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, 2015

¨	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
625 Ninth Street, Rapid City, South Dakota 57701
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 or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer    ¨    Accelerated filer    ¨    Non-accelerated filer    x Smaller reporting company    ¨

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

Yes    ¨    No    x

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, 2016
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	5
ITEM 1A.	RISK FACTORS	11
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	18
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS	18
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	24
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	55
ITEM 9A.	CONTROLS AND PROCEDURES	55
ITEM 9B.	OTHER INFORMATION	55
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	55
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	56
	SIGNATURES	58
	INDEX TO EXHIBITS	59

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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
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 Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Service Company	Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Wyoming	Black Hills Wyoming, LLC, an indirect, wholly-owned subsidiary of Black Hills Electric Generation, Inc., a subsidiary of Black Hills Non-regulated Holdings
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 operations on October 1, 2014.
City of Gillette	The City of Gillette, Wyoming, affiliate of the JPB.
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.
CPCN	Certificate of Public Convenience and Necessity
CPP	Clean Power Plan
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.
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 gas
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 Farms, LLC, a subsidiary of Duke Energy Generation Services

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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
JPB	Consolidated Wyoming Municipalities Electric Power System Joint Powers Board. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The JPB financed the purchase of 23% of the Wygen III power plant for the City of Gillette.
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
NERC	North American Electric Reliability Corporation
NOL	Net operating loss
NOx	Nitrogen oxide
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
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.
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.
Thunder Creek	Thunder Creek Gas Services, LLC
TIPA	Tax Increase Prevention Act of 2014
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, LLC

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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, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s 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 the Company undertakes 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 the Company’s 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 the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.

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 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, 2015, our ownership interests in electric generation plants were as follows:

Unit (1)	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Wygen III (1)	Coal	Gillette, WY	52%	57.2	2010
Neil Simpson II	Coal	Gillette, WY	100%	90.0	1995
Wyodak (2)	Coal	Gillette, WY	20%	72.4	1978
Cheyenne Prairie (3)	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

_______________________

(1) 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.

(2) 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.

(3) Cheyenne Prairie, a gas-fired power generation facility includes one combined-cycle, 95 MW unit that is jointly owned by Cheyenne Light (40 MW) and us (55 MW). This facilitywas placed into commercial operations on October 1, 2014.

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Distribution and Transmission. Our distribution and transmission system serves approximately 71,000 electric customers, with an electric transmission system of 1,179 miles of high voltage lines (greater than 69 kV) and 2,485 miles of lower voltage lines. 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. Approximately 90% of our retail electric revenues in 2015 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, 2015 was comprised of 36% commercial, 26% residential, 6% contract wholesale, 8% wholesale off-system, 12% industrial and 12% municipal and other revenue.

• We own 35% and Basin Electric owns 65% 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 the Eastern United States, respectively. This transmission tie provides transmission access to both the WECC region in the West and the MAPP region in the East. Our system is located in the WECC region. The total transfer capacity of the tie is 200 MW from West to East and 200 MW from East to West. This transmission tie allows us to buy and sell energy in the Eastern interconnection without having to isolate and physically reconnect load or generation between the two electrical transmission grids. The transmission tie accommodates scheduling transactions in both directions simultaneously. This transfer capability provides additional opportunity to sell our excess generation or to make economic purchases to serve our native load and our contract obligations, and to take advantage of the power price differentials between the two electric grids. Additionally, our system is capable of directly interconnecting up to 80 MW of generation or load to the Eastern transmission grid. Transmission constraints within the MAPP transmission system may limit the amount of capacity that may be directly interconnected to the Eastern system at any given time.

• 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.

• 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 2017, 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.

•An agreement under which we supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. 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:

2016-2017	20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019	15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021	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.

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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 53% of our energy requirements in 2015 and purchased approximately 47% 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 Cheyenne Light expiring in 2028, under which we will purchase up to 14.7 MW of wind energy through Cheyenne Light’s agreement with Happy Jack.

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

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

Since 1995, we have been a net producer of energy. Our 2015 winter peak system load was 369 MW and our 2015 summer peak system load was 424 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.

Operating Agreements

Related-party Gas Transportation Service Agreement - On October 1, 2014 we entered into a gas transportation service agreement with Cheyenne Light 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 Cheyenne Light 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. The revenues and expenses associated with these assets are included in rate base.

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

Rate Regulation

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

State	Authorized Rate of Return on Equity	Authorized Return on Rate Base	Capital Structure Debt/Equity	Effective Date	Other Tariffs, Riders and Rate Matters	Percentage of Off-System Sale Profits Shared with Customers
SD	Global Settlement	7.76%	Global Settlement	10/2014	ECA,TCA, Energy Efficiency Cost Recovery/ DSM	70%
SD		8.16%		6/2011	Environmental Improvement Cost Recovery Adjustment Tariff	N/A
WY	9.9%	8.13%	46.7%/53.3%	10/2014	ECA	65%
MT	15.0%	11.73%	47%/53%	1983	ECA	N/A
FERC	10.8%	9.10%	43%/57%	2/2009	FERC Transmission Tariff	N/A

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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, Montana and South Dakota which provide for pass-through of certain costs related to the purchase, production and/or transmission of electricity. In December 2015, we filed an application with the MTPSC to cancel the Montana Quarterly Fuel Rider and we expect a decision in the first quarter of 2016. 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 are:

• An approved vegetation management recovery mechanism that allows for recovery of and a return on prudently-incurred vegetation management costs.

• In South Dakota we have an annual adjustment clause which provides for the direct recovery of increased fuel and purchased power incurred to serve South Dakota customers. Additionally, the ECA contains an off-system sales sharing mechanism in which South Dakota customers receive a credit equal to 70% of off-system power marketing operating income. The modification also adjusts the methodology to directly assign renewable resources and firm purchases to the customer load. Wyoming has a similar Fuel and Purchased Power Cost Adjustment.

• In South Dakota we have an approved annual Environmental Improvement Cost Recovery Adjustment tariff that went into effect June 1, 2011 and recovers costs associated with generation plant environmental improvements.

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

Rate Matters

South Dakota

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for us of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides us a return on our investment in Cheyenne Prairie and associated infrastructure, and provides recovery of our share of operating expenses for this natural gas fired facility. We implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

Transmission

On July 23, 2015, we received approval from the WPSC for a CPCN originally filed on July 22, 2014 to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. We received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion of this line. Construction commenced in the first quarter of 2016, and the project is expected to be placed in service in 2016.

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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, 2015, we were subject to the following renewable energy portfolio standards or objectives:

• South Dakota. South Dakota has 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 by2015.

• Montana. In 2005 Montana 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, we filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. However, 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. Mandatory portfolio standards have increased, and 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 Regulations

We are subject to numerous federal, state and local laws and regulations relating to the protection of the environment and the safety and health of personnel and the public. These laws and regulations affect a broad range of our utility activities, and generally regulate: (i) the protection of air and water quality; (ii) the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of, and emergency response in connection with hazardous and toxic materials and wastes, including asbestos; and (iii) the protection of plant and animal species and minimization of noise emissions. We have incurred, and expect to incur, capital, operating and maintenance costs for the operations of our plants to comply with these laws and regulations. While the requirements are evolving, it is virtually certain that environmental requirements placed on the operations will continue to be more restrictive.

In 2011, the EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates on December 21, 2012, which impose emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. In anticipation of this rule and our evaluation of costs to retrofit these plants, we suspended operations at the Osage plant on October 1, 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012. We permanently retired Osage, Ben French and Neil Simpson I on March 21, 2014.

On February 16, 2012, the EPA published in the Federal Register the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), which became effective on April 16, 2012. This rule imposes requirements for mercury, acid gases, metals and other pollutants. Affected units had a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain very limited circumstances. The current state air permit for Wygen III provides mercury emission limits and monitoring requirements with which we are in compliance. Neil Simpson II and Wygen III have been utilized for internal study and review of mercury emission control technology and have mercury monitors in place. Due to mercury absorbent issues encountered in 2015, the state of Wyoming approved a one year compliance deadline extension to April 16, 2016 for Neil Simpson II and Wygen III, for mercury only. The other components of the MATS rule remain in effect and these plants are in compliance with those requirements. The Wyodak plant is in compliance with all requirements of the MATS regulation.

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On June 3, 2010, the EPA promulgated the GHG Tailoring Rule, implementing regulations of GHG for permitting purposes. This rule will impact us in the event of a major modification at an existing facility or in the event we establish a new major source of GHG emissions, as defined by EPA regulations. Upon renewal of operating permits for existing permitted facilities, monitoring and reporting requirements will be implemented. This rule established the basis for EPA’s October 23, 2015 suite of GHG emission rules for existing, new, modified and reconstructed facilities. The portion of this rule-making that applies to existing power generation sources is known as the Clean Power Plan (CPP). The portion of this rule-making that applies to new generating units effectively prohibits new coal-fired power plants from being constructed until carbon capture and sequestration becomes technically and economically feasible. The basis of the CPP regulation is to decrease existing coal-fired generation, increase the utilization of existing gas-fired combined cycle generation, increase renewable energy and increase use of DSM. States are required to develop and submit compliance plans to the EPA, with the initial submittal due by September 2016. The rule allows for a two year extension to submit a final plan and the states we operate in have indicated they will be submitting the extension request. Also on October 23, 2015, EPA proposed a Federal Implementation Plan, which will be imposed on any state that fails to submit a plan or fails to include the required contents of the plan. That rule will contain the modeling standards for CPP compliance and will be an integral part of state plan development. On February 9, 2016, the U.S. Supreme Court entered an order staying the Clean Power Plan. The stay of the CPP will remain in place until the U.S. Supreme Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision on the substantive challenges to the CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant of a petition for certiorari. The effect of the order is to delay the CPP’s compliance deadlines until challenges to the CPP have been fully litigated and the U.S. Supreme Court has ruled. We do not expect a final judicial decision on challenges to the CPP earlier than mid-2017. While we cannot predict the terms of state plans, any limits on CO₂ emissions at our existing plants could have a material impact on our customer rates, financial position, results of operations and/or cash flows. In 2015 we met with South Dakota and Wyoming regulatory agencies to discuss the rule implementation and potential compliance pathways.

Wyoming passed GHG legislation in 2012 and 2013, enabling the state to implement the EPA’s GHG program. Wyoming adopted and submitted a GHG regulatory program to the EPA, which the EPA approved and published in the November 22, 2013 Federal Register. As of December 23, 2013, Wyoming has full jurisdiction over the GHG permitting program which includes the transfer of the Cheyenne Prairie EPA GHG air permit, to the state of Wyoming. This eliminates the increased time, expense and considerable risk of obtaining a permit from the EPA.

In 2015, we reported 2014 GHG emissions from our Power Generation facilities in order to comply with the EPA’s GHG Annual Inventory regulation, issued in 2009. We continue to report annual GHG emissions as required by the EPA. Climate change issues are the subject of a number of lawsuits, the outcome of which could impact the utility industry. We will continue to review GHG impacts as legislation or regulation develops and litigation is resolved.

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 and the closure of certain generating facilities. 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. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility customers and other purchasers of the power generated by our non-regulated power plants, including utility affiliates. Any unrecovered costs could have a material impact on our results of operations, financial position or cash flows. 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.

In August 2012, the EPA proposed revisions to the Electric Utility New Source Performance Standards for stationary combustion turbines. This rule is expected to be finalized in 2016 and, as proposed, will be applicable to Cheyenne Prairie and eventually all the combustion turbines in our fleet. Among other things, the rule seeks to eliminate startup exemptions and clearly define overhauls for impact on the EPA’s New Source Review regulations, with the intention of eventually bringing all units under the applicability of this rule. The primary impact is expected to be on our older existing units, which will eventually be required to meet tighter NO_x emission limitations.

By May 3, 2013, all of our diesel generator engines were required to comply with EPA’s Stationary Reciprocating Internal Combustion Engine Hazardous Air Pollutant regulations. Evaluations were completed, emission control equipment was installed and emission testing confirmed compliance with those requirements.

10

In 2011, the State of Wyoming issued a letter requiring Neil Simpson II to include startup and shutdown SO₂ and NO_x emissions when evaluating compliance with permitted emission limits. This represented a significant change from requirements in the original 1993 air permit. Minor engineered design changes were made to improve scrubber performance during startup. Those changes enabled the unit to meet the new requirements. The unit was previously fitted with state of the art low NO_x burners that support compliance with this new requirement. Also in 2014, Neil Simpson II and Wygen III have converted startup fuel from diesel to natural gas to support potential start-up requirements and future GHG state compliance plans.

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.

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 2015 or pending adoption.

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 from those discussed in our forward-looking statements, or otherwise.

Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore are not recoverable, which could adversely affect our results of operations, financial position or liquidity.

Our electricity 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. Our returns could be threatened by plant outages, machinery failures, increased purchased power costs, acts of nature, acts of terrorism or other unexpected events over which we have no control that could cause our costs to increase and operating margins to decline. 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 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 will 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.

11

Our financial performance depends on the successful operations 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 involves risks, including:

• Operational limitations imposed by environmental and other regulatory requirements;

• 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 the ability to operate our facilities;

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

• Inability to recruit and retain skilled technical labor;

• 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;

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

• 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

• Labor relations.

National and regional economic conditions may cause increased counter-party risk, late payments and uncollectible accounts, which could adversely affect our results of operations, financial position or 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, our results of operations, financial position and liquidity could be adversely impacted.

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

Our credit rating on our First Mortgage Bonds is A1 by Moody’s, A- by S&P and A by Fitch. Any reduction in our credit ratings by the rating agencies could adversely affect our ability to refinance our existing debt and to complete new financings on reasonable terms or at all. In addition, a downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations. A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under new transactions.

12

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;

• Contract restrictions upon the timing of scheduled outages;

• 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;

• Unexpected engineering, environmental or geological problems; and

• 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 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.

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. The related power 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 the 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 are subject to significant, unpredictable price fluctuations over relatively short periods of time.

13

Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events. These events could disrupt or impair our operations, create additional costs and cause 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 mechanical problems that could cause substantial adverse financial impacts. These events could result in injury or loss of human life, significant damage to property or natural resources (including public parks), environmental pollution, impairment of our operations, and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. 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 significant.

Our operating results can be adversely affected by variations from normal weather patterns.

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 financial condition and results of operations.

Our businesses are 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 storms. 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 failure to achieve or maintain compliance with existing or future governmental laws, regulations or requirements could adversely affect our results of operations, financial position or liquidity. Additionally, the potentially high cost of complying with such requirements or addressing environmental liabilities could also adversely affect our results of operations, financial position or liquidity.

Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally must obtain and comply with a variety of regulations, licenses, permits and other approvals in order to operate, which could require significant capital expenditures and operating costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of penalties, liens or fines; claims for property damage or personal injury; and/ or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, which could require additional unexpected expenditures or cause us to reevaluate the feasibility of continued operations at certain sites and have a detrimental effect on our business.

Future steps to bring our facilities into compliance, if necessary, could be expensive, and could adversely affect our results of operation and financial condition. We expect our environmental compliance expenditures to be substantial in the future due to the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate.

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 affected 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, distribution property losses and cyber security risks.

14

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 seek 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 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 greenhouse gas 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 will likely 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 caption “Environmental Regulations.”

On February 16, 2012, the EPA published in the Federal Register MATS, with an effective date of April 16, 2012. Affected units had a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain circumstances. We applied for and received a one year extension for mercury only, with the remaining aspects of the MATS rule remaining in effect. All our impacted plants (Neil Simpson II, Wygen III and the Wyodak Plant) are in compliance with the applicable rule provisions.

The GHG Tailoring Rule, implementing regulations of GHG for permitting purposes, became effective in June 2010. This rule will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Upon renewal of operating permits for existing facilities monitoring and reporting requirements will be implemented. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could impose more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units was published October 23, 2015. The rule effectively prohibits new coal fired units until carbon capture and sequestration becomes technically and economically feasible.

On October 23, 2015, the EPA finalized the Clean Power Plan to cut carbon emissions from existing electric generating units. The design of the Clean Power Plan is to decrease existing coal-fired generation, and increase the utilization of existing gas generation, increase renewable energy, and DSM. This rule could have a significant impact on our coal and natural gas generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. On February 9, 2016, the U.S. Supreme Court entered an order staying the Clean Power Plan. The stay of the CPP will remain in place until the U.S. Supreme Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision on the substantive challenges to the CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant of a petition for certiorari. The effect of the order is to delay the CPP’s compliance deadlines until challenges to the CPP have been fully litigated and the U.S. Supreme Court has ruled. We do not expect a final judicial decision on challenges to the CPP earlier than mid-2017. While we cannot predict the terms of state plans, any limits on CO₂ emissions at our existing plants could have a material impact on our customer rates, financial position, results of operations and/or cash flows. In 2015, we met with state air programs and public utility commissions on several occasions. We will continue to work closely with state regulatory staff as these plans develop.

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. The impact of GHG legislation or regulation on our company will depend upon many factors, including but not limited to, the timing of implementation, state clean power plan requirements, the GHG sources that are regulated, the overall GHG emissions cap level and the availability of technologies to control or reduce GHG emissions. If an allowance or credit trading structure is implemented, the impact will depend on the allocation of emission allowances to specific sources, the costs of those allowances or credits and the effect of carbon regulation on natural gas and coal prices.

15

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, EPA, OSHA and SEC may impose significant and sometimes punitive civil and criminal penalties to enforce compliance requirements relative to our business. In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the NERC, with similar penalty authority for violations. If a serious regulatory violation did occur, and penalties were imposed by FERC or another federal agency, this action 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 or our independent registered public accounting firm 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.

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 and could adversely affect our results of operations, financial position and liquidity.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems and physical assets, could be direct targets of, or indirectly affected by, such activities. Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power and by delaying their 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.

16

A disruption of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because generation, transmission systems and natural gas pipelines are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system (such as severe weather or a generator or transmission facility outage, pipeline rupture, or a sudden significant increase or decrease in wind generation), within our system or within a neighboring system. Any such disruption could have a material impact on our financial results.

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

We operate in a highly regulated industry that requires the continuous use and operation of 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 and gas 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 to 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. FERC, through the North American Electric Reliability Corporation, requires certain safeguards be implemented to deter cyber attacks. 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 be recovered 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 plans 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.

We have a defined benefit pension plan that covers a substantial portion of our 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 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. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

In March 2010, the President of the United States signed the Patient Protection and Affordable Care Act of 2010 as amended by the Health Care and Education Reconciliation Act of 2010 (collectively the “2010 Acts”). The 2010 Acts will have a substantial impact on health care providers, insurers, employers and individuals. The 2010 Acts will impact employers and businesses differently depending on the size of the organization and the specific impacts on a company’s employees. Certain provisions of the 2010 Acts are effective while other provisions of the 2010 Acts will be effective in future years. The 2010 Acts could require, among other things, changes to our current employee benefit plans and in our administrative and accounting processes as well as changes to the costs of our plans. The ultimate extent and cost of these changes cannot be determined at this time and are being evaluated and updated as related regulations and interpretations of the 2010 Acts become available.

17

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.

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

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.

For the years ended December 31,	2015			Variance			2014			Variance			2013
	(in thousands)
Revenue	$	277,864		$	9,376		$	268,488		$	14,461		$	254,027
Fuel and purchased power	83,339			(10,637		)	93,976			4,539			89,437
Gross margin	194,525			20,013			174,512			9,922			164,590
Operating expenses	106,611			1,213			105,398			3,152			102,246
Operating income	87,914			18,800			69,114			6,770			62,344
Interest expense, net	(21,174		)	(1,472		)	(19,702		)	(411		)	(19,291		)
Other income	1,034			372			662			123			539
Income tax expense	(22,600		)	(6,088		)	(16,512		)	(3,093		)	(13,419		)
Net income	$	45,174		$	11,612		$	33,562		$	3,389		$	30,173

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The following tables provide certain electric utility operating statistics for the years ended December 31 (dollars in thousands):

Revenue
Customer Base	2015		Percentage Change		2014		Percentage Change		2013
Residential	$	72,659	4	%	$	69,712	8	%	$	64,566
Commercial	100,511		9	%	91,882		14	%	80,289
Industrial	33,336		17	%	28,451		3	%	27,705
Municipal	3,626		6	%	3,409		—	%	3,421
Total retail sales	210,132		9	%	193,454		10	%	175,981
Contract wholesale	17,537		(17	)%	21,206		(3	)%	21,956
Wholesale off-system	23,241		(17	)%	28,002		(5	)%	29,580
Total electric sales	250,910		3	%	242,662		7	%	227,517
Other revenue	26,954		4	%	25,826		(3	)%	26,510
Total revenue	$	277,864	3	%	$	268,488	6	%	$	254,027

MWh Sold
Customer Base	2015	Percentage Change		2014	Percentage Change		2013
Residential	521,828	(4	)%	542,008	(2	)%	555,204
Commercial	792,466	1	%	782,238	7	%	730,701
Industrial	429,140	7	%	399,648	(1	)%	404,009
Municipal	31,924	—	%	32,076	(7	)%	34,344
Total retail sales	1,775,358	1	%	1,755,970	2	%	1,724,258
Contract wholesale	260,893	(23	)%	340,871	(5	)%	357,193
Wholesale off-system	837,120	4	%	808,257	(19	)%	1,002,847
Total electric sales	2,873,371	(1	)%	2,905,098	(6	)%	3,084,298
Losses and company use	167,332	(6	)%	177,577	12	%	158,845
Total energy	3,040,703	(1	)%	3,082,675	(5	)%	3,243,143

We own approximately 445 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023. On March 21, 2014, we retired the Ben French, Neil Simpson I, and Osage coal-fired power plants. These three plants totaling 81 MW were closed because of federal environmental regulations. On October 1, 2014, we transferred the remaining net book value of these retired plants to a regulatory asset in accordance with an order granted by the SDPUC. These plants are primarily replaced by our share of Cheyenne Prairie.

Regulated Power Plant Fleet Availability	2015	2014		2013
Coal-fired plants	91.1%	91.8%		96.3%
Other plants	96.0%	91.5%	(a)	96.8%
Total availability	93.9%	91.6%		96.5%

_________________________

(a) 2014 decrease from 2013 was due to the scheduling of outages in 2014 compared to 2013.

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Resources	2015	Percentage Change		2014	Percentage Change		2013
MWh generated:
Coal	1,537,744	(3	)%	1,591,061	(10	)%	1,768,483
Gas	80,944	80	%	44,984	35	%	33,374
	1,618,688	(1	)%	1,636,045	(9	)%	1,801,857
MWh purchased	1,422,015	(2	)%	1,446,630	—	%	1,441,286
Total resources	3,040,703	(1	)%	3,082,675	(5	)%	3,243,143

Heating and Cooling Degree Days	2015		2014		2013
Actual
Heating degree days	6,521		7,373		7,582
Cooling degree days	577		481		724
Variance from 30-year average
Heating degree days	(8	)%	4	%	9	%
Cooling degree days	(14	)%	(28	)%	8	%

2015 Compared to 2014

Gross marginincreased primarily due to a return on capital investments in Cheyenne Prairie which increased gross margins by $11.9 million and increased energy cost recoveries by $2.7 million. Retail margins increased $4.7 million primarily due to commercial and industrial load increases from higher MWh sold. These increases are partially offset by an approximately $1.7 million decrease in residential margins driven primarily by a 12% decrease in heating degree days compared to the same period in the prior year.

Operations and maintenanceincreased reflecting an increase in depreciation expense primarily due to a higher asset base and amortization of regulatory plant decommissioning costs.

Interest expense, netincreased primarily due to interest costs from the $85 million of permanent financing put in place during the fourth quarter of 2014 for Cheyenne Prairie.

Other income, net was comparable to the prior year.

Income tax expense: The 2015 effective tax rate is comparable to the prior year.

2014 Compared to 2013

Gross marginincreased primarily due to a return on additional investments which increased base electric margins by $6.0 million and $1.8 million from the Cheyenne Prairie construction financing rider. An increase in commercial and industrial MWh sold increased gross margins $2.3 million. These increases were partially offset by a $1.1 million decrease in wholesale margins driven by plant outages affecting unit-contingent wholesale contracts.

Operations and maintenanceincreased primarily due to an increase in depreciation, driven by an increased asset base, higher employee costs, property taxes, and a true-up made in the prior year for generation dispatch services billed to a third party. These were partially offset by a decrease in vegetation management expenses.

Interest expense, netincreased primarily due to the increase in long-term debt from permanent financing put in place for Cheyenne Prairie by the sale of $85 million of first mortgage bonds on October 1, 2014.

Other income, net was comparable to the prior year.

20

Income tax expense: The effective rate is higher in 2014 due to an unfavorable true-up adjustment and the recording of the 2012 research and development credit in 2013.

Financing Plans and Activity

On October 1, 2014, in a private placement transaction to provide permanent financing for Cheyenne Prairie, we issued

$85 million of 4.43% coupon first mortgage bonds due October 20, 2044. Proceeds from the bond sale also funded the September 30, 2014 early redemption of our 5.35%$12 million pollution control revenue bonds, originally due October 1, 2024. In addition, we paid the accrued interest on these bonds of $0.3 million.

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, 2015:

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

Significant Events

Regulatory Matters

On July 23, 2015, we received approval from the WPSC for a CPCN originally filed on July 22, 2014 to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. We received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion of this line. Construction commenced in the first quarter of 2016, and the project is expected to be placed in service in 2016.

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for us of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides us a return on our investment in Cheyenne Prairie and associated infrastructure, and provides recovery of our share of operating expenses for this natural gas fired facility. We implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

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 our Notes to Financial Statements in this Annual Report on Form 10-K.

21

Pension and Other Postretirement Benefits

The Company, as described in Note 8 to the Financial Statements in this Annual Report on Form 10-K, has a defined benefit pension plan and post-retirement healthcare plan. As of December 31, 2012, a Master Trust was established for the investment of assets of the defined benefit pension plans. Each participating retirement plan has an undivided interest in the Master Trust.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; rate of future increases in compensation levels; and healthcare cost projections. 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 discount rate used to determine annual defined benefit pension costs accruals will be 4.25% in 2016 and the discount rate used in 2015 was 4.25%. In selecting the discount rate, we consider cash flow durations for each plan’s liabilities on high credit fixed income yield curves for comparable durations. We do not pre-fund our non-qualified plans or postretirement healthcare plans.

Beginning in 2016, the Company will change 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 uses 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 interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The company will account for this change as a change in estimate prospectively beginning in the first quarter of 2016. The discount rates used to measure the 2016 service costs are 4.81%, 4.88% and 4.18% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The discount rates used to measure the 2016 interest costs are 3.90%, 3.82% and 3.17% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The previous method would have used a discount rate for both service and interest costs of 4.63% for pension, 4.50% for supplemental non-qualified defined benefit and 4.03% for other postretirement benefit costs. The decrease in the 2016 service and interest costs is approximately $0.5 million, $0.03 million and $0.1 million for the pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively, as compared to the previous method.

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.

We use the asset and liability method of accounting for income taxes. Under this 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 net 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. We have chosen to early adopt on a prospective basis ASU 2015-17. As of December 31, 2015, we classify all deferred tax assets and liabilities as non-current amounts. The prior period is presented under the previous guidance for classifying deferred tax assets and deferred tax liabilities as current and non-current.

22

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 consolidated financial statements. With respect to changes in tax law, the Protecting Americans from Tax Hikes Act of 2015, which was enacted December 18, 2015, did not have a material impact on the amounts provided for income taxes including our ability to realize deferred tax assets. The Tax Increase Prevention Act (TIPA), which was enacted December 19, 2014, did not have a material impact on the amounts provided for income taxes including our ability to realize deferred tax assets. Certain provisions of the TIPA involving primarily the extension of 50 percent bonus depreciation resulted in the generation of a NOL for federal income tax purposes in 2014.

In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations had the effect of a change in law and as a result the impact was taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after January 1, 2014, with early adoption permitted. We implemented all of the provisions of the final regulations with the filing of the 2013 federal income tax return in September 2014. The adoption of the final regulations did not have a material impact on our financial statements.

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

Contingencies

When it is probable that an environmental or other legal liability has been incurred, a loss is recognized when the amount of the loss can be reasonably estimated. Estimates of the probability and the amount of loss are made based on currently available facts. Accounting for contingencies requires significant judgment regarding the estimated probabilities and ranges of exposure to potential liability. Our assessment of our exposure to contingencies could change to the extent there are additional future developments, or as more information becomes available. If actual obligations incurred are different from our estimates, the recognition of the actual amounts could have a material impact on our financial position, results of operations and cash flows. We describe any contingencies in Note 11 of the Financial Statements in this Annual Report on Form 10-K.

23

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

	Page
Management’s Report on Internal Controls Over Financial Reporting	25
Report of Independent Registered Public Accounting Firm	26
Statements of Income for the three years ended December 31, 2015	27
Statements of Comprehensive Income (Loss) for the three years ended December 31, 2015	28
Balance Sheets as of December 31, 2015 and 2014	29
Statements of Cash Flows for the three years ended December 31, 2015	31
Statements of Common Stockholder’s Equity for the three years ended December 31, 2015	32
Notes to Financial Statements	33

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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, 2015, 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, 2015.

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

25

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Black Hills Power, Inc.

Rapid City, South Dakota

We have audited the accompanying balance sheets of Black Hills Power, Inc. (the “Company”) as of December 31, 2015 and 2014, and the related statements of income, comprehensive income (loss), common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 26, 2016

26

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME

Years ended December 31,	2015			2014			2013
	(in thousands)
Revenue	$	277,864		$	268,488		$	254,027
Operating expenses:
Fuel and purchased power	83,339			93,976			89,437
Operations and maintenance	68,088			70,356			68,857
Depreciation and amortization	32,552			29,100			28,125
Taxes - property	5,971			5,942			5,264
Total operating expenses	189,950			199,374			191,683
Operating income	87,914			69,114			62,344
Other income (expense):
Interest expense	(22,337		)	(20,569		)	(19,725		)
AFUDC - borrowed	506			248			186
Interest income	657			619			248
AFUDC - equity	918			519			368
Other expense	(117		)	(105		)	(196		)
Other income	233			248			367
Total other income (expense)	(20,140		)	(19,040		)	(18,752		)
Income before income taxes	67,774			50,074			43,592
Income tax expense	(22,600		)	(16,512		)	(13,419		)
Net income	$	45,174		$	33,562		$	30,173

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

27

BLACK HILLS POWER, INC.

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Years ended December 31,	2015		2014			2013
	(in thousands)
Net income	$	45,174	$	33,562		$	30,173
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $(36), $189 and $(73), respectively)	68		(351		)	139
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(33), $(16) and $(23), respectively)	61		29			43
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $319, $(364) and $(23), respectively)	383		(300		)	41
Other comprehensive income (loss), net of tax	512		(622		)	223
Comprehensive income (loss), net of tax	$	45,686	$	32,940		$	30,396

See Note 7 for additional disclosure related to comprehensive income.

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

28

BLACK HILLS POWER, INC.

BALANCE SHEETS

As of December 31,	2015			2014
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	7,559		$	6,620
Receivables - customers, net	27,856			34,684
Receivables - affiliates	5,747			5,350
Other receivables, net	236			259
Money pool notes receivable	76,813			68,626
Materials, supplies and fuel	24,282			20,965
Deferred income tax assets, net, current	—			13,661
Regulatory assets, current	14,096			10,257
Other current assets	43,118			4,954
Total current assets	199,707			165,376
Investments	4,725			4,584
Property, plant and equipment	1,166,126			1,115,061
Less accumulated depreciation and amortization	(326,074		)	(309,767		)
Total property, plant and equipment, net	840,052			805,294
Other assets:
Regulatory assets, non-current	71,717			68,427
Other, non-current assets	3,292			11,708
Total other assets	75,009			80,135
TOTAL ASSETS	$	1,119,493		$	1,055,389

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

29

BLACK HILLS POWER, INC.

BALANCE SHEETS

(Continued)

As of December 31,	2015			2014
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	21,297		$	30,543
Accounts payable - affiliates	30,032			19,242
Accrued liabilities	69,454			16,415
Regulatory liabilities, current	—			3,073
Total current liabilities	120,783			69,273
Long-term debt	342,756			342,752
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	188,961			193,042
Regulatory liabilities, non-current	51,583			51,916
Benefit plan liabilities	20,033			20,981
Other, non-current liabilities	3,398			2,631
Total deferred credits and other liabilities	263,975			268,570
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	330,295			313,622
Accumulated other comprehensive loss	(1,307		)	(1,819		)
Total stockholder’s equity	391,979			374,794
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,119,493		$	1,055,389

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

30

BLACK HILLS POWER, INC.

STATEMENTS OF CASH FLOWS

Years ended December 31,	2015			2014			2013
	(in thousands)
Operating activities:
Net income	$	45,174		$	33,562		$	30,173
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	32,552			29,100			28,125
Deferred income taxes	7,690			16,518			13,582
AFUDC - equity	(918		)	(519		)	(368		)
Employee benefits	2,403			1,295			3,094
Other adjustments	232			(2,330		)	1,400
Change in operating assets and liabilities -
Accounts receivable and other current assets	(2,236		)	(10,412		)	(5,265		)
Accounts payable and other current liabilities	21,652			10,829			1,180
Contributions to defined benefit pension plan	—			(1,696		)	(2,299		)
Regulatory assets	(3,839		)	(5,366		)	107
Regulatory liabilities	(2,479		)	2,479			(17		)
Other operating activities	(5,680		)	(6,624		)	(3,149		)
Net cash provided by operating activities	94,551			66,836			66,563
Investing activities:
Property, plant and equipment additions	(56,795		)	(82,826		)	(74,390		)
Notes receivable from affiliate companies, net	(36,687		)	(51,334		)	6,353
Other investing activities	(128		)	(154		)	(72		)
Net cash provided by (used in) investing activities	(93,610		)	(134,314		)	(68,109		)
Financing activities:
Long-term debt - repayments	—			(12,200		)	—
Long-term debt - issuance	—			85,000			—
Other financing activities	(2		)	(961		)	—
Net cash provided by (used in) financing activities	(2		)	71,839			—
Net change in cash and cash equivalents	939			4,361			(1,546		)
Cash and cash equivalents:
Beginning of year	6,620			2,259			3,805
End of year	$	7,559		$	6,620		$	2,259

See Note 10 for Supplemental Cash Flows information.

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

31

BLACK HILLS POWER, INC.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

	2015			2014			2013
	(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	$	313,622		$	280,060		$	257,887
Net income	45,174			33,562			30,173
Non-cash dividend to Parent company	(28,501		)	—			(8,000		)
Balance end of year	$	330,295		$	313,622		$	280,060
Accumulated other comprehensive loss:
Balance beginning of year	$	(1,819	)	$	(1,197	)	$	(1,420	)
Other comprehensive (loss) income, net of tax	512			(622		)	223
Balance end of year	$	(1,307	)	$	(1,819	)	$	(1,197	)
Total stockholder’s equity	$	391,979		$	374,794		$	341,854

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

32

NOTES TO FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

(1)    BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc. (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. Actual results could differ 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.

Our regulated utility operations follow accounting standards for regulated operations and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating our electric operations. 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 criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations in an amount that could be material.

Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Balance Sheets.

33

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

	Maximum Recovery Period (in years)	2015		2014
Regulatory assets:
Unamortized loss on reacquired debt (a)	9	$	2,096	$	2,377
AFUDC(b)	45	8,571		8,365
Employee benefit plans(c)	12	20,866		24,418
Deferred energy costs(a)	1	19,875		14,696
Flow through accounting(a)	35	12,104		11,171
Decommissioning costs (b)	9	13,686		11,786
Other regulatory assets(a) (d)	2	8,615		5,871
Total regulatory assets		$	85,813	$	78,684
Regulatory liabilities:
Cost of removal for utility plant(a)	53	$	38,131	$	35,510
Employee benefit plans(c)	12	12,616		14,538
Other regulatory liabilities(c)	13	836		4,941
Total regulatory liabilities		$	51,583	$	54,989

____________________

(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, respectively.

(d) Includes approximately $5.0 million of vegetation management expenses.

Regulatory assets represent items we expect to recover from customers through rates.

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

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 plans 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 Costs - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our utility customers that are 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.

34

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. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. A regulatory asset established to reflect the 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 consistent with the flow-through method with respect to costs considered repairs for tax purposes and 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.

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 aspect of a rate regulated environment.

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. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collection success given the existing collections environment.

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

	2015			2014
Accounts receivable trade	$	15,268		$	24,946
Unbilled revenues	12,795			9,999
Allowance for doubtful accounts	(207		)	(261		)
Net accounts receivable trade	$	27,856		$	34,684

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Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured. 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, we 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 Receivables- customers, net on the accompanying Balance Sheets.

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost basis.

Other Current Assets

The following amounts by major classification are included in Other current assets on the accompanying Balance Sheets as of (in thousands):

	December 31, 2015		December 31, 2014
Accrued receivables related to litigation expenses and settlements	$	39,050	$	—
Other (none of which is individually significant)	4,068		4,954
Total other current assets	$	43,118	$	4,954

Accrued Liabilities

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

	December 31, 2015		December 31, 2014
Accrued employee compensation, benefits and withholdings	$	5,054	$	4,689
Accrued property taxes	4,962		4,721
Accrued payments related to litigation expenses and settlements	38,750		—
Accrued income taxes	13,031		—
Customer deposits and prepayments	2,216		1,934
Accrued interest	4,600		4,662
Other (none of which is individually significant)	841		409
Total accrued liabilities	$	69,454	$	16,415

Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the term of the related debt.

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Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is AFUDC, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations 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.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.3% in 2015, 2.3% in 2014 and 2.1% in 2013.

Derivatives and Hedging Activities

From time to time we utilize risk management contracts including forward purchases and sales to hedge the price of fuel for our combustion turbines and fixed-for-float swaps to fix the interest on any variable rate debt. Contracts that qualify as derivatives under accounting standards for derivatives, and that are not exempted such as normal purchase/normal sale, are required to be recorded in the balance sheet as either an asset or liability, measured at its fair value. Accounting standards for derivatives require that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Accounting standards for derivatives allow hedge accounting for qualifying fair value and cash flow hedges. Gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk should be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should be reported as a component of other comprehensive income and be reclassified into earnings or as a regulatory asset or regulatory liability, net of tax, in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales 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 exceptions, 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

Accounting standards for fair value measurements provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and also requires disclosures and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:

Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities.

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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.

Impairment of Long-Lived Assets

We periodically evaluate whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of our long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, we would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, we would recognize an impairment loss.

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.

We use the asset and liability method in accounting for income taxes. Under the 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. At December 31, 2015, we have chosen to early adopt on a prospective basis ASU 2015-17 as discussed below under Recently Issued and Adopted Accounting Standards. As of December 31, 2015, we classify all deferred tax assets and liabilities as non-current. The prior period is presented under the previous guidance for classifying deferred tax assets and deferred tax liabilities as current and non-current.

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 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 and Adopted Accounting Principles

Balance Sheet Classification of Deferred Taxes, ASU 2015-17

In November 2015, the FASB issued ASU 2015-17 providing guidance on financial statement presentation for deferred tax assets and deferred tax liabilities. All deferred taxes are to be presented as non-current. FASB issued this guidance as part of its initiative to reduce complexity in accounting standards. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those years (i.e., in the first quarter of 2017 for calendar year-end companies). The guidance may be applied either prospectively, for all deferred tax assets and liabilities, or retrospectively by reclassifying the comparative balance sheets. Early adoption is permitted. We have chosen early adoption as of December 31, 2015, on a prospective basis. At December 31, 2015, the balance sheet reflects a net non-current deferred tax liability of $189 million. The balance sheet presentation as of December 31, 2014 was not adjusted retrospectively and remains as previously reported with a net current deferred tax asset of $14 million and a non-current deferred tax liability of $193 million.

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Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted. We have chosen not to early adopt ASU 2015-03.

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, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The guidance would be effective for annual and interim reporting periods beginning after December 15, 2018 and early adoption is permitted. We are currently assessing the impact that adoption of ASU 2014-09 will have on our financial position, results of operations or cash flows.

(2)    PROPERTY, PLANT AND EQUIPMENT

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

				2015				2014
				Weighted				Weighted
				Average				Average	Lives (in years)
	2015			Useful Life (in years)	2014			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	569,182		46	$	567,936		48	40	65
Transmission	117,708			48	115,949			46	40	60
Distribution	353,241			46	336,652			39	20	60
Plant acquisition adjustment (a)	4,870			32	4,870			32	32	32
General	88,939			22	79,738			22	5	40
Total plant-in-service	1,133,940				1,105,145
Construction work in progress	32,186				9,916
Total electric plant	1,166,126				1,115,061
Less accumulated depreciation and amortization	(326,074		)		(309,767		)
Electric plant net of accumulated depreciation and amortization	$	840,052			$	805,294

__________________

(a) The plant acquisition adjustment is included in rate base and is being recovered with 15 years remaining.

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(3)    JOINTLY OWNED FACILITIES

We use the proportionate consolidation method to account for our percentage interest in the assets, liabilities and expenses of the following 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 - 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. Cheyenne Light owns the remaining 40 MW. This facility was placed into commercial operations on October 1, 2014. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

The investments in our jointly owned plants and accumulated depreciation are included in the corresponding captions in the accompanying Balance Sheets. Our share of direct expenses of the Plants is included in the corresponding categories of operating expenses in the accompanying Statements of Income. Each of the respective owners is responsible for providing its own financing.

As of December 31, 2015, our interests in jointly-owned generating facilities and transmission systems included on our Balance Sheets were as follows (in thousands):

Interest in jointly-owned facilities	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	111,532	$	1,039	$	56,812
Transmission Tie	$	19,648	$	—	$	5,390
Wygen III	$	137,860	$	446	$	16,217
Cheyenne Prairie	$	91,081	$	—	$	3,301

(4)    LONG-TERM DEBT

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

	Maturity Date	Interest Rate		2015			2014
First Mortgage Bonds due 2032	August 15, 2032	7.23	%	$	75,000		$	75,000
First Mortgage Bonds due 2039	November 1, 2039	6.125	%	180,000			180,000
First Mortgage Bonds due 2044	October 20, 2044	4.43	%	85,000			85,000
Unamortized discount, First Mortgage Bonds due 2039				(99		)	(103		)
Series 94A Debt (a)	June 1, 2024	0.75	%	2,855			2,855
Long-term debt				$	342,756		$	342,752

___________________

(a) Variable interest rate at December 31, 2015.

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On October 1, 2014 we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044. Proceeds from our bond sale funded the early redemption of our 5.35%$12 million pollution control revenue bonds, originally due October 1, 2024.

Net deferred financing costs of approximately $3.1 million and $3.3 million were recorded on the accompanying Balance Sheets in Other, non-current assets at December 31, 2015 and 2014, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $0.1 million, $0.1 million and $0.1 million for the years ended December 31, 2015, 2014 and 2013, respectively, 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, 2015.

Long-term Debt Maturities

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

2016	$	—
2017	$	—
2018	$	—
2019	$	—
2020	$	—
Thereafter	$	342,855

(5)    FAIR VALUE OF FINANCIAL INSTRUMENTS

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

	2015				2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents (a)	$	7,559	$	7,559	$	6,620	$	6,620
Long-term debt, including current maturities (b)	$	342,756	$	404,864	$	342,752	$	430,497

_______________

(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 using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods. For additional information on our long-term debt see Note 4.

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 and overnight repurchase agreement accounts. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.

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(6)    INCOME TAXES

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

	2015		2014			2013
Current	$	14,910	$	(6	)	$	(163	)
Deferred	7,690		16,518			13,582
Total income tax expense	$	22,600	$	16,512		$	13,419

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

	2015			2014
Deferred tax assets:
Employee benefits	$	4,683		$	4,995
Net operating loss	15			14,794
Regulatory liabilities	9,908			10,824
Other	16,171			2,864
Total deferred tax assets	30,777			33,477
Deferred tax liabilities:
Accelerated depreciation and other plant related differences	(187,666		)	(184,478		)
AFUDC	(8,571		)	(8,365		)
Regulatory assets	(4,236		)	(3,910		)
Employee benefits	(3,003		)	(3,723		)
Deferred costs	(14,765		)	(11,324		)
Other	(1,497		)	(1,058		)
Total deferred tax liabilities	(219,738		)	(212,858		)
Net deferred tax assets (liabilities)	$	(188,961	)	$	(179,381	)

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

	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
Amortization of excess deferred and investment tax credits	(0.1	)	(0.3	)	(0.3	)
Equity AFUDC	(0.6	)	(0.1	)	—
Flow through adjustments (a)	(0.9	)	(1.9	)	(2.5	)
Tax credits	—		(0.2	)	(0.8	)
Other	—		0.5		(0.6	)
	33.4	%	33.0	%	30.8	%

_________________________

(a) The flow-through adjustments relate primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. 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 our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit consistent with the flow through method.

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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):

	2015			2014
Unrecognized tax benefits at January 1	$	1,623		$	2,443
Additions for prior year tax positions	888			434
Reductions for prior year tax positions	(247		)	(1,254		)
Additions for current year tax positions	—			—
Unrecognized tax benefits at December 31	$	2,264		$	1,623

The reductions for prior year tax positions relate to the reversal through otherwise allowed tax depreciation. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.7 million.

It is our continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 2015 and 2014, the interest expense recognized was not material to our financial results.

In January 2016, the Company reached an agreement in principle with IRS Appeals with respect to research and development tax credits and deductions for tax years 2007 through 2009, and expect a reduction of approximately $0.4 million with respect to our liability for unrecognized tax benefits on or before December 31, 2016.

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

At December 31, 2015, we are no longer in a federal NOL carry forward position.

(7)    COMPREHENSIVE INCOME

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

	Derivatives Designated as Cash Flow Hedges	Amounts Reclassified from AOCI
		2015			2014
Gains and Losses on cash flow hedges
Interest rate swaps gain (loss)	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	319			(364		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	383		$	(300	)
Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	94		$	45
Income tax	Income tax benefit (expense)	(33		)	(16		)
Total reclassification adjustments related to defined benefit plans, net of tax		$	61		$	29

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, 2014	$	(1,018	)	$	(801	)	$	(1,819	)
Other comprehensive income (loss)	383			129			512
As of December 31, 2015	$	(635	)	$	(672	)	$	(1,307	)
	Interest Rate Swaps			Employee Benefit Plans			Total
As of December 31, 2013	$	(719	)	$	(478	)	$	(1,197	)
Other comprehensive income (loss)	(299		)	(323		)	(622		)
As of December 31, 2014	$	(1,018	)	$	(801	)	$	(1,819	)

(8)    EMPLOYEE BENEFIT PLANS

Funded Status of Benefit Plans

The funded status of the postretirement benefit plan is required to be recognized in the statement of financial position. The funded status for the pension plan is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. The measurement date of the plans is December 31, our year-end balance sheet date. As of December 31, 2015, the unfunded status of our Defined Benefit Pension Plan was $11 million, the unfunded status of our Supplemental Non-qualified Defined Benefit Plans was $3.4 million and the unfunded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $6.2 million.

We apply accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to Accumulated other comprehensive income (loss) was alternatively recorded as a regulatory asset or regulatory liability, net of tax.

Defined Benefit 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.

Pension Plan assets are held in a Master Trust that was established for the investment of assets of the Plan and other Employer-sponsored retirement plans. Each participating retirement plan has an undivided interest in the Master Trust.

The BHC Board of Directors have approved the Plans’ 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 Plans’ 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 Plans’ benefit payment obligations. The Pension Plans’ assets consist primarily of equity, fixed income and hedged investments. The expected long-term rate of return for investments was 6.75% and 6.75% for the 2015 and 2014 plan years, respectively. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements.

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Pension Plan Assets

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

	2015		2014
Equity securities	26	%	27	%
Real estate	5		5
Fixed income funds	59		58
Cash and cash equivalents	1		2
Hedge funds	9		8
Total	100	%	100	%

Supplemental Non-qualified Defined Benefit Retirement Plans

We have various supplemental retirement plans (“Supplemental Plans”) for key executives. The Supplemental Plans are non-qualified defined benefit plans. The Supplemental Plans are subject to various vesting schedules.

Supplemental Plan Assets

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

Non-pension Defined Benefit Postretirement Healthcare Plan

Employees who are participants in our Non-Pension 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. 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 and Estimated Cash Flows

Cash contributions for pension plans are made directly to the Pension Plan Trust accounts. 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):

	2015		2014
Defined Benefit Plans
Defined Benefit Pension Plan	$	—	$	1,696
Non-pension Defined Benefit Postretirement Healthcare Plan	$	267	$	399
Supplemental Non-qualified Defined Benefit Plan	$	211	$	217
Defined Contribution Plans
Company Retirement Contribution	$	811	$	638
Matching Contributions	$	1,423	$	1,377

Although we are not required we expect to contribute approximately $1.6 million to our Defined Benefit Pension Plan in 2016.

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Fair Value Measurements

As required by accounting standards for 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. Our 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 as of December 31 (in thousands):

Defined Benefit Pension Plan	2015
	Level 1		Level 2		Level 3		Total Fair Value
Common Collective Trust - Cash and Cash Equivalents	$	—	$	498	$	—	$	498
Common Collective Trust - Equity	—		14,198		—		14,198
Common Collective Trust - Fixed Income	—		32,615		—		32,615
Common Collective Trust - Real Estate	—		418		2,113		2,531
Hedge Funds	—		—		4,881		4,881
Total investments measured at fair value	$	—	$	47,729	$	6,994	$	54,723

Defined Benefit Pension Plan	2014
	Level 1		Level 2		Level 3		Total Fair Value
Common Collective Trust - Cash and Cash Equivalents	$	—	$	899	$	—	$	899
Common Collective Trust - Equity	—		16,107		—		16,107
Common Collective Trust - Fixed Income	—		34,474		—		34,474
Common Collective Trust - Real Estate	—		761		1,918		2,679
Hedge Funds	—		—		4,939		4,939
Total investments measured at fair value	$	—	$	52,241	$	6,857	$	59,098

Cash and Cash Equivalents: This category is comprised of theAXA Equitable General Fixed Income Fundand Common Collective Trusts - cash and cash equivalents. The AXA Equitable General Fixed Income Fund is a fund of diversified portfolios, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately place 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 at which loans with similar characteristics have. 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.

Common Collective Trust: 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. Certain of the funds’ assets contain participant withdrawal policy and, therefore, are categorized as Level 3. The funds without participant withdrawal limitations are categorized as Level 2.

46

Hedge Funds: Hedge 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. The Plan’s investment in the hedge fund is categorized as Level 3.

The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended December 31 (in thousands):

	2015
Balance, beginning of period	$	6,857
Purchase	93
Unrealized gain (loss)	63
Settlements	(19		)
Balance, end of period	$	6,994

The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):

	Fair Value at		Valuation	Level 3	Range (Weighted)
	December 31, 2015		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate (a)	$	2,113	Market Approach	Redemption Restriction	N/A
Hedge Funds (b)	$	4,881	Market Approach	Redemption Restriction	N/A

_____________

(a) The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. 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 the 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 fund does contain a participant withdrawal policy.

(b) The fair value of the Hedge Funds is determined based on pricing provided or reviewed by third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed annually as they are issued.

47

Plan Reconciliations

The following tables provide a reconciliation of the Employee Benefit Plan’s obligations and fair value of assets, components of the net periodic expense and elements of regulatory assets and liabilities and AOCI (in thousands):

Benefit Obligations

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2015			2014			2015			2014			2015			2014
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	71,178		$	60,223		$	3,599		$	3,131		$	6,038		$	5,850
Service cost	797			704			—			—			233			222
Interest cost	2,956			2,991			142			146			214			241
Actuarial loss (gain)	(5,650		)	11,879			(104		)	540			27			115
Benefits paid	(3,284		)	(4,452		)	(211		)	(218		)	(387		)	(488		)
Asset transfer (to) from affiliate	(38		)	(167		)	—			—			(7		)	24
Medicare Part D adjustment	—			—			—			—			(30		)	(15		)
Plan participants’ contributions	—			—			—			—			120			89
Projected benefit obligation at end of year	$	65,959		$	71,178		$	3,426		$	3,599		$	6,208		$	6,038

A reconciliation of the fair value of Plan assets (as of the December 31 measurement date) is as follows (in thousands):

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans					Non-pension Defined Benefit Postretirement Healthcare Plan
	2015			2014			2015			2014		2015			2014
Beginning market value of plan assets	$	59,098		$	56,405		$	—		$	—	$	—		$	—
Investment income	(1,057		)	5,462			—			—		—			—
Benefits paid	(3,284		)	(4,452		)	(211		)	—		(387		)	—
Participant contributions	—			—			—			—		120			—
Employer contributions	—			1,696			211			—		267			—
Asset transfer to affiliate	(34		)	(13		)	—			—		—			—
Ending market value of plan assets	$	54,723		$	59,098		$	—		$	—	$	—		$	—

Amounts recognized in the Balance Sheets at December 31 consist of (in thousands):

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plan
	2015			2014			2015			2014			2015			2014
Regulatory asset (liability)	$	19,816		$	22,717		$	—		$	—		$	(1,946	)	$	2,306
Current liability	$	—		$	—		$	(216	)	$	(217	)	$	(619	)	$	(519	)
Non-current liability	$	(11,236	)	$	(12,080	)	$	(3,210	)	$	(3,382	)	$	(5,587	)	$	(5,519	)

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Accumulated Benefit Obligation (in thousands)

	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2015		2014		2015		2014		2015		2014
Accumulated benefit obligation	$	62,240	$	65,699	$	3,426	$	3,599	$	6,208	$	6,038

Components of Net Periodic Expense (in thousands)

	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2015			2014			2013			2015		2014		2013		2015			2014			2013
Service cost	$	797		$	704		$	852		$	—	$	—	$	—	$	233		$	222		$	216
Interest cost	2,956			2,991			2,969			142		146		133		214			241			239
Expected return on assets	(3,935		)	(3,702		)	(3,764		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	43			43			43			—		—		—		(336		)	(335		)	(278		)
Amortization of transition obligation	—			—			2,609			—		—		—		—			—			—
Recognized net actuarial loss (gain)	2,196			940			—			93		45		66		—			—			9
Net periodic expense	$	2,057		$	976		$	2,709		$	235	$	191	$	199	$	111		$	128		$	186

Accumulated Other Comprehensive Income (Loss)

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 Retirement Plans					Non-pension Defined Benefit Postretirement Healthcare Plan
	2015		2014		2015		2014			2015		2014
Net loss	$	—	$	—	$	673	$	(801	)	$	—	$	—
Prior service cost	—		—		—		—			—		—
Total accumulated other comprehensive income (loss)	$	—	$	—	$	673	$	(801	)	$	—	$	—

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 2016 are as follows (in thousands):

	Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
Net gain (loss)	$	1,297	$	53	$	—
Prior service cost	28		—		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2016	$	1,325	$	53	$	(218	)

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Assumptions

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2015		2014		2013		2015		2014		2013		2015		2014		2013
Weighted-average assumptions used to determine benefit obligations:
Discount rate	4.63	%	4.25	%	5.10	%	4.29	%	3.98	%	4.68	%	4.03	%	3.70	%	4.45	%
Rate of increase in compensation levels	3.57	%	3.86	%	3.86	%	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	4.25	%	5.10	%	4.35	%	3.98	%	4.68	%	3.88	%	3.70	%	4.45	%	3.65	%
Expected long-term rate of return on assets (a)	6.75	%	6.75	%	7.25	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.86	%	3.86	%	3.91	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________

(a) The expected rate of return on plan assets is 6.75% for the calculation of the 2016 net periodic pension cost.

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

	2015		2014
Healthcare trend rate pre-65
Trend for next year	6.35	%	7.50	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2024		2027
Healthcare trend rate post-65
Trend for next year	5.20	%	6.25	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2023		2024

We do not pre-fund our post-retirement benefit plan. The table below shows the estimated impacts of an increase or decrease to our healthcare trend rate for our Retiree Health Care Plan (in thousands):

Change in Assumed Trend Rate	Service and Interest Costs			Accumulated Periodic Postretirement Benefit Obligation
1% increase	$	10		$	221
1% decrease	$	(1	)	$	(205	)

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Beginning in 2016, the company will change 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 uses 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. Previously, those costs were determined using a single weighted-average discount rate. 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 new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The company will account for this change as a change in estimate prospectively beginning in the first quarter of 2016. See "Pension and Postretirement Benefit Obligations" within our Critical Accounting Policies in Item 7 on 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 Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
2016	$	3,492	$	216	$	619
2017	$	3,594	$	248	$	618
2018	$	3,677	$	246	$	613
2019	$	3,814	$	243	$	607
2020	$	3,911	$	240	$	621
2021-2025	$	21,108	$	1,583	$	2,841

Defined Contribution Plan

The Parent sponsors a 401(k) retirement savings plan in which our employees may participate. Participants may elect to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis, up to a maximum amount established by the Internal Revenue Service. The plan provides for company matching contributions and company retirement contributions. Employer contributions vest at 20% per year and are fully vested when the participant has 5 years of service.

(9)    RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

In 2015, we recorded a non-cash dividend to our Parent for approximately $28.5 million and decreased the utility money pool note receivable, net for approximately $28.5 million. No amounts were recorded for 2014.

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):

	2015		2014
Receivable - affiliates	$	5,747	$	5,350
Accounts payable - affiliates	$	30,032	$	19,242

Money Pool Notes Receivable and Notes Payable

We have a Utility Money Pool Agreement (the Agreement) with BHC, Cheyenne Light and Black Hills Utility Holdings. Under the agreement, we may borrow from BHC however the Agreement restricts us from loaning funds to BHC or to any of BHCs’ non-utility subsidiaries. The Agreement does not restrict us from making dividends to BHC. Borrowings under the agreement bear interest at the weighted average daily cost of our parent company’s credit facility 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 rate plus 1.0%.

The cost of borrowing under the Utility Money Pool was 1.45% at December 31, 2015.

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

	2015		2014
Notes receivable (payable), net	$	76,813	$	68,626

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

	2015		2014		2013
Net interest income (expense)	$	1,153	$	304	$	505

Other Balances and Transactions

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

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

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

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

Related-party Gas Transportation Service Agreement

On October 1, 2014, we entered into a gas transportation service agreement with Cheyenne Light 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.

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

	2015		2014		2013
	(in thousands)
Revenues:
Energy sold to Cheyenne Light	$	1,857	$	1,894	$	1,338
Rent from electric properties	$	4,772	$	4,102	$	3,627
Purchases:
Purchase of coal from WRDC	$	16,401	$	16,861	$	18,542
Purchase of excess energy from Cheyenne Light	$	898	$	3,033	$	3,640
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	1,578	$	1,959	$	1,886
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	2,739	$	3,200	$	3,207
Corporate support services from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	26,655	$	32,332	$	30,738

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(10)    SUPPLEMENTAL CASH FLOW INFORMATION

Years ended December 31,	2015			2014			2013
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	3,870		$	4,234		$	13,590
Non-cash decrease to money pool note receivable, net	$	(28,501	)	$	—		$	(8,000	)
Non-cash dividend to Parent company	$	28,501		$	—		$	8,000
Supplemental disclosure of cash flow information:
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(21,913	)	$	(19,573	)	$	(19,174	)
Income taxes	$	—		$	—		$	219

(11)    COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

We have the following power purchase and transmission agreements, not including related party agreements, as of December 31, 2015 (see Note 9 for information on related party agreements):

• A PPA with PacifiCorp expiring on December 31, 2023, which provides for the purchase by us 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 access agreement to deliver up to 50 MW of power on PacifiCorp’s transmission system to wholesale customers in the western region through December 31, 2023; and

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

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

Contract	Contract Type	2015		2014		2013
PacifiCorp	Electric capacity and energy	$	13,990	$	13,943	$	13,026
PacifiCorp	Transmission access	$	1,213	$	1,227	$	1,384
Thunder Creek	Gas transport capacity	$	633	$	633	$	633

Future Contractual Obligations

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

2016	$	12,827
2017	$	12,824
2018	$	6,513
2019	$	6,408
2020	$	5,880
Thereafter	$	17,641

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Long-Term Power Sales Agreements

We have the following power sales agreements as of December 31, 2015:

• An agreement with MDU to supply up to a maximum of 25 MW on a cost reimbursement basis during periods of reduced production at Wygen III;

• A capacity and energy agreement with MDU through December 31, 2023 to supply up to a maximum of 50 MW;

• An agreement with the City of Gillette to supply its first 23 MW on a cost reimbursement basis during periods of reduced production at Wygen III. Under this agreement, we will also provide the City of Gillette their operating component of spinning reserves;

• A unit-contingent energy and capacity sales agreement with MEAN expiring on May 31, 2023. This contract is based 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 energy and capacity purchase requirements decrease over the term of the agreement; and

• 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.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. On April 16, 2013, private landowners filed suit in the United States District Court for the District of Wyoming asserting that the fire was caused by Black Hills Power’s negligent maintenance of a transmission line. The Company denied these claims. These landowners sought recovery for reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate. The State of Wyoming intervened in the lawsuit, asserting claims for fire suppression costs, and similar damage claims related to state-owned lands. As of December 31, 2015, we believed that a loss associated with settlement of pending claims was probable. Accordingly, we had recorded a loss contingency liability related to these claims and a receivable for costs we believed were reimbursable and probable of recovery under our insurance coverage. In consideration of the risk and uncertainty of litigation, the Company subsequently concluded a settlement of all claims, with all parties to the litigation. On January 4, 2016, the court entered its order dismissing the litigation with prejudice. The resolution of the State and private claims did not have a material effect upon our consolidated financial condition, results of operations or cash flows.

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 consolidated 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 consolidated 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.

53

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.

Air

Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO₂, NO_x, mercury particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen III and Wyodak plants. Title IV of the Clean Air Act created an SO₂ allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2045.

The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which impose emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. In anticipation of this rule, we suspended operations at the Osage plant on October 1, 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012. We permanently retired Ben French, Osage and Neil Simpson I on March 21, 2014. The net book value of these plants was allowed regulatory accounting treatment and is recorded as a Regulatory Asset on the accompanying Balance Sheets.

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.

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.

(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
2015
Operating revenues	$	70,283	$	68,038	$	72,111	$	67,432
Operating income	$	21,490	$	21,143	$	23,456	$	21,825
Net income	$	10,403	$	10,547	$	12,287	$	11,937
2014
Operating revenues	$	71,267	$	60,741	$	67,729	$	68,751
Operating income	$	17,546	$	13,782	$	19,007	$	18,779
Net income	$	8,643	$	6,230	$	9,916	$	8,773

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

FINANCIAL DISCLOSURE

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of 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, 2015. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

Management’s Report on Internal Control over Financial Reporting is presented on Page 25 of this Annual Report on Form 10-K.

During our fourth fiscal quarter, there have been no changes in our internal controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

ITEM 9B.    OTHER INFORMATION

None.

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	2015		2014
Audit Fees	$	360	$	337
Tax Fees	16		7
Audit-related fees	—		—
Total	$	376	$	344

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 tax assistance with tax audits. These services include assistance regarding federal tax compliance and advice, review of tax returns, and federal tax planning.

Audit-Related Fees. Fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported under “Audit Fees.” These services may include internal control reviews; attest services that are not required by statute or regulation; employee benefit plan audits; due diligence, consultations and audits related to mergers and acquisitions; and consultations concerning financial accounting and reporting standards.

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, 2015, 2014 and 2013

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:
2015	$	261	$	602	$	(656	)	$	207
2014	$	220	$	699	$	(658	)	$	261
2013	$	102	$	754	$	(636	)	$	220

56

3. Exhibits

Exhibit Number	Description
3.1*	Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*	Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).
3.3*	Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).
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.

(a) See (a) 3. Exhibits above.

(b) See (a) 2. Schedules above.

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.

57

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, 2016

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, 2016
David R. Emery, Chairman and	Principal Executive Officer
Chief Executive Officer
/s/ RICHARD W. KINZLEY	Director and	February 26, 2016
Richard W. Kinzley, Senior Vice President	Principal Financial and
and Chief Financial Officer	Accounting Officer
/s/ LINDEN R. EVANS	Director	February 26, 2016
Linden R. Evans
/s/ STEVEN J. HELMERS	Director	February 26, 2016
Steven J. Helmers

58

INDEX TO EXHIBITS

Exhibit Number	Description
3.1*	Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*	Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).
3.3*	Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).
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	Financial Statements for XBRL Format

_________________________

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

59

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, 2016
		/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, 2016
		/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, 2015 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, 2016
		/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, 2015 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, 2016
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

XML

Document and Entity Information Document - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016
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, 2015
Amendment Flag	false
Document Fiscal Year End Focus	2015
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, Shares Outstanding		23,416,396
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float	$ 0

XML

Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Revenue	$ 277,864	$ 268,488	$ 254,027
Operating expenses:
Fuel and purchased power	83,339	93,976	89,437
Operations and maintenance	68,088	70,356	68,857
Depreciation and amortization	32,552	29,100	28,125
Taxes - property	5,971	5,942	5,264
Total operating expenses	189,950	199,374	191,683
Operating income	87,914	69,114	62,344
Other income (expense):
Interest expense	(22,337)	(20,569)	(19,725)
AFUDC - borrowed	506	248	186
Interest income	657	619	248
AFUDC - equity	918	519	368
Other expense	(117)	(105)	(196)
Other income	233	248	367
Total other income (expense)	(20,140)	(19,040)	(18,752)
Income from continuing operations before income taxes	67,774	50,074	43,592
Income tax (expense) benefit	(22,600)	(16,512)	(13,419)
Net income	$ 45,174	$ 33,562	$ 30,173

XML

Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ 45,174	$ 33,562	$ 30,173
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Benefit plan liability adjustments - net gain (loss) (net of tax of $(36), $189 and $(73), respectively)	68	(351)	139
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(33), $(16) and $(23), respectively)	61	29	43
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $319, $(364) and $(23), respectively)	383	(300)	41
Other comprehensive income (loss), net of tax	512	(622)	223
Comprehensive income (loss), net of tax	$ 45,686	$ 32,940	$ 30,396

XML

Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income (Parenthetical) [Abstract]
Benefit plan liability adjustments - net gain (loss), Tax	$ (36)	$ 189	$ (73)
Reclassification adjustment of benefit plan liability - net gain (loss) tax	(33)	(16)	(23)
Reclassification adjustment of cash flow hedges settled and included in net income (loss), Tax	$ 319	$ (364)	$ (23)

XML

Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 7,559	$ 6,620
Receivables - customers, net	27,856	34,684
Receivables - affiliates	5,747	5,350
Other receivables, net	236	259
Money pool notes receivable	76,813	68,626
Materials, supplies and fuel	24,282	20,965
Deferred income tax assets, net, current	0	13,661
Regulatory assets, current	14,096	10,257
Other current assets	43,118	4,954
Total current assets	199,707	165,376
Investments	4,725	4,584
Property, plant and equipment	1,166,126	1,115,061
Less accumulated depreciation and amortization	(326,074)	(309,767)
Total property, plant and equipment, net	840,052	805,294
Other assets:
Regulatory assets, non-current	71,717	68,427
Other, non-current assets	3,292	11,708
Total other assets	75,009	80,135
TOTAL ASSETS	1,119,493	1,055,389
Current liabilities:
Accounts payable	21,297	30,543
Accounts payable - affiliates	30,032	19,242
Accrued liabilities	69,454	16,415
Regulatory liabilities, current	0	3,073
Total current liabilities	120,783	69,273
Long-term debt	342,756	342,752
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	188,961	193,042
Regulatory liabilities, non-current	51,583	51,916
Benefit plan liabilities	20,033	20,981
Other, non-current liabilities	3,398	2,631
Total deferred credits and other liabilities	$ 263,975	$ 268,570
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	330,295	313,622
Accumulated other comprehensive loss	(1,307)	(1,819)
Total stockholder's equity	391,979	374,794
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$ 1,119,493	$ 1,055,389

XML

Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Common Stock, Par Value Per Share (usd per share)	$ 1.00	$ 1.00
Common Stock, Shares Authorized	50,000,000	50,000,000
Common Stock, Shares, Issued	23,416,396	23,416,396
Common Stock, Shares, Outstanding	23,416,396	23,416,396

XML

Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income	$ 45,174	$ 33,562	$ 30,173
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	32,552	29,100	28,125
Deferred income taxes	7,690	16,518	13,582
AFUDC - equity	(918)	(519)	(368)
Employee benefits	2,403	1,295	3,094
Other adjustments	232	(2,330)	1,400
Change in operating assets and liabilities -
Accounts receivable and other current assets	(2,236)	(10,412)	(5,265)
Accounts payable and other current liabilities	21,652	10,829	1,180
Contributions to defined benefit pension plan	0	(1,696)	(2,299)
Regulatory assets	(3,839)	(5,366)	107
Regulatory liabilities	(2,479)	2,479	(17)
Other operating activities	(5,680)	(6,624)	(3,149)
Net cash provided by (used in) operating activities	94,551	66,836	66,563
Investing activities:
Property, plant and equipment additions	(56,795)	(82,826)	(74,390)
Notes receivable from affiliate companies, net	(36,687)	(51,334)	6,353
Other investing activities	(128)	(154)	(72)
Net cash provided by (used in) investing activities	(93,610)	(134,314)	(68,109)
Financing activities:
Long-term debt - repayments	0	(12,200)	0
Long-term debt - issuance	0	85,000	0
Other financing activities	(2)	(961)	0
Net cash provided by (used in) financing activities	(2)	71,839	0
Net change in cash and cash equivalents	939	4,361	(1,546)
Cash and cash equivalents:
Beginning of year	6,620	2,259	3,805
End of year	$ 7,559	$ 6,620	$ 2,259

XML

Statements of Common Stockholder's Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Common Stock, Shares, Issued - Beginning Balance at Dec. 31, 2012		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, 2013		23,416,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2012		$ 23,416	$ 39,575	$ 257,887	$ (1,420)
Stockholders' Equity Attributable to Parent [Abstract]
Stock Issued During Period, Value, New Issues		0	0
Net income	$ 30,173			30,173
Non-cash Dividend to Parent Company				(8,000)
Other Comprehensive Income (Loss), Net of Tax	223				223
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2013	$ 341,854	$ 23,416	39,575	280,060	(1,197)
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, 2014	23,416,396	23,416,000
Stockholders' Equity Attributable to Parent [Abstract]
Stock Issued During Period, Value, New Issues		$ 0	0
Net income	$ 33,562			33,562
Non-cash Dividend to Parent Company				0
Other Comprehensive Income (Loss), Net of Tax	(622)				(622)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2014	$ 374,794	$ 23,416	39,575	313,622	(1,819)
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	23,416,396	23,416,000
Stockholders' Equity Attributable to Parent [Abstract]
Stock Issued During Period, Value, New Issues		$ 0	0
Net income	$ 45,174
Non-cash Dividend to Parent Company				(28,501)
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)

XML

Business Description and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

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. (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. Actual results could differ 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.

Our regulated utility operations follow accounting standards for regulated operations and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating our electric operations. 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 criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations in an amount that could be material.

Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Balance Sheets.

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

	Maximum Recovery Period (in years)	2015		2014
Regulatory assets:
Unamortized loss on reacquired debt (a)	9	$	2,096	$	2,377
AFUDC(b)	45	8,571		8,365
Employee benefit plans(c)	12	20,866		24,418
Deferred energy costs(a)	1	19,875		14,696
Flow through accounting(a)	35	12,104		11,171
Decommissioning costs (b)	9	13,686		11,786
Other regulatory assets(a) (d)	2	8,615		5,871
Total regulatory assets		$	85,813	$	78,684
Regulatory liabilities:
Cost of removal for utility plant(a)	53	$	38,131	$	35,510
Employee benefit plans(c)	12	12,616		14,538
Other regulatory liabilities(c)	13	836		4,941
Total regulatory liabilities		$	51,583	$	54,989

____________________

(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, respectively.

(d) Includes approximately $5.0 million of vegetation management expenses.

Regulatory assets represent items we expect to recover from customers through rates.

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

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 plans 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 Costs - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our utility customers that are 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.

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. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. A regulatory asset established to reflect the 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 consistent with the flow-through method with respect to costs considered repairs for tax purposes and 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.

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 aspect of a rate regulated environment.

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. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collection success given the existing collections environment.

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

	2015			2014
Accounts receivable trade	$	15,268		$	24,946
Unbilled revenues	12,795			9,999
Allowance for doubtful accounts	(207		)	(261		)
Net accounts receivable trade	$	27,856		$	34,684

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured. 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, we 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 Receivables- customers, net on the accompanying Balance Sheets.

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost basis.

Other Current Assets

The following amounts by major classification are included in Other current assets on the accompanying Balance Sheets as of (in thousands):

	December 31, 2015		December 31, 2014
Accrued receivables related to litigation expenses and settlements	$	39,050	$	—
Other (none of which is individually significant)	4,068		4,954
Total other current assets	$	43,118	$	4,954

Accrued Liabilities

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

	December 31, 2015		December 31, 2014
Accrued employee compensation, benefits and withholdings	$	5,054	$	4,689
Accrued property taxes	4,962		4,721
Accrued payments related to litigation expenses and settlements	38,750		—
Accrued income taxes	13,031		—
Customer deposits and prepayments	2,216		1,934
Accrued interest	4,600		4,662
Other (none of which is individually significant)	841		409
Total accrued liabilities	$	69,454	$	16,415

Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the term of the related debt.

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is AFUDC, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations 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.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.3% in 2015, 2.3% in 2014 and 2.1% in 2013.

Derivatives and Hedging Activities

From time to time we utilize risk management contracts including forward purchases and sales to hedge the price of fuel for our combustion turbines and fixed-for-float swaps to fix the interest on any variable rate debt. Contracts that qualify as derivatives under accounting standards for derivatives, and that are not exempted such as normal purchase/normal sale, are required to be recorded in the balance sheet as either an asset or liability, measured at its fair value. Accounting standards for derivatives require that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Accounting standards for derivatives allow hedge accounting for qualifying fair value and cash flow hedges. Gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk should be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should be reported as a component of other comprehensive income and be reclassified into earnings or as a regulatory asset or regulatory liability, net of tax, in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales 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 exceptions, 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

Accounting standards for fair value measurements provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and also requires disclosures and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:

Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities.

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.

Impairment of Long-Lived Assets

We periodically evaluate whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of our long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, we would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, we would recognize an impairment loss.

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.

We use the asset and liability method in accounting for income taxes. Under the 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. At December 31, 2015, we have chosen to early adopt on a prospective basis ASU 2015-17 as discussed below under Recently Issued and Adopted Accounting Standards. As of December 31, 2015, we classify all deferred tax assets and liabilities as non-current. The prior period is presented under the previous guidance for classifying deferred tax assets and deferred tax liabilities as current and non-current.

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 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 and Adopted Accounting Principles

Balance Sheet Classification of Deferred Taxes, ASU 2015-17

In November 2015, the FASB issued ASU 2015-17 providing guidance on financial statement presentation for deferred tax assets and deferred tax liabilities. All deferred taxes are to be presented as non-current. FASB issued this guidance as part of its initiative to reduce complexity in accounting standards. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those years (i.e., in the first quarter of 2017 for calendar year-end companies). The guidance may be applied either prospectively, for all deferred tax assets and liabilities, or retrospectively by reclassifying the comparative balance sheets. Early adoption is permitted. We have chosen early adoption as of December 31, 2015, on a prospective basis. At December 31, 2015, the balance sheet reflects a net non-current deferred tax liability of $189 million. The balance sheet presentation as of December 31, 2014 was not adjusted retrospectively and remains as previously reported with a net current deferred tax asset of $14 million and a non-current deferred tax liability of $193 million.

Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted. We have chosen not to early adopt ASU 2015-03.

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, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The guidance would be effective for annual and interim reporting periods beginning after December 15, 2018 and early adoption is permitted. We are currently assessing the impact that adoption of ASU 2014-09 will have on our financial position, results of operations or cash flows.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2015

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):

				2015				2014
				Weighted				Weighted
				Average				Average	Lives (in years)
	2015			Useful Life (in years)	2014			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	569,182		46	$	567,936		48	40	65
Transmission	117,708			48	115,949			46	40	60
Distribution	353,241			46	336,652			39	20	60
Plant acquisition adjustment (a)	4,870			32	4,870			32	32	32
General	88,939			22	79,738			22	5	40
Total plant-in-service	1,133,940				1,105,145
Construction work in progress	32,186				9,916
Total electric plant	1,166,126				1,115,061
Less accumulated depreciation and amortization	(326,074		)		(309,767		)
Electric plant net of accumulated depreciation and amortization	$	840,052			$	805,294

__________________

(a) The plant acquisition adjustment is included in rate base and is being recovered with 15 years remaining.

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Jointly Owned Facilities

12 Months Ended

Dec. 31, 2015

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Jointly Owned Facilities

JOINTLY OWNED FACILITIES

We use the proportionate consolidation method to account for our percentage interest in the assets, liabilities and expenses of the following 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 - 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. Cheyenne Light owns the remaining 40 MW. This facility was placed into commercial operations on October 1, 2014. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

The investments in our jointly owned plants and accumulated depreciation are included in the corresponding captions in the accompanying Balance Sheets. Our share of direct expenses of the Plants is included in the corresponding categories of operating expenses in the accompanying Statements of Income. Each of the respective owners is responsible for providing its own financing.

As of December 31, 2015, our interests in jointly-owned generating facilities and transmission systems included on our Balance Sheets were as follows (in thousands):

Interest in jointly-owned facilities	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	111,532	$	1,039	$	56,812
Transmission Tie	$	19,648	$	—	$	5,390
Wygen III	$	137,860	$	446	$	16,217
Cheyenne Prairie	$	91,081	$	—	$	3,301

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Long term Debt

12 Months Ended

Dec. 31, 2015

Long-term Debt, Unclassified [Abstract]

Long term Debt

LONG-TERM DEBT

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

	Maturity Date	Interest Rate		2015			2014
First Mortgage Bonds due 2032	August 15, 2032	7.23	%	$	75,000		$	75,000
First Mortgage Bonds due 2039	November 1, 2039	6.125	%	180,000			180,000
First Mortgage Bonds due 2044	October 20, 2044	4.43	%	85,000			85,000
Unamortized discount, First Mortgage Bonds due 2039				(99		)	(103		)
Series 94A Debt (a)	June 1, 2024	0.75	%	2,855			2,855
Long-term debt				$	342,756		$	342,752

___________________

(a) Variable interest rate at December 31, 2015.

On October 1, 2014 we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044. Proceeds from our bond sale funded the early redemption of our 5.35%$12 million pollution control revenue bonds, originally due October 1, 2024.

Net deferred financing costs of approximately $3.1 million and $3.3 million were recorded on the accompanying Balance Sheets in Other, non-current assets at December 31, 2015 and 2014, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $0.1 million, $0.1 million and $0.1 million for the years ended December 31, 2015, 2014 and 2013, respectively, 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, 2015.

Long-term Debt Maturities

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

2016	$	—
2017	$	—
2018	$	—
2019	$	—
2020	$	—
Thereafter	$	342,855

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

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

	2015				2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents (a)	$	7,559	$	7,559	$	6,620	$	6,620
Long-term debt, including current maturities (b)	$	342,756	$	404,864	$	342,752	$	430,497

_______________

(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 using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods. For additional information on our long-term debt see Note 4.

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 and overnight repurchase agreement accounts. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.

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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

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

	2015		2014			2013
Current	$	14,910	$	(6	)	$	(163	)
Deferred	7,690		16,518			13,582
Total income tax expense	$	22,600	$	16,512		$	13,419

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

	2015			2014
Deferred tax assets:
Employee benefits	$	4,683		$	4,995
Net operating loss	15			14,794
Regulatory liabilities	9,908			10,824
Other	16,171			2,864
Total deferred tax assets	30,777			33,477
Deferred tax liabilities:
Accelerated depreciation and other plant related differences	(187,666		)	(184,478		)
AFUDC	(8,571		)	(8,365		)
Regulatory assets	(4,236		)	(3,910		)
Employee benefits	(3,003		)	(3,723		)
Deferred costs	(14,765		)	(11,324		)
Other	(1,497		)	(1,058		)
Total deferred tax liabilities	(219,738		)	(212,858		)
Net deferred tax assets (liabilities)	$	(188,961	)	$	(179,381	)

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

	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
Amortization of excess deferred and investment tax credits	(0.1	)	(0.3	)	(0.3	)
Equity AFUDC	(0.6	)	(0.1	)	—
Flow through adjustments (a)	(0.9	)	(1.9	)	(2.5	)
Tax credits	—		(0.2	)	(0.8	)
Other	—		0.5		(0.6	)
	33.4	%	33.0	%	30.8	%

_________________________

(a) The flow-through adjustments relate primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. 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 our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit consistent with the flow through method.

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):

	2015			2014
Unrecognized tax benefits at January 1	$	1,623		$	2,443
Additions for prior year tax positions	888			434
Reductions for prior year tax positions	(247		)	(1,254		)
Additions for current year tax positions	—			—
Unrecognized tax benefits at December 31	$	2,264		$	1,623

The reductions for prior year tax positions relate to the reversal through otherwise allowed tax depreciation. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.7 million.

It is our continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 2015 and 2014, the interest expense recognized was not material to our financial results.

In January 2016, the Company reached an agreement in principle with IRS Appeals with respect to research and development tax credits and deductions for tax years 2007 through 2009, and expect a reduction of approximately $0.4 million with respect to our liability for unrecognized tax benefits on or before December 31, 2016.

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

At December 31, 2015, we are no longer in a federal NOL carry forward position.

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Comprehensive Income

12 Months Ended

Dec. 31, 2015

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

Comprehensive Income

COMPREHENSIVE INCOME

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

	Derivatives Designated as Cash Flow Hedges	Amounts Reclassified from AOCI
		2015			2014
Gains and Losses on cash flow hedges
Interest rate swaps gain (loss)	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	319			(364		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	383		$	(300	)
Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	94		$	45
Income tax	Income tax benefit (expense)	(33		)	(16		)
Total reclassification adjustments related to defined benefit plans, net of tax		$	61		$	29

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, 2014	$	(1,018	)	$	(801	)	$	(1,819	)
Other comprehensive income (loss)	383			129			512
As of December 31, 2015	$	(635	)	$	(672	)	$	(1,307	)
	Interest Rate Swaps			Employee Benefit Plans			Total
As of December 31, 2013	$	(719	)	$	(478	)	$	(1,197	)
Other comprehensive income (loss)	(299		)	(323		)	(622		)
As of December 31, 2014	$	(1,018	)	$	(801	)	$	(1,819	)

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2015

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Funded Status of Benefit Plans

The funded status of the postretirement benefit plan is required to be recognized in the statement of financial position. The funded status for the pension plan is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. The measurement date of the plans is December 31, our year-end balance sheet date. As of December 31, 2015, the unfunded status of our Defined Benefit Pension Plan was $11 million, the unfunded status of our Supplemental Non-qualified Defined Benefit Plans was $3.4 million and the unfunded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $6.2 million.

We apply accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to Accumulated other comprehensive income (loss) was alternatively recorded as a regulatory asset or regulatory liability, net of tax.

Defined Benefit 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.

Pension Plan assets are held in a Master Trust that was established for the investment of assets of the Plan and other Employer-sponsored retirement plans. Each participating retirement plan has an undivided interest in the Master Trust.

The BHC Board of Directors have approved the Plans’ 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 Plans’ 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 Plans’ benefit payment obligations. The Pension Plans’ assets consist primarily of equity, fixed income and hedged investments. The expected long-term rate of return for investments was 6.75% and 6.75% for the 2015 and 2014 plan years, respectively. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements.

Pension Plan Assets

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

	2015		2014
Equity securities	26	%	27	%
Real estate	5		5
Fixed income funds	59		58
Cash and cash equivalents	1		2
Hedge funds	9		8
Total	100	%	100	%

Supplemental Non-qualified Defined Benefit Retirement Plans

We have various supplemental retirement plans (“Supplemental Plans”) for key executives. The Supplemental Plans are non-qualified defined benefit plans. The Supplemental Plans are subject to various vesting schedules.

Supplemental Plan Assets

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

Non-pension Defined Benefit Postretirement Healthcare Plan

Employees who are participants in our Non-Pension 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. 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 and Estimated Cash Flows

Cash contributions for pension plans are made directly to the Pension Plan Trust accounts. 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):

	2015		2014
Defined Benefit Plans
Defined Benefit Pension Plan	$	—	$	1,696
Non-pension Defined Benefit Postretirement Healthcare Plan	$	267	$	399
Supplemental Non-qualified Defined Benefit Plan	$	211	$	217
Defined Contribution Plans
Company Retirement Contribution	$	811	$	638
Matching Contributions	$	1,423	$	1,377

Although we are not required we expect to contribute approximately $1.6 million to our Defined Benefit Pension Plan in 2016.

Fair Value Measurements

As required by accounting standards for 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. Our 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 as of December 31 (in thousands):

Defined Benefit Pension Plan	2015
	Level 1		Level 2		Level 3		Total Fair Value
Common Collective Trust - Cash and Cash Equivalents	$	—	$	498	$	—	$	498
Common Collective Trust - Equity	—		14,198		—		14,198
Common Collective Trust - Fixed Income	—		32,615		—		32,615
Common Collective Trust - Real Estate	—		418		2,113		2,531
Hedge Funds	—		—		4,881		4,881
Total investments measured at fair value	$	—	$	47,729	$	6,994	$	54,723

Defined Benefit Pension Plan	2014
	Level 1		Level 2		Level 3		Total Fair Value
Common Collective Trust - Cash and Cash Equivalents	$	—	$	899	$	—	$	899
Common Collective Trust - Equity	—		16,107		—		16,107
Common Collective Trust - Fixed Income	—		34,474		—		34,474
Common Collective Trust - Real Estate	—		761		1,918		2,679
Hedge Funds	—		—		4,939		4,939
Total investments measured at fair value	$	—	$	52,241	$	6,857	$	59,098

Cash and Cash Equivalents: This category is comprised of theAXA Equitable General Fixed Income Fundand Common Collective Trusts - cash and cash equivalents. The AXA Equitable General Fixed Income Fund is a fund of diversified portfolios, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately place 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 at which loans with similar characteristics have. 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.

Common Collective Trust: 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. Certain of the funds’ assets contain participant withdrawal policy and, therefore, are categorized as Level 3. The funds without participant withdrawal limitations are categorized as Level 2.

Hedge Funds: Hedge 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. The Plan’s investment in the hedge fund is categorized as Level 3.

The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended December 31 (in thousands):

	2015
Balance, beginning of period	$	6,857
Purchase	93
Unrealized gain (loss)	63
Settlements	(19		)
Balance, end of period	$	6,994

The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):

	Fair Value at		Valuation	Level 3	Range (Weighted)
	December 31, 2015		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate (a)	$	2,113	Market Approach	Redemption Restriction	N/A
Hedge Funds (b)	$	4,881	Market Approach	Redemption Restriction	N/A

_____________

(a) The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. 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 the 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 fund does contain a participant withdrawal policy.

(b) The fair value of the Hedge Funds is determined based on pricing provided or reviewed by third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed annually as they are issued.

Plan Reconciliations

The following tables provide a reconciliation of the Employee Benefit Plan’s obligations and fair value of assets, components of the net periodic expense and elements of regulatory assets and liabilities and AOCI (in thousands):

Benefit Obligations

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2015			2014			2015			2014			2015			2014
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	71,178		$	60,223		$	3,599		$	3,131		$	6,038		$	5,850
Service cost	797			704			—			—			233			222
Interest cost	2,956			2,991			142			146			214			241
Actuarial loss (gain)	(5,650		)	11,879			(104		)	540			27			115
Benefits paid	(3,284		)	(4,452		)	(211		)	(218		)	(387		)	(488		)
Asset transfer (to) from affiliate	(38		)	(167		)	—			—			(7		)	24
Medicare Part D adjustment	—			—			—			—			(30		)	(15		)
Plan participants’ contributions	—			—			—			—			120			89
Projected benefit obligation at end of year	$	65,959		$	71,178		$	3,426		$	3,599		$	6,208		$	6,038

A reconciliation of the fair value of Plan assets (as of the December 31 measurement date) is as follows (in thousands):

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans					Non-pension Defined Benefit Postretirement Healthcare Plan
	2015			2014			2015			2014		2015			2014
Beginning market value of plan assets	$	59,098		$	56,405		$	—		$	—	$	—		$	—
Investment income	(1,057		)	5,462			—			—		—			—
Benefits paid	(3,284		)	(4,452		)	(211		)	—		(387		)	—
Participant contributions	—			—			—			—		120			—
Employer contributions	—			1,696			211			—		267			—
Asset transfer to affiliate	(34		)	(13		)	—			—		—			—
Ending market value of plan assets	$	54,723		$	59,098		$	—		$	—	$	—		$	—

Amounts recognized in the Balance Sheets at December 31 consist of (in thousands):

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plan
	2015			2014			2015			2014			2015			2014
Regulatory asset (liability)	$	19,816		$	22,717		$	—		$	—		$	(1,946	)	$	2,306
Current liability	$	—		$	—		$	(216	)	$	(217	)	$	(619	)	$	(519	)
Non-current liability	$	(11,236	)	$	(12,080	)	$	(3,210	)	$	(3,382	)	$	(5,587	)	$	(5,519	)

Accumulated Benefit Obligation (in thousands)

	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2015		2014		2015		2014		2015		2014
Accumulated benefit obligation	$	62,240	$	65,699	$	3,426	$	3,599	$	6,208	$	6,038

Components of Net Periodic Expense (in thousands)

	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2015			2014			2013			2015		2014		2013		2015			2014			2013
Service cost	$	797		$	704		$	852		$	—	$	—	$	—	$	233		$	222		$	216
Interest cost	2,956			2,991			2,969			142		146		133		214			241			239
Expected return on assets	(3,935		)	(3,702		)	(3,764		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	43			43			43			—		—		—		(336		)	(335		)	(278		)
Amortization of transition obligation	—			—			2,609			—		—		—		—			—			—
Recognized net actuarial loss (gain)	2,196			940			—			93		45		66		—			—			9
Net periodic expense	$	2,057		$	976		$	2,709		$	235	$	191	$	199	$	111		$	128		$	186

Accumulated Other Comprehensive Income (Loss)

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 Retirement Plans					Non-pension Defined Benefit Postretirement Healthcare Plan
	2015		2014		2015		2014			2015		2014
Net loss	$	—	$	—	$	673	$	(801	)	$	—	$	—
Prior service cost	—		—		—		—			—		—
Total accumulated other comprehensive income (loss)	$	—	$	—	$	673	$	(801	)	$	—	$	—

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 2016 are as follows (in thousands):

	Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
Net gain (loss)	$	1,297	$	53	$	—
Prior service cost	28		—		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2016	$	1,325	$	53	$	(218	)

Assumptions

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2015		2014		2013		2015		2014		2013		2015		2014		2013
Weighted-average assumptions used to determine benefit obligations:
Discount rate	4.63	%	4.25	%	5.10	%	4.29	%	3.98	%	4.68	%	4.03	%	3.70	%	4.45	%
Rate of increase in compensation levels	3.57	%	3.86	%	3.86	%	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	4.25	%	5.10	%	4.35	%	3.98	%	4.68	%	3.88	%	3.70	%	4.45	%	3.65	%
Expected long-term rate of return on assets (a)	6.75	%	6.75	%	7.25	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.86	%	3.86	%	3.91	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________

(a) The expected rate of return on plan assets is 6.75% for the calculation of the 2016 net periodic pension cost.

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

	2015		2014
Healthcare trend rate pre-65
Trend for next year	6.35	%	7.50	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2024		2027
Healthcare trend rate post-65
Trend for next year	5.20	%	6.25	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2023		2024

We do not pre-fund our post-retirement benefit plan. The table below shows the estimated impacts of an increase or decrease to our healthcare trend rate for our Retiree Health Care Plan (in thousands):

Change in Assumed Trend Rate	Service and Interest Costs			Accumulated Periodic Postretirement Benefit Obligation
1% increase	$	10		$	221
1% decrease	$	(1	)	$	(205	)

Beginning in 2016, the company will change 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 uses 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. Previously, those costs were determined using a single weighted-average discount rate. 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 new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The company will account for this change as a change in estimate prospectively beginning in the first quarter of 2016. See "Pension and Postretirement Benefit Obligations" within our Critical Accounting Policies in Item 7 on 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 Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
2016	$	3,492	$	216	$	619
2017	$	3,594	$	248	$	618
2018	$	3,677	$	246	$	613
2019	$	3,814	$	243	$	607
2020	$	3,911	$	240	$	621
2021-2025	$	21,108	$	1,583	$	2,841

Defined Contribution Plan

The Parent sponsors a 401(k) retirement savings plan in which our employees may participate. Participants may elect to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis, up to a maximum amount established by the Internal Revenue Service. The plan provides for company matching contributions and company retirement contributions. Employer contributions vest at 20% per year and are fully vested when the participant has 5 years of service.

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Related Party Transactions

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

Related Party Transactions

RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

In 2015, we recorded a non-cash dividend to our Parent for approximately $28.5 million and decreased the utility money pool note receivable, net for approximately $28.5 million. No amounts were recorded for 2014.

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):

	2015		2014
Receivable - affiliates	$	5,747	$	5,350
Accounts payable - affiliates	$	30,032	$	19,242

Money Pool Notes Receivable and Notes Payable

We have a Utility Money Pool Agreement (the Agreement) with BHC, Cheyenne Light and Black Hills Utility Holdings. Under the agreement, we may borrow from BHC however the Agreement restricts us from loaning funds to BHC or to any of BHCs’ non-utility subsidiaries. The Agreement does not restrict us from making dividends to BHC. Borrowings under the agreement bear interest at the weighted average daily cost of our parent company’s credit facility 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 rate plus 1.0%.

The cost of borrowing under the Utility Money Pool was 1.45% at December 31, 2015.

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

	2015		2014
Notes receivable (payable), net	$	76,813	$	68,626

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

	2015		2014		2013
Net interest income (expense)	$	1,153	$	304	$	505

Other Balances and Transactions

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

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

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

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

Related-party Gas Transportation Service Agreement

On October 1, 2014, we entered into a gas transportation service agreement with Cheyenne Light 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.

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

	2015		2014		2013
	(in thousands)
Revenues:
Energy sold to Cheyenne Light	$	1,857	$	1,894	$	1,338
Rent from electric properties	$	4,772	$	4,102	$	3,627
Purchases:
Purchase of coal from WRDC	$	16,401	$	16,861	$	18,542
Purchase of excess energy from Cheyenne Light	$	898	$	3,033	$	3,640
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	1,578	$	1,959	$	1,886
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	2,739	$	3,200	$	3,207
Corporate support services from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	26,655	$	32,332	$	30,738

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

Years ended December 31,	2015			2014			2013
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	3,870		$	4,234		$	13,590
Non-cash decrease to money pool note receivable, net	$	(28,501	)	$	—		$	(8,000	)
Non-cash dividend to Parent company	$	28,501		$	—		$	8,000
Supplemental disclosure of cash flow information:
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(21,913	)	$	(19,573	)	$	(19,174	)
Income taxes	$	—		$	—		$	219

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Commitment and Contingencies

12 Months Ended

Dec. 31, 2015

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 agreements, not including related party agreements, as of December 31, 2015 (see Note 9 for information on related party agreements):

• A PPA with PacifiCorp expiring on December 31, 2023, which provides for the purchase by us 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 access agreement to deliver up to 50 MW of power on PacifiCorp’s transmission system to wholesale customers in the western region through December 31, 2023; and

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

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

Contract	Contract Type	2015		2014		2013
PacifiCorp	Electric capacity and energy	$	13,990	$	13,943	$	13,026
PacifiCorp	Transmission access	$	1,213	$	1,227	$	1,384
Thunder Creek	Gas transport capacity	$	633	$	633	$	633

Future Contractual Obligations

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

2016	$	12,827
2017	$	12,824
2018	$	6,513
2019	$	6,408
2020	$	5,880
Thereafter	$	17,641

Long-Term Power Sales Agreements

We have the following power sales agreements as of December 31, 2015:

• An agreement with MDU to supply up to a maximum of 25 MW on a cost reimbursement basis during periods of reduced production at Wygen III;

• A capacity and energy agreement with MDU through December 31, 2023 to supply up to a maximum of 50 MW;

• An agreement with the City of Gillette to supply its first 23 MW on a cost reimbursement basis during periods of reduced production at Wygen III. Under this agreement, we will also provide the City of Gillette their operating component of spinning reserves;

• A unit-contingent energy and capacity sales agreement with MEAN expiring on May 31, 2023. This contract is based 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 energy and capacity purchase requirements decrease over the term of the agreement; and

• 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.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. On April 16, 2013, private landowners filed suit in the United States District Court for the District of Wyoming asserting that the fire was caused by Black Hills Power’s negligent maintenance of a transmission line. The Company denied these claims. These landowners sought recovery for reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate. The State of Wyoming intervened in the lawsuit, asserting claims for fire suppression costs, and similar damage claims related to state-owned lands. As of December 31, 2015, we believed that a loss associated with settlement of pending claims was probable. Accordingly, we had recorded a loss contingency liability related to these claims and a receivable for costs we believed were reimbursable and probable of recovery under our insurance coverage. In consideration of the risk and uncertainty of litigation, the Company subsequently concluded a settlement of all claims, with all parties to the litigation. On January 4, 2016, the court entered its order dismissing the litigation with prejudice. The resolution of the State and private claims did not have a material effect upon our consolidated financial condition, results of operations or cash flows.

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 consolidated 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 consolidated 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.

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.

Air

Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO₂, NO_x, mercury particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen III and Wyodak plants. Title IV of the Clean Air Act created an SO₂ allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2045.

The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which impose emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. In anticipation of this rule, we suspended operations at the Osage plant on October 1, 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012. We permanently retired Ben French, Osage and Neil Simpson I on March 21, 2014. The net book value of these plants was allowed regulatory accounting treatment and is recorded as a Regulatory Asset on the accompanying Balance Sheets.

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.

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.

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Quarterly Historical Data (Unaudited)

12 Months Ended

Dec. 31, 2015

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
2015
Operating revenues	$	70,283	$	68,038	$	72,111	$	67,432
Operating income	$	21,490	$	21,143	$	23,456	$	21,825
Net income	$	10,403	$	10,547	$	12,287	$	11,937
2014
Operating revenues	$	71,267	$	60,741	$	67,729	$	68,751
Operating income	$	17,546	$	13,782	$	19,007	$	18,779
Net income	$	8,643	$	6,230	$	9,916	$	8,773

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2015

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:
2015	$	261	$	602	$	(656	)	$	207
2014	$	220	$	699	$	(658	)	$	261
2013	$	102	$	754	$	(636	)	$	220

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Business Description and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

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. Actual results could differ 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.

Our regulated utility operations follow accounting standards for regulated operations and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating our electric operations. 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 criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations in an amount that could be material.

Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Balance Sheets.

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. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collection success given the existing collections environment.

Revenue Recognition

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured. 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, we 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 Receivables- customers, net on the accompanying Balance Sheets.

Materials, Supplies, and Fuel

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost basis.

Deferred Financing Costs

Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the term of the related debt.

Property, Plant and Equipment

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is AFUDC, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations 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.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.3% in 2015, 2.3% in 2014 and 2.1% in 2013.

Derivatives and Hedging Activities

Derivatives and Hedging Activities

From time to time we utilize risk management contracts including forward purchases and sales to hedge the price of fuel for our combustion turbines and fixed-for-float swaps to fix the interest on any variable rate debt. Contracts that qualify as derivatives under accounting standards for derivatives, and that are not exempted such as normal purchase/normal sale, are required to be recorded in the balance sheet as either an asset or liability, measured at its fair value. Accounting standards for derivatives require that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Accounting standards for derivatives allow hedge accounting for qualifying fair value and cash flow hedges. Gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk should be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should be reported as a component of other comprehensive income and be reclassified into earnings or as a regulatory asset or regulatory liability, net of tax, in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales 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 exceptions, 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

Accounting standards for fair value measurements provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and also requires disclosures and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:

Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities.

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.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

We periodically evaluate whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of our long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, we would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, we would recognize an impairment loss.

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.

We use the asset and liability method in accounting for income taxes. Under the 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. At December 31, 2015, we have chosen to early adopt on a prospective basis ASU 2015-17 as discussed below under Recently Issued and Adopted Accounting Standards. As of December 31, 2015, we classify all deferred tax assets and liabilities as non-current. The prior period is presented under the previous guidance for classifying deferred tax assets and deferred tax liabilities as current and non-current.

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 accounting standards for income taxes. The unrecognized tax benefit is classified in Other - non-current liabilities on the accompanying Balance Sheets.

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Business Description and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Regulatory Assets and Liabilities

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

	Maximum Recovery Period (in years)	2015		2014
Regulatory assets:
Unamortized loss on reacquired debt (a)	9	$	2,096	$	2,377
AFUDC(b)	45	8,571		8,365
Employee benefit plans(c)	12	20,866		24,418
Deferred energy costs(a)	1	19,875		14,696
Flow through accounting(a)	35	12,104		11,171
Decommissioning costs (b)	9	13,686		11,786
Other regulatory assets(a) (d)	2	8,615		5,871
Total regulatory assets		$	85,813	$	78,684
Regulatory liabilities:
Cost of removal for utility plant(a)	53	$	38,131	$	35,510
Employee benefit plans(c)	12	12,616		14,538
Other regulatory liabilities(c)	13	836		4,941
Total regulatory liabilities		$	51,583	$	54,989

____________________

(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, respectively.

(d) Includes approximately $5.0 million of vegetation management expenses.

Schedule of Accounts, Notes, Loans and Financing Receivable

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

	2015			2014
Accounts receivable trade	$	15,268		$	24,946
Unbilled revenues	12,795			9,999
Allowance for doubtful accounts	(207		)	(261		)
Net accounts receivable trade	$	27,856		$	34,684

Schedule of Other Current Assets

The following amounts by major classification are included in Other current assets on the accompanying Balance Sheets as of (in thousands):

	December 31, 2015		December 31, 2014
Accrued receivables related to litigation expenses and settlements	$	39,050	$	—
Other (none of which is individually significant)	4,068		4,954
Total other current assets	$	43,118	$	4,954

Schedule of Accrued Liabilities

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

	December 31, 2015		December 31, 2014
Accrued employee compensation, benefits and withholdings	$	5,054	$	4,689
Accrued property taxes	4,962		4,721
Accrued payments related to litigation expenses and settlements	38,750		—
Accrued income taxes	13,031		—
Customer deposits and prepayments	2,216		1,934
Accrued interest	4,600		4,662
Other (none of which is individually significant)	841		409
Total accrued liabilities	$	69,454	$	16,415

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

				2015				2014
				Weighted				Weighted
				Average				Average	Lives (in years)
	2015			Useful Life (in years)	2014			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	569,182		46	$	567,936		48	40	65
Transmission	117,708			48	115,949			46	40	60
Distribution	353,241			46	336,652			39	20	60
Plant acquisition adjustment (a)	4,870			32	4,870			32	32	32
General	88,939			22	79,738			22	5	40
Total plant-in-service	1,133,940				1,105,145
Construction work in progress	32,186				9,916
Total electric plant	1,166,126				1,115,061
Less accumulated depreciation and amortization	(326,074		)		(309,767		)
Electric plant net of accumulated depreciation and amortization	$	840,052			$	805,294

__________________

(a) The plant acquisition adjustment is included in rate base and is being recovered with 15 years remaining.

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Jointly Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2015

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Schedule Of Jointly Owned Facilities

As of December 31, 2015, our interests in jointly-owned generating facilities and transmission systems included on our Balance Sheets were as follows (in thousands):

Interest in jointly-owned facilities	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	111,532	$	1,039	$	56,812
Transmission Tie	$	19,648	$	—	$	5,390
Wygen III	$	137,860	$	446	$	16,217
Cheyenne Prairie	$	91,081	$	—	$	3,301

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Long Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments

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

	Maturity Date	Interest Rate		2015			2014
First Mortgage Bonds due 2032	August 15, 2032	7.23	%	$	75,000		$	75,000
First Mortgage Bonds due 2039	November 1, 2039	6.125	%	180,000			180,000
First Mortgage Bonds due 2044	October 20, 2044	4.43	%	85,000			85,000
Unamortized discount, First Mortgage Bonds due 2039				(99		)	(103		)
Series 94A Debt (a)	June 1, 2024	0.75	%	2,855			2,855
Long-term debt				$	342,756		$	342,752

___________________

(a) Variable interest rate at December 31, 2015.

On October 1, 2014 we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044. Proceeds from our bond sale funded the early redemption of our 5.35%$12 million pollution control revenue bonds, originally due October 1, 2024.

Schedule of Maturities of Long-term Debt

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

2016	$	—
2017	$	—
2018	$	—
2019	$	—
2020	$	—
Thereafter	$	342,855

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2015

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):

	2015				2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents (a)	$	7,559	$	7,559	$	6,620	$	6,620
Long-term debt, including current maturities (b)	$	342,756	$	404,864	$	342,752	$	430,497

_______________

(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 using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods. For additional information on our long-term debt see Note 4.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

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):

	2015		2014			2013
Current	$	14,910	$	(6	)	$	(163	)
Deferred	7,690		16,518			13,582
Total income tax expense	$	22,600	$	16,512		$	13,419

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):

	2015			2014
Deferred tax assets:
Employee benefits	$	4,683		$	4,995
Net operating loss	15			14,794
Regulatory liabilities	9,908			10,824
Other	16,171			2,864
Total deferred tax assets	30,777			33,477
Deferred tax liabilities:
Accelerated depreciation and other plant related differences	(187,666		)	(184,478		)
AFUDC	(8,571		)	(8,365		)
Regulatory assets	(4,236		)	(3,910		)
Employee benefits	(3,003		)	(3,723		)
Deferred costs	(14,765		)	(11,324		)
Other	(1,497		)	(1,058		)
Total deferred tax liabilities	(219,738		)	(212,858		)
Net deferred tax assets (liabilities)	$	(188,961	)	$	(179,381	)

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:

	2015		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%
Amortization of excess deferred and investment tax credits	(0.1	)	(0.3	)	(0.3	)
Equity AFUDC	(0.6	)	(0.1	)	—
Flow through adjustments (a)	(0.9	)	(1.9	)	(2.5	)
Tax credits	—		(0.2	)	(0.8	)
Other	—		0.5		(0.6	)
	33.4	%	33.0	%	30.8	%

_________________________

(a) The flow-through adjustments relate primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. 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 our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit consistent with the flow through method.

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):

	2015			2014
Unrecognized tax benefits at January 1	$	1,623		$	2,443
Additions for prior year tax positions	888			434
Reductions for prior year tax positions	(247		)	(1,254		)
Additions for current year tax positions	—			—
Unrecognized tax benefits at December 31	$	2,264		$	1,623

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Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2015

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):

	Derivatives Designated as Cash Flow Hedges	Amounts Reclassified from AOCI
		2015			2014
Gains and Losses on cash flow hedges
Interest rate swaps gain (loss)	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	319			(364		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	383		$	(300	)
Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	94		$	45
Income tax	Income tax benefit (expense)	(33		)	(16		)
Total reclassification adjustments related to defined benefit plans, net of tax		$	61		$	29

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, 2014	$	(1,018	)	$	(801	)	$	(1,819	)
Other comprehensive income (loss)	383			129			512
As of December 31, 2015	$	(635	)	$	(672	)	$	(1,307	)
	Interest Rate Swaps			Employee Benefit Plans			Total
As of December 31, 2013	$	(719	)	$	(478	)	$	(1,197	)
Other comprehensive income (loss)	(299		)	(323		)	(622		)
As of December 31, 2014	$	(1,018	)	$	(801	)	$	(1,819	)

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2015

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets

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

	2015		2014
Equity securities	26	%	27	%
Real estate	5		5
Fixed income funds	59		58
Cash and cash equivalents	1		2
Hedge funds	9		8
Total	100	%	100	%

Schedule of Contribution to Employee Plans

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

	2015		2014
Defined Benefit Plans
Defined Benefit Pension Plan	$	—	$	1,696
Non-pension Defined Benefit Postretirement Healthcare Plan	$	267	$	399
Supplemental Non-qualified Defined Benefit Plan	$	211	$	217
Defined Contribution Plans
Company Retirement Contribution	$	811	$	638
Matching Contributions	$	1,423	$	1,377

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended December 31 (in thousands):

	2015
Balance, beginning of period	$	6,857
Purchase	93
Unrealized gain (loss)	63
Settlements	(19		)
Balance, end of period	$	6,994

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques

The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):

	Fair Value at		Valuation	Level 3	Range (Weighted)
	December 31, 2015		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate (a)	$	2,113	Market Approach	Redemption Restriction	N/A
Hedge Funds (b)	$	4,881	Market Approach	Redemption Restriction	N/A

_____________

(a) The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. 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 the 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 fund does contain a participant withdrawal policy.

(b) The fair value of the Hedge Funds is determined based on pricing provided or reviewed by third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed annually as they are issued.

Schedule of Changes in Projected Benefit Obligations

The following tables provide a reconciliation of the Employee Benefit Plan’s obligations and fair value of assets, components of the net periodic expense and elements of regulatory assets and liabilities and AOCI (in thousands):

Benefit Obligations

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2015			2014			2015			2014			2015			2014
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	71,178		$	60,223		$	3,599		$	3,131		$	6,038		$	5,850
Service cost	797			704			—			—			233			222
Interest cost	2,956			2,991			142			146			214			241
Actuarial loss (gain)	(5,650		)	11,879			(104		)	540			27			115
Benefits paid	(3,284		)	(4,452		)	(211		)	(218		)	(387		)	(488		)
Asset transfer (to) from affiliate	(38		)	(167		)	—			—			(7		)	24
Medicare Part D adjustment	—			—			—			—			(30		)	(15		)
Plan participants’ contributions	—			—			—			—			120			89
Projected benefit obligation at end of year	$	65,959		$	71,178		$	3,426		$	3,599		$	6,208		$	6,038

Schedule of Changes in Fair Value of Plan Assets

A reconciliation of the fair value of Plan assets (as of the December 31 measurement date) is as follows (in thousands):

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans					Non-pension Defined Benefit Postretirement Healthcare Plan
	2015			2014			2015			2014		2015			2014
Beginning market value of plan assets	$	59,098		$	56,405		$	—		$	—	$	—		$	—
Investment income	(1,057		)	5,462			—			—		—			—
Benefits paid	(3,284		)	(4,452		)	(211		)	—		(387		)	—
Participant contributions	—			—			—			—		120			—
Employer contributions	—			1,696			211			—		267			—
Asset transfer to affiliate	(34		)	(13		)	—			—		—			—
Ending market value of plan assets	$	54,723		$	59,098		$	—		$	—	$	—		$	—

Schedule of Amounts Recognized in Balance Sheet

Amounts recognized in the Balance Sheets at December 31 consist of (in thousands):

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plan
	2015			2014			2015			2014			2015			2014
Regulatory asset (liability)	$	19,816		$	22,717		$	—		$	—		$	(1,946	)	$	2,306
Current liability	$	—		$	—		$	(216	)	$	(217	)	$	(619	)	$	(519	)
Non-current liability	$	(11,236	)	$	(12,080	)	$	(3,210	)	$	(3,382	)	$	(5,587	)	$	(5,519	)

Schedule of Accumulated and Projected Benefit Obligations

Accumulated Benefit Obligation (in thousands)

	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2015		2014		2015		2014		2015		2014
Accumulated benefit obligation	$	62,240	$	65,699	$	3,426	$	3,599	$	6,208	$	6,038

Schedule of Net Benefit Costs

Components of Net Periodic Expense (in thousands)

	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2015			2014			2013			2015		2014		2013		2015			2014			2013
Service cost	$	797		$	704		$	852		$	—	$	—	$	—	$	233		$	222		$	216
Interest cost	2,956			2,991			2,969			142		146		133		214			241			239
Expected return on assets	(3,935		)	(3,702		)	(3,764		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	43			43			43			—		—		—		(336		)	(335		)	(278		)
Amortization of transition obligation	—			—			2,609			—		—		—		—			—			—
Recognized net actuarial loss (gain)	2,196			940			—			93		45		66		—			—			9
Net periodic expense	$	2,057		$	976		$	2,709		$	235	$	191	$	199	$	111		$	128		$	186

Schedule of Net Periodic Benefit Cost Not yet Recognized

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 Retirement Plans					Non-pension Defined Benefit Postretirement Healthcare Plan
	2015		2014		2015		2014			2015		2014
Net loss	$	—	$	—	$	673	$	(801	)	$	—	$	—
Prior service cost	—		—		—		—			—		—
Total accumulated other comprehensive income (loss)	$	—	$	—	$	673	$	(801	)	$	—	$	—

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 2016 are as follows (in thousands):

	Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
Net gain (loss)	$	1,297	$	53	$	—
Prior service cost	28		—		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2016	$	1,325	$	53	$	(218	)

Schedule of Assumptions Used

Assumptions

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2015		2014		2013		2015		2014		2013		2015		2014		2013
Weighted-average assumptions used to determine benefit obligations:
Discount rate	4.63	%	4.25	%	5.10	%	4.29	%	3.98	%	4.68	%	4.03	%	3.70	%	4.45	%
Rate of increase in compensation levels	3.57	%	3.86	%	3.86	%	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	4.25	%	5.10	%	4.35	%	3.98	%	4.68	%	3.88	%	3.70	%	4.45	%	3.65	%
Expected long-term rate of return on assets (a)	6.75	%	6.75	%	7.25	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.86	%	3.86	%	3.91	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________

(a) The expected rate of return on plan assets is 6.75% for the calculation of the 2016 net periodic pension cost.

Schedule of Health Care Cost Trend Rates

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

	2015		2014
Healthcare trend rate pre-65
Trend for next year	6.35	%	7.50	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2024		2027
Healthcare trend rate post-65
Trend for next year	5.20	%	6.25	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2023		2024

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

The table below shows the estimated impacts of an increase or decrease to our healthcare trend rate for our Retiree Health Care Plan (in thousands):

Change in Assumed Trend Rate	Service and Interest Costs			Accumulated Periodic Postretirement Benefit Obligation
1% increase	$	10		$	221
1% decrease	$	(1	)	$	(205	)

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 Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
2016	$	3,492	$	216	$	619
2017	$	3,594	$	248	$	618
2018	$	3,677	$	246	$	613
2019	$	3,814	$	243	$	607
2020	$	3,911	$	240	$	621
2021-2025	$	21,108	$	1,583	$	2,841

Defined Benefit Pension Plan [Member]

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 as of December 31 (in thousands):

Defined Benefit Pension Plan	2015
	Level 1		Level 2		Level 3		Total Fair Value
Common Collective Trust - Cash and Cash Equivalents	$	—	$	498	$	—	$	498
Common Collective Trust - Equity	—		14,198		—		14,198
Common Collective Trust - Fixed Income	—		32,615		—		32,615
Common Collective Trust - Real Estate	—		418		2,113		2,531
Hedge Funds	—		—		4,881		4,881
Total investments measured at fair value	$	—	$	47,729	$	6,994	$	54,723

Defined Benefit Pension Plan	2014
	Level 1		Level 2		Level 3		Total Fair Value
Common Collective Trust - Cash and Cash Equivalents	$	—	$	899	$	—	$	899
Common Collective Trust - Equity	—		16,107		—		16,107
Common Collective Trust - Fixed Income	—		34,474		—		34,474
Common Collective Trust - Real Estate	—		761		1,918		2,679
Hedge Funds	—		—		4,939		4,939
Total investments measured at fair value	$	—	$	52,241	$	6,857	$	59,098

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2015

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):

	2015		2014
Receivable - affiliates	$	5,747	$	5,350
Accounts payable - affiliates	$	30,032	$	19,242

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):

	2015		2014
Notes receivable (payable), net	$	76,813	$	68,626

Schedule of Related Party Interest Income Expense

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

	2015		2014		2013
Net interest income (expense)	$	1,153	$	304	$	505

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:

	2015		2014		2013
	(in thousands)
Revenues:
Energy sold to Cheyenne Light	$	1,857	$	1,894	$	1,338
Rent from electric properties	$	4,772	$	4,102	$	3,627
Purchases:
Purchase of coal from WRDC	$	16,401	$	16,861	$	18,542
Purchase of excess energy from Cheyenne Light	$	898	$	3,033	$	3,640
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	1,578	$	1,959	$	1,886
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	2,739	$	3,200	$	3,207
Corporate support services from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	26,655	$	32,332	$	30,738

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Years ended December 31,	2015			2014			2013
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	3,870		$	4,234		$	13,590
Non-cash decrease to money pool note receivable, net	$	(28,501	)	$	—		$	(8,000	)
Non-cash dividend to Parent company	$	28,501		$	—		$	8,000
Supplemental disclosure of cash flow information:
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(21,913	)	$	(19,573	)	$	(19,174	)
Income taxes	$	—		$	—		$	219

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Commitment and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

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	2015		2014		2013
PacifiCorp	Electric capacity and energy	$	13,990	$	13,943	$	13,026
PacifiCorp	Transmission access	$	1,213	$	1,227	$	1,384
Thunder Creek	Gas transport capacity	$	633	$	633	$	633

Unrecorded Unconditional Purchase Obligations Disclosure

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

2016	$	12,827
2017	$	12,824
2018	$	6,513
2019	$	6,408
2020	$	5,880
Thereafter	$	17,641

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Quarterly Historical Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

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
2015
Operating revenues	$	70,283	$	68,038	$	72,111	$	67,432
Operating income	$	21,490	$	21,143	$	23,456	$	21,825
Net income	$	10,403	$	10,547	$	12,287	$	11,937
2014
Operating revenues	$	71,267	$	60,741	$	67,729	$	68,751
Operating income	$	17,546	$	13,782	$	19,007	$	18,779
Net income	$	8,643	$	6,230	$	9,916	$	8,773

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Business Description and Summary of Significant Accounting Policies: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Schedule Of Regulatory Assets And Liabilities [Line Items]
Deferred income tax liabilities, net, non-current		$ 188,961	$ 193,042
Regulatory Assets		85,813	78,684
Regulatory Liabilities		$ 51,583	54,989
Cost of removal for utility plant [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities, Maximum Recovery Period		53 years
Regulatory Liabilities	[1]	$ 38,131	35,510
Employee benefit plans [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities, Maximum Recovery Period		12 years
Regulatory Liabilities	[2]	$ 12,616	14,538
Other regulatory liabilities [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities, Maximum Recovery Period		13 years
Regulatory Liabilities	[2]	$ 836	4,941
Unamortized loss on reacquired debt [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period		9 years
Regulatory Assets	[1]	$ 2,096	2,377
Allowance for Funds Used During Construction [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period		45 years
Regulatory Assets	[3]	$ 8,571	8,365
Employee benefit plans [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period		12 years
Regulatory Assets	[2]	$ 20,866	24,418
Deferred energy costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period		1 year
Regulatory Assets	[1]	$ 19,875	14,696
Flow through accounting [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period		35 years
Regulatory Assets	[1]	$ 12,104	11,171
Decommissioning costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period		9 years
Regulatory Assets	[1]	$ 13,686	11,786
Other Regulatory Assets [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Maximum Recovery Period		2 years
Regulatory Assets	[1],[4]	$ 8,615	$ 5,871
Vegetation Management [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	[1],[4]	$ 5,000

[1] Recovery of costs but we are not allowed a rate of return.

[2] 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, respectively.

[3] In addition to recovery of costs, we are allowed a rate of return.

[4] Includes approximately $5.0 million of vegetation management expenses.

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Business Description and Summary of Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (207)	$ (261)
Net accounts receivable	27,856	34,684
Billed Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, trade	15,268	24,946
Unbilled Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, trade	$ 12,795	$ 9,999

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Business Description and Summary of Significant Accounting Policies: Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accrued receivables related to litigation expenses and settlements	$ 39,050	$ 0
Other (none of which is individually significant)	4,068	4,954
Total other current assets	$ 43,118	$ 4,954

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Business Description and Summary of Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Employee-related Liabilities, Current	$ 5,054	$ 4,689
Accrual for Taxes Other than Income Taxes, Current	4,962	4,721
Loss Contingency, Accrual, Current	38,750	0
Accrued Income Taxes	13,031	0
Customer Advances and Deposits, Current	2,216	1,934
Interest Payable, Current	4,600	4,662
Other Accrued Liabilities, Current	841	409
Accrued Liabilities, Current	$ 69,454	$ 16,415

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Business Description and Summary of Significant Accounting Policies: Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Composite Depreciation Rate for Plants in Service	2.30%	2.30%	2.10%

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Business Description and Summary of Significant Accounting Policies: Balance Sheet Classification of Deferred Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Deferred income tax liabilities, net, non-current	$ 188,961	$ 193,042
Deferred income tax assets, net, current	$ 0	$ 13,661

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Property, Plant and Equipment (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Production		$ 569,182		$ 567,936
Transmission		117,708		115,949
Distribution		353,241		336,652
Plant acquisition adjustment	[1]	4,870		4,870
General		88,939		79,738
Total plant-in-service		1,133,940		1,105,145
Construction work in progress		32,186		9,916
Total electric plant		1,166,126		1,115,061
Less accumulated depreciation and amortization		(326,074)		(309,767)
Electric plant net of accumulated depreciation and amortization		$ 840,052		$ 805,294
Acquisition Adjustment, Remaining Amortization Period		15 years
Electric Production [Member] | Weighted average useful life [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		46 years		48 years
Electric Production [Member] | Minimum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		40 years
Electric Production [Member] | Maximum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		65 years
Electric Transmission [Member] | Weighted average useful life [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		48 years		46 years
Electric Transmission [Member] | Minimum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		40 years
Electric Transmission [Member] | Maximum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		60 years
Electric Distribution [Member] | Weighted average useful life [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		46 years		39 years
Electric Distribution [Member] | Minimum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		20 years
Electric Distribution [Member] | Maximum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		60 years
Plant Acquisition Adjustment [Member] | Weighted average useful life [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		32 years	[1]	32 years
Plant Acquisition Adjustment [Member] | Minimum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		32 years
Plant Acquisition Adjustment [Member] | Maximum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		32 years
General [Member] | Weighted average useful life [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		22 years		22 years
General [Member] | Minimum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		5 years
General [Member] | Maximum [Member]
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Useful Life (in years)		40 years

[1] The plant acquisition adjustment is included in rate base and is being recovered with 15 years remaining.

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Jointly Owned Facilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) MW
Wyodak Plant [Member]
Jointly Owned Utility Plant Interests [Line Items]
Proportionate Ownership Percentage	20.00%
Plant in Service	$ 111,532
Construction Work in Progress	1,039
Accumulated Depreciation	$ 56,812
Transmission Tie [Member]
Jointly Owned Utility Plant Interests [Line Items]
Proportionate Ownership Percentage	35.00%
Plant in Service	$ 19,648
Construction Work in Progress	0
Accumulated Depreciation	$ 5,390
Wygen I I I Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Proportionate Ownership Percentage	52.00%
Plant in Service	$ 137,860
Construction Work in Progress	446
Accumulated Depreciation	$ 16,217
Cheyenne Prairie [Member]
Jointly Owned Utility Plant Interests [Line Items]
Electric Generation Capacity, Megawatts | MW	55
Plant in Service	$ 91,081
Construction Work in Progress	0
Accumulated Depreciation	$ 3,301
Cheyenne Prairie [Member] | Cheyenne Light [Member]
Jointly Owned Utility Plant Interests [Line Items]
Electric Generation Capacity, Megawatts | MW	40

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Long Term Debt (Details) - USD ($) $ in Thousands			12 Months Ended
		Oct. 01, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt			$ 342,756	$ 342,752
Deferred Finance Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net			3,100	3,300
Amortization of Financing Costs			$ 100	100	$ 100
First Mortgage Bonds Due 2032 [Member]
Debt Instrument [Line Items]
Maturity Date			Aug. 15, 2032
Interest Rate, Stated Percentage			7.23%
Long-term Debt, Gross			$ 75,000	75,000
First Mortgage Bonds Due 2039 [Member]
Debt Instrument [Line Items]
Maturity Date			Nov. 01, 2039
Interest Rate, Stated Percentage			6.125%
Long-term Debt, Gross			$ 180,000	180,000
Unamortized Discount			$ (99)	(103)
First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Maturity Date			Oct. 20, 2044
Interest Rate, Stated Percentage			4.43%
Long-term Debt, Gross			$ 85,000	85,000
Bonds Due 2024 [Member]
Debt Instrument [Line Items]
Maturity Date			Jun. 01, 2024
Variable Interest, Percentage Rate	[1]		0.75%
Long-term Debt, Gross	[1]		$ 2,855	$ 2,855
Electric Utilities [Member] | Black Hills Power [Member] | First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Interest Rate, Stated Percentage		4.43%
Long-term Debt, Gross		$ 85,000
Electric Utilities [Member] | Black Hills Power [Member] | Polution Control Revenue Bonds Due 2024 [Member]
Debt Instrument [Line Items]
Interest Rate, Stated Percentage		5.35%
Extinguishment of Debt, Amount		$ 12,000

[1] Variable interest rate at December 31, 2015.

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Long-Term Debt: Schedule of Maturities of Long-term Debt (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Long-term Debt, Unclassified [Abstract]
2016	$ 0
2017	0
2018	0
2019	0
2020	0
After 2020	$ 342,855

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Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying value		$ 7,559	$ 6,620	$ 2,259	$ 3,805
Long-term debt, including current maturities - carrying value		342,756	342,752
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying value	[1]	7,559	6,620
Long-term debt, including current maturities - carrying value	[2]	342,756	342,752
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - fair value	[1]	7,559	6,620
Long-term debt, including current maturities - fair value	[2]	$ 404,864	$ 430,497

[1] 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.

[2] Long-term debt is valued using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods. For additional information on our long-term debt see Note 4.

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Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Current	$ 14,910	$ (6)	$ (163)
Deferred	7,690	16,518	13,582
Total income tax expense	$ 22,600	$ 16,512	$ 13,419

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Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Components of Deferred Tax Assets [Abstract]
Employee benefits	$ 4,683	$ 4,995
Net operating loss	15	14,794
Regulatory liabilities	9,908	10,824
Other	16,171	2,864
Deferred Tax Assets, Gross	30,777	33,477
Components of Deferred Tax Liabilities [Abstract]
Accelerated depreciation and other plant related differences	(187,666)	(184,478)
Allowance for Funds Used During Construction	(8,571)	(8,365)
Regulatory assets	(4,236)	(3,910)
Employee benefits	(3,003)	(3,723)
Deferred costs	(14,765)	(11,324)
Other	(1,497)	(1,058)
Total deferred tax liabilities	(219,738)	(212,858)
Net deferred tax assets (liabilities)	$ (188,961)	$ (179,381)

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Income Taxes: Effective Tax Rate Differences from Statutory Tax Rates (Details)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal statutory rate		35.00%	35.00%	35.00%
Amortization of excess deferred and investment tax credits		(0.10%)	(0.30%)	(0.30%)
Equity AFUDC		(0.60%)	(0.10%)	0.00%
Flow through adjustments	[1]	(0.90%)	(1.90%)	(2.50%)
Tax credits		(0.00%)	(0.20%)	(0.80%)
Other		0.00%	0.50%	(0.60%)
Effective Income Tax Rate		33.40%	33.00%	30.80%

[1] The flow-through adjustments relate primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. 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 our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit consistent with the flow through method.

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Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning of Period	$ 1,623	$ 2,443
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	888	434
Reductions for prior year tax positions	(247)	(1,254)
Additions for current year tax positions	0	0
End of Period	2,264	$ 1,623
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 700

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Income Taxes: Interest, Penalties and Audits (Details) $ in Millions	1 Months Ended
	Jan. 31, 2016 USD ($)
Subsequent Event [Member]
Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities	$ 0.4

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Comprehensive Income: Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest Costs Incurred									$ 22,337	$ 20,569	$ 19,725
Income tax (expense) benefit									(22,600)	(16,512)	(13,419)
Net income	$ 11,937	$ 12,287	$ 10,547	$ 10,403	$ 8,773	$ 9,916	$ 6,230	$ 8,643	45,174	33,562	$ 30,173
First Mortgage Bonds Due 2032 [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Derivative, Notional Amount	50,000								$ 50,000
Derivative, Maturity Date									Aug. 08, 2002
Realized Loss Included Accumulated Other Comprehensive Income (Loss)	$ 1,800								$ 1,800
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Contract [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest Costs Incurred									64	64
Income tax (expense) benefit									319	(364)
Net income									383	(300)
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses									94	45
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income tax (expense) benefit									(33)	(16)
Net income									$ 61	$ 29
First Mortgage Bonds Due 2032 [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Debt Instrument, Maturity Date									Aug. 15, 2032

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Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (1,819)	$ (1,197)
Other comprehensive income (loss)	512	(622)	$ 223
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(1,307)	(1,819)	(1,197)
Interest Rate Swaps, Cash Flow Hedges, AOCI [Member] | Interest Rate Swaps [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(1,018)	(719)
Other comprehensive income (loss)	383	(299)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(635)	(1,018)	(719)
Employee Benefit Plans, AOCI [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(801)	(478)
Other comprehensive income (loss)	129	(323)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	$ (672)	$ (801)	$ (478)

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Employee Benefit Plans: Narrative (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Measurement Date		December 31
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		6.75%	6.75%
Defined Benefit Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Unfunded Status of Plan		$ (11.0)
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	[1]	6.75%	6.75%	7.25%
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Unfunded Status of Plan		$ (6.2)
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Unfunded Status of Plan		$ (3.4)

[1] The expected rate of return on plan assets is 6.75% for the calculation of the 2016 net periodic pension cost.

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Employee Benefit Plans: Target Plan Assets Allocation (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations	100.00%	100.00%
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations	26.00%	27.00%
Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations	5.00%	5.00%
Fixed Income Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations	59.00%	58.00%
Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations	1.00%	2.00%
Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Plan Asset Allocations	9.00%	8.00%

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Employee Benefit Plans: Plan Contribution (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	$ 1,600
Defined Contribution Plan, Company Retirement [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plans, Contributions by Employer	811	$ 638
Defined Contribution Plan, 401K [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plans, Contributions by Employer	1,423	1,377
Defined Benefit Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plans, Employer Contributions	0	1,696
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plans, Employer Contributions	267	399
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plans, Employer Contributions	$ 211	$ 217

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Employee Benefit Plans: Fair Value Measurements (Details) - Defined Benefit Pension Plan [Member] - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 54,723	$ 59,098	$ 56,405
Common Collective Trust - Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		498	899
Common Collective Trust - Equity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		14,198	16,107
Common Collective Trust - Fixed Income [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		32,615	34,474
Common Collective Trust - Real Estate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		2,531	2,679
Hedge Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		4,881	4,939
Fair Value, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 1 [Member] | Common Collective Trust - Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 1 [Member] | Common Collective Trust - Equity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 1 [Member] | Common Collective Trust - Fixed Income [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 1 [Member] | Common Collective Trust - Real Estate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 1 [Member] | Hedge Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		47,729	52,241
Fair Value, Level 2 [Member] | Common Collective Trust - Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		498	899
Fair Value, Level 2 [Member] | Common Collective Trust - Equity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		14,198	16,107
Fair Value, Level 2 [Member] | Common Collective Trust - Fixed Income [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		32,615	34,474
Fair Value, Level 2 [Member] | Common Collective Trust - Real Estate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		418	761
Fair Value, Level 2 [Member] | Hedge Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		6,994	6,857
Fair Value, Level 3 [Member] | Common Collective Trust - Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 3 [Member] | Common Collective Trust - Equity [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 3 [Member] | Common Collective Trust - Fixed Income [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fair Value, Level 3 [Member] | Common Collective Trust - Real Estate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	2,113	1,918
Fair Value, Level 3 [Member] | Hedge Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	$ 4,881	$ 4,939

[1] The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. 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 the 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 fund does contain a participant withdrawal policy.

[2] The fair value of the Hedge Funds is determined based on pricing provided or reviewed by third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed annually as they are issued.

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Employee Benefit Plans: Level 3 Roll Forward (Details) - Defined Benefit Pension Plan [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	$ 54,723	$ 59,098	$ 56,405
Fair Value, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period	6,857
Purchase	93
Unrealized gain (loss)	63
Settlements	(19)
Balance, end of period	6,994
Defined Benefit Plan, Fair Value of Plan Assets	$ 6,994	$ 6,857

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Employee Benefit Plans: Changes in Benefit Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	$ 71,178	$ 60,223
Service cost	797	704	$ 852
Interest cost	2,956	2,991	2,969
Actuarial loss (gain)	(5,650)	11,879
Benefits Paid	(3,284)	(4,452)
Asset transfer (to) from affiliate	(38)	(167)
Medicare Part D adjustment	0	0
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	65,959	71,178	60,223
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	3,599	3,131
Service cost	0	0	0
Interest cost	142	146	133
Actuarial loss (gain)	(104)	540
Benefits Paid	(211)	(218)
Asset transfer (to) from affiliate	0	0
Medicare Part D adjustment	0	0
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	3,426	3,599	3,131
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	6,038	5,850
Service cost	233	222	216
Interest cost	214	241	239
Actuarial loss (gain)	27	115
Benefits Paid	(387)	(488)
Asset transfer (to) from affiliate	(7)	24
Medicare Part D adjustment	(30)	(15)
Plan participants’ contributions	120	89
Projected benefit obligation at end of year	$ 6,208	$ 6,038	$ 5,850

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Employee Benefit Plans: Changes in Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Pension Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets	$ 59,098	$ 56,405
Investment income	(1,057)	5,462
Benefits paid	(3,284)	(4,452)
Employer Contributions	0	1,696
Asset transfer to affiliate	(34)	(13)
Ending market value of plan assets	54,723	59,098
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets	0	0
Investment income	0	0
Benefits paid	(211)	0
Employer Contributions	211	217
Defined Benefit Plan, Contributions by Employer	211	0
Asset transfer to affiliate	0	0
Ending market value of plan assets	0	0
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets	0	0
Investment income	0	0
Benefits paid	(387)	0
Participant Contributions	120	0
Employer Contributions	267	399
Defined Benefit Plan, Contributions by Employer	267	0
Asset transfer to affiliate	0	0
Ending market 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, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-current liability	$ (20,033)	$ (20,981)
Defined Benefit Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset (liability)	19,816	22,717
Current liability	0	0
Non-current liability	(11,236)	(12,080)
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset (liability)	0	0
Current liability	(216)	(217)
Non-current liability	(3,210)	(3,382)
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset (liability)	(1,946)	2,306
Current liability	(619)	(519)
Non-current liability	$ (5,587)	$ (5,519)

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Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated benefit obligation	$ 62,240	$ 65,699
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated benefit obligation	3,426	3,599
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated benefit obligation	$ 6,208	$ 6,038

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Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 797	$ 704	$ 852
Interest cost	2,956	2,991	2,969
Expected return on assets	(3,935)	(3,702)	(3,764)
Amortization of prior service cost (credits)	43	43	43
Amortization of transition obligation	0	0	2,609
Recognized net actuarial loss (gain)	2,196	940	0
Net periodic expense	2,057	976	2,709
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	0
Interest cost	142	146	133
Expected return on assets	0	0	0
Amortization of prior service cost (credits)	0	0	0
Amortization of transition obligation	0	0	0
Recognized net actuarial loss (gain)	93	45	66
Net periodic expense	235	191	199
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	233	222	216
Interest cost	214	241	239
Expected return on assets	0	0	0
Amortization of prior service cost (credits)	(336)	(335)	(278)
Amortization of transition obligation	0	0	0
Recognized net actuarial loss (gain)	0	0	9
Net periodic expense	$ 111	$ 128	$ 186

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Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Pension Plan [Member]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax [Abstract]
Net loss	$ 0	$ 0
Prior service cost	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	1,297
Prior service cost	28
Total net periodic benefit cost expected to be recognized during calendar year 2016	1,325
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax [Abstract]
Net loss	673	(801)
Prior service cost	0	0
Total accumulated other comprehensive income (loss)	673	(801)
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	53
Prior service cost	0
Total net periodic benefit cost expected to be recognized during calendar year 2016	53
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax [Abstract]
Net loss	0	0
Prior service cost	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 2016	$ (218)

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Employee Benefit Plans: Defined Benefit Plans Assumptions (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected long-term rate of return on assets		6.75%	6.75%
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
1% Increase on Service and Interest Costs		$ 10
1% Increase on Accumulated Periodic Postretirement Benefit Obligation		221
1% Decrease on Service and Interest Cost		(1)
1% Decrease on Accumulated Periodic Postretirement Benefit Obligation		$ (205)
Defined Benefit Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate		4.63%	4.25%	5.10%
Rate of increase in compensation levels		3.57%	3.86%	3.86%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		4.25%	5.10%	4.35%
Expected long-term rate of return on assets	[1]	6.75%	6.75%	7.25%
Rate of increase in compensation levels		3.86%	3.86%	3.91%
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year		6.75%
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate		4.29%	3.98%	4.68%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		3.98%	4.68%	3.88%
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate		4.03%	3.70%	4.45%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		3.70%	4.45%	3.65%
Healthcare trend rate pre-65 [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year		6.35%	7.50%
Ultimate trend rate		4.50%	4.50%
Year Ultimate Trend Reached		2024	2027
Healthcare trend rate post-65 [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year		5.20%	6.25%
Ultimate trend rate		4.50%	4.50%
Year Ultimate Trend Reached		2023	2024

[1] The expected rate of return on plan assets is 6.75% for the calculation of the 2016 net periodic pension cost.

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Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Defined Benefit Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2016	$ 3,492
2017	3,594
2018	3,677
2019	3,814
2020	3,911
2021-2025	21,108
Supplemental Non-qualified Defined Benefit Retirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2016	216
2017	248
2018	246
2019	243
2020	240
2021-2025	1,583
Non-pension Defined Benefit Postretirement Healthcare Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2016	619
2017	618
2018	613
2019	607
2020	621
2021-2025	$ 2,841

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Employee Benefit Plans: Defined Contribution Plan (Details)	12 Months Ended
	Dec. 31, 2015
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Maximum Annual Contribution Per Employee, Percent	50.00%
Employers Matching Contribution, Annual Vesting Percentage	20.00%
Employee Vesting Period	5 years

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Related Party Transactions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) MW	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Related Party Transaction [Line Items]
Receivables - affiliates	$ 5,747	$ 5,350
Accounts payable - affiliates	$ 30,032	19,242
Utility Money Pool Interest Rate	1.45%
Notes Receivable (Payable), net - Utility Money Pool	$ 76,813	68,626
Net interest income (expense)	1,153	304	$ 505
Purchase of Excess Energy, Cheyenne Light [Member]
Related Party Transaction [Line Items]
Costs and Expenses	898	3,033	3,640
Parent [Member]
Related Party Transaction [Line Items]
Non-cash Dividend to Parent Company	$ 28,501	0	8,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	1.00%
Subsidiary of Common Parent [Member]
Related Party Transaction [Line Items]
Transfer from Investments	$ 28,501	0	8,000
Subsidiary of Common Parent [Member] | Purchase Of Natural Gas, Cheyenne Light [Member]
Related Party Transaction [Line Items]
Long-term Purchase Commitment, Period	40 years
Subsidiary of Common Parent [Member] | Coal, Purchased [Member]
Related Party Transaction [Line Items]
Costs and Expenses	$ 16,401	16,861	18,542
Subsidiary of Common Parent [Member] | Happy Jack Wind Purchase Power Agreeement [Member]
Related Party Transaction [Line Items]
Date of Contract Expiration	Sep. 03, 2028
Number of Megawatts Capacity Purchased | MW	15
Costs and Expenses	$ 1,578	1,959	1,886
Subsidiary of Common Parent [Member] | Silver Sage Wind Power Purchase Agreement [Member]
Related Party Transaction [Line Items]
Date of Contract Expiration	Sep. 30, 2029
Number of Megawatts Capacity Purchased | MW	20
Costs and Expenses	$ 2,739	3,200	3,207
Subsidiary of Common Parent [Member] | Allocated Costs From Related Parties [Member]
Related Party Transaction [Line Items]
Costs and Expenses	26,655	32,332	30,738
Subsidiary of Common Parent [Member] | Energy sold to Cheyenne Light [Member]
Related Party Transaction [Line Items]
Revenue	1,857	1,894	1,338
Subsidiary of Common Parent [Member] | Lease Agreements [Member]
Related Party Transaction [Line Items]
Revenue	$ 4,772	$ 4,102	$ 3,627

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 3,870	$ 4,234	$ 13,590
Interest and Income Taxes (Paid) Refunded, Cash Flow Information [Abstract]
Interest (net of amounts capitalized)	(21,913)	(19,573)	(19,174)
Income taxes	0	0	219
Subsidiary of Common Parent [Member]
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Non-cash decrease to money pool note receivable, net	(28,501)	0	(8,000)
Parent [Member]
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Non-cash Dividend to Parent Company	$ 28,501	$ 0	$ 8,000

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Commitment and Contingencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) MW	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Contractual Obligation, Fiscal Year Maturity [Abstract]
2015	$ 12,827
2016	12,824
2017	6,513
2018	6,408
2019	5,880
Thereafter	$ 17,641
M D U, Montana Dakota Utilities [Member] | Wygen I I I Generating Facility [Member]
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW	25
City Of Gillette [Member] | Wygen I I I Generating Facility [Member]
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW	23
Purchase Power Contract, MEAN, 10 M W [Member]
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 [Member] | Wygen I I I Generating Facility [Member]
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW	10
Purchase Power Contract, MEAN, 10 M W [Member] | Neil Simpson I I [Member]
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW	10
Thunder Creek - Gas Transport Capacity [Member]
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase of Fuel, Date of Contract Expiration	Oct. 31, 2019
Gas Gathering, Transportation, Marketing and Processing Costs	$ 633	$ 633	$ 633
PacifiCorp Purchase Power Agreement [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2023
Number of M W Capacity Purchased Under Long-term Contract | MW	50
Cost of Purchased Power	$ 13,990	13,943	13,026
PacifiCorp Transmission [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2023
Number of M W Capacity Purchased Under Long-term Contract | MW	50
Cost of Purchased Power	$ 1,213	$ 1,227	$ 1,384
Maximum [Member] | M D U, Montana Dakota Utilities [Member]
Sales Capacity Commitments [Abstract]
Number of MW Sold Under Long-Term Contract | MW	50

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Quarterly Financial information Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Selected Quarterly Financial Information [Abstract]
Operating Revenue	$ 67,432	$ 72,111	$ 68,038	$ 70,283	$ 68,751	$ 67,729	$ 60,741	$ 71,267	$ 277,864	$ 268,488	$ 254,027
Operating Income	21,825	23,456	21,143	21,490	18,779	19,007	13,782	17,546	87,914	69,114	62,344
Net income	$ 11,937	$ 12,287	$ 10,547	$ 10,403	$ 8,773	$ 9,916	$ 6,230	$ 8,643	$ 45,174	$ 33,562	$ 30,173

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Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Movement in Valuation Allowances and Reserves [Roll Forward]
Allowance for doubtful accounts, balance at beginning of year	$ 261	$ 220	$ 102
Additions charged to costs and expenses	602	699	754
Deductions charged to costs and expenses	(656)	(658)	(636)
Allowance for doubtful accounts, balance at end of year	$ 207	$ 261	$ 220