Madison River at Three Forks, MT
8-K December 12, 2016
Investor Update December 2016
2
Forward Looking Statements
Forward Looking Statements
During the course of this presentation, there will be forward-
looking statements within the meaning of the “safe harbor”
provisions of the Private Securities Litigation Reform Act of
1995. Forward-looking statements often address our
expected future business and financial performance, and
often contain words such as “expects,” “anticipates,”
“intends,” “plans,” “believes,” “seeks,” or “will.”
The information in this presentation is based upon our
current expectations as of the date hereof unless otherwise
noted. Our actual future business and financial
performance may differ materially and adversely from our
expectations expressed in any forward-looking statements.
We undertake no obligation to revise or publicly update our
forward-looking statements or this presentation for any
reason. Although our expectations and beliefs are based
on reasonable assumptions, actual results may differ
materially. The factors that may affect our results are listed
in certain of our press releases and disclosed in the
Company’s most recent Form 10-K and 10-Q along with
other public filings with the SEC.
Company Information
NorthWestern Corporation
dba: NorthWestern Energy
www.northwesternenergy.com
Corporate Support Office
3010 West 69th Street
Sioux Falls, SD 57106
(605) 978-2900
Montana Operational Support Office
11 East Park
Butte, MT 59701
(406) 497-1000
SD/NE Operational Support Office
600 Market Street West
Huron, SD 57350
(605) 353-7478
Director of Investor Relations
Travis Meyer
605-978-2945
travis.meyer@northwestern.com
NWE: An Investment for the Long Term
3
• 100% Regulated electric & natural gas utility business
• 100 year history of competitive customer rates, system reliability and customer satisfaction
• Solid economic indicators in service territory
• A diverse electric supply portfolio that is approximately 54% hydro and wind (combined MT & SD)
• Customer service satisfaction scores above the JD Power survey average
• Residential electric and natural gas rates below the national average
• Solid system reliability (EEI 2nd quartile)
• Low leaks per 100 miles of pipe (AGA 1st quartile)
• Named a “Utility Customer Champion” by Cogent Reports (top trusted utility brand in the West region)
• Consistent track record of earnings and dividend growth
• Strong cash flows aided by net operating loss carry-forwards
• Strong balance sheet and solid investment grade credit ratings
• Recent hydro & wind transactions increase rate base & provide energy supply stability
• Disciplined maintenance capital investment program
• Reintegrating energy supply portfolio
• Significant future investment in a comprehensive transmission, distribution, and substation
infrastructure project to address asset lives, safety, capacity and grid modernization
Pure Electric
& Gas Utility
Solid Utility
Foundation
Strong
Earnings &
Cash Flows
Attractive
Future Growth
Prospects
(NYSE Ethics)
Best Practices
Corporate
Governance
About NorthWestern
4
Montana Operations
Electric
359,000 customers
24,350 miles – transmission & distribution lines
851 MW nameplate owned power generation
Natural Gas
191,500 customers
7,200 miles of transmission and distribution pipeline
18 Bcf of gas storage capacity
Owns 66 Bcf of proven natural gas reserves
South Dakota Operations
Electric
62,800 customers
3,550 miles – transmission & distribution lines
440 MW nameplate owned power generation
Natural Gas
45,700 customers
1,625 miles of transmission and distribution pipeline
Nebraska Operations
Natural Gas
42,000 customers
750 miles of distribution pipeline
Beethoven
A Diversified Electric and Gas Utility
5
Gross Margin in 2015:
Electric: $663M
Natural Gas: $178M
Gross Margin in 2015:
Montana: $729M
South Dakota: $102M
Nebraska: $ 10M
Average Customers in 2015:
Residential: 579k
Commercial: 111k
Industrial: 7k
NorthWestern’s ‘80/20’ rules:
Approximately 80% Electric, 80% Residential and
80% Montana jurisdictional
Above data reflects full year 2015 results.
Jurisdiction and service type based upon gross margin contribution.
See “Non-GAAP Financial Measures” slide in appendix for Gross Margin reconciliation.
NorthWestern Energy Profile
6
Financial and Company Statistics
Solid Economic Indicators
7
• Unemployment rates in all three of our
states are meaningfully below National
Average.
• Customer growth rates historically exceed
National Averages.
Source: NorthWestern customer growth - 2008-2015 Forms 10-K
Unemployment Rate: US Department of Labor via SNL Database 2/19/16
Electric: EEI Statistical Yearbook (published December 2014, table 7.2)
Natural Gas: EIA.gov (Data table "Number of Natural Gas Consumers")
Strong Utility Foundation
8
Electric source: Edison Electric Institute Typical Bills and Average Rates Report, 1/1/16
Natural gas source: US EIA - Monthly residential supply and delivery rates as of 1/29/16
Customer service satisfaction scores in line or better than survey average (JD Powers)
Residential electric and natural gas rates below national average
Solid electric system reliability and low gas leaks per mile
System Average Interruption Duration Index (SAIDI)
NWE versus EEI System Reliability Quartiles
2016 Earnings Guidance
9
NorthWestern reaffirms our full-year 2016 adjusted (Non-GAAP) guidance range of $3.20 - $3.35 per
diluted share, based upon, but not limited to, the following major assumptions and expectations:
• Normal weather in our electric and natural gas service territories;
• A consolidated non-GAAP income tax rate of approximately 6% - 10% of pre-tax income (as compared to
(3)% - 1% of GAAP; and
• Diluted average shares outstanding of approximately 48.5 million.
Continued investment in our system to serve our customers and communities is
expected to provide a targeted 7-10% total return to our investors through a
combination of earnings growth and dividend yield.
See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”.
$2.60 - $2.75 $3.20-$3.35
Investment for Our Customers’ Benefit
10
Over the past 7 years we have
been reintegrating our Montana
energy supply portfolio and
making additional investments
across our entire service territory
to enhance system safety,
reliability and capacity.
We have made these
enhancements with minimal
impact to customers’ bills and
lower than the US average bills,
while delivering solid earnings
growth for our investors.
2008-2015 CAGRs
Estimated Rate Base: 16.9%
GAAP Diluted EPS: 8.6%
NWE typical electric bill: 1.5%
NWE typical natural gas bill: (6.9%)
US average electric bill: 2.2%
US avg. natural gas bill *** (4.1%)
Track Record of Delivering Results
11
Notes: - ROE in 2011, 2012 , 2013, 2014 & 2015 on a Non-GAAP Adjusted basis, would be 10.5%, 9.8%, 9.6% ,9.4% & 9.9% respectively.
- 2016 ROAE and 2016 Dividend payout ratio estimate based on midpoint of our updated guidance range of $3.20-$3.35.
- Details regarding Non-GAAP Adjusted EPS can be found in the “Adjusted EPS Schedule” page of the appendix
Return on Equity within
9.5% - 11.0% band over
the last 5 years.
Annual dividend increases
since emergence in 2004.
5 Year (2011-2015) Avg.
Return on Equity: 10.4%
5 Year (2011-2015) CAGR
Dividend Growth: 7.5%
Current Dividend Yield
Approximately 3.5%
Total Shareholder Return
12 • 13 member peer group: ALE (Allete), AVA (Avista), BKH (Black Hills), EE (El Paso Electric), GXP (Great Plains), IDA (IDA Corp), MGEE (Madison Gas & Electric), OGE (OGE Energy), OTTR (Otter Tail Power), PNM (PNM Resources), POR (Portland Electric),, VVC (Vectren), WR (Westar)
While maintenance capex and total
dividend payments have continued to grow
since 2011 (16.6% and 14.8% CAGR
respectively), Cash Flow from Operations
has continued to outpace maintenance
capex and averaged approximately
$38 million of positive Free Cash Flow
per year.
With the addition of production tax credits
from the Beethoven Wind project and
continued flow-through tax benefits, we
anticipate our effective tax rate rising into
the low-twenties by 2020. Additionally, we
expect NOLs to be available into 2020 to
reduce cash taxes.
Strong Cash Flows
13
(1)
See “Non-GAAP Financial Measure” slide in appendix for Free Cash Flows reconciliation.
Components of Free Cash Flow
This expected tax rate and the expected availability of NOLs are subject to significant business, economic, regulatory and competitive uncertainties and contingencies, many of
which are beyond the control of the Company and its management, and are based upon assumptions with respect to future decisions, which are subject to change. Actual results
will vary and those variations may be material. For discussion of some of the important factors that could cause these variations, please consult the “Risk Factors” section of the
preliminary prospectus. Nothing in this presentation should be regarded as a representation by any person that these objectives will be achieved and the Company undertakes no
duty to update its objectives.
(2)
Net Operating Loss (NOL) Carryforward Balance
(2)
(1)
Balance Sheet Strength and Liquidity
14
2016 to 2017 EPS & Dividend Bridge
Preliminary
2017 ESTIMATES
Basic assumptions
include, but are not
limited to:
• Normal weather in our
electric and natural gas
service territories;
• A consolidated effective
income tax rate of
approximately 7% - 11%
of pre-tax income; and
• Diluted average shares
outstanding of
approximately
48.5 million.
15
* 2017 earnings drivers shown above are calculated using a 38.5% effective tax rate. The “Incremental tax benefits” as
shown above are primarily due to potential for increased repairs tax deductions on maintenance capital spending in 2017.
16
Regulatory Update
Regulatory Item Current / Anticipated Action
FERC / DGGS: April 2014 order regarding
cost allocation at DGGS between retail and
wholesale customers.
FERC denied our request for rehearing and required us to make refunds. Refunds
were made in June 2016. Also in June 2016, we filed a petition for review with the US
Circuit Court of Appeals for the District of Columbia Circuit. Briefing schedule has
been established with final briefs due by the end of the first quarter 2017. We do not
expect a decision until the second half of 2017, at the earliest.
LRAM: MPSC October 2015 Order eliminating
the lost revenue adjustment mechanism.
Future rate filings will set rates to recover test-year costs and return. We are
evaluating other revenue based regulatory mechanisms, such as decoupling, for
example, that could be pursued to address these kinds of revenue losses and others,
going forward. The MPSC held a workshop focused on decoupling on October 28th.
Natural Gas: MPSC October 2015 natural gas
tracker order revising interim rates our last two
gas production asset acquisitions and requiring
a filing prior to October 2016 to place them into
rate base.
In conjunction with the filing required for our natural gas production assets in
Montana, we submitted a natural gas distribution, transmission and storage rate filing
based on a 2015 test year in September 2016 requesting approximately $10.9 million
annual increase to revenue and 7.33% return on $432.1 million of rate base. We are
currently in the discovery process. A procedural schedule has not been established. Rate Filings: Annual “First Look” process to
evaluate need for rate filings in each of our
jurisdictions based on a 2015 test year.
Colstrip: In May 2016, the MPSC issued a
final order disallowing recovery of replacement
power and portfolio modeling costs included in
the electric supply tracker related to a 2013
outage at Colstrip Unit 4.
Appeals have been filed in two Montana district courts regarding disallowance: June
‘16 regarding portfolio modeling costs in the 2015 Tracker (Lewis & Clark County) and
September ‘16 regarding replacement power and modeling costs in the Consolidated
Docket (Yellowstone County). We believe we are likely to receive orders from the
courts in these matters within 9-20 months of filing.
Hydro Compliance Filing: In December
2015, we filed, with the MPSC, a hydro
compliance filing to remove Kerr Project costs,
adjust for actual revenue credits and increase
property taxes to reflect actual amounts.
In January ‘16, the MPSC approved an interim adjustment and opened a separate
contested docket requesting additional detail. A hearing was held in September
2016. The only contested issue at the hearing was the level of A&G expenses that
should be deducted due to the transfer of the Kerr Project. During a public work
session on November 29th, the commission directed staff to prepare an order that
would reduce A&G expense collected through the revenue requirement by
approximately $1.1 million annually. We anticipate a final order in the next 60 days.
Montana Natural Gas Rate Filing
17
Montana PSC Docket D2016.9.68
In September 2016, we
filed a request with
MPSC for an annual
revenue increase of
$10.9 million.
This increase is
primarily due to
investments made to
our gas infrastructure
and natural gas
reserves since 2012.
The $10.9 million
increase will represent
a 6.77% increase* in
monthly bills for a
typical residential
customer using 100
therms per month.
* Increase over September 2016 bill.
NWE 100 Therm bill with proposed rates:
18
Highly Renewable Supply Portfolio
Based upon 2015 delivered electric portfolio, approximately 54% of
our total company owned and contracted supply is renewable or
supports renewables.
* Wind Owned delivered in 2015 includes a partial year of production from the Beethoven wind farm,
which was acquired on September 25, 2015.
Infrastructure Projects
19
• In Montana, our Distribution System Infrastructure
Project (DSIP) and Transmission System Infrastructure
Project (TSIP), both of which are currently in process, are to
maintain a safe and reliable electric and natural gas
distribution and transmission system.
– The primary goals:
– arrest and/or reverse the trend in aging infrastructure;
– maintain/improve reliability and safety;
– build capacity into the system; and
– prepare our network for the adoption of
new technologies.
– Capital Investment
– DSIP: approximately $360 million ($185 million spent
through 2015) of capital investment into the
multiyear project through 2020.
– TSIP: approximately $188 million ($4 million spend
through 2015) projected through 2020.
Capital Spending Forecast
20
Estimated capital spending of $1.66 billion over the next 5 years, including approximately $187 million to meet a
shortfall in dispatchable generation capacity in Montana and South Dakota. We anticipate issuing a request for
proposal (RFP) in Montana during the first quarter 2017 to evaluate third party alternatives, which may include
long-term purchase power agreements or build-transfer options. Spending on any capacity resources will be
subject to the development of a plan for clear regulatory recovery. Additional information is available in our 2015
Montana and 2014 South Dakota Electric Resource Supply Plans.
We anticipate funding the capital projects with a combination of cash flows, aided by NOLs anticipated to be
available into 2020, and long-term debt. If other opportunities arise that are not in the above projections (natural
gas reserves, hydro expansion, acquisitions, etc.), new equity funding may be necessary.
(This plan is subject to change, including levelizing the capital spending over the next five years.)
Owned
Owned
Target
Total Annual Need
Natural Gas Reserves Opportunity
21
As we continue to add to our natural
gas reserves portfolio, we anticipate a
reduction in supply cost volatility for
our customers.
As a result of the October 2015
natural gas tracker order, we are
required to make a filing prior to
September 2016 to include our last
two acquisitions (NFR and Devon)
into rate base.
First ~6 Bcf annual
production acquired
for ~$100M
Remaining 6-7 Bcf
annual production
needed to meet target.
Estimated cost of $50M to $100M
We continue to pursue opportunities to secure
low cost gas reserves for our customers.
• Three acquisitions totaling approximately $100 million since
September 2010:
• 84.6 Bcf of natural gas reserves and associated gathering
systems along with 82 miles of transmission.
• Provides approximately 5.3 Bcf of annual production.
• Target to own 50% of our 25 Bcf total annual need
• Retail customers (20 Bcf)
• DGGS & Basin Creek generation facilities (5 Bcf)
• Current gas prices are very attractive for buyers but it is
difficult to find sellers willing to transact at these low rates.
Montana 2015 Electric Supply Resource Plan
22
The resource initiatives and actions
developed in 2015 Electricity Supply
Resource Procurement Plan identify
the critical future needs of our
portfolio, including solutions to
resolve our current negative planning
reserve margin.
The plan identifies how to co-
optimize hydro, wind and thermal
resources to best meet the
anticipated large capacity needs with
the least-cost, lowest-risk resources.
A baseline life extension analysis
indicates potential for 86 MW of
hydro capacity additions. These
additions are not included in the
current plan but will continue to be
evaluated for cost effectiveness.
The Montana Public Service
Commission doesn’t approve or
reject plan, but will issue their own
comments. Timeline yet to be
determined.
Spending on the generation assets will be
subject to the development of a plan for
clear regulatory recovery.
Source: Company’s IRP or other publications
Montana 2015 Electric Supply Resource Plan
23
Spending on the generation assets will be
subject to the development of a plan for
clear regulatory recovery.
* Assumes no
retirements and no
additions.
** Montana supply plan
would add 689MW of
capacity and require
approximately
$1.3 billion of
investment through
2029.
Current Capacity* Economically Optimal Portfolio**
Conclusion
24
Pure Electric
and Gas
Utility
Solid Utility
Foundation
Strong
Earnings and
Cash Flows
Attractive
Future
Growth
Prospects
Best
Practices
Corporate
Governance
25
Summary Financial Results (Third Quarter)
26
27
Gross Margin (Third Quarter)
(dollars in millions) Three Months Ended September 30,
2016 2015 Variance
Electric $ 176.9 $ 172.3 $ 4.6 2.7%
Natural Gas 27.9 26.8 1.1 4.1%
Gross Margin $ 204.8 $ 199.1 $ 5.7 2.9%
Increase in gross margin due to the following factors:
$ 9.2 South Dakota electric rate increase (includes Beethoven wind project)
1.4 Natural gas retail volumes
(1.8) Lost revenue adjustment mechanism
(0.4) Electric retail volumes
(0.4) Electric transmission
(0.2) Natural gas production
(0.3) Other
$ 7.5 Change in Gross Margin Impacting Net Income
$ (4.3) Hydro operations (Kerr conveyance)
(2.1) Production tax credits flowed-through trackers
(0.1) Natural gas production gathering fees
4.7 Property taxes recovered in trackers
$ (1.8) Change in Gross Margin Offset Within Net Income
$ 5.7 Increase in Consolidated Gross Margin
Weather (Third Quarter)
28
Average Temperature Ranks (last 122 years) Mean Temperature from Normal
While near normal for the quarter, cooler than normal late summer weather in Montana
had an unfavorable impact, primarily to our electric volumes.
Operating Expenses (Third Quarter)
29
Decrease in operating expenses due mainly to the following factors:
$11.0 million decrease in OG&A
$ (4.0) Hydro operations (Kerr Conveyance)
$ (2.9) Non-employee directors deferred compensation
$ (1.7) Distribution System Infrastructure Project (DSIP) expenses
$ (1.5) Employee benefits
$ (0.1) Natural gas production gathering expense
$ 1.0 Bad debt expense
$ (1.8) Other, including cost control measures
$5.0 million increase in property and other taxes due primarily to plant additions and
higher estimated property valuations in Montana, offset in part by a $0.3 million
decrease from the conveyance of the Kerr project to the CSKT in September 2015.
$4.1 million increase in depreciation and depletion expense primarily due to plant
additions, including approximately $1.4 million of depreciation associated with the
Beethoven wind project acquisition.
Three Months Ended September 30,
2016 2015 Variance
Operating, general & admin. $ 68.3 $ 79.3 $ (11.0) (13.9%)
Property and other taxes 40.7 35.7 5.0 14.0%
Depreciation and depletion 39.8 35.7 4.1 11.5%
Operating Expenses $ 148.8 $ 150.7 $ (1.9) (1.3%)
Operating to Net Income (Third Quarter)
30
$1.0 million decrease in interest expense was primarily due to debt refinancing
transactions partially offset by lower capitalization of allowance for funds used during
construction (AFUDC) and increased debt outstanding associated with the Beethoven wind
project acquisition.
$3.9 million decrease in other income due primarily to a $2.9 million decrease in the
value of deferred shares held in trust for non-employee directors deferred compensation
(which had a corresponding decrease to operating, general and administrative expenses)
and lower capitalization of AFUDC.
$16.1 million decrease in income tax expense due primarily to a tax accounting method
change related to costs to repair generation property and higher production tax credits
associated with the Beethoven wind project. These reductions were
partially offset by higher pre-tax income.
Three Months Ended September 30,
2016 2015 Variance
Operating Income $ 56.1 $ 48.5 $ 7.6 15.7%
Interest Expense (21.0) (22.0) 1.0 (4.5%)
Other (Loss)/Income (0.1) 3.8 (3.9) (102.6%)
Income Before Taxes 34.9 30.2 4.7 15.6%
Income Tax Benefit/(Expense) 9.7 (6.4) 16.1 (251.6%)
Net Income $ 44.6 $ 23.8 $ 20.8 87.4%
Balance Sheet
31
Cash Flow
32
The $46.5 million
decrease in
operating cash
flows is primarily
due to refunds
associated with
the DGGS FERC
ruling and the
South Dakota
electric rate case
of approximately
$30.8 million and
$7.2 million,
respectively, to
customers during
the first nine
months of 2016.
* DGGS refund of $30.8
million includes $27.3
million of deferred
revenues plus accrued
interest of $3.5 million.
Income Tax Reconciliation (Third Quarter)
33
The $16.1 million improvement in income taxes is primarily driven by additional flow-
through repairs deductions, as a result of a tax accounting method change with the IRS
related to costs to repair generation property, and higher production tax credits. These
reductions to taxes were partially offset by higher pre-tax income this quarter compared
to the same period in 2015.
Adjusted Earnings (Third Quarter ‘16 vs ’15)
34
The non-GAAP measures presented in the table above are being shown to reflect significant items that were not
contemplated in our original guidance, however they should not be considered a substitute for financial results
and measures determined or calculated in accordance with GAAP.
Summary Financial Results (YTD thru Qtr 3)
35
Weather (YTD thru Qtr 3)
36
Northwestern’s service territory is much more impacted by variances to Heating
Degree Days (HDD) than Cooling Degree Days (CDD) (i.e. approximately 16x more
HDD’s than CDD’s in Montana). All three of our jurisdictions have experienced 10-
13% fewer HDD’s in 2016 than normal.
Non-GAAP Adjusted Earnings (‘16 vs ’15)
37
The non-GAAP measures presented in the table above are being shown to reflect significant items that
were not contemplated in our original guidance, however they should not be considered a substitute for
financial results and measures determined or calculated in accordance with GAAP.
Non-GAAP Adjusted EPS
38
The non-GAAP measures presented in the table above are being shown to reflect significant items
that were not contemplated in our original guidance, however they should not be considered a
substitute for financial results and measures determined or calculated in accordance with GAAP.
39
2015 to 2016 Reconciliation (3rd Quarter & YTD)
(1) Income Tax Benefit (Expense) calculation on
reconciling items assumes normal effective tax
rate of 38.5%
(2) These items have offsets in operating
expenses or income tax expenses that result in
no impact to net income.
Owned Energy Supply Transmission Distribution
Electric (MW) MT SD Total 2015 Tx for Others MT SD Total Demand MT SD / NE Total
Base load coal 222 210 432 Electric (GWh) 11,300 100 11,400 Daily MWs 750 187 937
Wind 40 80 120 Natural Gas (Bcf) 22.5 29.5 52.0 Peak MWs 1,790 306 2,096
Hydro 442 - 442 Annual GWhs 6,400 1,640 8,040
Other resources 150 150 300 Annual Bcf 18.5 9.5 28.0
854 440 1,294 System (miles) MT SD Total
Electric 6,700 1,350 8,050 Customers MT SD / NE Total
Natural Gas (Bcf) MT SD Total Natural gas 2,100 55 2,155 Electric 359,000 62,800 421,800
Proven reserves 65.9 - 65.9 8,800 1,405 10,205 Natural gas 191,500 87,700 279,200
Annual production 5.3 - 5.3 550,500 150,500 701,000
Storage 17.8 - 17.8
System (miles) MT SD / NE Total
Electric 17,650 2,200 19,850
Natural gas 5,100 2,375 7,475
22,750 4,575 27,325
2015 System Statistics
40
Note: Statistics above are as of 12/31/2015
(1) Includes additional 3 MW for Ryan dam expansion
(2) Nebraska is a natural gas only jurisdiction
(2)
(1)
Experienced & Engaged Board of Directors
41
Dr. E. Linn Draper Jr.
• Chairman of the Board
• Independent
• Director since
November 1, 2004
Stephan P. Adik
• Committees: Audit
(chair), Human
Resources
• Independent
• Director since
November 1, 2004
Dorothy M. Bradley
• Committees: Human
Resources, Governance
and Innovation
• Independent
• Director since
April 22, 2009
Julia L. Johnson
• Committees:
Governance and
Innovation, Human
Resources
• Independent
• Director since
November 1, 2004
Robert C. Rowe
• Committees: None
• CEO and President
• Director since
August 13, 2008
Tony Clark
• Committees:
Governance and
Innovation
• Independent
• Director since
December 6, 2016
Dana J. Dykhouse
• Committees: Human
Resources (chair),
Audit
• Independent
• Director since
January 30, 2009
Jan R. Horsfall
• Committees: Audit,
Governance and
Innovation
• Independent
• Director since
April 23, 2015
Strong Executive Team
42
Robert C. Rowe
• President and
Chief Executive Officer
• Current position since
2008
Brian B. Bird
• Vice President and
Chief Financial Officer
• Current position since
2003
Michael R. Cashell
• Vice President -
Transmission
• Current Position since
2011
Patrick R. Corcoran
• Vice President –
Government and
Regulatory Affairs
• Current position since
2001
Heather H. Grahame
• Vice President and
General Counsel
• Current position since
2010
John D. Hines
• Vice President - Supply
• Current Position since
2011
Crystal D. Lail
• Vice President and
Controller
• Current position since
2015
Curtis T. Pohl
• Vice President -
Distribution
• Current position since
2003
Bobbi L. Schroeppel
• Vice President –
Customer Care,
Communications and
Human Resources
• Current Position since
2002
Our Commissioners
43
Name Party
Began
Serving
Term
Ends
Kirk Bushman R Jan-13 Jan-17
Travis Kavulla R Jan-11 Jan-19
Roger Koopman R Jan-13 Jan-17
Brad Johnson (Chairman) R Jan-15 Jan-19
Bob Lake R Jan-13 Jan-17
Commissioners are elected in statewide elections from each of
five districts. Chairperson is elected by fellow Commissioners.
Commissioner term is 4 years, Chairperson term is 2 years.
Montana
Public Service
Commission
Name Party
Began
Serving
Term
Ends
Kristie Fiegen R Aug-11 Jan-19
Gary Hanson R Jan-03 Jan-21
Chris Nelson (Chairman) R Jan-11 Jan-17
Commissioners are elected in statewide elections. Chairperson is
elected by fellow Commissioners. Commissioner term is 6 years,
Chairperson term is 1 year.
South Dakota
Public Utilities
Commission
Name Pa ty
Began
Serving
Term
Ends
Cyrstal Rh ades D Jan-15 Jan-21
Rod Johnson R Jan-93 Jan-17
Frank Landis Jr. (Chairman) R Jan-89 Jan-19
Tim Schram R Jan-07 Jan-19
Gerald Vap R Aug-01 Jan-17
Commissioners are elected in statewide elections. Chairperson is
elected by fellow Commissioners. Commissioner term is 6 years,
Chairperson term is 1 year.
Nebraska
Public Service
Commission
2016 Election Results
MT – R. Koopman & B. Lake
re-elected and Tony O’Donnell (R)
elected unopposed (beat K. Bushman
in primary)
SD – C. Nelson re-elected
NE – R. Johnston re-elected and Mary
Ridder (R) elected unopposed (beat J.
Vap in primary)
The Hydro Facilities
44
Overview of Hydro Facilities
Black Eagle
Hydro Asset Integration
• Montana Asset Optimization Study: As part of reintegrating the
hydro facilities into our generation portfolio, we initiated an
asset optimization study to maximize the value of our diverse
generation portfolio. The study was recently completed and
we are in the process of implementing new operating
procedures that we anticipate will reduce both operating cost
and market risk.
Kerr Dam Conveyance / Hydro Compliance Filing
• In accordance with the 1985 FERC relicensing, the facility was
conveyed to the Confederated Salish and Kootenai Tribes
(CSKT) on September 5, 2015.
• As required by the MPSC order approving the hydro
transaction, we filed a compliance filing in December 2015 to
remove the Kerr project from the hydros cost of service and to
adjust for actual revenue credits and property taxes. In
January ‘16, the MPSC approved an interim adjustment and
opened a separate contested docket requesting additional
detail. A hearing was held in September 2016. The only
contested issue at the hearing was the level of administrative
& general expenses that should be deducted due to the
transfer of the Kerr Project. We expect a final order during the
fourth quarter of 2016.
(1) As of June 2013.
Despite the 2015 drought conditions in western Montana, the hydro
assets generated at targeted capacity (5 year historical average).
Talen Energy’s recently announced sale of 292 MW of hydro
generation for $860 million (or $2,945 per KW) to Brookfield
Renewables is significantly higher cost (49%) than the 439 MW of
hydro generation we purchased for $870 million (or $1,982 per KW).
45
South Dakota Electric Operations
The owned and rate-based cost of energy from the Beethoven wind project over the
next 20 years is expected to be $44 million ($25 million net present value) less than the
PPA alternative, thus benefitting our customers’ bills over the long-term.
Beethoven Wind Project:
In September 2015, we completed the purchase of the 80 MW Beethoven wind
project, near Tripp, South Dakota for approximately $143 million from BayWa r.e.
Wind LLC.
The SDPUC granted approval of our request on placing the assets into rate base
using a 3-year levelized rate calculation.
We financed the project with $70 million in 25 year bonds at 4.26% and $57
million of equity, issuing 1.1 million shares at $51.81.
South Dakota Electric Rate Case:
In October 2015, the SDPUC commissioners approved the settlement agreement
we reached with the SDPUC staff and intervenors providing for an increase in
base rates of approximately $20.2 million based on an overall rate of return of
7.24%. In addition, the settlement would allow us to collect approximately $9.0
million annually related to the Beethoven Wind Project.
Source: BayWa r.e. Wind, LLC
We anticipate net income to increase by approximately $13.6 million in 2016 as a result of full year impact of the rate
adjustment and Beethoven acquisition.
SD Electric Transmission:
Effective October 1, 2015, we are a transmission owning member of Southwest Power Pool (SPP) for our South Dakota
transmission operations. Marketing activities in SPP are handled for us by a third party provider acting as our agent. Upon
entering SPP, we exited out of MAPP, which had been our transmission planning region.
EPA’s 2030 carbon target for Montana
NWE’s CO2
intensity*
decreased by
approximately 37%
with the addition
of the hydro
facilities to our
Montana
generation
portfolio.
However EPA’s
Clean Power Plan
targets are
statewide and not
utility specific
targets.
* lbs CO2 per MWH
produced
CO2
Intensity*
37%
46
EOP = Emergency Operations Plan
RPS = Renewable Portfolio Standard
47
Colstrip Unit 4 / Sierra Club Litigation
Background
• On March 6, 2013, the Sierra Club and the Montana Environmental Information Center
(MEIC) (both are plaintiffs) filed suit in the United States District Court for the District of
Montana (court) against the six individual Owners of the Colstrip Generating Station
(Colstrip)
• Colstrip consists of four coal fired generating units – units 1 & 2 are older than units 3 & 4.
• NWE has a 30% joint interest in unit 4 and a risk sharing agreement with Talen Montana
regarding the operation of units 3 & 4, which each party receives 15% of the combined
output and respective operating and construction costs.
• Original suit was for alleged violations of the Clean Air Act and the Montana State
Implementation Plan.
Current Results
• On July 12, 2016 the parties lodged a consent decree with the Court.
• The Court entered the consent decree on September 6, 2016.
• Decree provides the following
• Dismisses all of the claims against all Colstrip units
• Provides no shut down date for Units 3 & 4
• Provides that Units 1 & 2 must be shut down by July 1, 2022 (NWE has no
ownership or role in Units 1 & 2 shut down)
• Permits parties to petition the Court for costs and attorneys’ fees
Up next
• The consent decree gave the Plaintiffs and Defendants the right to seek recovery of
attorneys’ fees and costs from the other party by filing a motion with the Court by
October 6, 2016. All parties (Plaintiffs and Defendants) filed such a motion on a timely
basis. We cannot predict an outcome, but we do not anticipate that the outcome will have
a significant impact on our results of operations or cash flows.
48
EPA’s Clean Power Plan (CPP)
The February 9th Supreme Court 5-4 vote to stay the EPA CPP rules
• We will be working with state agencies and other stakeholders to evaluate the implications.
• We hope the EPA takes this opportunity to address Montana’s serious concerns with the 47%
statewide reduction required in the final rule.
If the CPP rules were utility specific, NorthWestern would be in
excellent shape…. but emission targets are established at a state level.
• NorthWestern’s Montana electric supply portfolio has a low carbon
emissions rate, lower than the final 2030 Montana rate mandated by
EPA, with nearly 60 percent of the power delivered to NorthWestern’s
customers coming from owned or contracted hydro or wind sources.
• NorthWestern’s South Dakota electric supply portfolio delivers
approximately 28% of its power from owned and contracted wind.
Source: www.eenews.net/interactive/clean_power_plan
Parallel paths forward
• Montana and South Dakota, along with many other states, are participating in legal challenges to the rule.
Montana’s 47% emission rate reduction requirement is the highest in the nation.
• NorthWestern has filed an administrative Petition for Reconsideration with the EPA. If unsuccessful, we
anticipate Montana will file a request for a 2-year extension to meet compliance deadlines.
• Although we have filed for reconsideration, we are continuing to evaluate our path forward to comply with
the CPP rule. The Montana governor has created a CPP advisory council whose purpose is to gather
information and provide the Montana Department of Environmental Quality (MDEQ) recommendations on
policies and actions necessary for compliance in Montana. With the Supreme Court decision to Stay the
EPA CPP rules, the activities of the advisory council have been placed on hold. We have representation
on the council.
DGGS Update – Denied Rehearing Request
49 Note: Please see Regulatory Matters footnote and Risk Factors section of our recent Form 10-K and Form 10-Q for additional disclosures.
Non-GAAP Financial Measures
50
The data presented in this presentation includes financial
information prepared in accordance with GAAP, as well as other
Non-GAAP financial measures such as Gross Margin (Revenues
less Cost of Sales), Free Cash Flows (Cash flows from
operations less maintenance capex and dividends) and Net Debt
(Total debt less capital leases), that are considered “Non-GAAP
financial measures.” Generally, a Non-GAAP financial measure
is a numerical measure of a company’s financial performance,
financial position or cash flows that exclude (or include) amounts
that are included in (or excluded from) the most directly
comparable measure calculated and presented in accordance
with GAAP. The presentation of Gross Margin, Free Cash Flows
and Net Debt is intended to supplement investors’ understanding
of our operating performance. Gross Margin is used by us to
determine whether we are collecting the appropriate amount of
energy costs from customers to allow recovery of operating costs.
Net Debt is used by our company to determine whether we are
properly levered to our Total Capitalization (Net Debt plus
Equity). Our Gross Margin, Free Cash Flows and Net Debt
measures may not be comparable to other companies’ similarly
labeled measures. Furthermore, these measures are not
intended to replace measures as determined in accordance with
GAAP as an indicator of operating performance.
(in thousands) 2011 2012 2013 2014 2015
Reported GAAP diluted EPS 2.53$ 2.66$ 2.46$ 2.99$ 3.17$
Non-GAAP Adjustments
Weather (0.05) 0.14 (0.05) (0.02) 0.17
Rate adjustments - - - - -
Insurance recoveries - - - - -
Income tax adjustments (0.17) (0.06) - (0.47) -
Transmission revenue - low hydro 0.05 - - - -
Dispute with former employee 0.05 - - - -
DGGS FERC ALJ initial decision (2011 portion) - 0.12 - - -
Release of MPSC DGGS deferral - (0.05) - - -
DSM Lost Revenue recovery - (0.05) (0.02) - -
CELP arbitration decision - (0.79) - - -
MSTI Impairment - 0.40 - - -
Hydro Transaction costs - - 0.11 0.24 -
Hydro operations (Nov. 18, 2014 - Dec. 31, 2014) - - - (0.14) -
Hydro equity dilution - - - 0.08 -
Remove ben f t of insurance settlement (0.27)
QF liability adjustment 0.08
Adjusted Non-GAAP diluted EPS 2.41$ 2.37$ 2.50$ 2.68$ 3.15$
Use of Non-GAAP Financial Measures - Reconcile to Non-GAAP diluted EPS
(in millions) Electric Gas Other Total
Oper ting Revenues 944.4$ 269.9$ -$ 1,214.3$
Cost of Sales 281.3 91.6 - 372.9
Gro s Margin 663.2$ 178.3$ -$ 841.4$
(in millions) Montana South Dakota Nebraska Total
Operating Revenues 985.3$ 195.6$ 33.4$ 1,214.3$
Cost of Sales 256.1 93.9 22.8 372.9
Gross Margin 729.2$ 101.7$ 10.5$ 841.4$
Use of Non-GAAP Financial Measures - Gross Margin for 2015
Use of Non-GAAP Financial Measures - Gross Margin for 2015
51