10% (3.70%)  
Reconciliation of Projected Benefit Obligation:      
Projected Benefit Obligation at January 1 $ 302,740 $ 311,650  
Service Cost 5,518 6,059 4,666
Interest Cost 14,195 13,344 13,111
Benefit Payments (13,088) (11,790)  
Actuarial (Gain) Loss 5,272 (16,523)  
Projected Benefit Obligation at December 31 314,637 302,740 311,650
Reconciliation of Accrued Postretirement Cost:      
Expense (5,733) (8,060) (4,781)
Executive Survivor and Supplemental Retirement Plan (ESSRP)      
Reconciliation of Fair Value of Plan Assets:      
Fair Value of Plan Assets at January 1  
Actual Return on Plan Assets  
Employer Contributions 1,188 1,119  
Benefit Payments (1,188) (1,119)  
Fair Value of Plan Assets at December 31
Reconciliation of Projected Benefit Obligation:      
Projected Benefit Obligation at January 1 35,811 35,650  
Service Cost 252 189 51
Interest Cost 1,667 1,523 1,520
Benefit Payments (1,188) (1,119)  
Plan Amendments    
Actuarial (Gain) Loss 793 (432)  
Projected Benefit Obligation at December 31 37,335 35,811 35,650
Reconciliation of Accrued Postretirement Cost:      
Expense (2,712) (2,702) (1,832)
Employer Contributions 1,188 1,119  
Other Postretirement Benefits      
Reconciliation of Fair Value of Plan Assets:      
Fair Value of Plan Assets at January 1  
Actual Return on Plan Assets  
Employer Contributions 2,825 2,365  
Benefit Payments (Net of Medicare Part D Subsidy) (5,908) (5,324)  
Participant Premium Payments 3,083 2,959  
Fair Value of Plan Assets at December 31
Reconciliation of Projected Benefit Obligation:      
Projected Benefit Obligation at January 1 48,730 53,638  
Service Cost (Net of Medicare Part D Subsidy) 1,301 1,297 1,055
Interest Cost (Net of Medicare Part D Subsidy) 2,503 2,097 2,200
Benefit Payments (Net of Medicare Part D Subsidy) (5,908) (5,324)  
Participant Premium Payments 3,083 2,959  
Actuarial (Gain) Loss 12,862 (5,937)  
Projected Benefit Obligation at December 31 62,571 48,730 53,638
Reconciliation of Accrued Postretirement Cost:      
Accrued Postretirement Cost at January 1 (47,652) (46,413)  
Expense (4,329) (3,604) (3,465)
Employer Contributions 2,825 2,365  
Accrued Postretirement Cost at December 31 $ (49,156) $ (47,652) $ (46,413)
XML 132 R109.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Weighted-Average Assumptions Used to Determine Benefit Obligations (Details 5)
Dec. 31, 2016
Dec. 31, 2015
Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Discount Rate 4.60% 4.76%
Rate of Increase in Future Compensation Level 3.00% 3.13%
Executive Survivor and Supplemental Retirement Plan (ESSRP)    
Defined Benefit Plan Disclosure [Line Items]    
Discount Rate 4.60% 4.76%
Rate of Increase in Future Compensation Level 3.00% 3.13%
Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Discount Rate 4.46% 4.57%
XML 133 R110.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Measurement Dates (Details 6)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Pension Plan    
Defined Benefit Plan Disclosure [Line Items]    
Net Periodic Pension Cost Jan. 01, 2016 Jan. 01, 2015
Market Value of Assets Dec. 31, 2016 Dec. 31, 2015
Pension Plan | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
End of Year Benefit Obligations Jan. 01, 2016 Jan. 01, 2015
Pension Plan | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
End of Year Benefit Obligations Dec. 31, 2016 Dec. 31, 2015
Other Postretirement Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Net Periodic Pension Cost Jan. 01, 2016 Jan. 01, 2015
Other Postretirement Benefits | Minimum    
Defined Benefit Plan Disclosure [Line Items]    
End of Year Benefit Obligations Jan. 01, 2016 Jan. 01, 2015
Other Postretirement Benefits | Maximum    
Defined Benefit Plan Disclosure [Line Items]    
End of Year Benefit Obligations Dec. 31, 2016 Dec. 31, 2015
XML 134 R111.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Estimated Amounts of Unrecognized Net Actuarial Losses and Prior Service Costs to be Amortized (Details 7)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
USD ($)
Pension Plan  
Decrease in Regulatory Assets:  
Amortization of Unrecognized Prior Service Cost $ 120
Amortization of Unrecognized Actuarial Loss 5,090
Decrease in Accumulated Other Comprehensive Loss:  
Amortization of Unrecognized Prior Service Cost 3
Amortization of Unrecognized Actuarial Loss 125
Total Estimated Amortization 5,338
Executive Survivor and Supplemental Retirement Plan (ESSRP)  
Decrease in Regulatory Assets:  
Amortization of Unrecognized Prior Service Cost 16
Amortization of Unrecognized Actuarial Loss 285
Decrease in Accumulated Other Comprehensive Loss:  
Amortization of Unrecognized Prior Service Cost 38
Amortization of Unrecognized Actuarial Loss 440
Total Estimated Amortization 779
Other Postretirement Benefits  
Decrease in Regulatory Assets:  
Amortization of Unrecognized Prior Service Cost
Amortization of Unrecognized Actuarial Loss 932
Decrease in Accumulated Other Comprehensive Loss:  
Amortization of Unrecognized Prior Service Cost
Amortization of Unrecognized Actuarial Loss 23
Total Estimated Amortization $ 955
XML 135 R112.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Benefit Payments, which Reflect Expected Future Service, as Appropriate, Expected to be Paid out from Plan Assets (Details 8)
$ in Thousands
Dec. 31, 2016
USD ($)
Pension Plan  
Defined Benefit Plan Disclosure [Line Items]  
2017 $ 13,413
2018 14,140
2019 14,806
2020 15,564
2021 16,335
Years 2022-2026 92,083
Executive Survivor and Supplemental Retirement Plan (ESSRP)  
Defined Benefit Plan Disclosure [Line Items]  
2017 1,253
2018 1,487
2019 1,562
2020 1,544
2021 1,754
Years 2022-2026 12,700
Other Postretirement Benefits  
Defined Benefit Plan Disclosure [Line Items]  
2017 3,512
2018 3,669
2019 3,828
2020 3,912
2021 4,046
Years 2022-2026 $ 20,377
XML 136 R113.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - The policy of the Plan is to invest assets in accordance with the allocations (Details 9) - Pension Plan
 12 Months Ended
Dec. 31, 2016
Equity | less than 100% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 30.00%
Equity | less than 100% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 65.00%
Equity | 100% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 25.00%
Equity | 100% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 60.00%
Equity | 105% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 20.00%
Equity | 105% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 55.00%
Equity | >=110% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 15.00%
Equity | >=110% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 50.00%
Investment Grade Fixed Income | less than 100% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 35.00%
Investment Grade Fixed Income | less than 100% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 75.00%
Investment Grade Fixed Income | 100% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 40.00%
Investment Grade Fixed Income | 100% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 80.00%
Investment Grade Fixed Income | 105% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 45.00%
Investment Grade Fixed Income | 105% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 85.00%
Investment Grade Fixed Income | >=110% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 50.00%
Investment Grade Fixed Income | >=110% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 90.00%
Below Investment Grade Fixed Income | less than 100% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 0.00% [1]
Below Investment Grade Fixed Income | less than 100% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 15.00% [1]
Below Investment Grade Fixed Income | 100% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 0.00% [1]
Below Investment Grade Fixed Income | 100% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 15.00% [1]
Below Investment Grade Fixed Income | 105% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 0.00% [1]
Below Investment Grade Fixed Income | 105% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 15.00% [1]
Below Investment Grade Fixed Income | >=110% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 0.00% [1]
Below Investment Grade Fixed Income | >=110% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 15.00% [1]
Other | less than 100% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 0.00% [2]
Other | less than 100% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 20.00% [2]
Other | 100% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 0.00% [2]
Other | 100% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 20.00% [2]
Other | 105% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 0.00% [2]
Other | 105% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 20.00% [2]
Other | >=110% PBO | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 0.00% [2]
Other | >=110% PBO | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Asset Allocation 20.00% [2]
[1] Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds.
[2] Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund.
XML 137 R114.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Pension Plan Asset Allocations by Asset Category (Details 10) - Pension Plan
Dec. 31, 2016
Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Actual Plan Asset Allocations 100.00% 100.00%
Equity Securities    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Actual Plan Asset Allocations 57.80% 56.50%
Large Capitalization Equity Securities    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Actual Plan Asset Allocations 21.40% 21.20%
International Equity Securities    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Actual Plan Asset Allocations 22.00% 21.60%
Small and Mid-Capitalization Equity Securities    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Actual Plan Asset Allocations 9.00% 8.10%
SEI Dynamic Asset Allocation Fund    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Actual Plan Asset Allocations 5.40% 5.60%
Fixed-Income Securities and Cash    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Actual Plan Asset Allocations 34.30% 35.80%
Other - SEI Energy Debt Collective Fund    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Actual Plan Asset Allocations 4.10% 3.60%
Other - SEI Special Situation Collective Investment Trust    
Defined Benefit Plan Disclosure [Line Items]    
Defined Benefit Plan, Actual Plan Asset Allocations 3.80% 4.10%
XML 138 R115.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Pension Fund Assets Measured at Fair Value and NAV (Details 11) - Pension Plan - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]      
Assets in Level 1 of the Fair Value Hierarchy $ 234,303 $ 215,676  
SEI Energy Debt Collective Fund at NAV 10,441 8,342  
SEI Special Situation Collective Investment Trust Fund at NAV [1] 9,601 9,621  
Total Assets $ 254,345 $ 233,639 $ 244,589
[1] On December 30, 2016 the Company instructed the pension fund manager to sell the pension fund investment in the SEI Special Situation Collective Investment Trust Fund. The cash value of the investment on settlement of the sale in January 2017 was $9,679,000.
XML 139 R116.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Pension Fund Assets Measured at Fair Value and NAV (Parenthetical)(Details 11)
 12 Months Ended
Dec. 31, 2016
USD ($)
Pension Plan  
Defined Benefit Plan Disclosure [Line Items]  
Cash value of investment on settlement $ 9,679,000
XML 140 R117.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Pension Fund Assets Measured at Fair Value (Details 12) - Pension Plan - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]      
Total Assets $ 254,345 $ 233,639 $ 244,589
Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Total Assets 234,303 215,676  
Level 1 | Large Capitalization Equity Securities Mutual Fund      
Defined Benefit Plan Disclosure [Line Items]      
Total Assets 54,483 49,513  
Level 1 | International Equity Securities Mutual Funds      
Defined Benefit Plan Disclosure [Line Items]      
Total Assets 55,916 50,504  
Level 1 | Small and Mid-Capitalization Equity Securities Mutual Fund      
Defined Benefit Plan Disclosure [Line Items]      
Total Assets 23,011 18,823  
Level 1 | SEI Dynamic Asset Allocation Mutual Fund      
Defined Benefit Plan Disclosure [Line Items]      
Total Assets 13,622 13,004  
Level 1 | Fixed Income Securities Mutual Funds      
Defined Benefit Plan Disclosure [Line Items]      
Total Assets 87,268 83,830  
Level 1 | Cash Management - Money Market Fund      
Defined Benefit Plan Disclosure [Line Items]      
Total Assets $ 3 $ 2  
XML 141 R118.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Healthcare Cost-Trend Rates (Details 13) - Other Postretirement Benefits
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]    
Rate to Which the Cost-Trend Rate is Assumed to Decline 4.50% 4.50%
Year the Rate Reaches the Ultimate Trend Rate 2038 2038
Pre-65    
Defined Benefit Plan Disclosure [Line Items]    
Healthcare Cost-Trend Rate Assumed for Next Year 6.01% 6.16%
Post-65    
Defined Benefit Plan Disclosure [Line Items]    
Healthcare Cost-Trend Rate Assumed for Next Year 6.23% 6.43%
XML 142 R119.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits - Effects of One Percentage Change in Assumed healthcare Cost-Trend Rates (Details 14) - Other Postretirement Benefits
$ in Thousands
 12 Months Ended
Dec. 31, 2016
USD ($)
Defined Benefit Plan Disclosure [Line Items]  
Effect of 1 point increase on the Postretirement Benefit Obligation $ 7,151
Effect of 1 point increase on Total of Service and Interest Cost 653
Effect of 1 point increase on Expense 1,454
Effect of 1 point decrease on the Postretirement Benefit Obligation (7,492)
Effect of 1 point decrease on Total of Service and Interest Cost (519)
Effect of 1 point decrease on Expense $ (907)
XML 143 R120.htm IDEA: XBRL DOCUMENT v3.6.0.2
Pension Plan and Other Postretirement Benefits (Detail Textuals) - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]      
Contributions made to 401K plan by the companies $ 3,877,000 $ 3,602,000 $ 3,171,000
Contributions made by the company to employee stock ownership plan $ 647,000 $ 674,000 $ 696,000
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined benefit plan, vesting percentage 100.00%    
Defined benefit plan vesting period 5 years    
Assumed rate of return on pension fund assets for the determination of 2017 net periodic pension cost 7.50%    
Pension Plan | SEI Energy Debt Fund      
Defined Benefit Plan Disclosure [Line Items]      
Amount invested in pension fund assets $ 10,000,000    
Executive Survivor and Supplemental Retirement Plan (ESSRP)      
Defined Benefit Plan Disclosure [Line Items]      
Period of benefit payments to the beneficiaries on their deaths 15 years    
Other Postretirement Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Health insurance benefits, requisite age 55 years    
Health insurance benefits, requisite service period 10 years    
Estimated future employer contributions in the next fiscal year $ 3,500,000    
Medicare part D subsidy expected to received in 2017 $ 416,000    
XML 144 R121.htm IDEA: XBRL DOCUMENT v3.6.0.2
Fair Value of Financial Instruments - Long-term debt including current maturities (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Carrying Amount    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Cash and Cash Equivalents
Short-Term Debt (42,883) (80,672)
Long-Term Debt including Current Maturities (538,542) (496,268)
Fair Value    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Cash and Cash Equivalents
Short-Term Debt (42,883) (80,672)
Long-Term Debt including Current Maturities $ (583,835) $ (561,245)
XML 145 R122.htm IDEA: XBRL DOCUMENT v3.6.0.2
Fair Value of Financial Instruments (Detail Textuals)
 12 Months Ended
Dec. 31, 2016
Otter Tail Corporation Credit Agreement  
Fair Value Of Financial Instruments [Line Items]  
Line of credit facility, description of variable rate basis LIBOR
Basis spread on variable rate 1.75%
OTP Credit Agreement  
Fair Value Of Financial Instruments [Line Items]  
Line of credit facility, description of variable rate basis LIBOR
Basis spread on variable rate 1.25%
XML 146 R123.htm IDEA: XBRL DOCUMENT v3.6.0.2
Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Property, Plant and Equipment [Line Items]    
Total Gross Plant $ 2,225,444 $ 2,101,718
Less Accumulated Depreciation and Amortization 748,219 713,904
Net Plant 1,477,225 1,387,814
Electric Plant    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 2,010,354 1,884,880
Less Accumulated Depreciation and Amortization 622,657 592,001
Net Plant 1,387,697 1,292,879
Electric Plant | Production Plant    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 891,330 879,121
Electric Plant | Transmission Plant    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 410,679 391,941
Electric Plant | Distribution Plant    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 466,285 451,820
Electric Plant | General Plant    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 92,063 97,881
Electric Plant | Electric Plant In Service    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 1,860,357 1,820,763
Electric Plant | Construction In Progress    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 149,997 64,117
Nonelectric Plant    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 215,090 216,838
Less Accumulated Depreciation and Amortization 125,562 121,903
Net Plant 89,528 94,935
Nonelectric Plant | Equipment    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 155,809 155,715
Nonelectric Plant | Buildings And Leasehold Improvements    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 51,323 41,149
Nonelectric Plant | Land    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 4,694 4,479
Nonelectric Plant | Nonelectric Operations Plant    
Property, Plant and Equipment [Line Items]    
Total Gross Plant 211,826 201,343
Nonelectric Plant | Construction In Progress    
Property, Plant and Equipment [Line Items]    
Total Gross Plant $ 3,264 $ 15,495
XML 147 R124.htm IDEA: XBRL DOCUMENT v3.6.0.2
Property, Plant and Equipment - Estimated Service Lives for Properties (Details 1)
 12 Months Ended
Dec. 31, 2016
Electric Plant | Minimum  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 5 years
Electric Plant | Minimum | Production Plant  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 9 years
Electric Plant | Minimum | Transmission Plant  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 42 years
Electric Plant | Minimum | Distribution Plant  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 5 years
Electric Plant | Minimum | General Plant  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 5 years
Electric Plant | Maximum  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 82 years
Electric Plant | Maximum | Production Plant  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 82 years
Electric Plant | Maximum | Transmission Plant  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 70 years
Electric Plant | Maximum | Distribution Plant  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 68 years
Electric Plant | Maximum | General Plant  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 50 years
Nonelectric Plant | Minimum  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 3 years
Nonelectric Plant | Minimum | Equipment  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 3 years
Nonelectric Plant | Minimum | Buildings And Leasehold Improvements  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 7 years
Nonelectric Plant | Maximum  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 40 years
Nonelectric Plant | Maximum | Equipment  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 12 years
Nonelectric Plant | Maximum | Buildings And Leasehold Improvements  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 40 years
XML 148 R125.htm IDEA: XBRL DOCUMENT v3.6.0.2
Property, Plant and Equipment (Detail Textuals)
 12 Months Ended
Dec. 31, 2016
Electric Plant | Minimum  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 5 years
Electric Plant | Maximum  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 82 years
Nonelectric Plant | Minimum  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 3 years
Nonelectric Plant | Maximum  
Property, Plant and Equipment [Line Items]  
Property, Plant and Equipment, Useful Life 40 years
XML 149 R126.htm IDEA: XBRL DOCUMENT v3.6.0.2
Income Taxes - Reconciliation of Income Tax Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Tax Disclosure [Abstract]      
Tax Computed at Federal Statutory Rate - Continuing Operations $ 28,741 $ 28,081 $ 25,704
Increases (Decreases) in Tax from:      
Federal PTCs (7,175) (6,962) (7,517)
State Income Taxes Net of Federal Income Tax Expense 2,848 4,945 1,993
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes (850) (850) (849)
Corporate-owned Life Insurance (680) (167) (354)
Dividend Received/Paid Deduction (537) (560) (622)
Section 199 Domestic Production Activities Deduction (482) (1,026)
Investment Tax Credit Amortization (350) (571) (597)
Allowance for Funds Used During Construction - Equity (280) (426) (505)
Differences Reversing in Excess of Federal Rates 77 (1,143) (106)
Permanent and Other Differences (1,231) (705) 436
Total Income Tax Expense - Continuing Operations 20,081 21,642 16,557
Income Tax Expense - Discontinued Operations - U.S. 138 2,991 3,952
Income Tax Expense - Continuing and Discontinued Operations $ 20,219 $ 24,633 $ 20,509
Overall Effective Federal, State and Foreign Income Tax Rate 24.50% 29.30% 26.20%
XML 150 R127.htm IDEA: XBRL DOCUMENT v3.6.0.2
Income Taxes - Components of Income tax expense (Details 1) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Tax Expense From Continuing Operations Includes the Following:      
Current Federal Income Taxes $ 1,070 $ 211 $ 124
Current State Income Taxes 1,211 1 5
Deferred Federal Income Taxes 23,586 23,050 21,044
Deferred State Income Taxes 2,589 6,763 4,347
Federal PTCs (7,175) (6,962) (7,517)
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes (850) (850) (849)
Investment Tax Credit Amortization (350) (571) (597)
Total Income Tax Expense - Continuing Operations 20,081 21,642 16,557
Total Income Before Income Taxes - Continuing and Discontinued Operations $ 82,540 $ 83,978 $ 78,232
XML 151 R128.htm IDEA: XBRL DOCUMENT v3.6.0.2
Income Taxes - Deferred Tax Assets and Liabilities (Details 2) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Deferred Tax Assets    
Benefit Liabilities $ 44,381 $ 41,788
Federal PTCs 43,433 39,505
Retirement Benefits Liabilities 38,390 41,958
North Dakota Wind Tax Credits 32,962 32,962
Cost of Removal 31,636 29,463
Differences Related to Property 9,876 10,177
Net Operating Loss Carryforward 3,865 22,824
Vacation Accrual 2,725 2,500
Investment Tax Credits 818 1,109
Other 7,793 7,617
Total Deferred Tax Assets 215,879 229,903
Deferred Tax Liabilities    
Differences Related to Property (371,761) (366,234)
Retirement Benefits Regulatory Asset (38,390) (41,958)
Excess Tax over Book Pension (15,509) (13,775)
North Dakota Wind Tax Credits (3,654) (3,179)
Impact of State Net Operating Losses on Federal Taxes (1,352) (1,596)
Other (11,804) (10,830)
Total Deferred Tax Liabilities (442,470) (437,572)
Deferred Income Taxes $ (226,591) $ (207,669)
XML 152 R129.htm IDEA: XBRL DOCUMENT v3.6.0.2
Income Taxes - Expiration of Tax Net Operating Losses and Tax Credits Available (Details 3)
$ in Thousands
Dec. 31, 2016
USD ($)
Federal Net Operating Losses  
Net Operating Loss Carryforward [Abstract]  
Net Operating Losses, Amount
Net Operating Losses, Year of Expiration 2017
Net Operating Losses, Year of Expiration 2027-36
State Net Operating Losses  
Net Operating Loss Carryforward [Abstract]  
Net Operating Losses, Amount 3,865
Net Operating Losses, Year of Expiration 2017
Net Operating Losses, Year of Expiration 2027-36 3,865
Federal Tax Credits  
Tax Credit Carryforward [Abstract]  
Tax Credits, Amount 46,435
Tax Credits, Year of Expiration 2017
Tax Credits, Year of Expiration 2027-36 46,435
State Tax Credits  
Tax Credit Carryforward [Abstract]  
Tax Credits, Amount 33,993
Tax Credits, Year of Expiration 2017 389
Tax Credits, Year of Expiration 2027-36 $ 33,604
XML 153 R130.htm IDEA: XBRL DOCUMENT v3.6.0.2
Income Taxes - Summary of Activity Related to Unrecognized Tax benefit (Details 4) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]      
Balance on January 1 $ 468 $ 222 $ 4,239
Increases Related to Tax Positions for Prior Years 406 236 120
Decreases Related to Tax Positions for Prior Years     (4,142)
Increases Related to Tax Positions for Current Year 114 10 5
Uncertain Positions Resolved During Year (97)    
Balance on December 31 $ 891 $ 468 $ 222
XML 154 R131.htm IDEA: XBRL DOCUMENT v3.6.0.2
Income Taxes (Detail Textuals) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Tax Disclosure [Abstract]      
Federal income tax rate 35.00% 35.00% 35.00%
Increase in percentage of production tax credits 3.60%    
Wind tax credits amortization period 25 years    
Carryforward period on a portion of the North Dakota wind tax credits from the Langdon wind project 5 years    
Adjustment of deferred tax assets and deferred tax credits for unused North Dakota wind tax credits from Langdon wind project $ 0.4    
Period for unrecognized tax benefits not expected change 12 months    
XML 155 R132.htm IDEA: XBRL DOCUMENT v3.6.0.2
Asset Retirement Obligations - Reconciliations of Carrying Amounts of Present Value of Legal AROs, Capitalized Asset Retirement Costs and Related Accumulated Depreciation and Summary of Settlement Activity (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Asset Retirement Obligations    
Beginning Balance $ 8,084 $ 7,721
New Obligations Recognized 451
Adjustments Due to Revisions in Cash Flow Estimates (103) (424)
Accrued Accretion 360 336
Settlements
Ending Balance 8,341 8,084
Asset Retirement Costs Capitalized    
Beginning Balance 3,086 3,059
New Obligations Recognized 451
Adjustments Due to Revisions in Cash Flow Estimates (103) (424)
Settlements
Ending Balance 2,983 3,086
Accumulated Depreciation - Asset Retirement Costs Capitalized    
Beginning Balance 673 527
New Obligations Recognized
Adjustments Due to Revisions in Cash Flow Estimates
Depreciation Expense 122 146
Settlements
Ending Balance 795 673
Settlements    
Original Capitalized Asset Retirement Cost - Retired
Accumulated Depreciation
Asset Retirement Obligation
Settlement Cost
Gain on Settlement - Deferred Under Regulatory Accounting
XML 156 R133.htm IDEA: XBRL DOCUMENT v3.6.0.2
Asset Retirement Obligations (Detail Textuals)
$ in Thousands
Dec. 31, 2016
USD ($)
Turbine
Dec. 31, 2015
USD ($)
Dec. 31, 2014
USD ($)
Asset Retirement Obligations [Line Items]      
Asset Retirement Obligation $ 8,341 $ 8,084 $ 7,721
Otter Tail Power Company      
Asset Retirement Obligations [Line Items]      
Asset Retirement Obligation $ 500    
North Dakota      
Asset Retirement Obligations [Line Items]      
Number of wind turbines | Turbine 92    
XML 157 R134.htm IDEA: XBRL DOCUMENT v3.6.0.2
Discontinued Operations - Results of Discontinued Operations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]      
Operating Revenues   $ 24,623 $ 149,860
Operating Expenses $ (422) 31,635 140,002
Asset Impairment Charge   1,000 5,605
Interest Expense  
Other Income (Deductions)   69 539
Income Tax (Benefit) Expense 138 (1,539) 3,952
Net (Loss) Income from Operations 284 (6,404) 840
(Loss) Gain on Disposition Before Taxes   11,690  
Income Tax (Benefit) Expense   4,530  
Net Gain on Disposition   7,160  
Net (Loss) Income 284 756 840
Foley | Disposal Group, Held-for-sale or Disposed of by Sale      
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]      
Operating Revenues   21,625 105,333
Operating Expenses 250 26,839 100,826
Asset Impairment Charge   1,000 5,605
Interest Expense   177 510
Other Income (Deductions)   (42) (38)
Income Tax (Benefit) Expense (136) (921) 1,388
Net (Loss) Income from Operations (114) (5,512) (3,034)
(Loss) Gain on Disposition Before Taxes   (204)  
Income Tax (Benefit) Expense   (227)  
Net Gain on Disposition   23  
Net (Loss) Income   (5,489)  
AEV, Inc. | Disposal Group, Held-for-sale or Disposed of by Sale      
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]      
Operating Revenues   2,998 44,527
Operating Expenses 4,532 40,297
Asset Impairment Charge  
Interest Expense   27 184
Other Income (Deductions)   2 304
Income Tax (Benefit) Expense 5 (638) 1,729
Net (Loss) Income from Operations (5) (921) 2,621
(Loss) Gain on Disposition Before Taxes   11,894  
Income Tax (Benefit) Expense   4,757  
Net Gain on Disposition   7,137  
Net (Loss) Income   6,216  
Wind Tower Business | Disposal Group, Held-for-sale or Disposed of by Sale      
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]      
Operating Revenues  
Operating Expenses (757) (462) 19
Asset Impairment Charge  
Interest Expense  
Other Income (Deductions)   111
Income Tax (Benefit) Expense 303 229 (8)
Net (Loss) Income from Operations 454 344 (11)
(Loss) Gain on Disposition Before Taxes    
Income Tax (Benefit) Expense    
Net Gain on Disposition    
Net (Loss) Income   344  
Dock and Boatlift Business | Disposal Group, Held-for-sale or Disposed of by Sale      
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]      
Operating Revenues  
Operating Expenses 85 966 (180)
Asset Impairment Charge  
Interest Expense  
Other Income (Deductions)   277
Income Tax (Benefit) Expense (34) (386) 183
Net (Loss) Income from Operations (51) (580) 274
(Loss) Gain on Disposition Before Taxes    
Income Tax (Benefit) Expense    
Net Gain on Disposition    
Net (Loss) Income   (580)  
Intercompany Transactions Adjustment      
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]      
Operating Revenues  
Operating Expenses (240) (960)
Asset Impairment Charge  
Interest Expense   (204) (694)
Other Income (Deductions)   (2) (4)
Income Tax (Benefit) Expense 177 660
Net (Loss) Income from Operations 265 $ 990
(Loss) Gain on Disposition Before Taxes    
Income Tax (Benefit) Expense    
Net Gain on Disposition    
Net (Loss) Income   $ 265  
XML 158 R135.htm IDEA: XBRL DOCUMENT v3.6.0.2
Discontinued Operations - Major Components of Assets and Liabilities of Discontinued Operations (Details 1) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]    
Current Liabilities $ 1,363 $ 2,098
Liabilities of Discontinued Operations 1,363 2,098
Foley | Disposal Group, Held-for-sale or Disposed of by Sale    
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]    
Current Liabilities
Liabilities of Discontinued Operations
AEV, Inc. | Disposal Group, Held-for-sale or Disposed of by Sale    
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]    
Current Liabilities
Liabilities of Discontinued Operations
Wind Tower Business | Disposal Group, Held-for-sale or Disposed of by Sale    
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]    
Current Liabilities 589 1,299
Liabilities of Discontinued Operations 589 1,299
Dock and Boatlift Business | Disposal Group, Held-for-sale or Disposed of by Sale    
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]    
Current Liabilities 774 799
Liabilities of Discontinued Operations $ 774 $ 799
XML 159 R136.htm IDEA: XBRL DOCUMENT v3.6.0.2
Discontinued Operations - Warranty Reserves (Details 2) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Movement in Standard Product Warranty Accrual [Roll Forward]    
Warranty Reserve Balance, Beginning of Year $ 2,103 $ 2,527
Additional Provision for Warranties Made During the Year
Less Settlements Made During the Year (24) (124)
Decrease in Warranty Estimates for Prior Years (710) (300)
Warranty Reserve Balance, End of Year $ 1,369 $ 2,103
XML 160 R137.htm IDEA: XBRL DOCUMENT v3.6.0.2
Discontinued Operations (Detail Textuals) - USD ($)
$ in Thousands
 1 Months Ended 3 Months Ended 12 Months Ended
Apr. 30, 2015
Feb. 28, 2015
Mar. 31, 2015
Dec. 31, 2014
Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Proceeds from sale of business         $ 39,401
Disposal Group, Held-for-sale or Disposed of by Sale | Foley          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Proceeds from sale of business $ 12,000        
Amount of working capital received 6,300        
Selling expenses $ 1,000        
Goodwill impairment charge     $ 1,000 $ 5,600  
Disposal Group, Held-for-sale or Disposed of by Sale | AEV, Inc.          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Proceeds from sale of business   $ 22,300      
Amount of working capital received   600      
Selling expenses   $ 800      
Disposal Group, Held-for-sale or Disposed of by Sale | Foley and Aevenia          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Pretax charges         $ 4,400
XML 161 R138.htm IDEA: XBRL DOCUMENT v3.6.0.2
Subsequent Events - Summary of stock incentive awards to executive officers under the 2014 Stock Incentive Plan (Details) - Subsequent Event - 2014 Stock Incentive Plan - Executive Officers
Feb. 02, 2017
$ / shares
shares
Restricted Stock Units (RSU) | 25% per year through February 6, 2021  
Subsequent Event [Line Items]  
Shares/UnitsGranted | shares 15,900
Weighted Average Grant-Date Fair Value per Award | $ / shares $ 37.65
Vesting percentage 25.00%
Vesting date Feb. 06, 2021
Stock Performance Awards | December 31, 2019  
Subsequent Event [Line Items]  
Shares/UnitsGranted | shares 59,500
Weighted Average Grant-Date Fair Value per Award | $ / shares $ 31.00
Vesting date Dec. 31, 2019
XML 162 R139.htm IDEA: XBRL DOCUMENT v3.6.0.2
Subsequent Events (Detail Textuals) - 2014 Stock Incentive Plan - shares
Feb. 02, 2017
Feb. 04, 2016
Dec. 31, 2016
Subsequent Event [Line Items]      
Target number of shares awarded     1,900,000
Executive Officers | Stock Performance Awards      
Subsequent Event [Line Items]      
Target number of shares awarded   81,500  
Basis for achieving performance target, description   Common shares for achieving the target set for the Company's 3-year average adjusted return on equity  
Executive Officers | Stock Performance Awards | Maximum      
Subsequent Event [Line Items]      
Actual payment percentage of target amount   150.00%  
Executive Officers | Stock Performance Awards | Performance Target One      
Subsequent Event [Line Items]      
Target number of shares awarded   54,333  
Basis for achieving performance target, description  
Common shares based on the Company's total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2016 through December 31, 2018.
  
Executive Officers | Stock Performance Awards | Performance Target Two      
Subsequent Event [Line Items]      
Target number of shares awarded   27,167  
Basis for achieving performance target, description  
Common shares for achieving the target set for the Company's 3-year average adjusted return on equity.
  
Subsequent Event | Stock Performance Awards      
Subsequent Event [Line Items]      
Number of trading days 20 days    
Period specified for average adjusted return 3 years    
Subsequent Event | Executive Officers | Stock Performance Awards      
Subsequent Event [Line Items]      
Target number of shares awarded 59,500    
Maximum number of common shares authorized for payment 89,250    
Subsequent Event | Executive Officers | Stock Performance Awards | Minimum      
Subsequent Event [Line Items]      
Actual payment percentage of target amount 0.00%    
Subsequent Event | Executive Officers | Stock Performance Awards | Maximum      
Subsequent Event [Line Items]      
Actual payment percentage of target amount 150.00%    
Subsequent Event | Executive Officers | Stock Performance Awards | Performance Target One      
Subsequent Event [Line Items]      
Target number of shares awarded 39,667    
Basis for achieving performance target, description
Based on the Company's total shareholder return relative to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January 1, 2017 through December 31, 2019, with the beginning and ending share values based on the average closing price of a share of the Company's common stock for the 20 trading days immediately following January 1, 2017 and the average closing price for the 20 trading days immediately preceding January 1, 2020.
    
Subsequent Event | Executive Officers | Stock Performance Awards | Performance Target Two      
Subsequent Event [Line Items]      
Target number of shares awarded 19,833    
XML 163 R140.htm IDEA: XBRL DOCUMENT v3.6.0.2
SCHEDULE 1 Condensed Balance Sheets (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Current Assets        
Cash and Cash Equivalents $ 2,007
Accounts Receivable 68,242 62,974    
Income Taxes Receivable 662 4,000    
Other 8,144 8,453    
Total Current Assets 208,015 206,689    
Investments in Subsidiaries 8,417 8,284    
Other Assets 34,104 32,784    
Total Assets 1,912,385 1,818,683 $ 1,738,116  
Current Liabilities        
Short-Term Debt 42,883 80,672    
Current Maturities of Long-Term Debt 33,201 52,422    
Other 15,377 15,416    
Total Current Liabilities 215,671 271,116    
Other Noncurrent Liabilities 21,706 23,854    
Commitments and Contingencies    
Capitalization        
Long-Term Debt, Net of Current Maturities 505,341 443,846    
Common Shareholder Equity 196,741 189,286    
Total Capitalization 1,175,445 1,048,869    
Total Liabilities and Equity 1,912,385 1,818,683    
Otter Tail Corporation        
Current Assets        
Cash and Cash Equivalents 6,218     $ 7,907
Accounts Receivable 12 38    
Accounts Receivable from Subsidiaries 1,706 2,311    
Interest Receivable from Subsidiaries 141 175    
Income Taxes Receivable 662 4,000    
Notes Receivable from Subsidiaries 1,671 5,645    
Other 936 1,096    
Total Current Assets 11,346 13,265    
Investments in Subsidiaries 692,723 713,344    
Notes Receivable from Subsidiaries 79,843 72,560    
Deferred Income Taxes 35,387 37,406    
Other Assets 29,079 26,957    
Total Assets 848,378 863,532    
Current Liabilities        
Short-Term Debt   59,666    
Current Maturities of Long-Term Debt 231 52,422    
Accounts Payable to Subsidiaries 5,958 5,959    
Notes Payable to Subsidiaries 38,519 99,467    
Other 5,838 6,035    
Total Current Liabilities 50,546 223,549    
Other Noncurrent Liabilities 32,556 34,015    
Commitments and Contingencies    
Capitalization        
Long-Term Debt, Net of Current Maturities 95,172 945    
Common Shareholder Equity 670,104 605,023    
Total Capitalization 765,276 605,968    
Total Liabilities and Equity $ 848,378 $ 863,532    
XML 164 R141.htm IDEA: XBRL DOCUMENT v3.6.0.2
SCHEDULE 1 Condensed Statements of Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Operating Loss      
Revenue $ 803,539 $ 779,804 $ 799,262
Operating Expenses 692,440 670,590 699,731
Operating Loss 111,099 109,214 99,531
Other Income (Expense)      
Interest Charges (31,886) (31,160) (29,648)
Other Income 2,905 2,177 3,557
Income Tax Benefit 20,081 21,642 16,557
Net Income 62,321 59,345 57,723
Otter Tail Corporation      
Operating Loss      
Revenue
Operating Expenses 9,689 10,188 12,593
Operating Loss (9,689) (10,188) (12,593)
Other Income (Expense)      
Equity Income in Earnings of Subsidiaries 67,047 66,067 64,926
Interest Charges (6,817) (6,786) (6,326)
Interest Charges to Subsidiaries (173) (193) (117)
Interest Income from Subsidiaries 4,897 4,786 4,980
Other Income 1,621 421 1,379
Total Other Income 66,575 64,295 64,842
Income Before Income Taxes 56,886 54,107 52,249
Income Tax Benefit (5,435) (5,238) (5,474)
Net Income $ 62,321 $ 59,345 $ 57,723
XML 165 R142.htm IDEA: XBRL DOCUMENT v3.6.0.2
SCHEDULE 1 Condensed Statements of Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Cash Flows from Operating Activities      
Net Cash Provided by Operating Activities $ 163,386 $ 117,540 $ 112,474
Cash Flows from Investing Activities      
Return of Capital (Investment in Subsidiaries) 4,402 6,302 2,785
Net Cash Provided by (Used in) Investing Activities (159,324) (155,970) (164,496)
Cash Flows from Financing Activities      
Change in Checks Written in Excess of Cash (3,363) 2,857 1,236
Net Short-Term (Repayments) Borrowings (37,789) 69,818 (40,341)
Proceeds from Issuance of Common Stock 44,435 14,233 26,259
Common Stock Issuance Expenses (562) (451) (673)
Payments for Retirement of Capital Stock (104) (1,596) (590)
Proceeds from the Issuance of Long-Term Debt 130,000   150,000
Short-Term and Long-Term Debt Issuance Expenses (888) (312) (856)
Payments for Retirement of Long-Term Debt (87,547) (212) (41,088)
Dividends Paid and Other Distributions (48,244) (46,223) (44,261)
Net Cash (Used in) Provided by Financing Activities (4,062) 38,430 50,864
Net Change in Cash and Cash Equivalents (2,007)
Cash and Cash Equivalents at Beginning of Period 2,007
Cash and Cash Equivalents at End of Period
Otter Tail Corporation      
Cash Flows from Operating Activities      
Net Cash Provided by Operating Activities 83,296 53,958 47,697
Cash Flows from Investing Activities      
Return of Capital (Investment in Subsidiaries) 9,912 (88,079) (44,000)
Debt Issued to Subsidiaries (3,309) (12,592) (7,662)
Cash Provided by (Used in) Investing Activities 106 (11) (44)
Net Cash Provided by (Used in) Investing Activities 6,709 (100,682) (51,706)
Cash Flows from Financing Activities      
Change in Checks Written in Excess of Cash (428) 213 215
Net Short-Term (Repayments) Borrowings (59,666) 48,812 10,854
(Repayments to) Borrowings from Subsidiaries (60,948) 32,249 4,656
Proceeds from Issuance of Common Stock 44,435 14,233 26,259
Common Stock Issuance Expenses (562) (451) (673)
Payments for Retirement of Capital Stock (104) (1,596) (590)
Proceeds from the Issuance of Long-Term Debt 130,000    
Short-Term and Long-Term Debt Issuance Expenses (723) (312) (170)
Payments for Retirement of Long-Term Debt (87,547) (201) (188)
Dividends Paid and Other Distributions (48,244) (46,223) (44,261)
Net Cash (Used in) Provided by Financing Activities (83,787) $ 46,724 (3,898)
Net Change in Cash and Cash Equivalents 6,218   (7,907)
Cash and Cash Equivalents at Beginning of Period     $ 7,907
Cash and Cash Equivalents at End of Period $ 6,218    
XML 166 R143.htm IDEA: XBRL DOCUMENT v3.6.0.2
SCHEDULE 1 Related Party Transactions (Details) - Otter Tail Corporation - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable $ 1,706 $ 2,311
Interest Receivable 141 175
Current Notes Receivable 1,671 5,645
Long-Term Notes Receivable 79,843 72,560
Accounts Payable 5,958 5,959
Current Notes Payable 38,519 99,467
Otter Tail Power Company    
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable 1,572 1,928
Interest Receivable
Current Notes Receivable
Long-Term Notes Receivable
Accounts Payable 10 11
Current Notes Payable
Vinyltech Corporation    
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable 3
Interest Receivable 20 32
Current Notes Receivable
Long-Term Notes Receivable 11,500 8,500
Accounts Payable
Current Notes Payable 15,951 14,844
Northern Pipe Products, Inc.    
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable
Interest Receivable 10 8
Current Notes Receivable
Long-Term Notes Receivable 5,943 3,160
Accounts Payable
Current Notes Payable 6,560 7,088
BTD Manufacturing, Inc.    
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable 13
Interest Receivable 92 107
Current Notes Receivable 3,924
Long-Term Notes Receivable 52,000 53,500
Accounts Payable
Current Notes Payable 2,342
Wind Tower Business    
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable
Interest Receivable
Current Notes Receivable 1,441 1,444
Long-Term Notes Receivable
Accounts Payable
Current Notes Payable
Dock and Boatlift Business    
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable
Interest Receivable
Current Notes Receivable 230 277
Long-Term Notes Receivable
Accounts Payable
Current Notes Payable
T.O. Plastics, Inc.    
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable
Interest Receivable 19 28
Current Notes Receivable
Long-Term Notes Receivable 10,400 7,400
Accounts Payable
Current Notes Payable 12,378 6,405
Varistar Corporation    
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable 60 60
Interest Receivable
Current Notes Receivable
Long-Term Notes Receivable
Accounts Payable 5,948 5,948
Current Notes Payable 1,288 71,130
Otter Tail Assurance Limited    
Condensed Financial Statements, Captions [Line Items]    
Accounts Receivable 71 310
Interest Receivable
Current Notes Receivable
Long-Term Notes Receivable
Accounts Payable
Current Notes Payable
XML 167 R144.htm IDEA: XBRL DOCUMENT v3.6.0.2
SCHEDULE 1 Dividends (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]      
Cash Dividends Paid to Parent by Subsidiaries $ 77,779 $ 46,188 $ 44,261
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