BLACK HILLS POWER INC - FORM 10-K

BLACK HILLS POWER INC - FORM 10-K - February 28, 2017

Attached files

Attached files

BLACK HILLS POWER INC Reports

file	filename
EX-32.2 - EXHIBIT 32.2 - BLACK HILLS POWER INC	bhpex-322cfo122016.htm
EX-32.1 - EXHIBIT 32.1 - BLACK HILLS POWER INC	bhpex-321ceo122016.htm
EX-31.2 - EXHIBIT 31.2 - BLACK HILLS POWER INC	bhpex-312cfo122016.htm
EX-31.1 - EXHIBIT 31.1 - BLACK HILLS POWER INC	bhpex-311ceo122016.htm

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, 2016



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ___________________ to __________________

	Commission File Number 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, 2017
Common stock, $1.00 par value	23,416,396 shares

Reduced Disclosure

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



TABLE OF CONTENTS

		Page

	GLOSSARY OF TERMS AND ABBREVIATIONS	3

ITEMS 1. and 2.	BUSINESS AND PROPERTIES	6

ITEM 1A.	RISK FACTORS	13

ITEM 1B.	UNRESOLVED STAFF COMMENTS	19

ITEM 3.	LEGAL PROCEEDINGS	19

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	20

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS	20

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	26

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	58

ITEM 9A.	CONTROLS AND PROCEDURES	58

ITEM 9B.	OTHER INFORMATION	58

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	59

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	60

ITEM 16.	FORM 10-K SUMMARY	62

	SIGNATURES	63

	INDEX TO EXHIBITS	64

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AC	Alternating Current
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by FASB
Baseload plant	A power generation facility used to meet some or all of a given region’s continuous energy demand, producing energy at a constant rate.
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation, the Parent of Black Hills Power, Inc.
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of our utility company as well as our utility affiliates
Black Hills Energy South Dakota Electric	Includes Black Hills Power’s operations in South Dakota, Wyoming and Montana
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of BHC (doing business as Black Hills Energy South Dakota)
Black Hills Service Company	Black Hills Service Company LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Energy Wyoming Electric	Includes Cheyenne Lights electric utility operations
CFTC	United States Commodity Futures Trading Commission
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of BHC
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility in Cheyenne, Wyoming, jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Prairie was placed into commercial operations on October 1, 2014.
City of Gillette	The City of Gillette, Wyoming, affiliate of the JPB.
CO₂	Carbon dioxide
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
CT	Combustion turbine
DC	Direct current
DSM	Demand Side Management
ECA	Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers.
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 Farm, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
IRS	Internal Revenue Service
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
NAV	Net Asset Value
NERC	North American Electric Reliability Corporation
NOL	Net operating loss
NOAA	National Oceanic and Atmospheric Administration
NOAA Climate Normals	This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.
NO_x	Nitrogen oxide
OPEB	Other Post-Employment Benefits
OSHA	Occupational Safety and Health Organization
PacifiCorp	PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway
Peak System Load	Peak system load represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.
PPA	Power Purchase Agreement
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
SO₂	Sulfur dioxide
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
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
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, is owned 80% by PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.

PART I

Forward-Looking Information

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

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

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

ITEMS 1 and 2. BUSINESS AND PROPERTIES

General

Black Hills Power (“the Company,” “we,” “us” and “our”) is a regulated electric utility incorporated in South Dakota, doing business as Black Hills Energy - 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, 2016, our ownership interests in electric generation plants were as follows:



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

_______________________


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


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


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

Distribution and Transmission. Our distribution and transmission system serves approximately 71,000 electric customers, with an electric transmission system of 1,260 miles of high voltage lines (greater than 69 kV) and 2,497 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. A majority of our retail electric revenues in 2016 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, 2016 was comprised of 36% commercial, 27% residential, 7% contract wholesale, 6% 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:



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.


•	An agreement from January 1, 2017 through December 31, 2021 under which we provide 50 MW of energy to Cargill during heavy and light load timing intervals.

Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide approximately 445 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. We generated approximately 57% of our energy requirements in 2016 and purchased approximately 43% which was supplied under the following contracts:


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


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


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


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

Since 1995, we have been a net producer of energy. Our 2016 winter peak system load was 389 MW and our 2016 summer peak system load was 438 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 Wyoming Electric in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

Shared Services Agreement - We have a shared services agreement with Wyoming Electric and Black Hills Wyoming whereby each entity charges for the use of assets and the performance of services being used by, or performed for, an affiliate entity. 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	Authorized 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		7.76%		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	N/A	N/A
FERC	10.8%	9.10%	43%/57%	2/2009	FERC Transmission Tariff	N/A

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

Some of the mechanisms we have in place include:


•	An approved 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 which 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. The first segment of this project connecting Teckla to Osage, Wyoming was energized on August 31, 2016. The second segment of the project is expected to be placed in service in the first half of 2017.

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, 2016, 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 by 2015.

•

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, 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.

Water Issues

Our facilities are subject to a variety of state and federal regulations governing existing and potential water/wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through NPDES and storm water permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA proposed effluent limitation guidelines and standards on June 7, 2013 and published the final rule on November 3, 2015. This rule will have an impact on the Wyodak Plant, requiring conversion to a dry method of handling coal ash and further restrictions of constituent concentrations in any off-site discharges. Our share of those costs is estimated at $1.8 million. The terms of this new regulation become effective at the next permit renewal, which will be in 2020.

Additionally, the EPA regulates surface water oil pollution through its oil pollution prevention regulations. All of our facilities subject to these regulations have compliant prevention plans in place.

Clean Air Act

Title IV of the Clean Air Act created an SO₂ allowance trading regime as part of the federal acid rain program. Each allowance gives the owner the right to emit one ton of SO₂.Certain facilities are allocated allowances based on their historical operating data. At the end of each year, each emitting unit must possess allowances sufficient to cover its emissions for the preceding year. Allowances may be traded, so affected units that expect to emit more SO₂ than their allocated allowances may purchase allowances on the open market.

Title IV applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen III, Cheyenne Prairie and Wyodak plants. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2046. We expect to integrate the cost of obtaining the required number of allowances needed for future projects into our overall financial analysis of such new projects.

Title V of the Clean Air Act requires that all of our generating facilities obtain operating permits. All of our existing facilities have received Title V permits, with the exception of Wygen III and Cheyenne Prairie Generating Station. Wygen III and Cheyenne Prairie Generating Station are allowed to operate under their construction permit until the Title V permit is issued by the state. The Title V application for Wygen III was submitted in January 2011, with the permit expected in 2017. The Cheyenne Prairie Generating Station Title V application was submitted in 2015, with the permit expected in 2017. All applications were filed in accordance with regulatory requirements.

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), with an effective date of April 16, 2012. This rule imposes requirements for mercury, acid gases, metals and other pollutants. As of April 16, 2016, all plants are in compliance.

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 2017 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.

Regional Haze

The Regional Haze Program is an EPA rule to improve visibility in our National Parks and Wilderness Areas. The state of Wyoming is currently developing its 2017 initial progress report under the EPA’s Regional Haze Program. Neil Simpson II is not currently a discussion item in that draft report, but could be in the future.

The Wyodak Power Plant is included in EPA’s January 30, 2014 Regional Haze Federal Implementation Plan, which includes significant additional NO_x controls by March 1, 2019. Our share of those costs is estimated at $20 million. The State of Wyoming and PacifiCorp filed requests for reconsideration and Administrative Stay with EPA and the United States Court of Appeals for the 10th Circuit. On September 9, 2014, the 10th Circuit stayed EPA’s NO_x requirement for Wyodak pending outcome of the appeal, which is anticipated to be settled by the summer of 2017.

Greenhouse Gas Regulations

The GHG Tailoring Rule, effective June 2010, 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, published October 2015, effectively prohibits new coal-fired units until carbon capture and sequestration becomes technically and economically feasible.

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 objective 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 demand side management. The U.S. Supreme Court entered an order staying the CPP in February 2016, pending appeal. 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. If the CPP is implemented in its current form, we cannot predict the terms of state plans and 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 and again in 2016, we met with staff of state air programs and public utility commissions on several occasions. We will continue to work closely with state regulatory staff as these plans develop.

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 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 2016, we reported 2015 GHG emissions from our 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 and/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. The results of the 2016 U.S. elections add uncertainty as to the final disposition of recently enacted and proposed EPA regulations, including the Clean Power Plan. We will continue to monitor new developments for potential impacts to our operations.

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 2016 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.

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.

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. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our direct and allocated borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

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

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

Operating electric generating facilities 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 our ability to operate our facilities;


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


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


•	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 service facilities and equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;


•	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.

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

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


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


•	Contractual restrictions upon the timing of scheduled outages;


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


•	The unavailability or increased cost of equipment;


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


•	Supply interruptions, work stoppages and labor disputes;


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


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


•	Weather interferences;


•	Availability and cost of fuel supplies;


•	Unexpected engineering, environmental or geological problems; and


•	Unanticipated cost overruns.

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

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

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

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

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

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

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

Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, 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. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt and to complete new financings on reasonable terms, or at all. A credit rating downgrade could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades.

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

A portion of our net income is attributable to sales of contract and off-system wholesale electricity. 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 may be subject to significant, unpredictable price fluctuations over relatively short periods of time.

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

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

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

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

Our business is located in areas that could be subject to seasonal natural disasters such as severe snow and ice storms, flooding and wildfires. These factors could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs associated with these 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 costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, and any failure to do so, could adversely affect our results of operations, financial position or liquidity.

Our business is subject to 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 and 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 operations and financial condition. Environmental compliance expenditures could be substantial in the future if the trend towards stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate continues.

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 or inadequate facility maintenance, distribution property losses and cyber-security risks.

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

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

Federal and state laws concerning 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 may result in more stringent emission limitations, which could have a material impact on our costs of operations. Various pending or final state and EPA regulations that will impact our facilities are also discussed in Item 1 of this Annual Report on Form 10-K under the caption “Environmental Regulations.”

The GHG Tailoring Rule, effective June 2010 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, published October 2015, effectively prohibits new coal-fired units until carbon capture and sequestration becomes technically and economically feasible.

On October 23, 2015, the EPA finalized the CPP to cut carbon emissions from existing electric generating units. The design of the CPP is to decrease existing coal-fired generation, increase the utilization of existing gas generation, increase renewable energy and demand side management. The rule, which does not propose to regulate individual emission sources, calls for each state to develop plans to meet the EPA-assigned statewide average emission rate target for that state 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. The U.S. Supreme Court entered an order staying the CPP in February 2016, pending appeal. 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. In 2015 and again in 2016, we met with the staff of 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.

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

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

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

Certain Federal laws, including the Migratory Bird Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation and wind projects, 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. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. 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.

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

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

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

We use and operate sophisticated information technology systems and network infrastructure. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees. Cyber attacks targeting our electronic control systems used at our generating facilities and for electric 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, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective due to the evolving nature and sophistication of cyber attacks. Despite our implementation of security measures and safeguards, all of our information technology systems are vulnerable to disability, failures or unauthorized access, including cyber attacks. If our information technology systems were to fail or be breached by a cyber attack or a computer virus and be unable to 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. Significant regulatory developments have, and likely will continue to, require changes to our current employee benefit plans and in our administrative and accounting processes, as well as changes to the cost of our plans, and the increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

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

Significant Events

Name Rebranding

We now operate with the trade name Black Hills Energy South Dakota. BHC rebranded all of its regulated utilities to operate under the name Black Hills Energy.

Regulatory Matters

During the first quarter of 2016, we commenced construction of the $54 million, 230-kV, 144 mile transmission line that will connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, Wyoming was energized on August 31, 2016. The second segment of the project is expected to be placed in service in the first half of 2017.

Non-GAAP Financial Measure

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

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

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



For the years ended December 31,	2016			Variance			2015			Variance			2014
	(in thousands)
Revenue	$	267,632		$	(10,232	)	$	277,864		$	9,376		$	268,488
Fuel and purchased power	75,026			(8,313		)	83,339			(10,637		)	93,976
Gross margin	192,606			(1,919		)	194,525			20,013			174,512

Operating expenses	107,026			415			106,611			1,213			105,398
Operating income	85,580			(2,334		)	87,914			18,800			69,114

Interest expense, net	(20,192		)	982			(21,174		)	(1,472		)	(19,702		)
Other income, net	2,278			1,244			1,034			372			662
Income tax expense	(22,528		)	72			(22,600		)	(6,088		)	(16,512		)
Net income	$	45,138		$	(36	)	$	45,174		$	11,612		$	33,562

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



Revenue
Customer Base	2016		Percentage Change		2015		Percentage Change		2014
Residential	$	72,084	(1	)%	$	72,659	4	%	$	69,712
Commercial	97,579		(3	)%	100,511		9	%	91,882
Industrial	33,409		—	%	33,336		17	%	28,451
Municipal	3,705		2	%	3,626		6	%	3,409
Total retail sales	206,777		(2	)%	210,132		9	%	193,454
Contract wholesale	17,037		(3	)%	17,537		(17	)%	21,206
Wholesale off-system	15,431		(34	)%	23,241		(17	)%	28,002
Total electric sales	239,245		(5	)%	250,910		3	%	242,662
Other revenue	28,387		5	%	26,954		4	%	25,826
Total revenue	$	267,632	(4	)%	$	277,864	3	%	$	268,488



MWh Sold
Customer Base	2016	Percentage Change		2015	Percentage Change		2014
Residential	520,798	—	%	521,828	(4	)%	542,008
Commercial	783,319	(1	)%	792,466	1	%	782,238
Industrial	429,912	—	%	429,140	7	%	399,648
Municipal	33,591	5	%	31,924	—	%	32,076
Total retail sales	1,767,620	—	%	1,775,358	1	%	1,755,970
Contract wholesale	246,630	(5	)%	260,893	(23	)%	340,871
Wholesale off-system ^(a)	597,695	(29	)%	837,120	4	%	808,257
Total electric sales	2,611,945	(9	)%	2,873,371	(1	)%	2,905,098
Losses and company use	155,370	(7	)%	167,332	(6	)%	177,577
Total energy	2,767,315	(9	)%	3,040,703	(1	)%	3,082,675

_________________________


(a)	Decrease in 2016 is driven by weaker market conditions

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	2016			2015		2014
Coal-fired plants	86.5	%	^(a)	91.1	%	91.8	%
Other plants	98.0	%		96.0	%	91.5	%	^(b)
Total availability	93.0	%		93.9	%	91.6	%

_________________________


(a)	2016 reflects planned and unplanned outages.


(b)	2014 reflects scheduled outages.



Resources	2016	Percentage Change		2015	Percentage Change		2014
MWh generated:
Coal	1,467,403	(5	)%	1,537,744	(3	)%	1,591,061
Gas	118,467	46	%	80,944	80	%	44,984
	1,585,870	(2	)%	1,618,688	(1	)%	1,636,045

MWh purchased	1,181,445	(17	)%	1,422,015	(2	)%	1,446,630
Total resources	2,767,315	(9	)%	3,040,703	(1	)%	3,082,675



Heating and Cooling Degree Days	2016		2015		2014
Actual
Heating degree days	6,402		6,521		7,373
Cooling degree days	646		577		481

Variance from 30-year average ^(a)
Heating degree days	(10	)%	(8	)%	4	%
Cooling degree days	(4	)%	(14	)%	(28	)%

______________


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

2016 Compared to 2015

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

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

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

Other income, net was comparable to the prior year.

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

2015 Compared to 2014

Gross margin increased 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 maintenance increased reflecting an increase in depreciation expense primarily due to a higher asset base and amortization of regulatory plant decommissioning costs.

Interest expense, net increased 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.

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, 2016:



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

Critical Accounting Estimates

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

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

Pension and Other Postretirement Benefits

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

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

The pension benefit cost for 2017 for our non-contributory funded pension plan is expected to be approximately $0.6 million compared to $1.5 million in 2016. The decrease in pension benefit cost is driven by the merging of three of Black Hills Corporation’s defined benefit pension plans into one, improved mortality rates and better than expected return on plan assets partially offset by a decrease in the discount rate.

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

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

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



Assumptions	Percentage Change	December 31, 2016 Increase/(Decrease) PBO/APBO ^(a)	2017 Increase/(Decrease) Expense - Pretax

Pension
Discount rate ^(b)	+/- 0.5	(3,658)/4,020	(854)/803
Expected return on assets	+/- 0.5	N/A	(266)/266

OPEB
Discount rate ^(b)	+/- 0.5	(211)/225	11/(12)
Expected return on assets	+/- 0.5	N/A	N/A
Health care cost trend rate ^(b)	+/- 1.0	125/(121)	5/(5)

__________________________


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


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

Regulation

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

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

Unbilled Revenue

Revenues attributable to energy delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense. Factors influencing the determination of unbilled revenues may include estimates of delivered sales volumes based on weather information and customer consumption trends.

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.

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

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



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS



	Page

Management’s Report on Internal Controls Over Financial Reporting	27

Report of Independent Registered Public Accounting Firm	28

Statements of Income for the three years ended December 31, 2016	29

Statements of Comprehensive Income (Loss) for the three years ended December 31, 2016	30

Balance Sheets as of December 31, 2016 and 2015	31

Statements of Cash Flows for the three years ended December 31, 2016	33

Statements of Common Stockholder’s Equity for the three years ended December 31, 2016	34

Notes to Financial Statements	35

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, 2016, 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, 2016.

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

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, 2016 and 2015, 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, 2016. 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) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 28, 2017

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME



Years ended December 31,	2016			2015			2014
	(in thousands)

Revenue	$	267,632		$	277,864		$	268,488

Operating expenses:
Fuel and purchased power	75,026			83,339			93,976
Operations and maintenance	66,384			68,088			70,356
Depreciation and amortization	34,030			32,552			29,100
Taxes - property	6,612			5,971			5,942
Total operating expenses	182,052			189,950			199,374

Operating income	85,580			87,914			69,114

Other income (expense):
Interest expense	(22,908		)	(22,337		)	(20,569		)
AFUDC - borrowed	1,140			506			248
Interest income	1,576			657			619
AFUDC - equity	2,165			918			519
Other expense	(185		)	(117		)	(105		)
Other income	298			233			248
Total other income (expense)	(17,914		)	(20,140		)	(19,040		)

Income before income taxes	67,666			67,774			50,074
Income tax expense	(22,528		)	(22,600		)	(16,512		)

Net income	$	45,138		$	45,174		$	33,562

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

BLACK HILLS POWER, INC.

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



Years ended December 31,	2016			2015		2014
	(in thousands)

Net income	$	45,138		$	45,174	$	33,562

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $27, $(36) and $189, respectively)	(50		)	68		(351		)
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(29), $(33) and $(16), respectively)	53			61		29
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $(22), $319 and $(364), respectively)	42			383		(300		)
Other comprehensive income (loss), net of tax	45			512		(622		)

Comprehensive income (loss), net of tax	$	45,183		$	45,686	$	32,940

See Note 7 for additional disclosure related to comprehensive income.

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

BLACK HILLS POWER, INC.

BALANCE SHEETS



As of December 31,	2016			2015
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	234		$	297
Receivables - customers, net	30,614			27,856
Receivables - affiliates	9,526			6,734
Other receivables, net	351			236
Money pool notes receivable	28,409			76,813
Materials, supplies and fuel	22,389			24,282
Regulatory assets, current	18,119			14,096
Other current assets	3,876			43,118
Total current assets	113,518			193,432

Investments	4,841			4,725

Property, plant and equipment	1,236,387			1,166,126
Less accumulated depreciation and amortization	(338,828		)	(326,074		)
Total property, plant and equipment, net	897,559			840,052

Other assets:
Regulatory assets, non-current	74,015			71,717
Other, non-current assets	3,816			152
Total other assets	77,831			71,869
TOTAL ASSETS	$	1,093,749		$	1,110,078

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

BLACK HILLS POWER, INC.

BALANCE SHEETS

(Continued)



As of December 31,	2016			2015
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	14,158		$	14,472
Accounts payable - affiliates	31,799			30,582
Accrued liabilities	37,436			69,454
Regulatory liabilities, current	84			—
Total current liabilities	83,477			114,508

Long-term debt	339,756			339,616

Deferred credits and other liabilities:
Deferred income tax liabilities, net	211,443			188,961
Regulatory liabilities, non-current	53,866			51,583
Benefit plan liabilities	19,544			20,033
Other, non-current liabilities	1,001			3,398
Total deferred credits and other liabilities	285,854			263,975

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	322,933			330,295
Accumulated other comprehensive loss	(1,262		)	(1,307		)
Total stockholder’s equity	384,662			391,979
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,093,749		$	1,110,078

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

BLACK HILLS POWER, INC.

STATEMENTS OF CASH FLOWS



Years ended December 31,	2016			2015			2014
	(in thousands)
Operating activities:
Net income	$	45,138		$	45,174		$	33,562
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	34,030			32,552			29,100
Deferred income taxes	20,690			7,690			16,518
AFUDC - equity	(2,165		)	(918		)	(519		)
Employee benefits	1,770			2,403			1,295
Other adjustments	391			232			(2,330		)
Change in operating assets and liabilities -
Accounts receivable and other current assets	(3,963		)	(3,223		)	(10,412		)
Accounts payable and other current liabilities	6,175			20,455			7,210
Contributions to defined benefit pension plan	(820		)	—			(1,696		)
Regulatory assets	(4,023		)	(3,839		)	(5,366		)
Regulatory liabilities	—			(2,479		)	2,479
Other operating activities	(8,339		)	(5,680		)	(6,624		)
Net cash provided by operating activities	88,884			92,367			63,217

Investing activities:
Property, plant and equipment additions	(84,750		)	(56,795		)	(82,826		)
Notes receivable from affiliate companies, net	(4,095		)	(36,687		)	(51,334		)
Other investing activities	(102		)	(128		)	(154		)
Net cash (used in) investing activities	(88,947		)	(93,610		)	(134,314		)

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	(63		)	(1,245		)	742

Cash and cash equivalents:
Beginning of year	297			1,542			800
End of year	$	234		$	297		$	1,542

See Note 10 for Supplemental Cash Flows information.

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

BLACK HILLS POWER, INC.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY



	2016			2015			2014
	(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	$	330,295		$	313,622		$	280,060
Net income	45,138			45,174			33,562
Non-cash dividend to Parent company	(52,500		)	(28,501		)	—
Balance end of year	$	322,933		$	330,295		$	313,622

Accumulated other comprehensive loss:
Balance beginning of year	$	(1,307	)	$	(1,819	)	$	(1,197	)
Other comprehensive (loss) income, net of tax	45			512			(622		)
Balance end of year	$	(1,262	)	$	(1,307	)	$	(1,819	)

Total stockholder’s equity	$	384,662		$	391,979		$	374,794

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

NOTES TO FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc., doing business as Black Hills Energy - South Dakota (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.

Revisions

Certain revisions have been made to prior years’ financial information to conform to the current year presentation.

We revised our presentation of cash and book overdrafts and certain cash transactions processed on behalf of affiliates. For accounts with the same financial institution where there is a banking arrangement that clears payments with balances in other bank accounts, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Cash collected or disbursed on behalf of affiliates is presented as Receivables - affiliates or Accounts Payable - affiliates. Prior year amounts were corrected to conform to the current year presentation, which decreased cash and cash equivalents by $7.3 million, $5.1 million and $1.5 million as of December 31, 2015, December 31, 2014 and December 31, 2013, respectively; increased Receivables - affiliates by $1.0 million, increased Accounts payable - affiliates by $0.6 million and decreased Accounts payable by $6.9 million as of December 31, 2015. It also decreased net cash flows provided by operations by $2.2 million and $3.6 million for the years ended December 31, 2015 and 2014 respectively. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the balance sheet as of December 31, 2015 and to the statements of cash flows for the years ended December 31, 2015 and 2014. There is no impact to the Statements of Income, Statements of Comprehensive Income (Loss) or Statements of Common Stockholder’s Equity for any period reported.

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)	2016		2015
Regulatory assets:
Unamortized loss on reacquired debt^(a)	8	$	1,815	$	2,096
Deferred taxes on AFUDC ^(b)	45	9,367		8,571
Employee benefit plans ^(c)	12	20,100		20,866
Deferred energy costs ^(a)	1	23,016		19,875
Deferred taxes on flow through accounting ^(a)	35	12,545		12,104
Decommissioning costs ^(b)	8	12,456		13,686
Other regulatory assets ^{(a) (d)}	2	12,835		8,615
Total regulatory assets		$	92,134	$	85,813

Regulatory liabilities:
Cost of removal for utility plant ^(a)	61	$	41,541	$	38,131
Employee benefit plans ^(c)	12	12,304		12,616
Other regulatory liabilities ^(c)	13	105		836
Total regulatory liabilities		$	53,950	$	51,583

____________________

(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 vegetation management expense of approximately $12.0 million and $5.0 million in 2016 and 2015, respectively.

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

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

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

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension 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.

Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. 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):



	2016			2015
Accounts receivable trade	$	16,972		$	15,268
Unbilled revenues	13,799			12,795
Allowance for doubtful accounts	(157		)	(207		)
Net accounts receivable trade	$	30,614		$	27,856

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. Sales and franchise taxes collected from our customers is 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 a true-up of the estimated unbilled revenue amounts are 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, 2016		December 31, 2015
Accrued receivables related to litigation expenses and settlements	$	—	$	39,050
Other (none of which is individually significant)	3,876		4,068
Total other current assets	$	3,876	$	43,118

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 2.2% in 2016, 2.3% in 2015 and 2.3% in 2014.

Accrued Liabilities

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



	December 31, 2016		December 31, 2015
Accrued employee compensation, benefits and withholdings	$	4,783	$	5,054
Accrued property taxes	5,522		4,962
Accrued payments related to litigation expenses and settlements	—		38,750
Accrued income taxes	17,069		13,031
Customer deposits and prepayments	2,825		2,216
Accrued interest and contract adjustment payments	4,614		4,600
Other (none of which is individually significant)	2,623		841
Total accrued liabilities	$	37,436	$	69,454

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 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.

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 Standards

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

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

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASC is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for us beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07

On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent). This ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and were applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU did not materially affect our financial statements and disclosures, but did change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

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. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of December 31, 2016, we presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of approximately $3.1 million in the Balance Sheets as of December 31, 2015.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We will adopt this standard for annual and interim reporting periods beginning after December 15, 2017 and are actively assessing all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity delivered in that period. Therefore, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff-based sales. The evaluation of other revenue streams is ongoing, including those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected.

(2) PROPERTY, PLANT AND EQUIPMENT

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



				2016				2015
				Weighted				Weighted
				Average				Average	Lives (in years)
	2016			Useful Life (in years)	2015			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	576,833		46	$	569,182		46	30	63
Transmission	147,398			48	117,708			48	40	70
Distribution	364,304			46	353,241			46	15	75
Plant acquisition adjustment ^(a)	4,870			32	4,870			32	32	32
General	88,114			23	88,939			22	3	65
Total plant-in-service	1,181,519				1,133,940
Construction work in progress	54,868				32,186
Total electric plant	1,236,387				1,166,126
Less accumulated depreciation and amortization	(338,828		)		(326,074		)
Electric plant net of accumulated depreciation and amortization	$	897,559			$	840,052

__________________


(a)	The plant acquisition adjustment is included in rate base and is being recovered with 14 years remaining.

(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, including 200 MW West to East and 200 MW from East to West. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.


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


•	We own 55 MW of Cheyenne Prairie, a 95 MW gas-fired power generation facility located in Cheyenne, Wyoming. Wyoming Electric owns the remaining 40 MW. 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, 2016, 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	$	113,611	$	256	$	55,878
Transmission Tie	$	19,978	$	13	$	5,793
Wygen III	$	138,261	$	1,806	$	17,635
Cheyenne Prairie	$	91,365	$	155	$	6,015

(4) LONG-TERM DEBT

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



	Maturity Date	Interest Rate		2016			2015
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				(94		)	(99		)
Series 94A Debt ^(a)	June 1, 2024	0.88	%	2,855			2,855
Unamortized Debt Expense				(3,005		)	(3,140		)
Long-term Debt				$	339,756		$	339,616

___________________


(a)	Variable interest rate at December 31, 2016.

Net deferred financing costs of approximately $3.0 million and $3.1 million were recorded on the accompanying Balance Sheets in long-term debt at December 31, 2016 and 2015, 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, 2016, 2015 and 2014, 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, 2016.

Long-term Debt Maturities

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



2017	$	—
2018	$	—
2019	$	—
2020	$	—
2021	$	—
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):



	2016				2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents ^(a)	$	234	$	234	$	297	$	297
Long-term debt ^(b)	$	339,756	$	410,466	$	339,616	$	404,864

_______________


(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.

(6) INCOME TAXES

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



	2016		2015		2014
Current	$	1,838	$	14,910	$	(6	)
Deferred	20,690		7,690		16,518
Total income tax expense	$	22,528	$	22,600	$	16,512

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



	2016			2015
Deferred tax assets:
Employee benefits	$	5,163		$	4,683
Regulatory liabilities	9,099			9,908
Other	1,815			16,186
Total deferred tax assets	16,077			30,777

Deferred tax liabilities:
Accelerated depreciation and other plant related differences ^(a)	(202,047		)	(196,237		)
Regulatory assets	(4,391		)	(4,236		)
Employee benefits	(3,075		)	(3,003		)
Deferred costs	(16,920		)	(14,765		)
Other	(1,087		)	(1,497		)
Total deferred tax liabilities	(227,520		)	(219,738		)

Net deferred tax assets (liabilities)	$	(211,443	)	$	(188,961	)

_________________________


(a)	To conform to the 2016 presentation of accelerated depreciation and other plant-related differences, 2015 is net of deferred tax liabilities of $8.6 million, previously presented as AFUDC Equity.

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



	2016		2015		2014
Federal statutory rate	35.0	%	35.0	%	35.0	%
Amortization of excess deferred and investment tax credits	(0.4	)	(0.1	)	(0.3	)
AFUDC Equity	(0.9	)	(0.6	)	(0.1	)
Flow through adjustments ^(a)	(0.9	)	(0.9	)	(1.9	)
Tax credits	(0.1	)	—		(0.2	)
Other	0.6		—		0.5
	33.3	%	33.4	%	33.0	%

_________________________


(a)	The flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs 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 tax expense.

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):



	2016			2015
Unrecognized tax benefits at January 1	$	2,264		$	1,623
Additions for prior year tax positions	1,194			888
Reductions for prior year tax positions	(682		)	(247		)
Settlements for prior year tax positions	(2,283		)	—
Unrecognized tax benefits at December 31	$	493		$	2,264

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.2 million. The reductions for prior year tax positions relate primarily to the IRS settlement as discussed below.

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

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, 2016 and 2015, the interest expense recognized was not material to our financial results.

In January 2016, we reached a settlement in principle with IRS Appeals with respect to research and development tax credits and deductions for tax years 2007 through 2009. The settlement resulted in a reduction of approximately $2.9 million excluding interest. Accumulated deferred income taxes were restored by approximately $0.6 million and approximately $2.3 million was reclassified to current taxes payable.

We do not anticipate total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations on or before December 31, 2017.

At December 31, 2016, 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):



	Location on the Statements of Income	Amounts Reclassified from AOCI
		2016			2015
Gains and Losses on cash flow hedges:
Interest rate swaps gain (loss)	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	(22		)	319
Total reclassification adjustments related to cash flow hedges, net of tax		$	42		$	383

Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	82		$	94
Income tax	Income tax benefit (expense)	(29		)	(33		)
Total reclassification adjustments related to defined benefit plans, net of tax		$	53		$	61

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, 2015	$	(635	)	$	(672	)	$	(1,307	)
Other comprehensive income (loss)	42			3			45
As of December 31, 2016	$	(593	)	$	(669	)	$	(1,262	)


	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	)

(8) EMPLOYEE BENEFIT PLANS

Funded Status of Benefit Plans

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.

Black Hills Retirement Plan assets are held in a Master Trust. Due to the plan merger on December 31, 2016, reporting beginning in 2017 will no longer represent an undivided interest in the Master Trust. Our Board of Directors has 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 rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2016, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 44% to 52% equity and other return-seeking assets, and 48% to 56% fixed-income liability-hedging assets, and the expected rate of return from the associated asset categories.

The expected long-term rate of return for investments was 6.75% for the 2016 and 2015 plan years. 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:



	2016		2015
Equity securities	28	%	26	%
Real estate	5		5
Fixed income funds	57		59
Cash and cash equivalents	2		1
Hedge funds	8		9
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.

Defined Benefit Postretirement Healthcare Plan

Employees who are participants in our Postretirement Healthcare Plan (“Healthcare Plan”) and who retire on or after attaining minimum age and years of service requirements are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. 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 Master 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):



	2016		2015
Defined Benefit Plans
Defined Benefit Pension Plan	$	820	$	—
Defined Benefit Postretirement Healthcare Plan	$	279	$	267
Supplemental Non-qualified Defined Benefit Plan	$	221	$	211

Defined Contribution Plans
Company Retirement Contribution	$	851	$	811
Matching Contributions	$	1,400	$	1,423

While we do not have required contributions, we expect to make approximately $1.3 million in contributions to our Defined Benefit Pension Plan in 2017.

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	2016
	Level 1		Level 2		Level 3		NAV ^(a)	Total Fair Value
Common Collective Trust - Cash and Cash Equivalents	$	—	$	980	$	—	—	$	980
Common Collective Trust - Equity	—		14,927		—		—	14,927
Common Collective Trust - Fixed Income	—		31,003		—		—	31,003
Common Collective Trust - Real Estate	—		347		—		2,300	2,647
Hedge Funds	—		—		—		4,331	4,331
Total investments measured at fair value	$	—	$	47,257	$	—	6,631	$	53,888



Defined Benefit Pension Plan	2015
	Level 1		Level 2		Level 3		NAV ^(a)	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

________________________

(a)

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

Common Collective Trust - Cash and Cash Equivalents: This category is comprised of the AXA Equitable General Fixed Income Fund and 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 placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates 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 values 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 values 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 - Trust Funds: The Plan holds units of various Common Collective Trust Funds offered through a private placement. The units are valued daily using the NAV. The NAVs are based on the fair value of each fund’s underlying investments. Level 1 assets are priced using quotes for trades occurring in active markets for the identical asset. Level 2 assets are priced using observable inputs for the asset (for example, interest rates and yield curves observable at commonly quoted intervals, volatilities, prepayment speeds, loss severities, credit risks, and default rates) or inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). 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.

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.

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						Defined Benefit Postretirement Healthcare Plan
	2016			2015			2016			2015			2016			2015
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	65,959		$	71,178		$	3,426		$	3,599		$	6,208		$	6,038
Service cost	606			797			—			—			204			233
Interest cost	2,499			2,956			122			142			187			214
Actuarial loss (gain)	455			(5,650		)	78			(104		)	(446		)	27
Benefits paid	(3,215		)	(3,284		)	(222		)	(211		)	(420		)	(387		)
Plan participants transfer to affiliate ^(a)	(1,331		)	(38		)	—			—			(31		)	(7		)
Medicare Part D adjustment	—			—			—			—			—			(30		)
Plan participants’ contributions	—			—			—			—			141			120
Projected benefit obligation at end of year	$	64,973		$	65,959		$	3,404		$	3,426		$	5,843		$	6,208

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						Defined Benefit Postretirement Healthcare Plan
	2016			2015			2016			2015			2016			2015
Beginning fair value of plan assets	$	54,723		$	59,098		$	—		$	—		$	—		$	—
Investment income (loss)	2,485			(1,057		)	—			—			—			—
Benefits paid	(3,215		)	(3,284		)	(221		)	(211		)	(420		)	(387		)
Participant contributions	—			—			—			—			279			120
Employer contributions	820			—			221			211			141			267
Plan participants transfer to affiliate^(a)	(925		)	(34		)	—			—			—			—
Ending fair value of plan assets	$	53,888		$	54,723		$	—		$	—		$	—		$	—

__________________


(a)	Change is related to the merger of the three defined benefit pension plans maintained by Black Hills Corporation into one plan as of December 31, 2016.

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



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plan
	2016			2015			2016			2015			2016			2015
Regulatory asset (liability)	$	18,974		$	19,816		$	—		$	—		$	(2,087	)	$	(1,946	)
Current liability	$	—		$	—		$	(247	)	$	(216	)	$	(541	)	$	(619	)
Non-current liability	$	(11,085	)	$	(11,236	)	$	(3,157	)	$	(3,210	)	$	(5,302	)	$	(5,587	)

Accumulated Benefit Obligation (in thousands)



	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2016		2015		2016		2015		2016		2015
Accumulated benefit obligation	$	61,585	$	62,240	$	3,404	$	3,426	$	5,843	$	6,208

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
	2016			2015			2014			2016		2015		2014		2016			2015			2014
Service cost	$	606		$	797		$	704		$	—	$	—	$	—	$	204		$	233		$	222
Interest cost	2,499			2,956			2,991			122		142		146		187			214			241
Expected return on assets	(3,632		)	(3,935		)	(3,702		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	43			43			43			—		—		—		(337		)	(336		)	(335		)
Recognized net actuarial loss (gain)	1,995			2,196			940			82		93		45		—			—			—
Net periodic expense	$	1,511		$	2,057		$	976		$	204	$	235	$	191	$	54		$	111		$	128

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
	2016		2015		2016		2015		2016		2015
Net loss	$	—	$	—	$	669	$	672	$	—	$	—
Prior service cost	—		—		—		—		—		—
Total accumulated other comprehensive income (loss)	$	—	$	—	$	669	$	672	$	—	$	—

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 2017 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)	$	799	$	51	$	—
Prior service cost	28		—		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2017	$	827	$	51	$	(218	)

Assumptions



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2016		2015		2014		2016		2015		2014		2016		2015		2014
Weighted-average assumptions used to determine benefit obligations:
Discount rate	4.27	%	4.63	%	4.25	%	4.12	%	4.29	%	3.98	%	3.84	%	4.03	%	3.70	%
Rate of increase in compensation levels	3.47	%	3.57	%	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^(a)	4.63	%	4.25	%	5.10	%	4.29	%	3.98	%	4.68	%	4.03	%	3.70	%	4.45	%
Expected long-term rate of return on assets ^(b)	6.75	%	6.75	%	6.75	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.57	%	3.86	%	3.86	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________


(a)	The estimated discount rate for the merged Black Hills Corporation’s Retirement Plan is 4.27% for the calculation of the 2017 net periodic pension costs.


(b)	The expected rate of return on plan assets is 6.75% for the calculation of the 2017 net periodic pension cost.

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



	2016		2015
Healthcare trend rate pre-65
Trend for next year	6.10	%	6.35	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2024		2024

Healthcare trend rate post-65
Trend for next year	5.10	%	5.20	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2023		2023

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	$	5		$	125
1% decrease	$	(5	)	$	(121	)

Beginning in 2016, the Company changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. The new method 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 offset 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. We accounted for this change as a change in estimate beginning in the first quarter of 2016. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on this Form 10-K for additional details.

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



	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Defined Benefit Postretirement Healthcare Plan
2017	$	3,946	$	247	$	541
2018	$	3,543	$	243	$	562
2019	$	3,669	$	241	$	577
2020	$	3,766	$	237	$	585
2021	$	3,883	$	330	$	570
2022-2026	$	20,663	$	1,519	$	2,456

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

We recorded non-cash dividends to our Parent of approximately $53 million and $29 million in 2016 and 2015 respectively, and decreased the utility money pool note receivable, net for approximately $53 million and $29 million in 2016 and 2015, respectively.

Receivables and Payables

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



	2016		2015
Receivable - affiliates	$	9,526	$	6,734
Accounts payable - affiliates	$	31,799	$	30,582

Money Pool Notes Receivable and Notes Payable

We have a Utility Money Pool Agreement (the Agreement) with BHC, Wyoming Electric 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 external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one month LIBOR rate plus 1.0%.

The cost of borrowing under the Utility Money Pool was 2.21% at December 31, 2016.

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

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



	2016		2015		2014
Interest income	$	1,047	$	1,153	$	304

Interest expense allocation from Parent

BHC provides daily liquidity and cash management on behalf of all its subsidiaries. For the years ended December 31, 2016, 2015 and 2014, we were allocated $1.9 million, $2.1 million and $0.5 million, respectively, of interest expense allocations from BHC.

Other Balances and Transactions

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


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


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


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

Related-party Gas Transportation Service Agreement

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

Related-party Revenue and Purchases

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



	2016		2015		2014
	(in thousands)
Revenues:
Energy sold to Wyoming Electric	$	2,440	$	1,857	$	1,894
Rent from electric properties	$	5,046	$	4,772	$	4,102

Purchases:
Purchase of coal from WRDC	$	16,227	$	16,401	$	16,861
Purchase of excess energy from Wyoming Electric	$	252	$	898	$	3,033
Purchase of renewable wind energy from Wyoming Electric - Happy Jack	$	1,918	$	1,578	$	1,959
Purchase of renewable wind energy from Wyoming Electric - Silver Sage	$	3,300	$	2,739	$	3,200
Corporate support services from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	25,748	$	26,655	$	32,332

(10) SUPPLEMENTAL CASH FLOW INFORMATION



Years ended December 31,	2016			2015			2014
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	5,521		$	3,870		$	4,234
Non-cash decrease to money pool note receivable, net	$	(52,500	)	$	(28,501	)	$	—
Non-cash dividend to Parent company	$	52,500		$	28,501		$	—

Supplemental disclosure of cash flow information:
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(21,320	)	$	(21,913	)	$	(19,573	)
Income taxes	$	—		$	—		$	—

(11) COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

We have the following power purchase and transmission services agreements, not including related party agreements, as of December 31, 2016 (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 on October 31, 2019.

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



Contract	Contract Type	2016		2015		2014
PacifiCorp	Electric capacity and energy	$	12,221	$	13,990	$	13,943
PacifiCorp	Transmission access	$	1,428	$	1,213	$	1,227
Thunder Creek	Gas transport capacity	$	633	$	633	$	633

Future Contractual Obligations

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



2017	$	13,091
2018	$	6,388
2019	$	6,388
2020	$	6,388
2021	$	5,755
Thereafter	$	11,510

Long-Term Power Sales Agreements

We have the following power sales agreements as of December 31, 2016:


•	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.

Effective January 1, 2017, we have an energy sales agreement with Cargill through December 31, 2021 to supply 50 MW of energy during heavy and light load timing intervals.

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, hazardous air pollutants, 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 2046.

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 following the closure certification date.

(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
2016
Operating revenues	$	68,642	$	62,019	$	66,728	$	70,243
Operating income	$	20,780	$	18,936	$	22,410	$	23,454
Net income	$	11,186	$	9,806	$	12,010	$	12,136

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


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, 2016. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

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

Changes in Internal Control over Financial Reporting

Management’s Report on Internal Control over Financial Reporting is presented on Page 27 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	2016		2015
Audit Fees	$	216	$	360
Tax Fees	23		16
Audit-related fees	—		—
Total	$	239	$	376

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.

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.



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, 2016, 2015 and 2014



		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:
2016	$	207	$	644	$	(694	)	$	157
2015	$	261	$	602	$	(656	)	$	207
2014	$	220	$	699	$	(658	)	$	261


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.


ITEM 16.	FORM 10-K SUMMARY

None.

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 28, 2017

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



/s/ DAVID R. EMERY	Director and	February 28, 2017
David R. Emery, Chairman and	Principal Executive Officer
Chief Executive Officer

/s/ RICHARD W. KINZLEY	Director and	February 28, 2017
Richard W. Kinzley, Senior Vice President	Principal Financial and
and Chief Financial Officer	Accounting Officer

/s/ LINDEN R. EVANS	Director	February 28, 2017
Linden R. Evans

/s/ BRIAN G. IVERSON	Director	February 28, 2017
Brian G. Iverson

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.

Notes receivable (payable), net