10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
¨	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 1-07978

BLACK HILLS POWER, INC.
Incorporated in South Dakota	IRS Identification Number 46-0111677
7001 Mount Rushmore Road, Rapid City, South Dakota 57702
Registrant’s telephone number, including area code: (605) 721-1700
Securities registered pursuant to Section 12(b) of the Act: None
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    x    No    ¨

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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) 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 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.

This paragraph is not applicable to the Registrant.        x

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer        ¨    Accelerated filer        ¨

Non-accelerated filer        x (Do not check if a smaller reporting company)

Smaller reporting company    ¨

Emerging growth company    ¨

If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes    ¨    No    x

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.

All outstanding shares are held by the Registrant’s parent company, Black Hills Corporation. Accordingly, the aggregate market value of the voting common stock of the Registrant held by non-affiliates is $0.

Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.

Class	Outstanding at January 31, 2018
Common stock, $1.00 par value	23,416,396 shares

Reduced Disclosure

The Registrant meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

TABLE OF CONTENTS
		Page
	GLOSSARY OF TERMS AND ABBREVIATIONS	3
ITEMS 1. and 2.	BUSINESS AND PROPERTIES	6
ITEM 1A.	RISK FACTORS	12
ITEM 1B.	UNRESOLVED STAFF COMMENTS	18
ITEM 3.	LEGAL PROCEEDINGS	18
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	19
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS	19
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	25
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	57
ITEM 9A.	CONTROLS AND PROCEDURES	57
ITEM 9B.	OTHER INFORMATION	57
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	58
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	59
ITEM 16.	FORM 10-K SUMMARY	61
	SIGNATURES	62

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GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:

AC	Alternating Current
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by FASB
Baseload plant	A power generation facility used to meet some or all of a given region’s continuous energy demand, producing energy at a constant rate.
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation, the Parent of Black Hills Power, Inc.
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of our utility company as well as our utility affiliates
Black Hills Energy South Dakota Electric	Includes Black Hills Power’s operations in South Dakota, Wyoming and Montana
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of BHC (doing business as Black Hills Energy South Dakota)
Black Hills Service Company	Black Hills Service Company LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Energy Wyoming Electric	Includes Cheyenne Lights electric utility operations
CFTC	United States Commodity Futures Trading Commission
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of BHC
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility in Cheyenne, Wyoming, jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Prairie was placed into commercial service on October 1, 2014.
City of Gillette	Gillette, Wyoming
Cooling degree day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
CPP	Clean Power Plan
CT	Combustion turbine
DC	Direct current
DSM	Demand Side Management
ECA	Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers.
EIA	Environmental Improvement Adjustment
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FDIC	Federal Depository Insurance Corporation
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gases

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Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
Happy Jack	Happy Jack Wind Farm, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
IRS	Internal Revenue Service
kV	Kilovolt
LIBOR	London Interbank Offered Rate
MAPP	Mid-Continent Area Power Pool
MATS	Utility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
MDU	Montana Dakota Utilities Company
MEAN	Municipal Energy Agency of Nebraska
Moody’s	Moody’s Investor Services, Inc.
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
N/A	Not Applicable
Native load	Energy required to serve customers within our service territory
NAV	Net Asset Value
NERC	North American Electric Reliability Corporation
NOL	Net Operating Loss
NOAA	National Oceanic and Atmospheric Administration
NOAA Climate Normals	This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.
NOx	Nitrogen Oxide
OPEB	Other Post-Employment Benefits
OSHA	Occupational Safety and Health Organization
PacifiCorp	PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway
Peak System Load	Peak system load represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.
PPA	Power Purchase Agreement
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
SO2	Sulfur Dioxide
SourceGas	SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired by BHC on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
South Dakota Electric	Includes Black Hills Power operations in South Dakota, Wyoming and Montana
S&P	Standard & Poor’s Rating Services
Spinning Reserve	Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission outages.

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TCA	Transmission Cost Adjustment - adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017
TFA	Transmission Facility Adjustment
Thunder Creek	Thunder Creek Gas Services, LLC
WECC	Western Electricity Coordinating Council
Winter Storm Atlas	An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, LLC
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, is owned 80% by PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric	Includes Cheyenne Light’s electric utility operations

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PART I

Forward-Looking Information

This Form 10-K contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, we may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. Our expectations, beliefs and projections are expressed in good faith and we believe we have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in our records and other data available from third parties. Nonetheless, our expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of us are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.

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ITEMS 1 and 2.    BUSINESS AND PROPERTIES

General

Black Hills Power (“the Company,” “we,” “us” and “our”) is a regulated electric utility incorporated in South Dakota, doing business as BHE - SD Electric and serving customers in South Dakota, Wyoming and Montana. We began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation (“Parent”). Engaging in the generation, transmission and distribution of electricity provides a solid foundation of revenues, earnings and cash flow that support our capital expenditures, dividends to our Parent, and our overall performance and growth.

As of December 31, 2017, our ownership interests in electric generation plants were as follows:

Unit	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Wygen III (a)	Coal	Gillette, WY	52%	57.2	2010
Neil Simpson II	Coal	Gillette, WY	100%	90.0	1995
Wyodak (b)	Coal	Gillette, WY	20%	72.4	1978
Cheyenne Prairie (c)	Gas	Cheyenne, WY	58%	55.0	2014
Neil Simpson CT	Gas	Gillette, WY	100%	40.0	2000
Lange CT	Gas	Rapid City, SD	100%	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, SD	100%	10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, SD	100%	80.0	1977-1979
				444.6

_______________________

(a) We operate Wygen III, a 110 MW mine-mouth coal-fired power plant and own a 52% interest in the facility. MDU owns a 25% interest and the City of Gillette owns the remaining 23% interest. WRDC furnishes all of the coal fuel supply for the plant.

(b) Wyodak is a 362 MW mine-mouth coal-fired power plant owned 80% by PacifiCorp and 20% by us. This baseload plant is operated by PacifiCorp and WRDC furnishes all of the coal fuel supply for 100% of the plant.

(c) Cheyenne Prairie, a gas-fired power generation facility includes one combined-cycle, 95 MW unit that is jointly owned by Wyoming Electric (40 MW) and us (55 MW).

Distribution and Transmission. Our distribution and transmission system serves approximately 72,000 electric customers, with an electric transmission system of 1,264 miles of high voltage lines (greater than 69 kV) and 2,506 miles of lower voltage lines (69 kV or less). In addition, we jointly own 44 miles of high voltage lines with Basin Electric. Our service territory covers areas with a strong and stable economic base including western South Dakota, northeastern Wyoming and southeastern Montana. A majorityof our retail electric revenues in 2017 were generated in South Dakota. We are subject to state regulation by the SDPUC, the WPSC and the MTPSC.

The following are characteristics of our distribution and transmission business:

• We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, 2017 was comprised of 33% commercial, 25% residential, 11% contract wholesale, 5% wholesale off-system, 12% industrial and 14% municipal and other revenue.

• We own 35% of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western United States and eastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the MAPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. Our electric system is located in the WECC region. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids.

• We have firm point-to-point transmission access to deliver up to 50 MW of power on PacifiCorp’s transmission system to wholesale customers in the Western region through 2023.

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• We have firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming to serve our power sales contract with MDU through December 31, 2023, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.

Power Sales Agreements. We sell a portion of our current load under long-term contracts. Our key contracts include:

• MDU owns a 25% interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU.

• We have an agreement through December 31, 2023 under which we serve MDU with capacity and energy up to a maximum of 50 MW.

• The City of Gillette owns a 23% ownership interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement we will also provide the City of Gillette their operating component of spinning reserves.

• We have an agreement to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. The terms of the contract run from June 1 through May 31 for each interval listed below. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:

2018	20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2020	15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2022	12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023	10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

• An agreement from January 1, 2017 through December 31, 2021 to provide 50 MW of energy to Cargill (assigned to Macquarie on January 3, 2018) during heavy and light load timing intervals.

Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide approximately 445 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. We generated approximately 50% of our energy requirements in 2017 and purchased approximately 50% which was supplied under the following contracts:

• A PPA with PacifiCorp expiring in 2023, whereby we purchase 50 MW of coal-fired baseload power.

• A PPA with Wyoming Electric expiring in 2028, under which we will purchase up to 14.7 MW of wind energy through Wyoming Electric’s agreement with Happy Jack.

• A PPA with Wyoming Electric expiring in 2029, under which we will purchase up to 20 MW of wind energy through Wyoming Electric’s agreement with Silver Sage.

• A Generation Dispatch Agreement with Wyoming Electric that requires us to purchase all of Wyoming Electric’s excess energy.

Since 1995, we have been a net producer of energy. Our 2017 winter peak system load was 402 MW and our 2017 summer peak system load was 447 MW. None of our generation is restricted by hours of operation, thereby providing us the ability to generate power to meet demand whenever necessary and economically feasible. We have historically optimized the utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market, and through short-term sales contracts primarily in the WECC and MAPP regions. Our 220 MW of low-cost, coal-fired resources supports most of our native load requirements and positions us for wholesale off-system sales.

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Operating Agreements

Horizon Point Agreement - We have an arrangement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric.  This cost allocation, includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.

Related-party Gas Transportation Service Agreement - We have a gas transportation service agreement with Wyoming Electric in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

Shared Services Agreement- We have a shared services agreement with Wyoming Electric and Black Hills Wyoming whereby each entity charges for the use of assets and the performance of services being used by, or performed for, an affiliate entity.

Jointly Owned Facilities - We are parties to an agreement with the City of Gillette and MDU for joint ownership of Wygen III. We charge the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant.

Regulations

Regulatory Accounting

We follow accounting for regulated utility operations and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions in which we operate. If rate recovery becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our regulated operations. In the event we determine that we no longer meet the accounting criteria for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations of an amount that could be material.

Rate Regulation

The following table illustrates certain enacted regulatory information with respect to the states in which we operate:

Jurisdic-tion	Authorized Rate of Return on Equity	Authorized Return on Rate Base	Authorized Capital Structure Debt/Equity	Authorized Rate Base (in millions)	Effective Date	Additional Tariffed Mechanisms	Percentage of Off-System Sale Profits Shared with Customers
SD	Global Settlement	7.76%	Global Settlement	$543.9	10/2014	ECA,TCA, Energy Efficiency Cost Recovery/ DSM	70%
SD		7.76%			5/2014	Transmission Facility Adjustment (TFA)	N/A
SD		7.76%			6/2011	Environmental Improvement Adjustment Tariff (EIA)	N/A
WY	9.9%	8.13%	46.7%/53.3%	$46.8	10/2014	ECA	65%
FERC	10.8%	9.10%	43%/57%		2/2009	FERC Transmission Tariff	N/A

Rates for our retail electric service are subject to regulation by the SDPUC for customers in South Dakota, the WPSC for customers in Wyoming and the MTPSC for customers in Montana. Any changes in retail rates are subject to approval by the respective regulatory body. We have rate adjustment mechanisms in Wyoming and South Dakota which provide for pass-through of certain costs related to the purchase, production and/or transmission of electricity. We are also subject to the jurisdiction of FERC with respect to accounting practices and wholesale electricity sales. We have been granted market-based rate authority by FERC and are not required to file cost-based tariffs for wholesale electric rates. Rates charged by us for use of our transmission system are subject to regulation by FERC.

Some of the mechanisms we have in place include:

• An approved annual EIA tariff which recovers costs associated with generation plant environmental improvements. The EIA and TFA were suspended for a six-year period effective July 1, 2017. See Management’s Discussion and Analysis of Results of Operations in Item 7 of this Annual Report on Form 10-K for further information.

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• An annual adjustment clause which provides for the direct recovery of increased fuel and purchased power cost incurred to serve South Dakota customers. Additionally, the ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 100% of off-system power marketing operating income from the first $2 million of power marketing margin from short-term sales and a credit equal to 70% of power marketing margins from short-term sales in excess of the first $2 million. South Dakota Electric retains the additional 30%. The ECA methodology allows us to directly assign renewable resources and firm purchases to the customer load. In Wyoming, a similar fuel and purchased power cost adjustment is also in place.

• We have an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of our open access transmission tariff.

Common Use System (CUS). The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2018 the annual revenue requirement increased by $3.3 million and included estimated weighted average capital additions of $45 million for 2017 and 2018. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year.

State Regulation

Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage us to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. At December 31, 2017, we were subject to the following renewable energy portfolio standards or objectives:

• South Dakota. In 2015, South Dakota adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources.

• Montana. Montana has established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, the Montana Legislature adopted legislation that excluded us from all renewable portfolio standard requirements under Senate Bill 164, primarily due to the very low number of customers we have in Montana and the relatively high cost of meeting the renewable requirements.

• Wyoming. Wyoming currently has no renewable energy portfolio standard.

Absent a specific renewable energy mandate in South Dakota, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers. Portfolio standards may continue to increase the power supply costs of our electric utility operations. Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to secure full recovery of the costs we pay to be in compliance with standards or objectives. We cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.

Environmental Matters

Water Issues. Our facilities are subject to a variety of state and federal regulations governing existing and potential water/ wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through EPA’s surface water discharge and storm water permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA proposed effluent limitation guidelines and standards on June 7, 2013 and published the final rule on November 3, 2015. The terms of this new regulation impact the next permit renewal, which will be in 2020. Additionally, the EPA regulates surface water oil pollution through its oil pollution prevention regulations. All of our facilities subject to these regulations have compliant prevention plans in place.

Short-term Emission Limits.The EPA and State Air Quality Programs implemented short-term emission limits for coal and natural gas-fired generating units during normal and start-up operating scenarios for Sulfur Dioxide (SO2), Nitrogen Oxide (NOx) and Opacity. The limits pertain to emissions during start-up periods and upset conditions such as mechanical

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malfunctions. State and federal regulatory agencies typically excuse short-term emissions exceedances if they are reported and corrected immediately or if it occurs during start-up.

We proactively manage this requirement by improving maintenance efforts and installing additional pollution control systems to control SO2 emission short-term excursions during start-up. These actions have nearly eliminated our short-term emission limit compliance risk while plant availability remained above 90% for all four of our coal-fired plants at the Neil Simpson Complex. To eliminate the remaining potential for exceedances, an innovative trip logic mechanism was implemented to shut the power plant down if a predicted emission limit is to be exceeded. Similar efforts have been taken and similar results achieved with our natural gas fired combustion turbine sites as well.

Regional Haze (Impacts to the Wyodak Power Plant). The EPA Regional Haze rule was promulgated to improve visibility in our National Parks and Wilderness Areas.The State of Wyoming proposed controls in its Regional Haze State Implementation Plan (SIP) which allowed Pacificorp to install low-NO_x burners in its Wyodak Plant. The EPA did not agree with the State of Wyoming’s determination and overruled it in a Federal Implementation Plan (FIP). The State of Wyoming and other interested parties are challenging the EPA’s determination. If the challenge is unsuccessful, additional capital investment would be necessary to bring the Wyodak Plant into compliance. Our share of this capital investment would be approximately $40 million.

Clean Power Plan.The EPA was directed to repeal, revise, and replace the Clean Power Plan rule. The EPA issued two public notices in the Federal Register late in 2017. The first identified the EPA’s intent to repeal the rule and the second was issued to seek public input on proposals to replace the CPP with an Advanced Notice of Proposed Rule Making (ANPRM). Natural gas and renewable generation industries are pushing the EPA to replace the current rule. We will continue to monitor and comment on the proposals and take appropriate action related to any new or modified rules.

Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies. We assess risk annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. For additional information on environmental matters, see Item 1A and Note 11 of the Notes to Financial Statements in this Annual Report on Form 10-K.

New Accounting Pronouncements

See Note 1 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2017 or pending adoption.

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ITEM 1A.    RISK FACTORS

The nature of our business subjects us to a number of uncertainties and risks. The following risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company. These important factors and other matters discussed herein could cause our actual results or outcomes to differ materially.

Regulatory commissions may refuse to approve some or all of the utility rate increases we may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore are not recoverable.

Our regulated electric operations are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our direct and allocated borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

To some degree, we are permitted to recover certain costs (such as increased fuel, purchased power and transmission costs, as applicable) without having to file a rate case. To the extent we are able to pass through such costs to customers and a state public utility commission subsequently determines that such costs should not have been paid by customers, we may be required to refund such costs to customers. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.

Our financial performance depends on the successful operation of our facilities. If the risks involved in our operations are not appropriately managed or mitigated, our operations may not be successful and this could adversely affect our results of operations.

Operating electric generating facilities and electric distribution sustems involves risks, including:

• Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity that we sell to our retail and wholesale customers. If transmission is interrupted, our ability to sell or deliver product and satisfy our contractual obligations may be hindered;

• Interruptions to supply of fuel and other commodities used in generation and distribution. We purchase fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations, which could limit our ability to operate our facilities;

• Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical service facilities and equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;

• Operational limitations imposed by environmental and other regulatory requirements;

• Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak plant;

• Labor relations.

• Our ability to transition and replace our retirement-eligible employees;

• Inability to recruit and retain skilled technical labor;

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• Disruption in the functioning of our information technology and network infrastructure which are vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business functions; and

Changes in the interpretation of the TCJA could adversely affect us.

On December 22, 2017, the TCJA was signed into law, significantly reforming the U.S. Internal Revenue Code. The TCJA, among other things, includes a decrease in the U.S. federal corporate tax rate from 35% to 21%, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, and modifies or repeals many business deductions and credits. The new tax law contains several provisions that impacted our 2017 financial results and will impact the Company into the future. As allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Company has recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation, for which the impacts could not be finalized upon issuance of the Company’s financial statements, but reasonable estimates could be determined.

In accordance with ASC 740, the enactment of the law on December 22, 2017 required revaluation of federal deferred tax assets and liabilities using the new lower corporate statutory tax rate of 21%. As a result of the revaluation, deferred tax liabilities were reduced by approximately $103 million. Of the $103 million, approximately $97 million is related to our regulated utilities and was reclassified to a regulatory liability. This regulatory liability will generally be amortized over the remaining life of the related assets using the normalization principles as specifically prescribed in the TCJA. The revaluation of deferred tax assets and liabilities to the 21% federal corporate tax rate that are not subject to the regulatory construct resulted in a one-time, non-cash, income tax benefit of approximately $6 million in 2017.

We are working with utility regulators in each of the states we serve to provide benefits of tax reform to our customers.

The lower tax rate effective January 1, 2018, will negatively impact the Company’s cash flows for the next several years.

If we are unable to obtain reasonable outcomes with our utility regulators in passing benefits of the TCJA back to customers, or if our interpretations on the provisions of interest deductibility in the TCJA change, our results of operations, financial position and cash flows could be materially impacted.

Construction, expansion, refurbishment and operation of power generating and transmission facilities involve significant risks which could reduce profitability.

The construction, expansion, refurbishment and operation of power generating and transmission facilities involve many risks, including:

• The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;

• Contractual restrictions upon the timing of scheduled outages;

• The cost of supplying or securing replacement power during scheduled and unscheduled outages;

• The unavailability or increased cost of equipment;

• The cost of recruiting and retaining or the unavailability of skilled labor;

• Supply interruptions, work stoppages and labor disputes;

• Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;

• Opposition by members of the public or special-interest groups;

• Weather interferences;

• Availability and cost of fuel supplies;

• Unexpected engineering, environmental or geological problems; and

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• Unanticipated cost overruns.

The ongoing operation of our facilities involves many of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions, emerging technologies or responses to price increases.

Our revenues, results of operations and financial condition are impacted by demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives.  Each of these factors could materially affect our results of operations, financial position and cash flows.

Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations.

We rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to our natural gas-fired power plants. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.

National and regional economic conditions may cause increased counterparty risk, late payments and uncollectible accounts, which could adversely affect our results of operations, financial position and liquidity.

A future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our non-regulated customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, cost of capital and other operating costs.

Our credit rating on our First Mortgage Bonds is A1 by Moody’s, A- by S&P and A by Fitch. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt and to complete new financings on reasonable terms, or at all. A credit rating downgrade could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades.

Prices for some of our products and services as well as a portion of our operating costs are volatile and may cause our revenues and expenses to fluctuate significantly.

A portion of our net income is attributable to sales of contract and off-system wholesale electricity. Energy prices are influenced by many factors outside our control, including, among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions, and the rules, regulations and actions of system operators in those markets. Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets may be subject to significant, unpredictable price fluctuations over relatively short periods of time.

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Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events that could give rise to additional costs and cause a substantial loss to us.

Inherent in our electricity transmission and distribution activities are a variety of hazards and operating risks, such as fires, releases of hazardous materials, explosions and operational problems. These events could impact the safety of employees or others and result in injury or loss of human life, and cause significant damage to property or natural resources (including public lands), environmental pollution, impairment of our operations, and substantial financial losses to us. Particularly for our transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the damages resulting from any such events could be substantial. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events not fully covered by our insurance could have a material adverse effect on our financial position, results of operations or cash flows.

Operating results can be adversely affected by variations from normal weather conditions.

Our utility business is a seasonal business and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Unusually mild summers and winters therefore could have an adverse effect on our results of operations, financial condition and cash flows.

Our business is located in areas that could be subject to seasonal natural disasters such as severe snow and ice storms, flooding and wildfires. These factors could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs associated with these events. We may not be able to recover the costs incurred in restoring transmission and distribution property following these natural disasters through a change in our regulated rates thereby resulting in a negative impact on our results of operations, financial condition and cash flows.

The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, and any failure to do so, could adversely affect our results of operations, financial position or liquidity.

Our business is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations can require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.

We may not be successful in recovering capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent in environmental laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities. Although it is not expected that the costs to comply with current environmental regulations will have a material adverse effect on our financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.

Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting insurance businesses, international, national, state or local events and company-specific events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject, including but not limited to environmental hazards, fire-related liability from natural events or inadequate facility maintenance, distribution property losses and cyber-security risks.

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Municipal governments may seek to limit or deny franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.

Municipal governments within our utility service territories possess the power of condemnation and could establish a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.

Federal and state laws concerning GHG regulations and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. Recent developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants may result in more stringent emission limitations, which could have a material impact on our costs of operations. Various pending or final state and EPA regulations that will impact our facilities are also discussed in Item 1 of this Annual Report on Form 10-K under the section “Business and Properties.”

Due to uncertainty as to the final outcome of federal climate change legislation, legal challenges, state clean power plan developments or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, cash flows or financial position.

New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or reduction of load of coal-generating facilities and potential increased load of our combined cycle natural gas-fired units. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.

Increased risks of regulatory penalties could negatively impact our results of operations, financial position or liquidity.

Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, CFTC, EPA, OSHA, and SEC may impose significant civil and criminal penalties to enforce compliance requirements relative to our business, which could have a material adverse effect on our operations and/or our financial results.

Certain Federal laws, including the Migratory Bird Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation, and wind, could be restricted or delayed, or we could be required to implement expensive mitigation measures.

An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.

Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal controls. During their assessment of these controls, management may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to operate our business or access sources of liquidity.

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Threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our businesses, or the businesses of third parties, may impact our operations in unpredictable ways.

Terrorist acts or other similar events could harm our business by limiting its ability to generate, purchase or transmit power and by delaying the development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.

The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources and could adversely affect our reputation among customers and the public.

A cyber attack may disrupt our operations, or lead to a loss or misuse of confidential and proprietary information and create a potential liability.

We use and operate sophisticated information technology systems and network infrastructure. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees. Cyber attacks targeting our electronic control systems used at our generating facilities and for electric distribution systems, could result in a full or partial disruption of our electric operations. Cyber attacks targeting other key information technology systems could further add to a full or partial disruption of our operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data as a result of a cyber attack could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.

We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective due to the evolving nature and sophistication of cyber attacks. Despite our implementation of security measures and safeguards, all of our information technology systems are vulnerable to disability, failures or unauthorized access, including cyber attacks. If our information technology systems were to fail or be breached by a cyber attack or a computer virus and be unable to recover in a timely way, we would be unable to fulfill critical business functions and sensitive confidential and other data could be compromised which could have a material adverse effect not only on our financial results, but on our public reputation as well.

Market performance or changes in other assumptions could require us to make significant unplanned contributions to our pension plan and other postretirement benefit plans. Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.

As discussed in Note 8 to the to the Financial Statements in this Annual Report on Form 10-K, we have a defined benefit pension plan (the pension plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria), defined post-retirement healthcare plan and a non-qualified retirement plan that cover certain eligible employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations.

Increasing costs associated with our health care plans and other benefits may adversely affect our results of operations, financial position or liquidity.

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Significant regulatory developments have, and likely will continue to, require changes to our current employee benefit plans and in our administrative and accounting processes, as well as changes to the cost of our plans, and the increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

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Our electric utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there can be no assurance that the state public utility commissions will allow recovery.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub caption within Item 8, Note 11, “Commitments and Contingencies,” of our Notes to Financial Statements in this Annual Report on Form 10-K.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER

MATTERS

All of our common stock is held by our parent company, Black Hills Corporation. Accordingly, there is no established trading market for our common stock.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

Significant Events

Settlement

On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes a suspension of both the TFA and the EIA, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, is being amortized over the moratorium period. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million.

The June 16, 2017 settlement had no impact to base rates.

Transmission

Construction was completed on the 144 mile-long transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

In our Management’s Discussion and Analysis of Results of Operations, gross margin is calculated as operating revenue less cost of fuel and purchased power. Our gross margin is impacted by the fluctuations in power purchases and natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

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For the years ended December 31,	2017			Variance			2016			Variance			2015
	(in thousands)
Revenue	$	288,433		$	20,801		$	267,632		$	(10,232	)	$	277,864
Fuel and purchased power	87,638			12,612			75,026			(8,313		)	83,339
Gross margin	200,795			8,189			192,606			(1,919		)	194,525
Operating expenses	116,969			9,943			107,026			415			106,611
Operating income	83,826			(1,754		)	85,580			(2,334		)	87,914
Interest expense, net	(20,380		)	(188		)	(20,192		)	982			(21,174		)
Other income, net	1,980			(298		)	2,278			1,244			1,034
Income tax expense	(14,128		)	8,400			(22,528		)	72			(22,600		)
Net income	$	51,298		$	6,160		$	45,138		$	(36	)	$	45,174

2017 Compared to 2016

Gross marginincreased over the prior year reflecting a $5.6 million increase in rider revenues primarily related to transmission investment recovery. Higher cooling and heating degree days and higher customer counts were slightly offset by lower usage per customer and lower commercial and industrial demand. Both heating and cooling degree days’ variances from normal were favorable when compared to prior year comparisons to normal.

Operations and maintenanceincreased primarily due to $4.0 million in higher vegetation management expenses, $3.2 million in increased maintenance costs from higher outages, higher employee costs as a result of prior year integration activities and transition expenses charged to our Parent Company related to its prior year acquisition of SourceGas, and increased amortization expenses as a result of the SDPUC settlement.

Interest expense, net and other income, net were comparable to the same period in the prior year.

Income tax expense: The effective tax rate decreased in 2017 due to a tax benefit of $6.0 million resulting from re-measurement of net deferred tax liabilities in accordance with the ASC 740 and the enactment of the Tax Cuts and Jobs Act on December 22, 2017. This benefit was primarily related to the repricing of net operating losses and other tax basis items not included in the ratemaking construct.

2016 Compared to 2015

Gross margindecreased primarily due to a prior year return on invested capital of $1.2 million from a rate case, and a $1.3 million decrease due to third party billing true-ups related to the current and prior years, partially offset by the weather impact from the increase in cooling degree days compared to the same period in the prior year.

Operations and maintenanceincreased primarily due to higher depreciation expense driven by additional plant in service compared to the same period in the prior year, partially offset by lower employee costs driven by a change in operating expense allocations impacting us as a result of our Parent Company integrating the acquired SourceGas utilities.

Interest expense, netdecreased primarily due to higher AFUDC income in the current year driven by higher construction work-in-process balances compared to the same period in the prior year.

Other income, net was comparable to the prior year.

Income tax expense: The 2016 effective tax rate is comparable to the prior year.

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The following tables provide certain electric utility operating statistics for the years ended December 31:

Revenue (in thousands)
Customer Base	2017		Percentage Change		2016		Percentage Change		2015
Residential	$	72,764	1	%	$	72,084	(1	)%	$	72,659
Commercial	96,531		(1	)%	97,579		(3	)%	100,511
Industrial	33,464		—	%	33,409		—	%	33,336
Municipal	3,707		—	%	3,705		2	%	3,626
Total retail sales	206,466		—	%	206,777		(2	)%	210,132
Contract wholesale (a)	30,435		79	%	17,037		(3	)%	17,537
Wholesale off-system	14,271		(8	)%	15,431		(34	)%	23,241
Total electric sales	251,172		5	%	239,245		(5	)%	250,910
Other revenue (b)	37,261		31	%	28,387		5	%	26,954
Total revenue	$	288,433	8	%	$	267,632	(4	)%	$	277,864

_________________________

(a) Increase in 2017 is primarily driven by resource needs from a new 50 MW power sales agreement effective January 1, 2017.

(b) Increase in 2017 is primarily due to higher transmission revenues.

Quantities sold (MWh)
Customer Base	2017	Percentage Change		2016	Percentage Change		2015
Residential	526,730	1	%	520,798	—	%	521,828
Commercial	769,463	(2	)%	783,319	(1	)%	792,466
Industrial	430,301	—	%	429,912	—	%	429,140
Municipal	33,272	(1	)%	33,591	5	%	31,924
Total retail sales	1,759,766	—	%	1,767,620	—	%	1,775,358
Contract wholesale (a)	722,659	193	%	246,630	(5	)%	260,893
Wholesale off-system (b)	509,962	(15	)%	597,695	(29	)%	837,120
Total electric sales	2,992,387	15	%	2,611,945	(9	)%	2,873,371
Losses and company use (c)	195,005	26	%	155,370	(7	)%	167,332
Total energy	3,187,392	15	%	2,767,315	(9	)%	3,040,703

_________________________

(a) Increase in 2017 is primarily driven by resource needs from a new 50 MW power sales agreement effective January 1, 2017.

(b) Decrease in 2017 was primarily driven by commodity prices that impacted power marketing sales.

(c) Includes company uses, line losses, and excess exchange production.

We own approximately 445 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.

Regulated Power Plant Fleet Availability	2017		2016		2015
Coal-fired plants (a)	86.0	%	86.5	%	91.1	%
Other plants	96.4	%	98.0	%	96.0	%
Total availability	91.6	%	93.0	%	93.9	%

_________________________

(a) Both 2017 and 2016 included outages. 2017 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 2016 included a planned outage at Wygen III and an extended planned outage at Wyodak.

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Quantities Generated and Purchased (MWh)	2017	Percentage Change		2016	Percentage Change		2015
Coal-fired	1,485,254	1	%	1,467,403	(5	)%	1,537,744
Natural Gas (a)	96,661	(18	)%	118,467	46	%	80,944
Total Generated	1,581,915	—	%	1,585,870	(2	)%	1,618,688
Purchased (a) (b)	1,605,477	36	%	1,181,445	(17	)%	1,422,015
Total Generated and Purchased (b)	3,187,392	15	%	2,767,315	(9	)%	3,040,703

_________________________

(a) Change in 2017 is driven by the ability to purchase excess generation in the open market at a lower cost than to generate.

(b) Increase in 2017 is driven primarily by resource needs from a new 50 MW power sales agreement effective January 1, 2017.

Heating and Cooling Degree Days	2017		2016		2015
Actual
Heating degree days	6,870		6,402		6,521
Cooling degree days	709		646		577
Variance from 30-year average (a)
Heating degree days	(4	)%	(10	)%	(8	)%
Cooling degree days	11	%	(4	)%	(14	)%

______________

(a) 30-year average is from NOAA Climate Normals

Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. The following table represents our credit rating from each agency’s review which were in effect at December 31, 2017:

Rating Agency	Rating
S&P	A-
Moody’s	A1
Fitch	A

Critical Accounting Estimates

We prepare our financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results.

The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and Summary of Significant Accounting Policies” of the Notes to Financial Statements in this Annual Report on Form 10-K.

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Pension and Other Postretirement Benefits

As described in Note 8 of the Financial Statements in this Annual Report on Form 10-K, we have a defined benefit pension plan, a post-retirement healthcare plan and a non-qualified retirement plan. A Master Trust was established for the investment of assets of the defined benefit pension plan.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, health care cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

The pension benefit cost for 2018 for our non-contributory funded pension plan is expected to be approximately $1.3 million compared to $0.6 million in 2017. The increase in pension benefit cost is driven primarily by an increase in the discount rate.

Beginning in 2016, the Company changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. The new method used the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Prior to 2016, the service and interest costs were determined using a single weighted-average discount rate based on hypothetical AA Above Median yield curves used to measure the benefit obligation at the beginning of the period. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income.

The Company changed to the new method to provide a more precise measure of service and interest costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The Company accounted for this change as a change in estimate prospectively beginning in 2016.

The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:

		December 31,
Assumptions	Percentage Change	2017 Increase/(Decrease) PBO/APBO (a)	2018  Increase/(Decrease) Expense - Pretax
Pension
Discount rate (b)	+/- 0.5	(3,995)/4,402	(665)/639
Expected return on assets	+/- 0.5	N/A	(284)/284
OPEB
Discount rate (b)	+/- 0.5	(260)/284	9/(9)
Expected return on assets	+/- 0.5	N/A	N/A
Health care cost trend rate (b)	+/- 1.0	186/(174)	21/(20)

__________________________

(a) Projected benefit obligation (PBO) for pension plans and accumulated postretirement benefit obligation (APBO) for OPEB plans.

(b) Impact on service cost, interest cost and amortization of gains or losses.

23

Regulation

Our utility operations are subject to regulation with respect to rates, service area, accounting, and various other matters by state and federal regulatory authorities. The accounting regulations provide that rate-regulated public utilities account and report assets and liabilities consistent with the economic effects of the manner in which independent third-party regulators establish rates. Regulatory assets generally represent incurred or accrued costs that have been deferred when future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable for recovery in current rates or in future rate proceedings.

Income Taxes

We file a federal income tax return with other members of the Parent consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. As such, the Company has revalued the deferred income taxes at the 21% federal tax rate as of December 31, 2017 and as a result, deferred tax assets and liabilities were reduced by approximately $103 million. Of the $103 million, approximately $97 million is related to our regulated utilities and was reclassified to a regulatory liability. This regulatory liability will generally be amortized over the remaining life of the related assets using the normalization principles as specifically prescribed in the TCJA.

As allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Company has recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Company’s financial statements, but reasonable estimates could be determined.  The provisional amounts may change as the Company finalizes the analysis and computations and such changes could be material to the Company’s future results of operations, cash flows or financial position.

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our financial statements.

See Note 6 of the Notes to Financial Statements in this Annual Report on Form 10-K for additional information.

24

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

	Page
Management’s Report on Internal Controls Over Financial Reporting	26
Report of Independent Registered Public Accounting Firm	27
Statements of Income for the three years ended December 31, 2017	28
Statements of Comprehensive Income (Loss) for the three years ended December 31, 2017	29
Balance Sheets as of December 31, 2017 and 2016	30
Statements of Cash Flows for the three years ended December 31, 2017	32
Statements of Common Stockholder’s Equity for the three years ended December 31, 2017	33
Notes to Financial Statements	34

25

Management’s Report on Internal Control over Financial Reporting

Management of Black Hills Power is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed 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.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017, based on the criteria set forth in Internal Control - Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, 2017.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting because this requirement is inapplicable to companies such as ours which are known as non-accelerated filers.

Black Hills Power

26

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Black Hills Power, Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Black Hills Power, Inc. (the "Company") as of December 31, 2017 and 2016, the related statements of income, comprehensive income,common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2017, the related notes, and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 26, 2018

We have served as the Company’s auditor since 2002.

27

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME

Years ended December 31,	2017			2016			2015
	(in thousands)
Revenue	$	288,433		$	267,632		$	277,864
Operating expenses:
Fuel and purchased power	87,638			75,026			83,339
Operations and maintenance	74,064			66,384			68,088
Depreciation and amortization	35,862			34,030			32,552
Taxes - property	7,043			6,612			5,971
Total operating expenses	204,607			182,052			189,950
Operating income	83,826			85,580			87,914
Other income (expense):
Interest expense	(22,421		)	(22,908		)	(22,337		)
AFUDC - borrowed	1,137			1,140			506
Interest income	904			1,576			657
AFUDC - equity	2,165			2,165			918
Other expense	(300		)	(185		)	(117		)
Other income	115			298			233
Total other income (expense)	(18,400		)	(17,914		)	(20,140		)
Income before income taxes	65,426			67,666			67,774
Income tax expense	(14,128		)	(22,528		)	(22,600		)
Net income	$	51,298		$	45,138		$	45,174

The accompanying notes to financial statements are an integral part of these financial statements.

28

BLACK HILLS POWER, INC.

STATEMENTS OF COMPREHENSIVE INCOME

Years ended December 31,	2017			2016			2015
	(in thousands)
Net income	$	51,298		$	45,138		$	45,174
Other comprehensive income (loss):
Benefit plan liability adjustments - net gain (loss) (net of tax of $50, $27 and $(36), respectively)	(94		)	(50		)	68
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(30), $(29) and $(33), respectively)	56			53			61
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(22), $(22) and $319, respectively)	42			42			383
Other comprehensive income	4			45			512
Comprehensive income	$	51,302		$	45,183		$	45,686

See Note 7 for additional disclosure related to comprehensive income.

The accompanying notes to financial statements are an integral part of these financial statements.

29

BLACK HILLS POWER, INC.

BALANCE SHEETS

As of December 31,	2017			2016
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	16		$	234
Receivables - customers, net	29,050			30,614
Receivables - affiliates	5,664			9,526
Other receivables, net	196			351
Money pool notes receivable	—			28,409
Materials, supplies and fuel	23,443			22,389
Regulatory assets, current	18,993			18,119
Other current assets	4,528			3,876
Total current assets	81,890			113,518
Investments	4,926			4,841
Property, plant and equipment	1,311,819			1,236,387
Less accumulated depreciation and amortization	(358,946		)	(338,828		)
Total property, plant and equipment, net	952,873			897,559
Other assets:
Regulatory assets, non-current	59,710			74,015
Other, non-current assets	3,747			3,816
Total other assets	63,457			77,831
TOTAL ASSETS	$	1,103,146		$	1,093,749

The accompanying notes to financial statements are an integral part of these financial statements.

30

BLACK HILLS POWER, INC.

BALANCE SHEETS

(Continued)

As of December 31,	2017			2016
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	14,766		$	14,158
Accounts payable - affiliates	25,653			31,799
Money pool note payable	13,397			—
Accrued liabilities	38,205			37,436
Regulatory liabilities, current	842			84
Total current liabilities	92,863			83,477
Long-term debt	339,895			339,756
Deferred credits and other liabilities:
Deferred income tax liabilities, net	110,618			211,443
Regulatory liabilities, non-current	148,013			53,866
Benefit plan liabilities	16,285			19,544
Other, non-current liabilities	1,240			1,001
Total deferred credits and other liabilities	276,156			285,854
Commitments and contingencies (Notes 4, 8, 9 and 11)
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416			23,416
Additional paid-in capital	39,575			39,575
Retained earnings	332,499			322,933
Accumulated other comprehensive loss	(1,258		)	(1,262		)
Total stockholder’s equity	394,232			384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,103,146		$	1,093,749

The accompanying notes to financial statements are an integral part of these financial statements.

31

BLACK HILLS POWER, INC.

STATEMENTS OF CASH FLOWS

Years ended December 31,	2017			2016			2015
	(in thousands)
Operating activities:
Net income	$	51,298		$	45,138		$	45,174
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	35,862			34,030			32,552
Deferred income taxes	1,004			20,690			7,690
AFUDC - equity	(2,165		)	(2,165		)	(918		)
Employee benefits	817			1,770			2,403
Other adjustments	2,429			391			232
Change in operating assets and liabilities -
Accounts receivable and other current assets	3,287			(3,963		)	(3,223		)
Accounts payable and other current liabilities	(7,254		)	6,175			20,455
Regulatory assets	978			(4,023		)	(3,839		)
Regulatory liabilities	—			—			(2,479		)
Contributions to defined benefit pension plan	(4,000		)	(820		)	—
Other operating activities	(1,853		)	(8,339		)	(5,680		)
Net cash provided by operating activities	80,403			88,884			92,367
Investing activities:
Property, plant and equipment additions	(79,566		)	(84,750		)	(56,795		)
Notes receivable from affiliate companies, net	—			(4,095		)	(36,687		)
Other investing activities	(861		)	(102		)	(128		)
Net cash (used in) investing activities	(80,427		)	(88,947		)	(93,610		)
Financing activities:
Notes payable from affiliate companies, net	(194		)	—			—
Other financing activities	—			—			(2		)
Net cash provided by (used in) financing activities	(194		)	—			(2		)
Net change in cash and cash equivalents	(218		)	(63		)	(1,245		)
Cash and cash equivalents beginning of year	234			297			1,542
Cash and cash equivalents end of year	$	16		$	234		$	297

See Note 10 for Supplemental Cash Flows information.

The accompanying notes to financial statements are an integral part of these financial statements.

32

BLACK HILLS POWER, INC.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

	2017			2016			2015
	(in thousands)
Common stock shares:
Balance beginning of year	23,416			23,416			23,416
Issuance of common stock	—			—			—
Balance end of year	23,416			23,416			23,416
Common stock amounts:
Balance beginning of year	$	23,416		$	23,416		$	23,416
Issuance of common stock	—			—			—
Balance end of year	$	23,416		$	23,416		$	23,416
Additional paid-in capital:
Balance beginning of year	$	39,575		$	39,575		$	39,575
Issuance of common stock	—			—			—
Balance end of year	$	39,575		$	39,575		$	39,575
Retained earnings:
Balance beginning of year	$	322,933		$	330,295		$	313,622
Net income	51,298			45,138			45,174
Non-cash dividend to Parent company	(42,000		)	(52,500		)	(28,501		)
Adjustment for Transfer of Utility Money Pool	268			—			—
Balance end of year	$	332,499		$	322,933		$	330,295
Accumulated other comprehensive loss:
Balance beginning of year	$	(1,262	)	$	(1,307	)	$	(1,819	)
Other comprehensive (loss) income, net of tax	4			45			512
Balance end of year	$	(1,258	)	$	(1,262	)	$	(1,307	)
Total stockholder’s equity	$	394,232		$	384,662		$	391,979

The accompanying notes to financial statements are an integral part of these financial statements.

33

NOTES TO FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015

(1)    BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc., doing business as South Dakota Electric (the Company, “we,” “us” or “our”) is a regulated electric utility serving customers in South Dakota, Wyoming and Montana. We are a wholly-owned subsidiary of BHC or the Parent, a public registrant listed on the New York Stock Exchange.

Basis of Presentation

The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 3) and are prepared in accordance with GAAP.

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Regulatory Accounting

Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory

assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but

generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer

meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.

34

We had the following regulatory assets and liabilities as of December 31 (in thousands):

	Maximum Amortization (in years)	2017		2016
Regulatory assets
Unamortized loss on reacquired debt (a)	7	$	1,534	$	1,815
Deferred taxes on AFUDC (b)	45	5,095		9,367
Employee benefit plans (c)	12	19,465		20,100
Deferred energy and fuel cost adjustments - current (a)	1	14,066		18,119
Deferred gas cost adjustments (a)	1	5,536		4,897
Deferred taxes on flow through accounting (a)	54	7,579		12,545
Decommissioning costs, net of amortization (d)	6	10,252		12,456
Vegetation management, net of amortization (d)	6	12,669		12,109
Other regulatory assets (a) (d)	6	2,507		726
		$	78,703	$	92,134
Regulatory liabilities
Cost of removal for utility plant (a)	61	$	44,056	$	41,541
Employee benefit plans and related deferred taxes (c)	12	6,808		12,304
Excess deferred income taxes (c) (e)	40	97,101		—
Other regulatory liabilities (c)	13	890		105
		$	148,855	$	53,950

____________________

(a)Recovery of costs but we are not allowed a rate of return.

(b) In addition to recovery of costs, we are allowed a rate of return.

(c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

(d) In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million are being amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million.

(e) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018.

Regulatory assets represent items we expect to recover from customers through probable future increases in rates.

Unamortized Loss on Reacquired Debt - The early redemption premium on reacquired debt is being amortized over the remaining term of the original bonds.

Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset itself is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity, and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income. In addition, this regulatory asset includes the income tax effect of the

35

adjustment required under accounting for compensation-defined benefit plans to record the full pension and post-retirement benefit obligations. Such amounts have been grossed-up to reflect the revenue requirement associated with a rate regulated environment.

Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. We file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by the applicable state utility commissions.

Deferred Gas Cost Adjustment - We have GCA provisions that allow us to pass the cost of gas on to our customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. We file periodic estimates of future gas costs based on market forecasts with state utility commissions

Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes.

Decommissioning Costs - We received approval in 2014 for regulatory treatment on the remaining net book values and decommissioning costs of our decommissioned coal plants.

Vegetation Management Costs - We received approval in 2013 for regulatory treatment on vegetation management maintenance costs for our distribution system rights-of-way.

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Cost of Removal for Utility Plant - Cost of removal for utility plant represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.

Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.

Excess Deferred Income Taxes - The revaluation of our deferred tax assets and liabilities due to the passage of the TCJA is recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable consists of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs or payment received.

We maintain an allowance for doubtful accounts which reflects our best estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

36

Following is a summary of accounts receivable as of December 31 (in thousands):

	2017			2016
Accounts receivable, trade	$	15,994		$	16,972
Unbilled revenue	13,280			13,799
Less Allowance for doubtful accounts	(224		)	(157		)
Accounts receivable, net	$	29,050		$	30,614

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers are recorded on a net basis (excluded from Revenue).

Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Balance Sheets.

For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement.

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are recorded using the weighted-average cost method.

Deferred Financing Costs

Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities.

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Balance Sheets.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated electric properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be

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made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.1% in 2017, 2.2% in 2016 and 2.3% in 2015.

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Balance Sheets as of December 31 (in thousands):

	2017		2016
Accrued employee compensation, benefits and withholdings	$	4,305	$	4,783
Accrued property taxes	5,930		5,522
Accrued income taxes	17,472		17,069
Customer deposits and prepayments	4,863		2,825
Accrued interest	4,708		4,614
Other (none of which is individually significant)	927		2,623
Total accrued liabilities	$	38,205	$	37,436

Derivatives and Hedging Activities

The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and changes in the derivative instruments be recognized in earnings unless specific hedge accounting criteria are met and designated accordingly, including the normal purchase and normal sales exception.  Changes in the fair value for derivative instruments that do not meet this exception are recognized in the income statement as they occur.

From time to time we utilize risk management contracts including interest rate swaps to fix the interest on variable rate debt, or to lock in the Treasury yield component associated with anticipated issuance of senior notes.  For swaps that settled in connection with the issuance of senior debt, the effective portion is deferred as a component in AOCI and recognized as interest expense over the life of the senior note. As of December 31, 2017, we have no outstanding interest rate swap agreements.

Revenues and expenses on contracts that qualify as derivatives may be elected to be accounted for under the normal purchases and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting.  Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric operations, we enter into contracts to buy and sell energy to meet the requirements of our customers.  These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery.  If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exception, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging.

Fair Value Measurements

Assets and liabilities are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical

unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or

listed derivatives.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for

identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the

asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other

means.

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Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs

reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would

use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value

measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable

such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the

availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more

observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively

impacting the availability of observable pricing inputs.

Additional information is included in Note 5.

Income Taxes

We file a federal income tax return with other members of the Parent’s consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017.

We use the deferral method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Statements of Income.

We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other, non-current liabilities on the accompanying Balance Sheets. See Note 6 for additional information.

Recently Issued Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

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We have implemented this standard effective January 1, 2018 on a modified retrospective basis. We have completed our assessment of all revenue from existing contracts with customers and there is no significant impact to our revenue recognition practices, financial position, results of operations or cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term, generally limited to the services requested and received to date for such arrangements. For such arrangements, the performance obligation transfer of control and revenue recognition occurs when the electricity is delivered, consistent with the previous revenue recognition guidance. The same transfer of control and revenue recognition based on delivery principles also apply to our revenue contracts for wholesale and off-system power sales arrangements, and other non-regulated services. Therefore, we did not have a cumulative adjustment to Retained earnings or an impact on our revenue recognition policies as a result of the adoption of the new standard. The new standard will require us to provide more robust disclosures than required by previous guidance, including disclosures related to disaggregation of revenue into appropriate categories, performance obligations, and the judgments made in revenue recognition determinations.

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We have implemented this standard effective January 1, 2018. We will capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC to GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income, which are not expected to be material.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.We have implemented this standard effective January 1, 2018 on the retrospective transition method. This standard will not have a material impact on our financial position, results of operations or cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard.

We currently expect to adopt this standard on January 1, 2019 and anticipate electing the transition approach to not assess existing or expired land easements that were not previously accounted for as a lease. We continue to evaluate the impact of this

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new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and rights of way, pipeline laterals, purchase power agreements, and other industry-related areas. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes and systems.

(2)    PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31 consisted of the following (dollars in thousands):

				2017				2016
				Weighted				Weighted
				Average				Average	Lives (in years)
	2017			Useful Life (in years)	2016			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	587,323		46	$	576,833		46	40	54
Transmission	186,045			49	147,398			48	42	60
Distribution	375,214			46	364,304			46	21	62
Plant acquisition adjustment (a)	4,870			32	4,870			32	32	32
General	153,535			32	88,114			23	3	40
Total plant-in-service	1,306,987				1,181,519
Construction work in progress	4,832				54,868
Total electric plant	1,311,819				1,236,387
Less accumulated depreciation and amortization	(358,946		)		(338,828		)
Electric plant net of accumulated depreciation and amortization	$	952,873			$	897,559

__________________

(a) The plant acquisition adjustment is included in rate base and is being recovered with 13 years remaining.

(3)    JOINTLY OWNED FACILITIES

Our financial statements include our share of several jointly-owned utility facilities as described below. Our share

of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Statements of

Income (Loss). Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.

• We own a 20% interest in the Wyodak Plant (the “Plant”), a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and is the operator of the Plant. We receive our proportionate share of the Plant’s capacity and are committed to pay our share of its additions, replacements and operating and maintenance expenses.

• We own a 35% interest in, and are the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the transmission tie is 400 MW, including 200 MW West to East and 200 MW from East to West. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

• We own a 52% interest in the Wygen III power plant. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and a proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations.

• We own 55 MW of Cheyenne Prairie, a 95 MW gas-fired power generation facility located in Cheyenne, Wyoming. Wyoming Electric owns the remaining 40 MW. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

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As of December 31, 2017, our interests in jointly-owned generating facilities and transmission systems were (in thousands):

Interest in jointly-owned facilities	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	114,405	$	727	$	58,955
Transmission Tie	$	20,037	$	242	$	6,215
Wygen III	$	138,688	$	406	$	19,239
Cheyenne Prairie	$	91,631	$	89	$	8,746

(4)    LONG-TERM DEBT

Long-term debt outstanding at December 31 was as follows (in thousands):

		Interest Rate at		Balance Outstanding
	Due Date	December 31, 2017		December 31, 2017			December 31, 2016
First Mortgage Bonds due 2032	August 15, 2032	7.23	%	$	75,000		$	75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13	%	180,000			180,000
First Mortgage Bonds due 2044	October 20, 2044	4.43	%	85,000			85,000
Less unamortized debt discount				(90		)	(94		)
Series 94A Debt (a)	June 1, 2024	1.83	%	2,855			2,855
Less unamortized deferred financing costs				(2,870		)	(3,005		)
Long-term Debt				$	339,895		$	339,756

___________________

(a) Variable interest rate at December 31, 2017.

Net deferred financing costs of approximately $2.9 million and $3.0 million were recorded on the accompanying Balance Sheets in long-term debt at December 31, 2017 and 2016, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $0.1 million for the years ended December 31, 2017, 2016 and 2015 are included in Interest expense on the accompanying Statements of Income.

Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. We were in compliance with our debt covenants at December 31, 2017.

Long-term Debt Maturities

Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts and unamortized deferred financing costs) are as follows (in thousands):

2018	$	—
2019	$	—
2020	$	—
2021	$	—
2022	$	—
Thereafter	$	342,855

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(5)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at December 31 were as follows (in thousands):

	2017				2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents (a)	$	16	$	16	$	234	$	234
Long-term debt (b) (c)	$	339,895	$	446,978	$	339,756	$	410,466

_______________

(a) Fair value approximates carrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

(b) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

(c) Carrying amount of long-term debt is net of deferred financing costs.

The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.

Cash and Cash Equivalents

Included in cash and cash equivalents is cash.

Long-Term Debt

For additional information on our long-term debt, see Note 4.

(6)    INCOME TAXES

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. We have made our best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position.

In addition, as allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Company has recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Company’s  financial statements, but reasonable estimates could be determined.  However, the provisional amounts may change as the Company finalizes the analysis and computations and such changes could be material to the Company’s future results of operations, cash flows or financial position.

Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows (in thousands):

	2017		2016		2015
Current	$	13,124	$	1,838	$	14,910
Deferred	1,004		20,690		7,690
Total income tax expense	$	14,128	$	22,528	$	22,600

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The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):

	2017			2016
Deferred tax assets:
Employee benefits	$	3,012		$	5,163
Regulatory liabilities	24,984			9,099
Other	1,678			1,815
Total deferred tax assets	29,674			16,077
Deferred tax liabilities:
Accelerated depreciation and other plant related differences (a)	(122,002		)	(202,047		)
Regulatory assets	(7,008		)	(4,391		)
Employee benefits	(2,595		)	(3,075		)
Deferred costs	(8,447		)	(16,920		)
Other	(240		)	(1,087		)
Total deferred tax liabilities	(140,292		)	(227,520		)
Net deferred tax liability	$	(110,618	)	$	(211,443	)

(a) The net deferred tax liabilities were revalued for the change in federal tax rate to 21% under the TCJA. The revaluation resulted in a reduction to net deferred tax liabilities of approximately $103 million. Due to the regulatory construct, approximately $97 million of the revaluation was reclassified to a regulatory liability.

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:

	2017	2016	2015
Federal statutory rate	35.0%	35.0%	35.0%
Amortization of excess deferred and investment tax credits	(0.1)	(0.4)	(0.1)
AFUDC Equity	(1.0)	(0.9)	(0.6)
Flow through adjustments (a)	(1.8)	(0.9)	(0.9)
Tax credits	—	(0.1)	—
Tax reform (b)	(9.2)	—	—
Other	(1.3)	0.6	—
	21.6%	33.3%	33.4%

_________________________

(a) Flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to tax expense.

(b) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21%, effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change.

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The following table reconciles the total amounts of unrecognized tax benefits, without interest, included in Other deferred credits and other liabilities on the accompanying Balance Sheet (in thousands):

	2017			2016
Unrecognized tax benefits at January 1	$	493		$	2,264
Additions for current year tax positions	13			—
Additions for prior year tax positions	—			1,194
Reductions for prior year tax positions	(204		)	(682		)
Settlements for prior year tax positions	—			(2,283		)
Unrecognized tax benefits at December 31	$	302		$	493

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is not material to the financial results of the Company.

It is the Company’s continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 2017 and 2016, the interest expense recognized was not material to the financial results of the Company.

We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations on or before December 31, 2018.

We file income tax returns in the United States federal jurisdictions as a member of the BHC consolidated group.

At December 31, 2016, we were no longer in a federal NOL carryforward position.

(7)    COMPREHENSIVE INCOME

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.

The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands):

	Location on the Statements of Income (Loss)	Amounts Reclassified from AOCI
		2017			2016
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	(22		)	(22		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	42		$	42
Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	86		$	82
Income tax	Income tax benefit (expense)	(30		)	(29		)
Total reclassification adjustments related to defined benefit plans, net of tax		$	56		$	53

Derivatives designated as cash flow hedges relate to a treasury lock entered into in August 2002 to hedge $50 million of our First Mortgage Bonds due on August 15, 2032. The treasury lock cash settled on August 8, 2002, the bond pricing date, and resulted in a $1.8 million loss. The treasury lock is treated as a cash flow hedge and the resulting loss is carried in Accumulated other comprehensive loss and is being amortized over the life of the related bonds.

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Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands):

	Interest Rate Swaps			Employee Benefit Plans			Total
As of December 31, 2016	$	(593	)	$	(669	)	$	(1,262	)
Other comprehensive income (loss)	42			(38		)	4
As of December 31, 2017	$	(551	)	$	(707	)	$	(1,258	)
	Interest Rate Swaps			Employee Benefit Plans			Total
As of December 31, 2015	$	(635	)	$	(672	)	$	(1,307	)
Other comprehensive income (loss)	42			3			45
As of December 31, 2016	$	(593	)	$	(669	)	$	(1,262	)

(8)    EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

BHC sponsors a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.

The 401(k) Plan provides either a Company Matching Contribution or a Non-Elective Safe Harbor Contribution for all eligible participants. Certain eligible participants receive a Company Retirement Contribution based on the participant’s age and years of service or a Company Discretionary Contribution, depending upon the pension plan in which the employee participates. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20% per year with 100% vesting when the participant has 5 years of service with the Company.

Defined Benefit Pension Plan (Pension Plan)

We have a defined benefit pension plan (“Pension Plan”) covering certain eligible employees. The benefits for the Pension

Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The

Pension Plan has been closed to new employees and certain employees who did not meet age and service based criteria.

The Pension Plan assets are held in a Master Trust. Due to the plan merger on December 31, 2016, reporting beginning in 2017 no longer represents an undivided interest in the Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments.

The expected rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2017, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 37% to 45% equity securities and 55% to 63% fixed-income liability-hedging assets and the expected rate of return from these asset categories.

The expected long-term rate of return for investments was 6.25% and 6.75% for the Pension Plan 2017 and 2016 plan years, respectively. Our Pension Plan is funded in compliance with the federal government’s funding requirements.

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Plan Assets

The percentages of total plan asset by investment category of our Pension Plan assets at December 31 were as follows:

	2017		2016
Equity securities	26	%	28	%
Real estate	4		5
Fixed income funds	63		57
Cash and cash equivalents	1		2
Hedge funds	6		8
Total	100	%	100	%

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company.

Plan Assets

We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Healthcare Plans

Employees who are participants in our Postretirement Healthcare Plan (“Healthcare Plan”) and who retire on or after attaining minimum age and years of service requirements are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. Pre-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for Medicare-eligible BHP retirees is provided through an individual market healthcare exchange. We may amend or change the Healthcare Plan periodically. We are not pre-funding our retiree medical plan. We have determined that the Healthcare Plan’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

Plan Assets

We fund our Healthcare Plans on a cash basis as benefits are paid.

Plan Contributions

Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions for the years ended December 31 were as follows (in thousands):

	2017		2016
Defined Benefit Plans
Defined Benefit Pension Plan	$	4,000	$	820
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	348	$	420
Supplemental Non-qualified Defined Benefit Plan	$	246	$	221
Defined Contribution Plans
Company Retirement Contribution	$	861	$	851
Matching Contributions	$	1,306	$	1,400

While we do not have required contributions, we expect to make approximately $1.8 million in contributions to our Defined Benefit Pension Plan in 2018.

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Fair Value Measurements

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):

Pension Plan	December 31, 2017
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV (a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	184	$	—	$	184	$	—	$	184
Common Collective Trust - Cash and Cash Equivalents	—		314		—		314		—		314
Common Collective Trust - Equity	—		15,749		—		15,749		—		15,749
Common Collective Trust - Fixed Income	—		37,732		—		37,732		—		37,732
Common Collective Trust - Real Estate	—		249		—		249		2,258		2,507
Hedge Funds	—		—		—		—		3,398		3,398
Total investments measured at fair value	$	—	$	54,228	$	—	$	54,228	$	5,656	$	59,884

Pension Plan	December 31, 2016
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV (a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	196	$	—	$	196	$	—	$	196
Common Collective Trust - Cash and Cash Equivalents	—		784		—		784		—		784
Common Collective Trust - Equity	—		14,927		—		14,927		—		14,927
Common Collective Trust - Fixed Income	—		31,003		—		31,003		—		31,003
Common Collective Trust - Real Estate	—		347		—		347		2,300		2,647
Hedge Funds	—		—		—		—		4,331		4,331
Total investments measured at fair value	$	—	$	47,257	$	—	$	47,257	$	6,631	$	53,888

________________________

(a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above.

AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2.

Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.

48

Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The funds without participant withdrawal limitations are categorized as Level 2.

The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.

Common Collective Trust-Real Estate Fund: This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy.

Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. Generally, shares may be redeemed at the end of each quarter, with a 65 day notice and are limited to a percentage of total net asset value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.

Other Plan Information

The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI (in thousands):

Benefit Obligations

As of December 31,	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2017			2016			2017			2016			2017			2016
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	64,973		$	65,959		$	3,404		$	3,426		$	5,843		$	6,208
Service cost	545			606			—			—			206			204
Interest cost	2,341			2,499			116			122			176			187
Actuarial loss (gain)	4,008			455			144			78			130			(446		)
Benefits paid	(3,445		)	(3,215		)	(246		)	(222		)	(348		)	(420		)
Plan participants transfer to affiliate	(860		)	(1,331		)	—			—			(137		)	(31		)
Plan participants’ contributions	—			—			—			—			100			141
Projected benefit obligation at end of year	$	67,562		$	64,973		$	3,418		$	3,404		$	5,970		$	5,843

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Employee Benefit Plan Assets

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2017			2016			2017			2016			2017			2016
Beginning fair value of plan assets	$	53,888		$	54,723		$	—		$	—		$	—		$	—
Investment income (loss)	6,150			2,485			—			—			—			—
Benefits paid	(3,445		)	(3,215		)	(246		)	(221		)	(348		)	(420		)
Participant contributions	—			—			—			—			100			141
Employer contributions	4,000			820			246			221			248			279
Plan participants transfer to affiliate	(709		)	(925		)	—			—			—			—
Ending fair value of plan assets	$	59,884		$	53,888		$	—		$	—		$	—		$	—

The funded status of the plans and amounts recognized in the Balance Sheets at December 31 consist of (in thousands):

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2017			2016			2017			2016			2017			2016
Regulatory asset (liability)	$	18,998		$	18,974		$	—		$	—		$	(1,758	)	$	(2,087	)
Current liability	$	—		$	—		$	(245	)	$	(247	)	$	(534	)	$	(541	)
Non-current liability	$	(7,676	)	$	(11,085	)	$	(3,173	)	$	(3,157	)	$	(5,436	)	$	(5,302	)

Accumulated Benefit Obligation

As of December 31 (in thousands)	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2017		2016		2017		2016		2017		2016
Accumulated benefit obligation (a)	$	64,782	$	61,585	$	3,418	$	3,404	$	5,970	$	5,843

____________________

(a) The Defined Benefit Pension Plan Accumulated Benefit Obligation for 2017 and 2016 represents the obligation for the merged Black Hills Retirement Plan.

Components of Net Periodic Expense

Net periodic expense consisted of the following for the year ended December 31 (in thousands):

	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2017			2016			2015			2017		2016		2015		2017			2016			2015
Service cost	$	545		$	606		$	797		$	—	$	—	$	—	$	206		$	204		$	233
Interest cost	2,341			2,499			2,956			116		122		142		176			187			214
Expected return on assets	(3,591		)	(3,632		)	(3,935		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	43			43			43			—		—		—		(336		)	(337		)	(336		)
Recognized net actuarial loss (gain)	1,230			1,995			2,196			87		82		93		—			—			—
Net periodic expense	$	568		$	1,511		$	2,057		$	203	$	204	$	235	$	46		$	54		$	111

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AOCI

For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):

	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2017		2016		2017		2016		2017		2016
Net (gain) loss	$	—	$	—	$	707	$	669	$	—	$	—
Total AOCI	$	—	$	—	$	707	$	669	$	—	$	—

The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2018 are as follows (in thousands):

	Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
Net gain (loss)	$	1,341	$	67	$	—
Prior service cost	28		—		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2018	$	1,369	$	67	$	(218	)

Assumptions

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2017		2016		2015		2017		2016		2015		2017		2016		2015
Weighted-average assumptions used to determine benefit obligations:
Discount rate	3.71	%	4.27	%	4.63	%	3.62	%	4.12	%	4.29	%	3.60	%	3.84	%	4.03	%
Rate of increase in compensation levels	3.43	%	3.47	%	3.57	%	N/A		N/A		N/A		N/A		N/A		N/A
Weighted-average assumptions used to determine net periodic benefit cost for plan year:
Discount rate (a)	4.27	%	4.63	%	4.25	%	4.12	%	4.29	%	3.98	%	3.84	%	4.03	%	3.70	%
Expected long-term rate of return on assets (b)	6.75	%	6.75	%	6.75	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.47	%	3.57	%	3.86	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________

(a) The estimated discount rate for the merged Black Hills Corporation’s Retirement Plan is 3.71% for the calculation of the 2018 net periodic pension costs.

(b) The expected rate of return on plan assets is 6.25% for the calculation of the 2018 net periodic pension cost.

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The healthcare benefit obligation was determined at December 31 as follows:

	2017		2016
Trend Rate - Medical
Pre-65 for next year	7.00	%	6.10	%
Pre-65 Ultimate trend rate	4.50	%	4.50	%
Trend Year	2027		2024
Post-65 for next year	5.00	%	5.10	%
Post-65 Ultimate trend rate	4.50	%	4.50	%
Trend Year	2026		2023

We do not pre-fund our supplemental plan or our healthcare plan. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plan (in thousands):

Change in Assumed Trend Rate	Accumulated Periodic Postretirement Benefit Obligation			Service and Interest Costs
Increase 1%	$	186		$	7
Decrease 1%	$	(174	)	$	(7	)

Beginning in 2016, we changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on this Form 10-K for additional details.

The following benefit payments, which reflect future service, are expected to be paid (in thousands):

	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Defined Benefit Postretirement Healthcare Plan
2018	$	3,489	$	245	$	534
2019	$	3,628	$	242	$	621
2020	$	3,725	$	239	$	633
2021	$	3,835	$	333	$	613
2022	$	3,964	$	329	$	592
2023-2027	$	20,648	$	1,417	$	2,479

(9)    RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We recorded non-cash dividends to our Parent of approximately $42 million and $53 million in 2017 and 2016 respectively, and decreased the utility Money pool note receivable for approximately $42 million and $53 million in 2017 and 2016, respectively.

Receivables and Payables

We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31 were as follows (in thousands):

	2017		2016
Receivable - affiliates	$	5,664	$	9,526
Accounts payable - affiliates	$	25,653	$	31,799

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Money Pool Notes Receivable and Notes Payable

On September 1, 2017, the Utility Money Pool was transferred from Black Hills Power to our affiliate Black Hills Utility Holdings. This transfer reduced our cash by $0.7 million, reduced our Money pool notes receivable, net by $1.0 million and increased our Retained earnings by $0.3 million.

We will continue to participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings under the Agreement bear interest at the weighted average daily cost of our parent company’s external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0%.

The cost of borrowing under the Utility Money Pool was 1.96% at December 31, 2017.

We had the following balances with the Utility Money Pool as of December 31 (in thousands):

	2017			2016
Notes receivable (payable)	$	(13,397	)	$	28,409

Interest income relating to the Utility Money Pool for the years ended December 31, was as follows (in thousands):

	2017		2016		2015
Interest income	$	272	$	1,047	$	1,153

Interest expense allocation from Parent

BHC provides daily liquidity and cash management on behalf of all its subsidiaries. For the years ended December 31, 2017, 2016 and 2015, we were allocated $1.4 million, $1.9 million, and $2.1 million, respectively, of interest expense from BHC.

Other Balances and Transactions

We have the following Power Purchase and Transmission Services Agreements with affiliated entities:

• An agreement, expiring September 3, 2028, with Wyoming Electric to acquire 15 MW of the facility output from Happy Jack. Under a separate inter-company agreement expiring on September 3, 2028, Wyoming Electric has agreed to sell up to 15 MW of the facility output from Happy Jack to us.

• An agreement, expiring September 30, 2029, with Wyoming Electric to acquire 20 MW of the facility output from Silver Sage. Under a separate inter-company agreement expiring on September 30, 2029, Wyoming Electric has agreed to sell 20 MW of energy from Silver Sage to us.

• A Generation Dispatch Agreement with Wyoming Electric that requires us to purchase all of Wyoming Electric’s excess energy.

Related-party Gas Transportation Service Agreement

On October 1, 2014, we entered into a gas transportation service agreement with Wyoming Electric in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

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Related-party Revenue and Purchases

We had the following related-party transactions for the years ended December 31 included in the corresponding captions in the accompanying Statements of Income:

	2017		2016		2015
	(in thousands)
Revenues:
Energy sold to Cheyenne Light	$	2,481	$	2,440	$	1,857
Rent from electric properties	$	5,100	$	5,046	$	4,772
Fuel and purchased power:
Purchases of coal from WRDC	$	15,948	$	16,227	$	16,401
Purchase of excess energy from Cheyenne Light	$	601	$	252	$	898
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	1,924	$	1,918	$	1,578
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	3,290	$	3,300	$	2,739
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	393	$	399	$	410
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	27,869	$	25,748	$	26,655

Horizon Point Agreement

We have an arrangement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric.  This cost allocation, includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.

(10)    SUPPLEMENTAL CASH FLOW INFORMATION

Years ended December 31,	2017			2016			2015
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	6,565		$	5,521		$	3,870
Non-cash decrease to money pool note receivable	$	(42,000	)	$	(52,500	)	$	(28,501	)
Non-cash dividend to Parent company	$	42,000		$	52,500		$	28,501
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(21,517	)	$	(21,320	)	$	(21,913	)
Income taxes (paid) refunded	$	(12,719	)	$	—		$	—

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(11)    COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

We have the following power purchase and transmission services agreements, not including related party agreements, as of December 31, 2017 (see Note 9 for information on related party agreements):

• A PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.

• A firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp.

• An agreement with Thunder Creek for gas transport capacity, expiring October 31, 2019.

Costs incurred under these agreements were as follows for the years ended December 31 (in thousands):

Contract	Contract Type	2017		2016		2015
PacifiCorp	Electric capacity and energy	$	13,218	$	12,221	$	13,990
PacifiCorp	Transmission access	$	1,671	$	1,428	$	1,213
Thunder Creek	Gas transport capacity	$	633	$	633	$	633

Future Contractual Obligations

The following is a schedule of future minimum payments required under power purchase, transmission services, facility and vehicle leases, and gas supply agreements (in thousands):

2018	$	13,531
2019	$	6,839
2020	$	6,839
2021	$	6,206
2022	$	6,206
Thereafter	$	6,206

Long-Term Power Sales Agreements

We have the following power sales agreements as of December 31, 2017:

• During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.

• An agreement to serve MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023.

• During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which expires September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.

55

• A PPA with MEAN expiring May 31, 2023. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.

• Effective January 1, 2017, we have an energy sales agreement with Cargill (assigned to Macquarie on January 3, 2018) expiring December 31, 2021 to supply 50 MW of energy during heavy and light load timing intervals.

Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. They can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date.

In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date.

For additional information on environmental matters, see Item 1 in this Annual Report on Form 10-K.

Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the financial statements.

In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.

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(12)    QUARTERLY HISTORICAL DATA (Unaudited)

We operate on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter (in thousands):

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2017
Revenues	$	73,794	$	66,053	$	73,938	$	74,648
Operating income	$	23,376	$	17,712	$	23,698	$	19,040
Net income	$	12,570	$	9,287	$	13,826	$	15,615
2016
Revenues	$	68,642	$	62,019	$	66,728	$	70,243
Operating income	$	20,780	$	18,936	$	22,410	$	23,454
Net income	$	11,186	$	9,806	$	12,010	$	12,136

The fourth quarter of 2017 Net income includes a net tax benefit of $6.0 million from the impact of the TCJA.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 2017. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2017, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting is presented on Page 26 of this Annual Report on Form 10-K.

ITEM 9B.    OTHER INFORMATION

None.

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ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table sets forth the aggregate fees for services provided to us for the fiscal years ended December 31 by our independent registered public accounting firm, Deloitte & Touche LLP (in thousands):

Deloitte & Touche LLP	2017		2016
Audit Fees	$	407	$	216
Tax Fees	31		23
Total	$	438	$	239

Audit Fees. Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements included in quarterly reports and services that generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the Securities and Exchange Commission.

Tax Fees. Fees for services related to tax compliance, tax planning and advice including assistance with tax audits. These services include assistance regarding federal tax compliance and advice, review of tax returns, and federal tax planning.

The services performed by Deloitte & Touche LLP were pre-approved in accordance with the Black Hills Corporation Audit Committee’s pre-approval policy whereby the Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accountants. The Audit Committee annually reviews the services expected to be provided by the independent auditors and establishes pre-approval fee levels for each category of services to be provided, including audit, audit-related, tax and other services. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee.

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)	1.	Financial Statements
		Financial statements required by Item 15 are listed in the index included in Item 8 of Part II.
	2.	Schedules

Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016 and 2015

All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements incorporated by reference in this Form 10-K.

SCHEDULE II

BLACK HILLS POWER, INC. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31,
Description	Balance at beginning of year		Additions charged to costs and expenses		Deductions charged to costs and expenses			Balance at end of year
	(in thousands)
Allowance for doubtful accounts:
2017	$	157	$	882	$	(815	)	$	224
2016	$	207	$	644	$	(694	)	$	157
2015	$	261	$	602	$	(656	)	$	207

59

3. Exhibits            

Exhibit Number	Description
3.1*	Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 5, 2018.)
3.2*	Amended and Restated Bylaws of the Registrant dated March 30, 2015 (filed as Exhibit 3.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).
4.1*	Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc., and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).
10.1*	Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).
10.2*	Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).
10.3*	Bond Purchase Agreement dated as of June 30, 2014 by and among Black Hills Power, Inc., New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York and United of Omaha Life Insurance Company (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 2, 2014).
31.1	Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Financials for XBRL Format

_________________________

* Previously filed as part of the filing indicated and incorporated by reference herein.

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.

The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation.

60

ITEM 16. FORM 10-K SUMMARY

None.

61

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.

		BLACK HILLS POWER, INC.
		By	/s/ DAVID R. EMERY
		David R. Emery, Chairman and Chief Executive Officer
Dated:	February 26, 2018

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.

/s/ DAVID R. EMERY	Director and	February 26, 2018
David R. Emery, Chairman and	Principal Executive Officer
Chief Executive Officer
/s/ RICHARD W. KINZLEY	Director and	February 26, 2018
Richard W. Kinzley, Senior Vice President	Principal Financial and
and Chief Financial Officer	Accounting Officer
/s/ LINDEN R. EVANS	Director	February 26, 2018
Linden R. Evans
/s/ BRIAN G. IVERSON	Director	February 26, 2018
Brian G. Iverson

62

EX-31.1

Exhibit 31.1

CERTIFICATION

I, David R. Emery, certify that:

1. I have reviewed this Annual Report on Form 10-K of Black Hills Power, Inc.;

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(s) 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.

5. The registrant's other certifying officer(s) 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 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 26, 2018
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard W. Kinzley, certify that:

1. I have reviewed this Annual Report on Form 10-K of Black Hills Power, Inc.;

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(s) 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.

5. The registrant's other certifying officer(s) 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 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 26, 2018
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and
		Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Black Hills Power, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David R. Emery, Chairman and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 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.

Date:	February 26, 2018
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Black Hills Power, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard W. Kinzley, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 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.

Date:	February 26, 2018
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

XML

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	BLACK HILLS POWER INC
Entity Central Index Key	0000012400
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Document Fiscal Year End Focus	2017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Share Outstanding		23,416,396
Entity Well-known seasoned Issuer	Yes
Entity Voluntary Filers	No
Public Float			$ 0

XML

Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Revenue	$ 288,433	$ 267,632	$ 277,864
Operating expenses:
Fuel and purchased power	87,638	75,026	83,339
Operations and maintenance	74,064	66,384	68,088
Depreciation and amortization	35,862	34,030	32,552
Taxes - property	7,043	6,612	5,971
Total operating expenses	204,607	182,052	189,950
Operating income	83,826	85,580	87,914
Other income (expense):
Interest expense	(22,421)	(22,908)	(22,337)
AFUDC - borrowed	1,137	1,140	506
Interest income	904	1,576	657
AFUDC - equity	2,165	2,165	918
Other expense	(300)	(185)	(117)
Other income	115	298	233
Total other income (expense)	(18,400)	(17,914)	(20,140)
Income before income taxes	65,426	67,666	67,774
Income tax expense	(14,128)	(22,528)	(22,600)
Net income	$ 51,298	$ 45,138	$ 45,174

XML

Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 51,298	$ 45,138	$ 45,174
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax	(94)	(50)	68
Other comprehensive income (loss):
Other comprehensive income (loss)	4	45	512
Comprehensive income	51,302	45,183	45,686
Accumulated Defined Benefit Plans Adjustment
Other comprehensive income (loss):
Other comprehensive income (loss)	(38)	3
Reclassification out of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment
Statement of Comprehensive Income [Abstract]
Net income	56	53
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax	56	53	61
Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Statement of Comprehensive Income [Abstract]
Net income	42	42
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ 42	$ 42	$ 383

XML

Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Benefit plan liability adjustments - net gain (loss), Tax	$ 50	$ 27	$ (36)
Reclassification adjustment of benefit plan liability - net gain (loss) tax	(30)	(29)	(33)
Reclassification adjustment of cash flow hedges settled and included in net income (loss), Tax	$ (22)	$ (22)	$ 319

XML

Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 16	$ 234
Receivables - customers, net	29,050	30,614
Receivables - affiliates	5,664	9,526
Other receivables, net	196	351
Money pool notes receivable	0	28,409
Materials, supplies and fuel	23,443	22,389
Regulatory assets, current	18,993	18,119
Other current assets	4,528	3,876
Total current assets	81,890	113,518
Investments	4,926	4,841
Property, plant and equipment	1,311,819	1,236,387
Less accumulated depreciation and amortization	(358,946)	(338,828)
Total property, plant and equipment, net	952,873	897,559
Other assets:
Regulatory assets, non-current	59,710	74,015
Other, non-current assets	3,747	3,816
Assets, Noncurrent, Other than Noncurrent Investments and Property, Plant and Equipment	63,457	77,831
TOTAL ASSETS	1,103,146	1,093,749
Current liabilities:
Accounts payable	14,766	14,158
Accounts payable - affiliates	25,653	31,799
Money pool note payable	13,397	0
Accrued liabilities	38,205	37,436
Regulatory liabilities, current	842	84
Total current liabilities	92,863	83,477
Long-term debt	339,895	339,756
Deferred credits and other liabilities:
Deferred income tax liabilities, net	110,618	211,443
Regulatory liabilities, non-current	148,013	53,866
Benefit plan liabilities	16,285	19,544
Other, non-current liabilities	1,240	1,001
Total deferred credits and other liabilities	276,156	285,854
Commitments and contingencies (Notes 4, 8, 9 and 11)
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416	23,416
Additional paid-in capital	39,575	39,575
Retained earnings	332,499	322,933
Accumulated other comprehensive loss	(1,258)	(1,262)
Total stockholder’s equity	394,232	384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$ 1,103,146	$ 1,093,749

XML

Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common Stock, Par Value Per Share (usd per share)	$ 1	$ 1
Common Stock, Shares Authorized	50,000,000	50,000,000
Common Stock, Shares, Issued	23,416,396	23,416,396

XML

Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income	$ 51,298	$ 45,138	$ 45,174
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	35,862	34,030	32,552
Deferred income taxes	1,004	20,690	7,690
AFUDC - equity	(2,165)	(2,165)	(918)
Employee benefits	817	1,770	2,403
Other adjustments	2,429	391	232
Change in operating assets and liabilities -
Accounts receivable and other current assets	3,287	(3,963)	(3,223)
Accounts payable and other current liabilities	(7,254)	6,175	20,455
Regulatory assets	978	(4,023)	(3,839)
Regulatory liabilities	0	0	(2,479)
Contributions to defined benefit pension plan	(4,000)	(820)	0
Other operating activities	(1,853)	(8,339)	(5,680)
Net cash provided by operating activities	80,403	88,884	92,367
Investing activities:
Property, plant and equipment additions	(79,566)	(84,750)	(56,795)
Notes receivable from affiliate companies, net	0	(4,095)	(36,687)
Other investing activities	(861)	(102)	(128)
Net cash (used in) investing activities	(80,427)	(88,947)	(93,610)
Financing activities:
Notes payable from affiliate companies, net	(194)	0	0
Other financing activities	0	0	(2)
Net cash provided by (used in) financing activities	(194)	0	(2)
Net change in cash and cash equivalents	(218)	(63)	(1,245)
Cash and cash equivalents beginning of year	234	297	1,542
Cash and cash equivalents end of year	$ 16	$ 234	$ 297

XML

Statements of Common Stockholder's Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings Retained Earnings
Common Stock, Shares, Issued - Beginning Balance at Dec. 31, 2014		23,416,000
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Stock Issued During Period, Shares, New Issues		0
Common Stock, Shares, Issued - Ending Balance at Dec. 31, 2015		23,416,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2014		$ 23,416	$ 39,575	$ 313,622	$ (1,819)
Stockholders' Equity Attributable to Parent [Abstract]
Stock Issued During Period, Value, New Issues		0	0
Net income	$ 45,174			45,174
Non-cash Dividend to Parent Company				(28,501)
Adjustment for Transfer of Utility Money Pool						$ 0
Other Comprehensive Income (Loss), Net of Tax	512				512
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2015	$ 391,979	$ 23,416	39,575	330,295	(1,307)
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Stock Issued During Period, Shares, New Issues		0
Common Stock, Shares, Issued - Ending Balance at Dec. 31, 2016	23,416,396	23,416,000
Stockholders' Equity Attributable to Parent [Abstract]
Stock Issued During Period, Value, New Issues		$ 0	0
Net income	$ 45,138			45,138
Non-cash Dividend to Parent Company				(52,500)
Adjustment for Transfer of Utility Money Pool						0
Other Comprehensive Income (Loss), Net of Tax	45				45
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2016	$ 384,662	$ 23,416	39,575	322,933	(1,262)
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Stock Issued During Period, Shares, New Issues		0
Common Stock, Shares, Issued - Ending Balance at Dec. 31, 2017	23,416,396	23,416,000
Stockholders' Equity Attributable to Parent [Abstract]
Stock Issued During Period, Value, New Issues		$ 0	0
Net income	$ 51,298			51,298
Non-cash Dividend to Parent Company				(42,000)
Adjustment for Transfer of Utility Money Pool						$ 268
Other Comprehensive Income (Loss), Net of Tax	4				4
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2017	$ 394,232	$ 23,416	$ 39,575	$ 332,499	$ (1,258)

XML

Business Description and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Business Description and Significant Accounting Policies

BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc., doing business as South Dakota Electric (the Company, “we,” “us” or “our”) is a regulated electric utility serving customers in South Dakota, Wyoming and Montana. We are a wholly-owned subsidiary of BHC or the Parent, a public registrant listed on the New York Stock Exchange.

Basis of Presentation

The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 3) and are prepared in accordance with GAAP.

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Regulatory Accounting

Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory

assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but

generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer

meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.

We had the following regulatory assets and liabilities as of December 31 (in thousands):

	Maximum Amortization (in years)	2017		2016
Regulatory assets
Unamortized loss on reacquired debt (a)	7	$	1,534	$	1,815
Deferred taxes on AFUDC (b)	45	5,095		9,367
Employee benefit plans (c)	12	19,465		20,100
Deferred energy and fuel cost adjustments - current (a)	1	14,066		18,119
Deferred gas cost adjustments (a)	1	5,536		4,897
Deferred taxes on flow through accounting (a)	54	7,579		12,545
Decommissioning costs, net of amortization (d)	6	10,252		12,456
Vegetation management, net of amortization (d)	6	12,669		12,109
Other regulatory assets (a) (d)	6	2,507		726
		$	78,703	$	92,134
Regulatory liabilities
Cost of removal for utility plant (a)	61	$	44,056	$	41,541
Employee benefit plans and related deferred taxes (c)	12	6,808		12,304
Excess deferred income taxes (c) (e)	40	97,101		—
Other regulatory liabilities (c)	13	890		105
		$	148,855	$	53,950

____________________

(a)Recovery of costs but we are not allowed a rate of return.

(b) In addition to recovery of costs, we are allowed a rate of return.

(c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

(d) In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million are being amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million.

(e) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018.

Regulatory assets represent items we expect to recover from customers through probable future increases in rates.

Unamortized Loss on Reacquired Debt - The early redemption premium on reacquired debt is being amortized over the remaining term of the original bonds.

Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset itself is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity, and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income. In addition, this regulatory asset includes the income tax effect of the adjustment required under accounting for compensation-defined benefit plans to record the full pension and post-retirement benefit obligations. Such amounts have been grossed-up to reflect the revenue requirement associated with a rate regulated environment.

Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. We file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by the applicable state utility commissions.

Deferred Gas Cost Adjustment - We have GCA provisions that allow us to pass the cost of gas on to our customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. We file periodic estimates of future gas costs based on market forecasts with state utility commissions

Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes.

Decommissioning Costs - We received approval in 2014 for regulatory treatment on the remaining net book values and decommissioning costs of our decommissioned coal plants.

Vegetation Management Costs - We received approval in 2013 for regulatory treatment on vegetation management maintenance costs for our distribution system rights-of-way.

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Cost of Removal for Utility Plant - Cost of removal for utility plant represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.

Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.

Excess Deferred Income Taxes - The revaluation of our deferred tax assets and liabilities due to the passage of the TCJA is recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable consists of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs or payment received.

We maintain an allowance for doubtful accounts which reflects our best estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

Following is a summary of accounts receivable as of December 31 (in thousands):

	2017			2016
Accounts receivable, trade	$	15,994		$	16,972
Unbilled revenue	13,280			13,799
Less Allowance for doubtful accounts	(224		)	(157		)
Accounts receivable, net	$	29,050		$	30,614

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers are recorded on a net basis (excluded from Revenue).

Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Balance Sheets.

For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement.

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are recorded using the weighted-average cost method.

Deferred Financing Costs

Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities.

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Balance Sheets.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated electric properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.1% in 2017, 2.2% in 2016 and 2.3% in 2015.

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Balance Sheets as of December 31 (in thousands):

	2017		2016
Accrued employee compensation, benefits and withholdings	$	4,305	$	4,783
Accrued property taxes	5,930		5,522
Accrued income taxes	17,472		17,069
Customer deposits and prepayments	4,863		2,825
Accrued interest	4,708		4,614
Other (none of which is individually significant)	927		2,623
Total accrued liabilities	$	38,205	$	37,436

Derivatives and Hedging Activities

The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and changes in the derivative instruments be recognized in earnings unless specific hedge accounting criteria are met and designated accordingly, including the normal purchase and normal sales exception.  Changes in the fair value for derivative instruments that do not meet this exception are recognized in the income statement as they occur.

From time to time we utilize risk management contracts including interest rate swaps to fix the interest on variable rate debt, or to lock in the Treasury yield component associated with anticipated issuance of senior notes.  For swaps that settled in connection with the issuance of senior debt, the effective portion is deferred as a component in AOCI and recognized as interest expense over the life of the senior note. As of December 31, 2017, we have no outstanding interest rate swap agreements.

Revenues and expenses on contracts that qualify as derivatives may be elected to be accounted for under the normal purchases and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting.  Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric operations, we enter into contracts to buy and sell energy to meet the requirements of our customers.  These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery.  If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exception, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging.

Fair Value Measurements

Assets and liabilities are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical

unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or

listed derivatives.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for

identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the

asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other

means.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs

reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would

use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value

measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable

such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the

availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more

observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively

impacting the availability of observable pricing inputs.

Additional information is included in Note 5.

Income Taxes

We file a federal income tax return with other members of the Parent’s consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017.

We use the deferral method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Statements of Income.

We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other, non-current liabilities on the accompanying Balance Sheets. See Note 6 for additional information.

Recently Issued Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We have implemented this standard effective January 1, 2018 on a modified retrospective basis. We have completed our assessment of all revenue from existing contracts with customers and there is no significant impact to our revenue recognition practices, financial position, results of operations or cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term, generally limited to the services requested and received to date for such arrangements. For such arrangements, the performance obligation transfer of control and revenue recognition occurs when the electricity is delivered, consistent with the previous revenue recognition guidance. The same transfer of control and revenue recognition based on delivery principles also apply to our revenue contracts for wholesale and off-system power sales arrangements, and other non-regulated services. Therefore, we did not have a cumulative adjustment to Retained earnings or an impact on our revenue recognition policies as a result of the adoption of the new standard. The new standard will require us to provide more robust disclosures than required by previous guidance, including disclosures related to disaggregation of revenue into appropriate categories, performance obligations, and the judgments made in revenue recognition determinations.

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We have implemented this standard effective January 1, 2018. We will capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC to GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income, which are not expected to be material.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.We have implemented this standard effective January 1, 2018 on the retrospective transition method. This standard will not have a material impact on our financial position, results of operations or cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard.

We currently expect to adopt this standard on January 1, 2019 and anticipate electing the transition approach to not assess existing or expired land easements that were not previously accounted for as a lease. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and rights of way, pipeline laterals, purchase power agreements, and other industry-related areas. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes and systems.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31 consisted of the following (dollars in thousands):

				2017				2016
				Weighted				Weighted
				Average				Average	Lives (in years)
	2017			Useful Life (in years)	2016			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	587,323		46	$	576,833		46	40	54
Transmission	186,045			49	147,398			48	42	60
Distribution	375,214			46	364,304			46	21	62
Plant acquisition adjustment (a)	4,870			32	4,870			32	32	32
General	153,535			32	88,114			23	3	40
Total plant-in-service	1,306,987				1,181,519
Construction work in progress	4,832				54,868
Total electric plant	1,311,819				1,236,387
Less accumulated depreciation and amortization	(358,946		)		(338,828		)
Electric plant net of accumulated depreciation and amortization	$	952,873			$	897,559

__________________

(a) The plant acquisition adjustment is included in rate base and is being recovered with 13 years remaining.

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Jointly Owned Facilities

12 Months Ended

Dec. 31, 2017

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Jointly Owned Facilities

JOINTLY OWNED FACILITIES

Our financial statements include our share of several jointly-owned utility facilities as described below. Our share

of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Statements of

Income (Loss). Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.

• We own a 20% interest in the Wyodak Plant (the “Plant”), a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and is the operator of the Plant. We receive our proportionate share of the Plant’s capacity and are committed to pay our share of its additions, replacements and operating and maintenance expenses.

• We own a 35% interest in, and are the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the transmission tie is 400 MW, including 200 MW West to East and 200 MW from East to West. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

• We own a 52% interest in the Wygen III power plant. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and a proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations.

• We own 55 MW of Cheyenne Prairie, a 95 MW gas-fired power generation facility located in Cheyenne, Wyoming. Wyoming Electric owns the remaining 40 MW. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

As of December 31, 2017, our interests in jointly-owned generating facilities and transmission systems were (in thousands):

Interest in jointly-owned facilities	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	114,405	$	727	$	58,955
Transmission Tie	$	20,037	$	242	$	6,215
Wygen III	$	138,688	$	406	$	19,239
Cheyenne Prairie	$	91,631	$	89	$	8,746

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Long term Debt

12 Months Ended

Dec. 31, 2017

Long-term Debt, Unclassified [Abstract]

Long-term Debt

LONG-TERM DEBT

Long-term debt outstanding at December 31 was as follows (in thousands):

		Interest Rate at		Balance Outstanding
	Due Date	December 31, 2017		December 31, 2017			December 31, 2016
First Mortgage Bonds due 2032	August 15, 2032	7.23	%	$	75,000		$	75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13	%	180,000			180,000
First Mortgage Bonds due 2044	October 20, 2044	4.43	%	85,000			85,000
Less unamortized debt discount				(90		)	(94		)
Series 94A Debt (a)	June 1, 2024	1.83	%	2,855			2,855
Less unamortized deferred financing costs				(2,870		)	(3,005		)
Long-term Debt				$	339,895		$	339,756

___________________

(a) Variable interest rate at December 31, 2017.

Net deferred financing costs of approximately $2.9 million and $3.0 million were recorded on the accompanying Balance Sheets in long-term debt at December 31, 2017 and 2016, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $0.1 million for the years ended December 31, 2017, 2016 and 2015 are included in Interest expense on the accompanying Statements of Income.

Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. We were in compliance with our debt covenants at December 31, 2017.

Long-term Debt Maturities

Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts and unamortized deferred financing costs) are as follows (in thousands):

2018	$	—
2019	$	—
2020	$	—
2021	$	—
2022	$	—
Thereafter	$	342,855

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Fair Value of Financial Instruments Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at December 31 were as follows (in thousands):

	2017				2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents (a)	$	16	$	16	$	234	$	234
Long-term debt (b) (c)	$	339,895	$	446,978	$	339,756	$	410,466

_______________

(a) Fair value approximates carrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

(b) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

(c) Carrying amount of long-term debt is net of deferred financing costs.

The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.

Cash and Cash Equivalents

Included in cash and cash equivalents is cash.

Long-Term Debt

For additional information on our long-term debt, see Note 4.

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. We have made our best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position.

In addition, as allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Company has recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Company’s  financial statements, but reasonable estimates could be determined.  However, the provisional amounts may change as the Company finalizes the analysis and computations and such changes could be material to the Company’s future results of operations, cash flows or financial position.

Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows (in thousands):

	2017		2016		2015
Current	$	13,124	$	1,838	$	14,910
Deferred	1,004		20,690		7,690
Total income tax expense	$	14,128	$	22,528	$	22,600

The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):

	2017			2016
Deferred tax assets:
Employee benefits	$	3,012		$	5,163
Regulatory liabilities	24,984			9,099
Other	1,678			1,815
Total deferred tax assets	29,674			16,077
Deferred tax liabilities:
Accelerated depreciation and other plant related differences (a)	(122,002		)	(202,047		)
Regulatory assets	(7,008		)	(4,391		)
Employee benefits	(2,595		)	(3,075		)
Deferred costs	(8,447		)	(16,920		)
Other	(240		)	(1,087		)
Total deferred tax liabilities	(140,292		)	(227,520		)
Net deferred tax liability	$	(110,618	)	$	(211,443	)

(a) The net deferred tax liabilities were revalued for the change in federal tax rate to 21% under the TCJA. The revaluation resulted in a reduction to net deferred tax liabilities of approximately $103 million. Due to the regulatory construct, approximately $97 million of the revaluation was reclassified to a regulatory liability.

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:

	2017	2016	2015
Federal statutory rate	35.0%	35.0%	35.0%
Amortization of excess deferred and investment tax credits	(0.1)	(0.4)	(0.1)
AFUDC Equity	(1.0)	(0.9)	(0.6)
Flow through adjustments (a)	(1.8)	(0.9)	(0.9)
Tax credits	—	(0.1)	—
Tax reform (b)	(9.2)	—	—
Other	(1.3)	0.6	—
	21.6%	33.3%	33.4%

_________________________

(a) Flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to tax expense.

(b) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21%, effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change.

The following table reconciles the total amounts of unrecognized tax benefits, without interest, included in Other deferred credits and other liabilities on the accompanying Balance Sheet (in thousands):

	2017			2016
Unrecognized tax benefits at January 1	$	493		$	2,264
Additions for current year tax positions	13			—
Additions for prior year tax positions	—			1,194
Reductions for prior year tax positions	(204		)	(682		)
Settlements for prior year tax positions	—			(2,283		)
Unrecognized tax benefits at December 31	$	302		$	493

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is not material to the financial results of the Company.

It is the Company’s continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 2017 and 2016, the interest expense recognized was not material to the financial results of the Company.

We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations on or before December 31, 2018.

We file income tax returns in the United States federal jurisdictions as a member of the BHC consolidated group.

At December 31, 2016, we were no longer in a federal NOL carryforward position.

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Comprehensive Income

12 Months Ended

Dec. 31, 2017

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Comprehensive Income

COMPREHENSIVE INCOME

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.

The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands):

	Location on the Statements of Income (Loss)	Amounts Reclassified from AOCI
		2017			2016
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	(22		)	(22		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	42		$	42
Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	86		$	82
Income tax	Income tax benefit (expense)	(30		)	(29		)
Total reclassification adjustments related to defined benefit plans, net of tax		$	56		$	53

Derivatives designated as cash flow hedges relate to a treasury lock entered into in August 2002 to hedge $50 million of our First Mortgage Bonds due on August 15, 2032. The treasury lock cash settled on August 8, 2002, the bond pricing date, and resulted in a $1.8 million loss. The treasury lock is treated as a cash flow hedge and the resulting loss is carried in Accumulated other comprehensive loss and is being amortized over the life of the related bonds.

Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands):

	Interest Rate Swaps			Employee Benefit Plans			Total
As of December 31, 2016	$	(593	)	$	(669	)	$	(1,262	)
Other comprehensive income (loss)	42			(38		)	4
As of December 31, 2017	$	(551	)	$	(707	)	$	(1,258	)
	Interest Rate Swaps			Employee Benefit Plans			Total
As of December 31, 2015	$	(635	)	$	(672	)	$	(1,307	)
Other comprehensive income (loss)	42			3			45
As of December 31, 2016	$	(593	)	$	(669	)	$	(1,262	)

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2017

Defined Benefit Plan [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

BHC sponsors a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.

The 401(k) Plan provides either a Company Matching Contribution or a Non-Elective Safe Harbor Contribution for all eligible participants. Certain eligible participants receive a Company Retirement Contribution based on the participant’s age and years of service or a Company Discretionary Contribution, depending upon the pension plan in which the employee participates. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20% per year with 100% vesting when the participant has 5 years of service with the Company.

Defined Benefit Pension Plan (Pension Plan)

We have a defined benefit pension plan (“Pension Plan”) covering certain eligible employees. The benefits for the Pension

Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The

Pension Plan has been closed to new employees and certain employees who did not meet age and service based criteria.

The Pension Plan assets are held in a Master Trust. Due to the plan merger on December 31, 2016, reporting beginning in 2017 no longer represents an undivided interest in the Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments.

The expected rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2017, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 37% to 45% equity securities and 55% to 63% fixed-income liability-hedging assets and the expected rate of return from these asset categories.

The expected long-term rate of return for investments was 6.25% and 6.75% for the Pension Plan 2017 and 2016 plan years, respectively. Our Pension Plan is funded in compliance with the federal government’s funding requirements.

Plan Assets

The percentages of total plan asset by investment category of our Pension Plan assets at December 31 were as follows:

	2017		2016
Equity securities	26	%	28	%
Real estate	4		5
Fixed income funds	63		57
Cash and cash equivalents	1		2
Hedge funds	6		8
Total	100	%	100	%

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company.

Plan Assets

We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Healthcare Plans

Employees who are participants in our Postretirement Healthcare Plan (“Healthcare Plan”) and who retire on or after attaining minimum age and years of service requirements are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. Pre-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for Medicare-eligible BHP retirees is provided through an individual market healthcare exchange. We may amend or change the Healthcare Plan periodically. We are not pre-funding our retiree medical plan. We have determined that the Healthcare Plan’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

Plan Assets

We fund our Healthcare Plans on a cash basis as benefits are paid.

Plan Contributions

Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions for the years ended December 31 were as follows (in thousands):

	2017		2016
Defined Benefit Plans
Defined Benefit Pension Plan	$	4,000	$	820
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	348	$	420
Supplemental Non-qualified Defined Benefit Plan	$	246	$	221
Defined Contribution Plans
Company Retirement Contribution	$	861	$	851
Matching Contributions	$	1,306	$	1,400

While we do not have required contributions, we expect to make approximately $1.8 million in contributions to our Defined Benefit Pension Plan in 2018.

Fair Value Measurements

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):

Pension Plan	December 31, 2017
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV (a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	184	$	—	$	184	$	—	$	184
Common Collective Trust - Cash and Cash Equivalents	—		314		—		314		—		314
Common Collective Trust - Equity	—		15,749		—		15,749		—		15,749
Common Collective Trust - Fixed Income	—		37,732		—		37,732		—		37,732
Common Collective Trust - Real Estate	—		249		—		249		2,258		2,507
Hedge Funds	—		—		—		—		3,398		3,398
Total investments measured at fair value	$	—	$	54,228	$	—	$	54,228	$	5,656	$	59,884

Pension Plan	December 31, 2016
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV (a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	196	$	—	$	196	$	—	$	196
Common Collective Trust - Cash and Cash Equivalents	—		784		—		784		—		784
Common Collective Trust - Equity	—		14,927		—		14,927		—		14,927
Common Collective Trust - Fixed Income	—		31,003		—		31,003		—		31,003
Common Collective Trust - Real Estate	—		347		—		347		2,300		2,647
Hedge Funds	—		—		—		—		4,331		4,331
Total investments measured at fair value	$	—	$	47,257	$	—	$	47,257	$	6,631	$	53,888

________________________

(a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above.

AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2.

Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.

Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The funds without participant withdrawal limitations are categorized as Level 2.

The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.

Common Collective Trust-Real Estate Fund: This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy.

Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. Generally, shares may be redeemed at the end of each quarter, with a 65 day notice and are limited to a percentage of total net asset value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.

Other Plan Information

The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI (in thousands):

Benefit Obligations

As of December 31,	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2017			2016			2017			2016			2017			2016
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	64,973		$	65,959		$	3,404		$	3,426		$	5,843		$	6,208
Service cost	545			606			—			—			206			204
Interest cost	2,341			2,499			116			122			176			187
Actuarial loss (gain)	4,008			455			144			78			130			(446		)
Benefits paid	(3,445		)	(3,215		)	(246		)	(222		)	(348		)	(420		)
Plan participants transfer to affiliate	(860		)	(1,331		)	—			—			(137		)	(31		)
Plan participants’ contributions	—			—			—			—			100			141
Projected benefit obligation at end of year	$	67,562		$	64,973		$	3,418		$	3,404		$	5,970		$	5,843

Employee Benefit Plan Assets

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2017			2016			2017			2016			2017			2016
Beginning fair value of plan assets	$	53,888		$	54,723		$	—		$	—		$	—		$	—
Investment income (loss)	6,150			2,485			—			—			—			—
Benefits paid	(3,445		)	(3,215		)	(246		)	(221		)	(348		)	(420		)
Participant contributions	—			—			—			—			100			141
Employer contributions	4,000			820			246			221			248			279
Plan participants transfer to affiliate	(709		)	(925		)	—			—			—			—
Ending fair value of plan assets	$	59,884		$	53,888		$	—		$	—		$	—		$	—

The funded status of the plans and amounts recognized in the Balance Sheets at December 31 consist of (in thousands):

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2017			2016			2017			2016			2017			2016
Regulatory asset (liability)	$	18,998		$	18,974		$	—		$	—		$	(1,758	)	$	(2,087	)
Current liability	$	—		$	—		$	(245	)	$	(247	)	$	(534	)	$	(541	)
Non-current liability	$	(7,676	)	$	(11,085	)	$	(3,173	)	$	(3,157	)	$	(5,436	)	$	(5,302	)

Accumulated Benefit Obligation

As of December 31 (in thousands)	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2017		2016		2017		2016		2017		2016
Accumulated benefit obligation (a)	$	64,782	$	61,585	$	3,418	$	3,404	$	5,970	$	5,843

____________________

(a) The Defined Benefit Pension Plan Accumulated Benefit Obligation for 2017 and 2016 represents the obligation for the merged Black Hills Retirement Plan.

Components of Net Periodic Expense

Net periodic expense consisted of the following for the year ended December 31 (in thousands):

	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2017			2016			2015			2017		2016		2015		2017			2016			2015
Service cost	$	545		$	606		$	797		$	—	$	—	$	—	$	206		$	204		$	233
Interest cost	2,341			2,499			2,956			116		122		142		176			187			214
Expected return on assets	(3,591		)	(3,632		)	(3,935		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	43			43			43			—		—		—		(336		)	(337		)	(336		)
Recognized net actuarial loss (gain)	1,230			1,995			2,196			87		82		93		—			—			—
Net periodic expense	$	568		$	1,511		$	2,057		$	203	$	204	$	235	$	46		$	54		$	111

AOCI

For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):

	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2017		2016		2017		2016		2017		2016
Net (gain) loss	$	—	$	—	$	707	$	669	$	—	$	—
Total AOCI	$	—	$	—	$	707	$	669	$	—	$	—

The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2018 are as follows (in thousands):

	Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
Net gain (loss)	$	1,341	$	67	$	—
Prior service cost	28		—		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2018	$	1,369	$	67	$	(218	)

Assumptions

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2017		2016		2015		2017		2016		2015		2017		2016		2015
Weighted-average assumptions used to determine benefit obligations:
Discount rate	3.71	%	4.27	%	4.63	%	3.62	%	4.12	%	4.29	%	3.60	%	3.84	%	4.03	%
Rate of increase in compensation levels	3.43	%	3.47	%	3.57	%	N/A		N/A		N/A		N/A		N/A		N/A
Weighted-average assumptions used to determine net periodic benefit cost for plan year:
Discount rate (a)	4.27	%	4.63	%	4.25	%	4.12	%	4.29	%	3.98	%	3.84	%	4.03	%	3.70	%
Expected long-term rate of return on assets (b)	6.75	%	6.75	%	6.75	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.47	%	3.57	%	3.86	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________

(a) The estimated discount rate for the merged Black Hills Corporation’s Retirement Plan is 3.71% for the calculation of the 2018 net periodic pension costs.

(b) The expected rate of return on plan assets is 6.25% for the calculation of the 2018 net periodic pension cost.

The healthcare benefit obligation was determined at December 31 as follows:

	2017		2016
Trend Rate - Medical
Pre-65 for next year	7.00	%	6.10	%
Pre-65 Ultimate trend rate	4.50	%	4.50	%
Trend Year	2027		2024
Post-65 for next year	5.00	%	5.10	%
Post-65 Ultimate trend rate	4.50	%	4.50	%
Trend Year	2026		2023

We do not pre-fund our supplemental plan or our healthcare plan. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plan (in thousands):

Change in Assumed Trend Rate	Accumulated Periodic Postretirement Benefit Obligation			Service and Interest Costs
Increase 1%	$	186		$	7
Decrease 1%	$	(174	)	$	(7	)

Beginning in 2016, we changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on this Form 10-K for additional details.

The following benefit payments, which reflect future service, are expected to be paid (in thousands):

	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Defined Benefit Postretirement Healthcare Plan
2018	$	3,489	$	245	$	534
2019	$	3,628	$	242	$	621
2020	$	3,725	$	239	$	633
2021	$	3,835	$	333	$	613
2022	$	3,964	$	329	$	592
2023-2027	$	20,648	$	1,417	$	2,479

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Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We recorded non-cash dividends to our Parent of approximately $42 million and $53 million in 2017 and 2016 respectively, and decreased the utility Money pool note receivable for approximately $42 million and $53 million in 2017 and 2016, respectively.

Receivables and Payables

We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31 were as follows (in thousands):

	2017		2016
Receivable - affiliates	$	5,664	$	9,526
Accounts payable - affiliates	$	25,653	$	31,799

Money Pool Notes Receivable and Notes Payable

On September 1, 2017, the Utility Money Pool was transferred from Black Hills Power to our affiliate Black Hills Utility Holdings. This transfer reduced our cash by $0.7 million, reduced our Money pool notes receivable, net by $1.0 million and increased our Retained earnings by $0.3 million.

We will continue to participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings under the Agreement bear interest at the weighted average daily cost of our parent company’s external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0%.

The cost of borrowing under the Utility Money Pool was 1.96% at December 31, 2017.

We had the following balances with the Utility Money Pool as of December 31 (in thousands):

	2017			2016
Notes receivable (payable)	$	(13,397	)	$	28,409

Interest income relating to the Utility Money Pool for the years ended December 31, was as follows (in thousands):

	2017		2016		2015
Interest income	$	272	$	1,047	$	1,153

Interest expense allocation from Parent

BHC provides daily liquidity and cash management on behalf of all its subsidiaries. For the years ended December 31, 2017, 2016 and 2015, we were allocated $1.4 million, $1.9 million, and $2.1 million, respectively, of interest expense from BHC.

Other Balances and Transactions

We have the following Power Purchase and Transmission Services Agreements with affiliated entities:

• An agreement, expiring September 3, 2028, with Wyoming Electric to acquire 15 MW of the facility output from Happy Jack. Under a separate inter-company agreement expiring on September 3, 2028, Wyoming Electric has agreed to sell up to 15 MW of the facility output from Happy Jack to us.

• An agreement, expiring September 30, 2029, with Wyoming Electric to acquire 20 MW of the facility output from Silver Sage. Under a separate inter-company agreement expiring on September 30, 2029, Wyoming Electric has agreed to sell 20 MW of energy from Silver Sage to us.

• A Generation Dispatch Agreement with Wyoming Electric that requires us to purchase all of Wyoming Electric’s excess energy.

Related-party Gas Transportation Service Agreement

On October 1, 2014, we entered into a gas transportation service agreement with Wyoming Electric in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

Related-party Revenue and Purchases

We had the following related-party transactions for the years ended December 31 included in the corresponding captions in the accompanying Statements of Income:

	2017		2016		2015
	(in thousands)
Revenues:
Energy sold to Cheyenne Light	$	2,481	$	2,440	$	1,857
Rent from electric properties	$	5,100	$	5,046	$	4,772
Fuel and purchased power:
Purchases of coal from WRDC	$	15,948	$	16,227	$	16,401
Purchase of excess energy from Cheyenne Light	$	601	$	252	$	898
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	1,924	$	1,918	$	1,578
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	3,290	$	3,300	$	2,739
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	393	$	399	$	410
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	27,869	$	25,748	$	26,655

Horizon Point Agreement

We have an arrangement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric.  This cost allocation, includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

Years ended December 31,	2017			2016			2015
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	6,565		$	5,521		$	3,870
Non-cash decrease to money pool note receivable	$	(42,000	)	$	(52,500	)	$	(28,501	)
Non-cash dividend to Parent company	$	42,000		$	52,500		$	28,501
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(21,517	)	$	(21,320	)	$	(21,913	)
Income taxes (paid) refunded	$	(12,719	)	$	—		$	—

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Commitment and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

We have the following power purchase and transmission services agreements, not including related party agreements, as of December 31, 2017 (see Note 9 for information on related party agreements):

• A PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.

• A firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp.

• An agreement with Thunder Creek for gas transport capacity, expiring October 31, 2019.

Costs incurred under these agreements were as follows for the years ended December 31 (in thousands):

Contract	Contract Type	2017		2016		2015
PacifiCorp	Electric capacity and energy	$	13,218	$	12,221	$	13,990
PacifiCorp	Transmission access	$	1,671	$	1,428	$	1,213
Thunder Creek	Gas transport capacity	$	633	$	633	$	633

Future Contractual Obligations

The following is a schedule of future minimum payments required under power purchase, transmission services, facility and vehicle leases, and gas supply agreements (in thousands):

2018	$	13,531
2019	$	6,839
2020	$	6,839
2021	$	6,206
2022	$	6,206
Thereafter	$	6,206

Long-Term Power Sales Agreements

We have the following power sales agreements as of December 31, 2017:

• During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.

• An agreement to serve MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023.

• During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which expires September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.

• A PPA with MEAN expiring May 31, 2023. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.

• Effective January 1, 2017, we have an energy sales agreement with Cargill (assigned to Macquarie on January 3, 2018) expiring December 31, 2021 to supply 50 MW of energy during heavy and light load timing intervals.

Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. They can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date.

In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date.

For additional information on environmental matters, see Item 1 in this Annual Report on Form 10-K.

Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the financial statements.

In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.

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Quarterly Historical Data (Unaudited)

12 Months Ended

Dec. 31, 2017

Selected Quarterly Financial Information [Abstract]

Quarterly Historical Data (Unaudited)

QUARTERLY HISTORICAL DATA (Unaudited)

We operate on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter (in thousands):

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2017
Revenues	$	73,794	$	66,053	$	73,938	$	74,648
Operating income	$	23,376	$	17,712	$	23,698	$	19,040
Net income	$	12,570	$	9,287	$	13,826	$	15,615
2016
Revenues	$	68,642	$	62,019	$	66,728	$	70,243
Operating income	$	20,780	$	18,936	$	22,410	$	23,454
Net income	$	11,186	$	9,806	$	12,010	$	12,136

The fourth quarter of 2017 Net income includes a net tax benefit of $6.0 million from the impact of the TCJA.

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2017

Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts

SCHEDULE II

BLACK HILLS POWER, INC. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31,
Description	Balance at beginning of year		Additions charged to costs and expenses		Deductions charged to costs and expenses			Balance at end of year
	(in thousands)
Allowance for doubtful accounts:
2017	$	157	$	882	$	(815	)	$	224
2016	$	207	$	644	$	(694	)	$	157
2015	$	261	$	602	$	(656	)	$	207

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Business Description and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 3) and are prepared in accordance with GAAP.

Use of Estimates and Basis of Presentation

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

Cash Equivalents

Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Regulatory Accounting

Regulatory Accounting

Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory

assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but

generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer

meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable consists of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs or payment received.

We maintain an allowance for doubtful accounts which reflects our best estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

Revenue Recognition

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers are recorded on a net basis (excluded from Revenue).

Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Balance Sheets.

For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement.

Materials, Supplies, and Fuel

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are recorded using the weighted-average cost method.

Deferred Financing Costs

Deferred Financing Costs

Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities.

Property, Plant and Equipment

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Balance Sheets.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated electric properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.1% in 2017, 2.2% in 2016 and 2.3% in 2015.

Derivatives and Hedging Activities

Derivatives and Hedging Activities

The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and changes in the derivative instruments be recognized in earnings unless specific hedge accounting criteria are met and designated accordingly, including the normal purchase and normal sales exception.  Changes in the fair value for derivative instruments that do not meet this exception are recognized in the income statement as they occur.

From time to time we utilize risk management contracts including interest rate swaps to fix the interest on variable rate debt, or to lock in the Treasury yield component associated with anticipated issuance of senior notes.  For swaps that settled in connection with the issuance of senior debt, the effective portion is deferred as a component in AOCI and recognized as interest expense over the life of the senior note. As of December 31, 2017, we have no outstanding interest rate swap agreements.

Revenues and expenses on contracts that qualify as derivatives may be elected to be accounted for under the normal purchases and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting.  Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric operations, we enter into contracts to buy and sell energy to meet the requirements of our customers.  These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery.  If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exception, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging.

Fair Value Measurements

Fair Value Measurements

Assets and liabilities are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical

unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or

listed derivatives.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for

identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the

asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other

means.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs

reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would

use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value

measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable

such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the

availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more

observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively

impacting the availability of observable pricing inputs.

Income Taxes

Income Taxes

We file a federal income tax return with other members of the Parent’s consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017.

We use the deferral method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Statements of Income.

We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other, non-current liabilities on the accompanying Balance Sheets.

New Accounting Pronouncements

Recently Issued Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We have implemented this standard effective January 1, 2018 on a modified retrospective basis. We have completed our assessment of all revenue from existing contracts with customers and there is no significant impact to our revenue recognition practices, financial position, results of operations or cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term, generally limited to the services requested and received to date for such arrangements. For such arrangements, the performance obligation transfer of control and revenue recognition occurs when the electricity is delivered, consistent with the previous revenue recognition guidance. The same transfer of control and revenue recognition based on delivery principles also apply to our revenue contracts for wholesale and off-system power sales arrangements, and other non-regulated services. Therefore, we did not have a cumulative adjustment to Retained earnings or an impact on our revenue recognition policies as a result of the adoption of the new standard. The new standard will require us to provide more robust disclosures than required by previous guidance, including disclosures related to disaggregation of revenue into appropriate categories, performance obligations, and the judgments made in revenue recognition determinations.

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We have implemented this standard effective January 1, 2018. We will capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC to GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income, which are not expected to be material.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.We have implemented this standard effective January 1, 2018 on the retrospective transition method. This standard will not have a material impact on our financial position, results of operations or cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard.

We currently expect to adopt this standard on January 1, 2019 and anticipate electing the transition approach to not assess existing or expired land easements that were not previously accounted for as a lease. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and rights of way, pipeline laterals, purchase power agreements, and other industry-related areas. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes and systems.

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Business Description and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Regulatory Assets and Liabilities

We had the following regulatory assets and liabilities as of December 31 (in thousands):

	Maximum Amortization (in years)	2017		2016
Regulatory assets
Unamortized loss on reacquired debt (a)	7	$	1,534	$	1,815
Deferred taxes on AFUDC (b)	45	5,095		9,367
Employee benefit plans (c)	12	19,465		20,100
Deferred energy and fuel cost adjustments - current (a)	1	14,066		18,119
Deferred gas cost adjustments (a)	1	5,536		4,897
Deferred taxes on flow through accounting (a)	54	7,579		12,545
Decommissioning costs, net of amortization (d)	6	10,252		12,456
Vegetation management, net of amortization (d)	6	12,669		12,109
Other regulatory assets (a) (d)	6	2,507		726
		$	78,703	$	92,134
Regulatory liabilities
Cost of removal for utility plant (a)	61	$	44,056	$	41,541
Employee benefit plans and related deferred taxes (c)	12	6,808		12,304
Excess deferred income taxes (c) (e)	40	97,101		—
Other regulatory liabilities (c)	13	890		105
		$	148,855	$	53,950

____________________

(a)Recovery of costs but we are not allowed a rate of return.

(b) In addition to recovery of costs, we are allowed a rate of return.

(c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

(d) In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million are being amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million.

(e) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018.

Reg

Schedule of Accounts, Notes, Loans and Financing Receivable

Following is a summary of accounts receivable as of December 31 (in thousands):

	2017			2016
Accounts receivable, trade	$	15,994		$	16,972
Unbilled revenue	13,280			13,799
Less Allowance for doubtful accounts	(224		)	(157		)
Accounts receivable, net	$	29,050		$	30,614

Schedule of Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Balance Sheets as of December 31 (in thousands):

	2017		2016
Accrued employee compensation, benefits and withholdings	$	4,305	$	4,783
Accrued property taxes	5,930		5,522
Accrued income taxes	17,472		17,069
Customer deposits and prepayments	4,863		2,825
Accrued interest	4,708		4,614
Other (none of which is individually significant)	927		2,623
Total accrued liabilities	$	38,205	$	37,436

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment at December 31 consisted of the following (dollars in thousands):

				2017				2016
				Weighted				Weighted
				Average				Average	Lives (in years)
	2017			Useful Life (in years)	2016			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	587,323		46	$	576,833		46	40	54
Transmission	186,045			49	147,398			48	42	60
Distribution	375,214			46	364,304			46	21	62
Plant acquisition adjustment (a)	4,870			32	4,870			32	32	32
General	153,535			32	88,114			23	3	40
Total plant-in-service	1,306,987				1,181,519
Construction work in progress	4,832				54,868
Total electric plant	1,311,819				1,236,387
Less accumulated depreciation and amortization	(358,946		)		(338,828		)
Electric plant net of accumulated depreciation and amortization	$	952,873			$	897,559

__________________

(a) The plant acquisition adjustment is included in rate base and is being recovered with 13 years remaining.

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Jointly Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2017

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Schedule Of Jointly Owned Facilities

As of December 31, 2017, our interests in jointly-owned generating facilities and transmission systems were (in thousands):

Interest in jointly-owned facilities	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	114,405	$	727	$	58,955
Transmission Tie	$	20,037	$	242	$	6,215
Wygen III	$	138,688	$	406	$	19,239
Cheyenne Prairie	$	91,631	$	89	$	8,746

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Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments

Long-term debt outstanding at December 31 was as follows (in thousands):

		Interest Rate at		Balance Outstanding
	Due Date	December 31, 2017		December 31, 2017			December 31, 2016
First Mortgage Bonds due 2032	August 15, 2032	7.23	%	$	75,000		$	75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13	%	180,000			180,000
First Mortgage Bonds due 2044	October 20, 2044	4.43	%	85,000			85,000
Less unamortized debt discount				(90		)	(94		)
Series 94A Debt (a)	June 1, 2024	1.83	%	2,855			2,855
Less unamortized deferred financing costs				(2,870		)	(3,005		)
Long-term Debt				$	339,895		$	339,756

___________________

(a) Variable interest rate at December 31, 2017.

Schedule of Maturities of Long-term Debt

Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts and unamortized deferred financing costs) are as follows (in thousands):

2018	$	—
2019	$	—
2020	$	—
2021	$	—
2022	$	—
Thereafter	$	342,855

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Fair Value of Financial Instruments Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

The estimated fair values of our financial instruments at December 31 were as follows (in thousands):

	2017				2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents (a)	$	16	$	16	$	234	$	234
Long-term debt (b) (c)	$	339,895	$	446,978	$	339,756	$	410,466

_______________

(a) Fair value approximates carrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

(b) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

(c) Carrying amount of long-term debt is net of deferred financing costs.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows (in thousands):

	2017		2016		2015
Current	$	13,124	$	1,838	$	14,910
Deferred	1,004		20,690		7,690
Total income tax expense	$	14,128	$	22,528	$	22,600

Schedule of Deferred Tax Assets and Liabilities

The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):

	2017			2016
Deferred tax assets:
Employee benefits	$	3,012		$	5,163
Regulatory liabilities	24,984			9,099
Other	1,678			1,815
Total deferred tax assets	29,674			16,077
Deferred tax liabilities:
Accelerated depreciation and other plant related differences (a)	(122,002		)	(202,047		)
Regulatory assets	(7,008		)	(4,391		)
Employee benefits	(2,595		)	(3,075		)
Deferred costs	(8,447		)	(16,920		)
Other	(240		)	(1,087		)
Total deferred tax liabilities	(140,292		)	(227,520		)
Net deferred tax liability	$	(110,618	)	$	(211,443	)

(a) The net deferred tax liabilities were revalued for the change in federal tax rate to 21% under the TCJA. The revaluation resulted in a reduction to net deferred tax liabilities of approximately $103 million. Due to the regulatory construct, approximately $97 million of the revaluation was reclassified to a regulatory liability.

Schedule of Effective Income Tax Rate Reconciliation

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:

	2017	2016	2015
Federal statutory rate	35.0%	35.0%	35.0%
Amortization of excess deferred and investment tax credits	(0.1)	(0.4)	(0.1)
AFUDC Equity	(1.0)	(0.9)	(0.6)
Flow through adjustments (a)	(1.8)	(0.9)	(0.9)
Tax credits	—	(0.1)	—
Tax reform (b)	(9.2)	—	—
Other	(1.3)	0.6	—
	21.6%	33.3%	33.4%

_________________________

(a) Flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to tax expense.

(b) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21%, effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change.

Summary of Deferred Tax Liability Not Recognized

The following table reconciles the total amounts of unrecognized tax benefits, without interest, included in Other deferred credits and other liabilities on the accompanying Balance Sheet (in thousands):

	2017			2016
Unrecognized tax benefits at January 1	$	493		$	2,264
Additions for current year tax positions	13			—
Additions for prior year tax positions	—			1,194
Reductions for prior year tax positions	(204		)	(682		)
Settlements for prior year tax positions	—			(2,283		)
Unrecognized tax benefits at December 31	$	302		$	493

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Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2017

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Reclassification out of Accumulated Other Comprehensive Income

The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands):

	Location on the Statements of Income (Loss)	Amounts Reclassified from AOCI
		2017			2016
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	(22		)	(22		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	42		$	42
Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	86		$	82
Income tax	Income tax benefit (expense)	(30		)	(29		)
Total reclassification adjustments related to defined benefit plans, net of tax		$	56		$	53

Schedule of Accumulated Other Comprehensive Income (Loss)

Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands):

	Interest Rate Swaps			Employee Benefit Plans			Total
As of December 31, 2016	$	(593	)	$	(669	)	$	(1,262	)
Other comprehensive income (loss)	42			(38		)	4
As of December 31, 2017	$	(551	)	$	(707	)	$	(1,258	)
	Interest Rate Swaps			Employee Benefit Plans			Total
As of December 31, 2015	$	(635	)	$	(672	)	$	(1,307	)
Other comprehensive income (loss)	42			3			45
As of December 31, 2016	$	(593	)	$	(669	)	$	(1,262	)

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2017

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets

The percentages of total plan asset by investment category of our Pension Plan assets at December 31 were as follows:

	2017		2016
Equity securities	26	%	28	%
Real estate	4		5
Fixed income funds	63		57
Cash and cash equivalents	1		2
Hedge funds	6		8
Total	100	%	100	%

Schedule of Contribution to Employee Plans

Contributions for the years ended December 31 were as follows (in thousands):

	2017		2016
Defined Benefit Plans
Defined Benefit Pension Plan	$	4,000	$	820
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	348	$	420
Supplemental Non-qualified Defined Benefit Plan	$	246	$	221
Defined Contribution Plans
Company Retirement Contribution	$	861	$	851
Matching Contributions	$	1,306	$	1,400

Schedule of Changes in Projected Benefit Obligations

Benefit Obligations

As of December 31,	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2017			2016			2017			2016			2017			2016
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	64,973		$	65,959		$	3,404		$	3,426		$	5,843		$	6,208
Service cost	545			606			—			—			206			204
Interest cost	2,341			2,499			116			122			176			187
Actuarial loss (gain)	4,008			455			144			78			130			(446		)
Benefits paid	(3,445		)	(3,215		)	(246		)	(222		)	(348		)	(420		)
Plan participants transfer to affiliate	(860		)	(1,331		)	—			—			(137		)	(31		)
Plan participants’ contributions	—			—			—			—			100			141
Projected benefit obligation at end of year	$	67,562		$	64,973		$	3,418		$	3,404		$	5,970		$	5,843

Schedule of Changes in Fair Value of Plan Assets

Employee Benefit Plan Assets

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2017			2016			2017			2016			2017			2016
Beginning fair value of plan assets	$	53,888		$	54,723		$	—		$	—		$	—		$	—
Investment income (loss)	6,150			2,485			—			—			—			—
Benefits paid	(3,445		)	(3,215		)	(246		)	(221		)	(348		)	(420		)
Participant contributions	—			—			—			—			100			141
Employer contributions	4,000			820			246			221			248			279
Plan participants transfer to affiliate	(709		)	(925		)	—			—			—			—
Ending fair value of plan assets	$	59,884		$	53,888		$	—		$	—		$	—		$	—

Schedule of Amounts Recognized in Balance Sheet

The funded status of the plans and amounts recognized in the Balance Sheets at December 31 consist of (in thousands):

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2017			2016			2017			2016			2017			2016
Regulatory asset (liability)	$	18,998		$	18,974		$	—		$	—		$	(1,758	)	$	(2,087	)
Current liability	$	—		$	—		$	(245	)	$	(247	)	$	(534	)	$	(541	)
Non-current liability	$	(7,676	)	$	(11,085	)	$	(3,173	)	$	(3,157	)	$	(5,436	)	$	(5,302	)

Schedule of Accumulated and Projected Benefit Obligations

Accumulated Benefit Obligation

As of December 31 (in thousands)	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2017		2016		2017		2016		2017		2016
Accumulated benefit obligation (a)	$	64,782	$	61,585	$	3,418	$	3,404	$	5,970	$	5,843

____________________

(a) The Defined Benefit Pension Plan Accumulated Benefit Obligation for 2017 and 2016 represents the obligation for the merged Black Hills Retirement Plan.

Schedule of Net Benefit Costs

Components of Net Periodic Expense

Net periodic expense consisted of the following for the year ended December 31 (in thousands):

	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2017			2016			2015			2017		2016		2015		2017			2016			2015
Service cost	$	545		$	606		$	797		$	—	$	—	$	—	$	206		$	204		$	233
Interest cost	2,341			2,499			2,956			116		122		142		176			187			214
Expected return on assets	(3,591		)	(3,632		)	(3,935		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	43			43			43			—		—		—		(336		)	(337		)	(336		)
Recognized net actuarial loss (gain)	1,230			1,995			2,196			87		82		93		—			—			—
Net periodic expense	$	568		$	1,511		$	2,057		$	203	$	204	$	235	$	46		$	54		$	111

Schedule of Net Periodic Benefit Cost Not yet Recognized

For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):

	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2017		2016		2017		2016		2017		2016
Net (gain) loss	$	—	$	—	$	707	$	669	$	—	$	—
Total AOCI	$	—	$	—	$	707	$	669	$	—	$	—

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year

The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2018 are as follows (in thousands):

	Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
Net gain (loss)	$	1,341	$	67	$	—
Prior service cost	28		—		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2018	$	1,369	$	67	$	(218	)

Schedule of Assumptions Used

Assumptions

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2017		2016		2015		2017		2016		2015		2017		2016		2015
Weighted-average assumptions used to determine benefit obligations:
Discount rate	3.71	%	4.27	%	4.63	%	3.62	%	4.12	%	4.29	%	3.60	%	3.84	%	4.03	%
Rate of increase in compensation levels	3.43	%	3.47	%	3.57	%	N/A		N/A		N/A		N/A		N/A		N/A
Weighted-average assumptions used to determine net periodic benefit cost for plan year:
Discount rate (a)	4.27	%	4.63	%	4.25	%	4.12	%	4.29	%	3.98	%	3.84	%	4.03	%	3.70	%
Expected long-term rate of return on assets (b)	6.75	%	6.75	%	6.75	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.47	%	3.57	%	3.86	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________

(a) The estimated discount rate for the merged Black Hills Corporation’s Retirement Plan is 3.71% for the calculation of the 2018 net periodic pension costs.

(b) The expected rate of return on plan assets is 6.25% for the calculation of the 2018 net periodic pension cost.

Schedule of Health Care Cost Trend Rates

The healthcare benefit obligation was determined at December 31 as follows:

	2017		2016
Trend Rate - Medical
Pre-65 for next year	7.00	%	6.10	%
Pre-65 Ultimate trend rate	4.50	%	4.50	%
Trend Year	2027		2024
Post-65 for next year	5.00	%	5.10	%
Post-65 Ultimate trend rate	4.50	%	4.50	%
Trend Year	2026		2023

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plan (in thousands):

Change in Assumed Trend Rate	Accumulated Periodic Postretirement Benefit Obligation			Service and Interest Costs
Increase 1%	$	186		$	7
Decrease 1%	$	(174	)	$	(7	)

Schedule of Expected Benefit Payments

The following benefit payments, which reflect future service, are expected to be paid (in thousands):

	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Defined Benefit Postretirement Healthcare Plan
2018	$	3,489	$	245	$	534
2019	$	3,628	$	242	$	621
2020	$	3,725	$	239	$	633
2021	$	3,835	$	333	$	613
2022	$	3,964	$	329	$	592
2023-2027	$	20,648	$	1,417	$	2,479

Defined Benefit Pension Plan

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):

Pension Plan	December 31, 2017
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV (a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	184	$	—	$	184	$	—	$	184
Common Collective Trust - Cash and Cash Equivalents	—		314		—		314		—		314
Common Collective Trust - Equity	—		15,749		—		15,749		—		15,749
Common Collective Trust - Fixed Income	—		37,732		—		37,732		—		37,732
Common Collective Trust - Real Estate	—		249		—		249		2,258		2,507
Hedge Funds	—		—		—		—		3,398		3,398
Total investments measured at fair value	$	—	$	54,228	$	—	$	54,228	$	5,656	$	59,884

Pension Plan	December 31, 2016
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV (a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	196	$	—	$	196	$	—	$	196
Common Collective Trust - Cash and Cash Equivalents	—		784		—		784		—		784
Common Collective Trust - Equity	—		14,927		—		14,927		—		14,927
Common Collective Trust - Fixed Income	—		31,003		—		31,003		—		31,003
Common Collective Trust - Real Estate	—		347		—		347		2,300		2,647
Hedge Funds	—		—		—		—		4,331		4,331
Total investments measured at fair value	$	—	$	47,257	$	—	$	47,257	$	6,631	$	53,888

________________________

(a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Schedule of Related Party Accounts Receivable and Payable

We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31 were as follows (in thousands):

	2017		2016
Receivable - affiliates	$	5,664	$	9,526
Accounts payable - affiliates	$	25,653	$	31,799

Schedule of Related Party Notes and Associated Interest Income Expense

We had the following balances with the Utility Money Pool as of December 31 (in thousands):

	2017			2016
Notes receivable (payable)	$	(13,397	)	$	28,409

Schedule of Related Party Interest Income Expense

Interest income relating to the Utility Money Pool for the years ended December 31, was as follows (in thousands):

	2017		2016		2015
Interest income	$	272	$	1,047	$	1,153

Schedule of Revenues and Purchases from Related Parties

We had the following related-party transactions for the years ended December 31 included in the corresponding captions in the accompanying Statements of Income:

	2017		2016		2015
	(in thousands)
Revenues:
Energy sold to Cheyenne Light	$	2,481	$	2,440	$	1,857
Rent from electric properties	$	5,100	$	5,046	$	4,772
Fuel and purchased power:
Purchases of coal from WRDC	$	15,948	$	16,227	$	16,401
Purchase of excess energy from Cheyenne Light	$	601	$	252	$	898
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	1,924	$	1,918	$	1,578
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	3,290	$	3,300	$	2,739
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	393	$	399	$	410
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	27,869	$	25,748	$	26,655

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Years ended December 31,	2017			2016			2015
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	6,565		$	5,521		$	3,870
Non-cash decrease to money pool note receivable	$	(42,000	)	$	(52,500	)	$	(28,501	)
Non-cash dividend to Parent company	$	42,000		$	52,500		$	28,501
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(21,517	)	$	(21,320	)	$	(21,913	)
Income taxes (paid) refunded	$	(12,719	)	$	—		$	—

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Commitment and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment

Costs incurred under these agreements were as follows for the years ended December 31 (in thousands):

Contract	Contract Type	2017		2016		2015
PacifiCorp	Electric capacity and energy	$	13,218	$	12,221	$	13,990
PacifiCorp	Transmission access	$	1,671	$	1,428	$	1,213
Thunder Creek	Gas transport capacity	$	633	$	633	$	633

Unrecorded Unconditional Purchase Obligations Disclosure

The following is a schedule of future minimum payments required under power purchase, transmission services, facility and vehicle leases, and gas supply agreements (in thousands):

2018	$	13,531
2019	$	6,839
2020	$	6,839
2021	$	6,206
2022	$	6,206
Thereafter	$	6,206

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Quarterly Historical Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Selected Quarterly Financial Information [Abstract]

Schedule of Quarterly Financial Information

The following table sets forth selected unaudited historical operating results data for each quarter (in thousands):

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2017
Revenues	$	73,794	$	66,053	$	73,938	$	74,648
Operating income	$	23,376	$	17,712	$	23,698	$	19,040
Net income	$	12,570	$	9,287	$	13,826	$	15,615
2016
Revenues	$	68,642	$	62,019	$	66,728	$	70,243
Operating income	$	20,780	$	18,936	$	22,410	$	23,454
Net income	$	11,186	$	9,806	$	12,010	$	12,136

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Business Description and Summary of Significant Accounting Policies: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		6 Months Ended	12 Months Ended
	Jul. 01, 2017	Jun. 30, 2017	Dec. 31, 2017	Jun. 16, 2017	Dec. 31, 2016
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets			$ 78,703		$ 92,134
Regulatory Liabilities			$ 148,855		53,950
Amortization of Regulatory Asset	$ 2,700
Cost of removal for utility plant
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities, Maximum Recovery Period			61 years
Regulatory Liabilities			$ 44,056		41,541
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities, Maximum Recovery Period			12 years
Regulatory Liabilities			$ 6,808		12,304
Deferred Income Tax Charges a
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities, Maximum Recovery Period			40 years
Regulatory Liabilities			$ 97,101		0
Other regulatory liabilities
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities, Maximum Recovery Period			13 years
Regulatory Liabilities			$ 890		105
Unamortized loss on reacquired debt
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period			7 years
Regulatory Assets			$ 1,534		1,815
Allowance for Funds Used During Construction
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period			45 years
Regulatory Assets			$ 5,095		9,367
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period			12 years
Regulatory Assets			$ 19,465		20,100
Deferred energy costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period			1 year
Regulatory Assets			$ 14,066		18,119
Asset Recoverable Gas Costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period			1 year
Regulatory Assets			$ 5,536		4,897
Flow through accounting
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period			54 years
Regulatory Assets			$ 7,579		12,545
Decommissioning costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period			6 years
Regulatory Assets			$ 10,252		12,456
Decommissioning costs | South Dakota Public Utilities Commission (SDPUC)
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period	6 years
Regulatory Assets				$ 11,000
Decommissioning costs | South Dakota Public Utilities Commission (SDPUC) | Scenario, Previously Reported
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period		10 years
Vegetation Management
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period			6 years
Regulatory Assets			$ 12,669		12,109
Vegetation Management | South Dakota Public Utilities Commission (SDPUC)
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period	6 years
Regulatory Assets				$ 14,000
Other Regulatory Assets
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period			6 years
Regulatory Assets			$ 2,507		$ 726
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Catastrophe
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period	6 years
Regulatory Assets		$ 2,000
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Catastrophe | Scenario, Previously Reported
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period		10 years

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Business Description and Summary of Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Less Allowance for doubtful accounts	$ (224)	$ (157)
Accounts receivable, net	29,050	30,614
Billed Revenues
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, trade	15,994	16,972
Unbilled Revenues
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, trade	$ 13,280	$ 13,799

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Business Description and Summary of Significant Accounting Policies: Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Composite Depreciation Rate for Plants in Service	2.10%	2.20%	2.30%

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Business Description and Summary of Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accrued employee compensation, benefits and withholdings	$ 4,305	$ 4,783
Accrued property taxes	5,930	5,522
Accrued income taxes	17,472	17,069
Customer deposits and prepayments	4,863	2,825
Accrued interest	4,708	4,614
Other (none of which is individually significant)	927	2,623
Total accrued liabilities	$ 38,205	$ 37,436

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Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Total plant-in-service	$ 1,306,987	$ 1,181,519
Construction work in progress	4,832	54,868
Total electric plant	1,311,819	1,236,387
Less accumulated depreciation and amortization	(358,946)	(338,828)
Electric plant net of accumulated depreciation and amortization	$ 952,873	897,559
Remaining amortization period	13 years
Electric Production
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Production	$ 587,323	$ 576,833
Electric Production | Weighted average useful life
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	46 years	46 years
Electric Production | Minimum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	40 years
Electric Production | Maximum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	54 years
Electric Transmission
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Transmission	$ 186,045	$ 147,398
Electric Transmission | Weighted average useful life
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	49 years	48 years
Electric Transmission | Minimum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	42 years
Electric Transmission | Maximum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	60 years
Electric Distribution
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Distribution	$ 375,214	$ 364,304
Electric Distribution | Weighted average useful life
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	46 years	46 years
Electric Distribution | Minimum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	21 years
Electric Distribution | Maximum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	62 years
Plant Acquisition Adjustment
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant acquisition adjustment	$ 4,870	$ 4,870
Plant Acquisition Adjustment | Weighted average useful life
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	32 years	32 years
Plant Acquisition Adjustment | Minimum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	32 years
Plant Acquisition Adjustment | Maximum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	32 years
General
Public Utilities, Property, Plant and Equipment, Net [Abstract]
General	$ 153,535	$ 88,114
General | Weighted average useful life
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	32 years	23 years
General | Minimum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	3 years
General | Maximum
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)	40 years

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Jointly Owned Facilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) MW
Wyodak Plant
Jointly Owned Utility Plant Interests [Line Items]
Proportionate Ownership Percentage	20.00%
Plant in Service	$ 114,405
Construction Work in Progress	727
Accumulated Depreciation	$ 58,955
Transmission Tie
Jointly Owned Utility Plant Interests [Line Items]
Proportionate Ownership Percentage	35.00%
Utility Plant, Megawatt Capacity | MW	400
Plant in Service	$ 20,037
Construction Work in Progress	242
Accumulated Depreciation	$ 6,215
Transmission Tie | West to East Transmission Tie
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity | MW	200
Transmission Tie | East to West Transmission Tie
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity | MW	200
Wygen I I I Generating Facility
Jointly Owned Utility Plant Interests [Line Items]
Proportionate Ownership Percentage	52.00%
Plant in Service	$ 138,688
Construction Work in Progress	406
Accumulated Depreciation	$ 19,239
Cheyenne Prairie
Jointly Owned Utility Plant Interests [Line Items]
Electric Generation Capacity, Megawatts | MW	95
Plant in Service	$ 91,631
Construction Work in Progress	89
Accumulated Depreciation	$ 8,746
Cheyenne Prairie | Wyoming Electric
Jointly Owned Utility Plant Interests [Line Items]
Electric Generation Capacity, Megawatts | MW	40
Cheyenne Prairie | South Dakota Electric
Jointly Owned Utility Plant Interests [Line Items]
Electric Generation Capacity, Megawatts | MW	55

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Long-term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Unamortized Discount	$ (90)	$ (94)
Less unamortized deferred financing costs	(2,870)	(3,005)
Long-term Debt	339,895	339,756
Deferred Finance Costs, Noncurrent, Net	2,900	3,000
Amortization of Financing Costs	$ 100
First Mortgage Bonds Due 2032
Debt Instrument [Line Items]
Interest Rate, Stated Percentage	7.23%
Long-term Debt, Gross	$ 75,000	75,000
First Mortgage Bonds Due 2039
Debt Instrument [Line Items]
Interest Rate, Stated Percentage	6.125%
Long-term Debt, Gross	$ 180,000	180,000
First Mortgage Bonds Due 2044
Debt Instrument [Line Items]
Interest Rate, Stated Percentage	4.43%
Long-term Debt, Gross	$ 85,000	85,000
Bonds Due 2024
Debt Instrument [Line Items]
Variable Interest, Percentage Rate	1.83%
Long-term Debt, Gross	$ 2,855	$ 2,855

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Long-term Debt: Schedule of Maturities of Long-term Debt (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Long-term Debt, Unclassified [Abstract]
2018	$ 0
2019	0
2020	0
2021	0
2022	0
Thereafter	$ 342,855

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Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, at carrying value	$ 16	$ 234	$ 297	$ 1,542
Long-term debt, at carrying value	339,895	339,756
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, at carrying value	16	234
Long-term debt, at carrying value	339,895	339,756
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, at fair value	16	234
Long-term debt, at fair value	$ 446,978	$ 410,466

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Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current	$ 13,124	$ 1,838	$ 14,910
Deferred	1,004	20,690	7,690
Total income tax expense	$ 14,128	$ 22,528	$ 22,600

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Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Components of Deferred Tax Assets [Abstract]
Employee benefits	$ 3,012	$ 5,163
Regulatory liabilities	24,984	9,099
Other	1,678	1,815
Total deferred tax assets	29,674	16,077
Components of Deferred Tax Liabilities [Abstract]
Accelerated depreciation and other plant related differences	(122,002)	(202,047)
Regulatory assets	(7,008)	(4,391)
Employee benefits	(2,595)	(3,075)
Deferred costs	(8,447)	(16,920)
Other	(240)	(1,087)
Total deferred tax liabilities	(140,292)	(227,520)
Net deferred tax liability	(110,618)	$ (211,443)
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit)	103,000
Deferred Income Tax Charges a
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Provisional Income Tax Expense (Benefit)	$ 97,000

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Income Taxes: Effective Tax Rate Differences from Statutory Tax Rates (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal statutory rate	35.00%	35.00%	35.00%
Amortization of excess deferred and investment tax credits, percent	(0.10%)	(0.40%)	(0.10%)
AFUDC Equity, percent	(1.00%)	(0.90%)	(0.60%)
Flow through adjustments, percent	(1.80%)	(0.90%)	(0.90%)
Tax credits, percent	(0.00%)	(0.10%)	(0.00%)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	(9.20%)	0.00%	0.00%
Other, percent	(1.30%)	0.60%	0.00%
Effective Income Tax Rate	21.60%	33.30%	33.40%

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Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning of Period	$ 493	$ 2,264
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	13	0
Additions for prior year tax positions	0	1,194
Reductions for prior year tax positions	(204)	(682)
Settlements for prior year tax positions	0	(2,283)
End of Period	$ 302	$ 493

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Comprehensive Income: Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest Costs Incurred									$ 22,421	$ 22,908	$ 22,337
Income Tax Expense (Benefit)									14,128	22,528	22,600
Net income	$ 15,615	$ 13,826	$ 9,287	$ 12,570	$ 12,136	$ 12,010	$ 9,806	$ 11,186	51,298	45,138	$ 45,174
First Mortgage Bonds Due 2032
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Derivative, Notional Amount	50,000								50,000
Realized Loss Included Accumulated Other Comprehensive Income (Loss)	$ 1,800								1,800
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income Tax Expense (Benefit)									(22)	(22)
Net income									42	42
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income | Interest Rate Contract
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest Costs Incurred									64	64
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses									86	82
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income Tax Expense (Benefit)									(30)	(29)
Net income									$ 56	$ 53

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Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (1,262)	$ (1,307)
Other comprehensive income (loss)	4	45	$ 512
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(1,258)	(1,262)	(1,307)
Interest Rate Swaps, Cash Flow Hedges, AOCI | Interest Rate Swaps
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(593)	(635)
Other comprehensive income (loss)	42	42
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(551)	(593)	(635)
Employee Benefit Plans, AOCI
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(669)	(672)
Other comprehensive income (loss)	(38)	3
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	$ (707)	$ (669)	$ (672)

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Employee Benefit Plans: Narrative (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Maximum Annual Contribution Per Employee, Percent	50.00%
Employers Matching Contribution, Annual Vesting Percentage	20.00%
Defined Contribution Plan, Employee Vesting Period	5 years
Target Plan Asset Allocations, percent	100.00%	100.00%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	6.25%	6.75%
Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employers Matching Contribution, Annual Vesting Percentage	100.00%
Equity Securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Plan Asset Allocations, percent	26.00%	28.00%
Fixed Income Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Plan Asset Allocations, percent	63.00%	57.00%
Defined Benefit Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	6.75%	6.75%	6.75%
Defined Benefit Pension Plan | Equity Securities | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Plan Asset Allocations, percent	37.00%
Defined Benefit Pension Plan | Equity Securities | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Plan Asset Allocations, percent	45.00%
Defined Benefit Pension Plan | Fixed Income Funds | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Plan Asset Allocations, percent	55.00%
Defined Benefit Pension Plan | Fixed Income Funds | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Plan Asset Allocations, percent	63.00%

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Employee Benefit Plans: Target Plan Assets Allocation (Details)	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations, percent	100.00%	100.00%
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations, percent	26.00%	28.00%
Real Estate
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations, percent	4.00%	5.00%
Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations, percent	63.00%	57.00%
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations, percent	1.00%	2.00%
Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations, percent	6.00%	8.00%

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Employee Benefit Plans: Plan Contribution (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 1,800
Defined Contribution Plan, Company Retirement
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plans, Contributions by Employer	861	$ 851
Defined Contribution Plan, 401K
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plans, Contributions by Employer	1,306	1,400
Defined Benefit Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	4,000	820
Non-pension Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	248	279
Defined Benefit Plans, Employer Contributions	348	420
Supplemental Non-qualified Defined Benefit Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	246	221
Defined Benefit Plans, Employer Contributions	$ 246	$ 221

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Employee Benefit Plans: Fair Value Measurements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	65 days
Defined Benefit Pension Plan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	$ 59,884	$ 53,888	$ 54,723
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	59,884	53,888
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	54,228	47,257
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	5,656	6,631
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	184	196
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	184	196
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Common Collective Trust, Cash And Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	314	784
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	314	784
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	15,749	14,927
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	15,749	14,927
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	37,732	31,003
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	37,732	31,003
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	2,507	2,647
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	249	347
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	2,258	2,300
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	3,398	4,331
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	0	0
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	3,398	4,331
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Common Collective Trust, Cash And Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	54,228	47,257
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	184	196
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Common Collective Trust, Cash And Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	314	784
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	15,749	14,927
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	37,732	31,003
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	249	347
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Common Collective Trust, Cash And Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	0	0
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total investments measured at fair value	$ 0	$ 0

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Employee Benefit Plans: Changes in Benefit Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Pension Plan
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	$ 64,973	$ 65,959
Service cost	545	606	$ 797
Interest cost	2,341	2,499	2,956
Actuarial loss (gain)	4,008	455
Defined Benefit Plan, Benefits Paid	(3,445)	(3,215)
Asset transfer (to) from affiliate	(860)	(1,331)
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	67,562	64,973	65,959
Supplemental Non-qualified Defined Benefit Retirement Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	3,404	3,426
Service cost	0	0	0
Interest cost	116	122	142
Actuarial loss (gain)	144	78
Defined Benefit Plan, Benefits Paid	(246)	(222)
Asset transfer (to) from affiliate	0	0
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	3,418	3,404	3,426
Non-pension Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	5,843	6,208
Service cost	206	204	233
Interest cost	176	187	214
Actuarial loss (gain)	130	(446)
Defined Benefit Plan, Benefits Paid	(348)	(420)
Asset transfer (to) from affiliate	(137)	(31)
Plan participants’ contributions	100	141
Projected benefit obligation at end of year	$ 5,970	$ 5,843	$ 6,208

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Employee Benefit Plans: Changes in Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Pension Plan
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets	$ 53,888	$ 54,723
Investment income (loss)	6,150	2,485
Benefits paid	(3,445)	(3,215)
Participant contributions	0	0
Employer contributions	4,000	820
Asset transfer to affiliate	(709)	(925)
Ending fair value of plan assets	59,884	53,888
Supplemental Non-qualified Defined Benefit Retirement Plans
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets	0	0
Investment income (loss)	0	0
Defined Benefit Plan Benefits Paid From Plan and Company Assets	(246)	(221)
Participant contributions	0	0
Employer contributions	246	221
Asset transfer to affiliate	0	0
Ending fair value of plan assets	0	0
Non-pension Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets	0	0
Investment income (loss)	0	0
Benefits paid	(348)	(420)
Participant contributions	100	141
Employer contributions	248	279
Asset transfer to affiliate	0	0
Ending fair value of plan assets	$ 0	$ 0

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Employee Benefit Plans: Amounts Recognized in the Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-current liability	$ (16,285)	$ (19,544)
Defined Benefit Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset (liability)	18,998	18,974
Current liability	0	0
Non-current liability	(7,676)	(11,085)
Supplemental Non-qualified Defined Benefit Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset (liability)	0	0
Current liability	(245)	(247)
Non-current liability	(3,173)	(3,157)
Non-pension Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset (liability)	(1,758)	(2,087)
Current liability	(534)	(541)
Non-current liability	$ (5,436)	$ (5,302)

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Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated benefit obligation	$ 64,782	$ 61,585
Supplemental Non-qualified Defined Benefit Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated benefit obligation	3,418	3,404
Non-pension Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated benefit obligation	$ 5,970	$ 5,843

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Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 545	$ 606	$ 797
Interest cost	2,341	2,499	2,956
Expected return on assets	(3,591)	(3,632)	(3,935)
Amortization of prior service cost (credits)	43	43	43
Recognized net actuarial loss (gain)	1,230	1,995	2,196
Net periodic expense	568	1,511	2,057
Supplemental Non-qualified Defined Benefit Retirement Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	0
Interest cost	116	122	142
Expected return on assets	0	0	0
Amortization of prior service cost (credits)	0	0	0
Recognized net actuarial loss (gain)	87	82	93
Net periodic expense	203	204	235
Non-pension Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	206	204	233
Interest cost	176	187	214
Expected return on assets	0	0	0
Amortization of prior service cost (credits)	(336)	(337)	(336)
Recognized net actuarial loss (gain)	0	0	0
Net periodic expense	$ 46	$ 54	$ 111

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Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Pension Plan
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax [Abstract]
Net loss	$ 0	$ 0
Total accumulated other comprehensive income (loss)	0	0
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	1,341
Prior service cost	28
Total net periodic benefit cost expected to be recognized during calendar year 2018	1,369
Supplemental Non-qualified Defined Benefit Retirement Plans
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax [Abstract]
Net loss	707	669
Total accumulated other comprehensive income (loss)	707	669
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	67
Prior service cost	0
Total net periodic benefit cost expected to be recognized during calendar year 2018	67
Non-pension Defined Benefit Postretirement Healthcare Plan
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax [Abstract]
Net loss	0	0
Total accumulated other comprehensive income (loss)	0	$ 0
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	0
Prior service cost	(218)
Total net periodic benefit cost expected to be recognized during calendar year 2018	$ (218)

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Employee Benefit Plans: Defined Benefit Plans Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected long-term rate of return on assets	6.25%	6.75%
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
1% Increase on Service and Interest Costs	$ 7
1% Increase on Accumulated Periodic Postretirement Benefit Obligation	186
1% Decrease on Service and Interest Cost	(7)
1% Decrease on Accumulated Periodic Postretirement Benefit Obligation	$ (174)
Defined Benefit Pension Plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.71%	4.27%	4.63%
Rate of increase in compensation levels	3.43%	3.47%	3.57%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.27%	4.63%	4.25%
Expected long-term rate of return on assets	6.75%	6.75%	6.75%
Rate of increase in compensation levels	3.47%	3.57%	3.86%
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	3.71%
Supplemental Non-qualified Defined Benefit Retirement Plans
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.62%	4.12%	4.29%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.12%	4.29%	3.98%
Non-pension Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.60%	3.84%	4.03%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	3.84%	4.03%	3.70%
Healthcare trend rate pre-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	7.00%	6.10%
Ultimate trend rate	4.50%	4.50%
Year Ultimate Trend Reached	2027	2024
Healthcare trend rate post-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	5.00%	5.10%
Ultimate trend rate	4.50%	4.50%
Year Ultimate Trend Reached	2026	2023

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Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Defined Benefit Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2018	$ 3,489
2019	3,628
2020	3,725
2021	3,835
2022	3,964
2023-2027	20,648
Supplemental Non-qualified Defined Benefit Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2018	245
2019	242
2020	239
2021	333
2022	329
2023-2027	1,417
Non-pension Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2018	534
2019	621
2020	633
2021	613
2022	592
2023-2027	$ 2,479

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Employee Benefit Plans: Defined Contribution Plan (Details)	12 Months Ended
	Dec. 31, 2017
Defined Benefit Plan [Abstract]
Maximum Annual Contribution Per Employee, Percent	50.00%
Employers Matching Contribution, Annual Vesting Percentage	20.00%

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Related Party Transactions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Related Party Transaction [Line Items]
Receivables - affiliates	$ 5,664	$ 9,526
Accounts payable - affiliates	$ 25,653	31,799
Utility Money Pool Interest Rate	1.96%
Money pool note payable	$ 13,397	0
Money pool notes receivable	0	28,409
Utility Money Pool
Related Party Transaction [Line Items]
Net interest income (expense)	272	1,047	$ 1,153
Parent
Related Party Transaction [Line Items]
Non-cash dividend to Parent company	$ 42,000	52,500	28,501
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	1.00%
Interest Expense, Related Party	$ 1,400	1,900	2,100
Subsidiary of Common Parent
Related Party Transaction [Line Items]
Transfer from Investments	$ 42,000	52,500	28,501
Subsidiary of Common Parent | Purchase Of Natural Gas, Wyoming Gas
Related Party Transaction [Line Items]
Long-term Purchase Commitment, Period	40 years
Subsidiary of Common Parent | Purchase Of Natural Gas, Cheyenne Light
Related Party Transaction [Line Items]
Costs and Expenses	$ 393	399	410
Subsidiary of Common Parent | Coal, Purchased
Related Party Transaction [Line Items]
Costs and Expenses	15,948	16,227	16,401
Subsidiary of Common Parent | Purchase of Excess Energy, Cheyenne Light
Related Party Transaction [Line Items]
Costs and Expenses	$ 601	252	898
Subsidiary of Common Parent | Happy Jack Wind Purchase Power Agreeement
Related Party Transaction [Line Items]
Number of Megawatts Capacity Purchased | MW	15
Costs and Expenses	$ 1,924	1,918	1,578
Subsidiary of Common Parent | Silver Sage Wind Power Purchase Agreement
Related Party Transaction [Line Items]
Number of Megawatts Capacity Purchased | MW	20
Costs and Expenses	$ 3,290	3,300	2,739
Subsidiary of Common Parent | Allocated Costs From Related Parties
Related Party Transaction [Line Items]
Costs and Expenses	27,869	25,748	26,655
Subsidiary of Common Parent | Energy sold to Wyoming Electric
Related Party Transaction [Line Items]
Revenue	2,481	2,440	1,857
Subsidiary of Common Parent | Lease Agreements
Related Party Transaction [Line Items]
Revenue	5,100	$ 5,046	$ 4,772
Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings | Cash and Cash Equivalents | Subsidiary of Common Parent
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	700
Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings | Money Pool Notes Receivable | Subsidiary of Common Parent
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	1,000
Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings | Retained Earnings | Subsidiary of Common Parent
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 300

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 6,565	$ 5,521	$ 3,870
Interest and Income Taxes (Paid) Refunded, Cash Flow Information [Abstract]
Interest (net of amounts capitalized)	(21,517)	(21,320)	(21,913)
Income taxes (paid) refunded	(12,719)	0	0
Subsidiary of Common Parent
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Non-cash decrease to money pool note receivable	(42,000)	(52,500)	(28,501)
Parent
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Non-cash dividend to Parent company	$ 42,000	$ 52,500	$ 28,501

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Commitment and Contingencies (Details) $ in Thousands		12 Months Ended
	Jan. 01, 2017 MW	Dec. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Contractual Obligation, Fiscal Year Maturity [Abstract]
2018		$ 13,531
2019		6,839
2020		6,839
2021		6,206
2022		6,206
Thereafter		$ 6,206
M D U, Montana Dakota Utilities
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW		25
City Of Gillette
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW		23
Purchase Power Contract, MEAN, 10 M W
Sales Capacity Commitments [Abstract]
Long-term Contract To Sell Electric Power, Date of Contract Expiration		May 31, 2023
Purchase Power Contract, MEAN, 10 M W | Wygen I I I Generating Facility
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW		10
Purchase Power Contract, MEAN, 10 M W | Neil Simpson I I
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW		10
Maximum | M D U, Montana Dakota Utilities
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW		50
Maximum | Cargill Power Purchase Agreement
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW	50
Thunder Creek - Gas Transport Capacity
Long-term Purchase Commitment [Line Items]
Gas Gathering, Transportation, Marketing and Processing Costs		$ 633	$ 633	$ 633
Osage Plant Ash Impoundment
Sales Capacity Commitments [Abstract]
Commitment and Contingencies, Environmental Matters, Post Closure Monitoring, Period		30 years
Osage Plant, Industrial Rubble Landfill
Sales Capacity Commitments [Abstract]
Commitment and Contingencies, Environmental Matters, Post Closure Monitoring, Period		30 years
PacifiCorp Purchase Power Agreement
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration		Dec. 31, 2023
Number of Megawatts Capacity Purchased | MW		50
Cost of Purchased Power		$ 13,218	12,221	13,990
PacifiCorp Transmission
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration		Dec. 31, 2023
Number of Megawatts Capacity Purchased | MW		50
Cost of Purchased Power		$ 1,671	$ 1,428	$ 1,213

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Quarterly Financial information Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Revenues	$ 74,648	$ 73,938	$ 66,053	$ 73,794	$ 70,243	$ 66,728	$ 62,019	$ 68,642	$ 288,433	$ 267,632	$ 277,864
Operating income	19,040	23,698	17,712	23,376	23,454	22,410	18,936	20,780	83,826	85,580	87,914
Net income	15,615	$ 13,826	$ 9,287	$ 12,570	$ 12,136	$ 12,010	$ 9,806	$ 11,186	$ 51,298	$ 45,138	$ 45,174
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Income Tax Expense (Benefit)	$ 6,000

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Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
Allowance for doubtful accounts, balance at beginning of year	$ 157	$ 207	$ 261
Additions charged to costs and expenses	882	644	602
Deductions charged to costs and expenses	(815)	(694)	(656)
Allowance for doubtful accounts, balance at end of year	$ 224	$ 157	$ 207