UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form ~~10-K/A~~

~~Amendment No. 1~~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, ~~2011~~2014



¨	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~~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~~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~~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~~Registrant’s classes of common stock, as of the latest practicable date.



Class	Outstanding at ~~February 29, 2012~~January 31, 2015
Common stock, $1.00 par value	23,416,396 shares

Reduced Disclosure

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



TABLE OF CONTENTS

		Page

	GLOSSARY OF TERMS AND ABBREVIATIONS	3

ITEMS 1. and 2.	BUSINESS AND PROPERTIES	5

ITEM 1A.	RISK FACTORS	11

ITEM 1B.	UNRESOLVED STAFF COMMENTS	18

ITEM 3.	LEGAL PROCEEDINGS	18

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	18

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS	19

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	25

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	57

ITEM 9A.	CONTROLS AND PROCEDURES	57

ITEM 9B.	OTHER INFORMATION	57

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	58

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	59

	SIGNATURES	61

	INDEX TO EXHIBITS	62

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ASU	Accounting Standards Update as issued by FASB
Baseload plant	A power generation facility used to meet some or all of a given region’s continuous energy demand, producing energy at a constant rate.
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation, the Parent of Black Hills Power, Inc.
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Service Company	Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Wyoming	Black Hills Wyoming, LLC, an indirect, wholly-owned subsidiary of Black Hills Electric Generation, Inc., a subsidiary of Black Hills Non-regulated Holdings
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of BHC
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility in Cheyenne, Wyoming, jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Prairie was placed into commercial operations on October 1, 2014.
City of Gillette	The City of Gillette, Wyoming, affiliate of the JPB.
Cooling degree day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
CPCN	Certificate of Public Convenience and Necessity
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 Farms, 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
NERC	North American Electric Reliability Corporation
NOL	Net operating loss
NO_x	Nitrogen oxide
OSHA	Occupational Safety and Health Organization
PacifiCorp	PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway
Peak System Load	Peak system load represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.
PPA	Power Purchase Agreement
RMSA	Retirement Medical Savings Account
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
SO₂	Sulfur dioxide
S&P	Standard & Poor’s Rating Services
Spinning Reserve	Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission outages.
TCA	Transmission Cost Adjustment - adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
Thunder Creek	Thunder Creek Gas Services, LLC
TIPA	Tax Increase Prevention Act of 2014
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, LLC

PART I

Forward-Looking Information

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

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

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

ITEMS 1 and 2. BUSINESS AND PROPERTIES

General

Black Hills Power (“the Company,” “we,” “us” and “our”) is a regulated electric utility incorporated in South Dakota and serving customers in South Dakota, Wyoming and Montana. We began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation. 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, 2014, our ownership interests in electric generation plants were as follows:



Unit ⁽¹⁾	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Wygen III⁽²⁾	Coal	Gillette, WY	52%	57.2	2010
Neil Simpson II	Coal	Gillette, WY	100%	90.0	1995
Wyodak ⁽³⁾	Coal	Gillette, WY	20%	72.4	1978
Cheyenne Prairie⁽⁴⁾	Gas	Gillette, WY	58%	55.0	2014
Neil Simpson CT	Gas	Gillette, WY	100%	40.0	2000
Lange CT	Gas	Rapid City, SD	100%	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, SD	100%	10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, SD	100%	80.0	1977-1979
				444.6

_______________________

(1)

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. These plants are primarily replaced by our share of Cheyenne Prairie. On October 1, 2014, we transferred the remaining net book value of these plants to a regulatory asset in accordance with an order granted by the SDPUC.


(2)	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.


(3)	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.


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

Distribution and Transmission. Our distribution and transmission system serves approximately 70,000 electric customers, with an electric transmission system of 1,182 miles of high voltage lines (greater than 69 kV) and 2,474 miles of lower voltage lines. In addition, we jointly own 44 miles of high voltage lines with Basin Electric. Our service territory covers areas with a strong and stable economic base including western South Dakota, northeastern Wyoming and southeastern Montana. Approximately 90% of our retail electric revenues in 2014 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, 2014 was comprised of 34% commercial, 26% residential, 8% contract wholesale, 10% wholesale off-system, 11% industrial and 11% 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.

~~EXPLANATORY NOTE~~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:



2015-2017	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.

A PPA with MEAN whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III through May 2015.

Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide approximately 445 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. We generated approximately 53% of our energy requirements in 2014 and purchased approximately 47% which was supplied under the following contracts:

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

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

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

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

Since 1995, we have been a net producer of energy. Our 2014 winter peak system load was 389 MW and our 2014 summer peak system load was 410 MW. None of our generation is restricted by hours of operation, thereby providing us the ability to generate power to meet demand whenever necessary and economically feasible. We have historically optimized the utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market, and through short-term sales contracts primarily in the WECC and MAPP regions. Our 220 MW of low-cost, coal-fired resources supports most of our native load requirements and positions us for wholesale off-system sales.

Operating Agreements

Related-party Gas Transportation Service Agreement - On October 1, 2014 we entered into a gas transportation service agreement with Cheyenne Light in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

Shared Services Agreement- We have a shared services agreement with Cheyenne Light and Black Hills Wyoming whereby each entity charges for the use of assets and the performance of services being used by, or performed for, an affiliate entity. The revenues and expenses associated with these assets are included in rate base.

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

Regulations

Rate Regulation

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



State	Authorized Rate of Return on Equity	Authorized Return on Rate Base	Capital Structure Debt/Equity	Effective Date	Other Tariffs, Riders and Rate Matters	Percentage of Off-System Sale Profits Shared with Customers
SD	Global Settlement	7.93%	Global Settlement	6/2013	ECA,TCA, Energy Efficiency Cost Recovery/ DSM	65%
SD		8.16%		6/2011	Environmental Improvement Cost Recovery Adjustment Tariff	N/A
WY	9.9%	8.13%	46.7%/53.3%	10/2014	ECA	65%
MT	15.0%	11.73%	47%/53%	1983	ECA	N/A
FERC	10.8%	9.12%	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, Montana 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.

In September 2013, the SDPUC approved Cheyenne Prairie’s construction financing rider effective April 1, 2013 which allowed for recovery of construction financing costs from customers during the construction period in lieu of traditional AFUDC. The rider allowed us to earn and collect a rate of return during the construction period on the total project cost that relates to South Dakota customers. This rider was similar to the rider approved by WPSC effective November 1, 2012 which allowed us to earn and collect a rate of return during the construction period on approximately 60% of the total project cost that relates to Wyoming customers. These riders increased gross margin by approximately $1.8 million in 2014.

In South Dakota, Wyoming and Montana, we have cost adjustment mechanisms that allow us to pass to our customers the prudently-incurred cost of fuel and purchased power.

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 65% of off-system power marketing operating income. The modification also adjusts the methodology to directly assign renewable resources and firm purchases to the customer load. Wyoming has a similar Fuel and Purchased Power Cost Adjustment.

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

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

Rate Matters

Cheyenne Prairie

On October 1, 2014, Cheyenne Prairie, a jointly owned 132 MW generating facility located in Cheyenne, Wyoming, of which we own 55MW, was placed into commercial operations. Cheyenne Prairie was constructed on time and on budget. Rate activity in 2014 related to Cheyenne Prairie was:

South Dakota

On March 31, 2014, we filed a rate request with the SDPUC to increase annual revenue by $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt. We implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Hearings were held in January 2015, and the SDPUC’s final decision is expected in the first quarter of 2015.

Wyoming

On August 21, 2014, the WPSC approved rate case settlement agreements authorizing an increase of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt. The WPSC’s decision provides 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.

Power Plant Suspension/Retirements

In order to comply with environmental regulations, including the EPA Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants regulations, on March 21, 2014, we retired the Ben French, Neil Simpson I, and Osage coal-fired power plants. On October 1, 2014, we transferred the remaining net book value of these plants to a regulatory asset in accordance with an order granted by the SDPUC.

Transmission

On July 22, 2014, we filed a CPCN with the WPSC 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. On June 30, 2014, we filed an application with the SDPUC, for a permit to construct the South Dakota portion of this line. We have received approval from the SDPUC for a permit to construct the line and approval by the WPSC is anticipated in the second quarter of 2015.

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, 2014, 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, we filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. However, in March 2013, the Montana Legislature adopted legislation that excluded us from all renewable portfolio standard requirements under Senate Bill 164, primarily due to the very low number of customers we have in Montana and the relatively high cost of meeting the renewable requirements.

Wyoming. Wyoming currently has no renewable energy portfolio standard.

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

Environmental Regulations

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

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

On February 16, 2012, the EPA published in the Federal Register the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), which became effective on April 16, 2012. This rule imposes requirements for mercury, acid gases, metals and other pollutants. Affected units have a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain very limited circumstances. The current state air permit for Wygen III provides mercury emission limits and monitoring requirements with which we are in compliance. Neil Simpson II and Wygen III have been utilized for internal study and review of mercury emission control technology and have mercury monitors in place. Neil Simpson II, Wygen III and the Wyodak plant are expected to be in compliance with MATS by the compliance deadline, without incurring significant costs.

On June 3, 2010, the EPA promulgated the GHG Tailoring Rule, implementing regulations of GHG for permitting purposes. This rule will impact us in the event of a major modification at an existing facility or in the event we establish a new major source of GHG emissions, as defined by EPA regulations. Upon renewal of operating permits for existing permitted facilities monitoring and reporting requirements will be implemented. Since there are no emission standards or caps currently in place, we cannot predict how this requirement will impact our existing facilities upon permit renewal. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emission control practices and technologies.

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 2015 and, as proposed, will be applicable to Cheyenne Prairie and eventually all the combustion turbines in our fleet. Among other things, the rule seeks to eliminate startup exemptions and clearly define overhauls for impact on the EPA’s New Source Review regulations, with the intention of eventually bringing all units under the applicability of this rule. The primary impact is expected to be on our older existing units, which will eventually be required to meet tighter NO_x emission limitations.

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

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

Regulatory Accounting

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

New Accounting Pronouncements

See Note 1 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2014 or pending adoption.

ITEM 1A. RISK FACTORS

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

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

Our electricity operations are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. Our returns could be threatened by plant outages, machinery failures, increased purchased power costs, acts of nature, acts of terrorism or other unexpected events over which we have no control that could cause our costs to increase and operating margins to decline. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

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

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

Operating electric generating facilities involves risks, including:

Operational limitations imposed by environmental and other regulatory requirements;

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

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

Inability to recruit and retain skilled technical labor;

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

Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages. For example, as described in more detail under “Legal Proceedings,” a fire investigator concluded that a forest and grassland fire in the western Black Hills of Wyoming and South Dakota in 2012 was caused by the failure of a transmission structure owned, operated and maintained by us, and claims have been made against us related to the fire;

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

Labor relations.

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

A future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our non-regulated customers. If late payments and uncollectible accounts increase, our results of operations, financial position and liquidity could be adversely impacted.

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

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

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

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

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

Contract restrictions upon the timing of scheduled outages;

Cost of supplying or securing replacement power during scheduled and unscheduled outages;

The unavailability or increased cost of equipment;

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

Supply interruptions, work stoppages and labor disputes;

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

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

Weather interferences;

Unexpected engineering, environmental or geological problems; and

Unanticipated cost overruns.

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

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

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

Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events. These events could disrupt or impair our operations, create additional costs and cause substantial loss to us.

Inherent in our electricity transmission and distribution activities are a variety of hazards and operating risks, such as fires, releases of hazardous materials, explosions and mechanical problems that could cause substantial adverse financial impacts. These events could result in injury or loss of human life, significant damage to property or natural resources (including public parks), environmental pollution, impairment of our operations, and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. Particularly for our transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the damages resulting from any such events could be significant.

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

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

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

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

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

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

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

Our ability to obtain insurance, as well as the cost of such insurance, could be affected by developments affecting insurance businesses, international, national, state or local events and company-specific events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject, including but not limited to environmental hazards, wildfire-related liability, distribution property losses and cyber 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 seek a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations, and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.

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

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

On May 20, 2011, with amendments on December 21, 2012, the EPA’s Industrial and Commercial Boiler regulations became effective, which provide for hazardous air pollutant-related emission limits and monitoring requirements. The compliance deadline for this rule was March 21, 2014. Engineering evaluations were completed and confirmed the significant impact on our Neil Simpson I, Osage and Ben French facilities. These units were permanently retired on March 21, 2014. We have requested recovery for the remaining net book values of these plants and prudent decommissioning costs of these units. The WPSC granted approval of our request in the Wyoming rate case approved in August 2014, and our request with the SDPUC is pending with a decision expected in March 2015.

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. Affected units have a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain circumstances. It is expected that all of our plants will be in compliance by the initial 2015 deadline, with the primary impacts to Neil Simpson II, Wygen III and the Wyodak Plant including installation of mercury sorbent injection systems, along with additional monitoring and testing requirements.

The GHG Tailoring Rule, implementing regulations of GHG for permitting purposes, became effective in June 2010. This rule will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Upon renewal of operating permits for existing facilities monitoring and reporting requirements will be implemented. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could impose more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units was expected to be final by the end of 2014. As proposed, it effectively prohibits new coal fired units until carbon capture and sequestration becomes technically and economically feasible. It also effectively prohibits simple cycle natural gas combustion turbines from generating more than one-third of their capacity, averaged over a three year period. The rule was not finalized in 2014 and may be delayed to June 2015 to coincide with issuance of the Clean Power Plan regulations.

On June 2, 2014, the EPA proposed the Clean Power Plan to cut carbon emissions from existing electric generating units. The design of the Clean Power Plan is to decrease existing coal-fired generation, and increase the utilization of existing gas generation, increase renewable energy, and demand side management. This rule could have a significant impact on our coal and natural gas generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. We are currently evaluating this proposal, but cannot predict the impact on operations as this rule is expected to be final in June 2015, and state plans are expected to be due at the earliest in June 2016, with extensions possible to 2017 and 2018.

Due to uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, cash flows or financial position. The impact of GHG legislation or regulation on our company will depend upon many factors, including but not limited to the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level, and the availability of technologies to control or reduce GHG emissions. If a “cap and trade” structure is implemented, the impact will depend on the degree to which offsets are allowed, the allocation of emission allowances to specific sources, and the effect of carbon regulation on natural gas and coal prices.

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. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.

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

Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty structures for regulatory violations. The FERC, EPA, OSHA and SEC may impose significant and sometimes punitive civil and criminal penalties to enforce compliance requirements relative to our business. In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the NERC, with similar penalty authority for violations. If a serious regulatory violation did occur, and penalties were imposed by FERC or another federal agency, this action could have a material adverse effect on our operations and/or our financial results.

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

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

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

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

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems and physical assets, could be direct targets of, or indirectly affected by, such activities. Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power and by delaying their development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets, and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.

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

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

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

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

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

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

We have a defined benefit pension plan that covers a substantial portion of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and changes in governmental regulations.

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

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.


ITEM 3.	LEGAL PROCEEDINGS

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

PART II


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

MATTERS

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


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

Non-GAAP Financial Measure

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

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

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



For the years ended December 31,	2014			Variance			2013			Variance			2012
	(in thousands)
Revenue	$	268,488		$	14,461		$	254,027		$	10,718		$	243,309
Fuel and purchased power	93,976			4,539			89,437			1,918			87,519
Gross margin	174,512			9,922			164,590			8,800			155,790

Operating expenses	105,398			3,152			102,246			4,037			98,209
Operating income	69,114			6,770			62,344			4,763			57,581

Interest expense, net	(19,702		)	(411		)	(19,291		)	(2,226		)	(17,065		)
Other income	662			123			539			(340		)	879
Income tax expense	(16,512		)	(3,093		)	(13,419		)	890			(14,309		)
Net income	$	33,562		$	3,389		$	30,173		$	3,087		$	27,086

The following tables provide certain electric utility operating statistics for the years ended December 31 ~~2011~~(dollars in thousands):



Revenue
Customer Base	2014		Percentage Change		2013		Percentage Change		2012
Residential	$	69,712	8	%	$	64,566	10	%	$	58,523
Commercial	91,882		14	%	80,289		9	%	73,858
Industrial	28,451		3	%	27,705		8	%	25,656
Municipal	3,409		—	%	3,421		5	%	3,268
Total retail sales	193,454		10	%	175,981		9	%	161,305
Contract wholesale	21,206		(3	)%	21,956		8	%	20,290
Wholesale off-system	28,002		(5	)%	29,580		(7	)%	31,905
Total electric sales	242,662		7	%	227,517		7	%	213,500
Other revenue	25,826		(3	)%	26,510		(11	)%	29,809
Total revenue	$	268,488	6	%	$	254,027	4	%	$	243,309



Megawatt-Hours Sold
Customer Base	2014	Percentage Change		2013	Percentage Change		2012
Residential	542,008	(2	)%	555,204	4	%	532,342
Commercial	782,238	7	%	730,701	—	%	731,785
Industrial	399,648	(1	)%	404,009	(1	)%	407,301
Municipal	32,076	(7	)%	34,344	(4	)%	35,933
Total retail sales	1,755,970	2	%	1,724,258	1	%	1,707,361
Contract wholesale	340,871	(5	)%	357,193	5	%	340,036
Wholesale off-system	808,257	(19	)%	1,002,847	(21	)%	1,263,457
Total electric sales	2,905,098	(6	)%	3,084,298	(7	)%	3,310,854
Losses and company use	177,577	12	%	158,845	(20	)%	197,355
Total energy	3,082,675	(5	)%	3,243,143	(8	)%	3,508,209

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	2014	2013	2012
Coal-fired plants ^(a)	91.8%	96.3%	91.9%
Other plants ^(a)	91.5%	96.8%	98.5%
Total availability ^(a)	91.6%	96.5%	94.5%

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(a)	Decrease due to scheduling of outages in the current year compared to the prior year



Resources	2014	Percentage Change		2013	Percentage Change		2012
MWh generated:
Coal	1,591,061	(10	)%	1,768,483	(2	)%	1,796,936
Gas	44,984	35	%	33,374	1	%	33,183
	1,636,045	(9	)%	1,801,857	(2	)%	1,830,119

MWh purchased	1,446,630	—	%	1,441,286	(14	)%	1,678,090
Total resources	3,082,675	(5	)%	3,243,143	(8	)%	3,508,209



Heating and Cooling Degree Days	2014		2013		2012
Actual
Heating degree days	7,373		7,582		6,206
Cooling degree days	481		724		937

Variance from 30-year average
Heating degree days	4	%	9	%	(13	)%
Cooling degree days	(28	)%	8	%	47	%

2014 Compared to 2013

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

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

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

Other income, net was comparable to the prior year.

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

2013 Compared to 2012

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $5.5 million and $2.7 million from the Cheyenne Prairie construction financing rider.

Operations and maintenance increased primarily due to an increase in vegetation management, plant overhaul and maintenance costs, and employee compensation and benefit costs.

Interest expense, net increased primarily due to lower interest income received on affiliate borrowings and increased allocations of corporate debt costs.

Other income, net was comparable to the prior year.

Income tax expense: The effective tax rate decreased in 2013 primarily due to the result of the retroactive reinstatement of research and development credits.

Financing Plans and Activity

On September 30, 2014, we repaid in full $12 million in principal on the 5.35% Pollution Control Revenue Bonds originally due to mature on October 1, 2024. In addition, we paid the accrued interest on these bonds of $0.3 million.

On October 1, 2014, in a private placement transaction to provide permanent financing for Cheyenne Prairie, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044.

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. As of December 31, 2014, our credit ratings for our Senior Secured Debt, as assessed by the three major credit rating agencies, were as follows:



Rating Agency	Rating
S&P	A-
Moody’s^(a)	A1
Fitch ^(b)	A

______________________


(a)	On January 30, 2014, Moody’s upgraded the BHP credit rating to A1 with a stable outlook.


(b)	On June 13, 2014, Fitch upgraded the BHP credit rating to A with a Stable outlook.

Significant Events

Cheyenne Prairie

On October 1, 2014, Cheyenne Prairie, a jointly owned natural gas-fired generating facility was placed into commercial operation. We own 55 MW and Cheyenne Light owns 40 MW of the facility’s combined-cycle unit. Our cost was approximately $90 million for our share of the combined-cycle unit. Cheyenne Prairie was constructed on time and on budget. Construction financing costs were recovered through construction financing riders. New rates were implemented on October 1, 2014 for our customers in Wyoming, as previously approved by the WPSC, and interim rates were implemented on October 1, 2014 for customers in South Dakota.

Bond Issuance

On October 1, 2014, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044 to provide permanent financing for Cheyenne Prairie. Proceeds from the bond sale also funded the September 30, 2014 early redemption of our 5.35% $12 million pollution control revenue bonds, originally due October 1, 2024.

Regulatory Matters

On August 21, 2014, the WPSC approved rate case settlement agreements associated with Cheyenne Prairie authorizing an increase of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt.

On July 22, 2014, we filed a CPCN with the ~~Securities~~WPSC to construct 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, for the Wyoming portion of this line. On June 30, 2014, we filed an application with the SDPUC, for a permit to construct the South Dakota portion of this line. We have received approval from the SDPUC to construct the line and ~~Exchange Commission~~approval by the WPSC is anticipated in the second quarter of 2015.

On March 31, 2014, we filed a rate request with the SDPUC for an annual revenue increase of $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25%, and a capital structure of approximately 53.3% equity and 46.7% debt. Interim rates were implemented on October 1, 2014 when Cheyenne Prairie commenced commercial operations. A final ruling from the SDPUC is expected in the first quarter of 2015.

On March ~~12, 2012 (the “Original Filing”).~~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. These plants are primarily replaced by our share of Cheyenne Prairie. On October 1, 2014, we transferred the remaining net book value of these plants to a regulatory asset in accordance with an order granted by the SDPUC.

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 ~~filing this Amendment No. 1 on Form 10-K/A (“Amendment 1”) for~~required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the ~~sole purpose~~information available. These estimates and assumptions affect the reported amounts of ~~inserting~~assets and liabilities at the date of the ~~Report~~financial statements and the reported amounts of ~~Independent Registered Public~~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 ~~Firm (March 12, 2012), which was unintentionally omitted from the Original Filing (which only stated March 2012). For convenience, the full Report~~Policies” of ~~Independent Registered Accounting Firm is included~~our Notes to Financial Statements in this ~~Amendment 1.~~ Annual Report on Form 10-K.

~~Except~~

Pension and Other Postretirement Benefits

The Company, as described ~~above, no other changes have been made~~in Note 8 to the ~~Original Filing,~~Financial Statements in this Annual Report on Form 10-K, has a defined benefit pension plan and post-retirement healthcare plan. As of December 31, 2012, a Master Trust was established for the investment of assets of the defined benefit pension plans. Each participating retirement plan has an undivided interest in the Master Trust.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; rate of future increases in compensation levels; and healthcare cost projections. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

The discount rate used to determine annual defined benefit pension costs accruals will be 4.25% in 2015 and the discount rate used in 2014 was 5.1%. In selecting the discount rate, we consider cash flow durations for each plan’s liabilities on high credit fixed income yield curves for comparable durations. We do not pre-fund our non-qualified plans or postretirement healthcare plans.

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 liability method of accounting for income taxes. Under this ~~Amendment 1 does not otherwise amend, update~~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 ~~change~~permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities.

It is the Parent’s policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. Another acceptable accounting method and an exception to this general policy is to apply the deferral method whereby the credit is amortized as a reduction of income tax expense over the useful lives of the related property which gave rise to the credits.

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

Contingencies

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



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS



	Page

Management’s Report on Internal Controls Over Financial Reporting	26

Report of Independent Registered Public Accounting Firm	27

Statements of Income for the three years ended December 31, 2014	28

Statements of Comprehensive Income (Loss) for the three years ended December 31, 2014	29

Balance Sheets as of December 31, 2014 and 2013	30

Statements of Cash Flows for the three years ended December 31, 2014	32

Statements of Common Stockholder’s Equity for the three years ended December 31, 2014	33

Notes to Financial Statements	34

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, 2014, 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, 2014.

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"~~“Company”) as of December 31, ~~2011~~2014 and ~~2010~~2013, and the related statements of income, ~~statements of~~ comprehensive income (loss), common ~~stockholder's~~stockholder’s equity and cash flows for each of the three years in the period ended December 31, ~~2011~~2014. 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~~Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the ~~Company's~~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, ~~2011~~2014 and ~~2010~~2013, and the results of ~~its~~their operations and ~~its~~their cash flows for each of the three years in the period ended December 31, ~~2011~~2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement ~~schedule,~~schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 26, 2015

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME



Years ended December 31,	2014			2013			2012
	(in thousands)

Revenue	$	268,488		$	254,027		$	243,309

Operating expenses:
Fuel and purchased power	93,976			89,437			87,519
Operations and maintenance	70,356			68,857			65,835
Depreciation and amortization	29,100			28,125			27,621
Taxes - property	5,942			5,264			4,753
Total operating expenses	199,374			191,683			185,728

Operating income	69,114			62,344			57,581

Other income (expense):
Interest expense	(20,569		)	(19,725		)	(17,602		)
AFUDC - borrowed	248			186			161
Interest income	619			248			376
AFUDC - equity	519			368			325
Other expense	(105		)	(196		)	—
Other income	248			367			554
Total other income (expense)	(19,040		)	(18,752		)	(16,186		)

Income from continuing operations before income taxes	50,074			43,592			41,395
Income tax expense	(16,512		)	(13,419		)	(14,309		)

Net income	$	33,562		$	30,173		$	27,086

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,	2014			2013		2012
	(in thousands)

Net income	$	33,562		$	30,173	$	27,086

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $189, ($73) and $93, respectively)	(351		)	139		(171		)
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(16), $(23) and $0)	29			43		—

Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $(364), $(23) and $(23), respectively)	(300		)	41		41

Other comprehensive income (loss), net of tax	(622		)	223		(130		)

Comprehensive income (loss), net of tax	$	32,940		$	30,396	$	26,956

~~March 12,~~ 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,	2014			2013
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	6,620		$	2,259
Receivables - customers, net	34,684			25,799
Receivables - affiliates	5,350			4,934
Other receivables, net	259			579
Money pool notes receivable	68,626			17,292
Materials, supplies and fuel	20,965			23,278
Deferred income tax assets, net, current	13,661			2,170
Regulatory assets, current	10,257			4,891
Other current assets	4,954			4,933
Total current assets	165,376			86,135

Investments	4,584			4,431

Property, plant and equipment	1,115,061			1,095,884
Less accumulated depreciation and amortization	(309,767		)	(334,174		)
Total property, plant and equipment, net	805,294			761,710

Other assets:
Regulatory assets, non-current	68,427			40,373
Other, non-current assets	11,708			8,524
Total other assets	80,135			48,897
TOTAL ASSETS	$	1,055,389		$	901,173

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,	2014			2013
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	30,543		$	26,144
Accounts payable - affiliates	19,242			21,082
Accrued liabilities	16,415			14,966
Regulatory liabilities, current	3,073			161
Total current liabilities	69,273			62,353

Long-term debt	342,752			269,948

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	193,042			167,309
Regulatory liabilities, non-current	51,916			43,357
Benefit plan liabilities	20,981			12,105
Other, non-current liabilities	2,631			4,247
Total deferred credits and other liabilities	268,570			227,018

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	313,622			280,060
Accumulated other comprehensive loss	(1,819		)	(1,197		)
Total stockholder’s equity	374,794			341,854
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,055,389		$	901,173

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,	2014			2013			2012
	(in thousands)
Operating activities:
Net income	$	33,562		$	30,173		$	27,086
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	29,100			28,125			27,621
Deferred income taxes	16,518			13,582			24,628
AFUDC - equity	(519		)	(368		)	(325		)
Employee benefits	1,295			3,094			3,828
Other adjustments	(2,330		)	1,400			1,187
Change in operating assets and liabilities -
Accounts receivable and other current assets	(13,299		)	(5,175		)	2,916
Accounts payable and other current liabilities	10,829			1,180			(903		)
Contributions to defined benefit pension plan	(1,696		)	(2,299		)	(6,835		)
Other operating activities	(6,624		)	(3,149		)	(6,625		)
Net cash provided by (used in) operating activities	66,836			66,563			72,578

Investing activities:
Property, plant and equipment additions	(82,826		)	(74,390		)	(40,415		)
Notes receivable from affiliate companies, net	(51,334		)	6,353			(25,152		)
Other investing activities	(154		)	(72		)	469
Net cash provided by (used in) investing activities	(134,314		)	(68,109		)	(65,098		)

Financing activities:
Long-term debt - repayments	(12,200		)	—			(6,487		)
Long-term debt - issuance	85,000			—			—
Other financing activities	(961		)	—			—
Net cash provided by (used in) financing activities	71,839			—			(6,487		)

Net change in cash and cash equivalents	4,361			(1,546		)	993

Cash and cash equivalents:
Beginning of year	2,259			3,805			2,812
End of year	$	6,620		$	2,259		$	3,805

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



	2014			2013			2012
	(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	$	280,060		$	257,887		$	274,785
Net income	33,562			30,173			27,086
Non-cash dividend to Parent company	—			(8,000		)	(43,984		)
Balance end of year	$	313,622		$	280,060		$	257,887

Accumulated other comprehensive loss:
Balance beginning of year	$	(1,197	)	$	(1,420	)	$	(1,290	)
Other comprehensive (loss) income, net of tax	(622		)	223			(130		)
Balance end of year	$	(1,819	)	$	(1,197	)	$	(1,420	)

Total stockholder’s equity	$	374,794		$	341,854		$	319,458

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

NOTES TO FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

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

Basis of Presentation

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

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash Equivalents

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

Regulatory Accounting

Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC.

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

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

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



	Maximum Recovery Period (in years)	2014		2013
Regulatory assets:
Unamortized loss on reacquired debt^(a)	10	$	2,377	$	2,257
AFUDC^(b)	45	8,365		8,327
Employee benefit plans^{(c) (d)}	12	24,418		15,233
Deferred energy costs^(a)	1	14,696		7,711
Flow through accounting^(a)	35	11,171		9,723
Decommissioning costs	10	11,786		—
Other regulatory assets^(a)	2	5,871		2,013
Total regulatory assets		$	78,684	$	45,264

Regulatory liabilities:
Cost of removal for utility plant^(a)	44	$	35,510	$	30,467
Employee benefit plans^{(c) (d)}	12	14,538		10,177
Other regulatory liabilities^(c)	13	4,941		2,874
Total regulatory liabilities		$	54,989	$	43,518

____________________

(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)	Increases are due to a reduction in the discount rate and a change in the mortality tables used in employee benefit plan estimates.

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

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

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

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plans and post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income. In addition, this regulatory 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 amounts have been grossed-up to reflect the revenue requirement associated with a rate regulated environment.

Deferred Energy Costs - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our utility customers that are either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission.

Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. A regulatory asset established to reflect the future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit consistent with the flow-through method with respect to costs considered repairs for tax purposes and are capitalized for book purposes.

Decommissioning Costs - We received approval for regulatory treatment on the remaining net book values of our decommissioned coal plants in 2014. These balances were in Property, Plant and Equipment in 2013.

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):



	2014			2013
Accounts receivable trade	$	24,946		$	16,300
Unbilled revenues	9,999			9,719
Allowance for doubtful accounts	(261		)	(220		)
Net accounts receivable trade	$	34,684		$	25,799

Revenue Recognition

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

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

Materials, Supplies and Fuel

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

Deferred Financing Costs

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

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is AFUDC, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.3% in 2014, 2.1% in 2013 and 2.2% in 2012.

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 classify deferred tax assets and liabilities into current and non-current amounts based on the classification of the related assets and liabilities.

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. With respect to changes in tax law, the TIPA, which was enacted December 19, 2014, did not have a material impact on the amounts provided for income taxes including our ability to realize deferred tax assets. Certain provisions of the TIPA involving primarily the extension of 50% bonus depreciation resulted in the generation of an NOL for federal income tax purposes in 2014.

Recently Adopted Accounting Principles and Legislation

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforwards Exists, ASU 2013-11

In July 2013, the FASB issued an amendment to accounting for income taxes which provides guidance on financial statement presentation of an unrecognized tax benefit when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. The objective in issuing this amendment is to eliminate diversity in practice resulting from a lack of guidance on this topic in current GAAP. Under the amendment, an entity must present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward except under certain conditions. The amendment is effective for fiscal years beginning after December 15, 2013 and interim periods within those years, and should be applied to all unrecognized tax benefits that exist as of the effective date. The adoption of this standard did not have any impact on our financial position, results of operations or cash flows.

Final Tangible Property Regulations, Treasury Decision 9636

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

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

Recently Issued Accounting Pronouncements

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are currently assessing the impact, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.

~~PART IV~~(2) PROPERTY, PLANT AND EQUIPMENT

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



				2014				2013
				Weighted				Weighted
				Average				Average	Lives (in years)
	2014			Useful Life (in years)	2013			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	567,936		48	$	512,444		51	40	65
Transmission	115,949			46	115,149			46	40	60
Distribution	336,652			39	315,971			39	16	45
Plant acquisition adjustment ^(a)	4,870			32	4,870			32	32	32
General	79,738			22	70,228			22	5	33
Total plant-in-service	1,105,145				1,018,662
Construction work in progress	9,916				77,222
Total electric plant	1,115,061				1,095,884
Less accumulated depreciation and amortization	(309,767		)		(334,174		)
Electric plant net of accumulated depreciation and amortization	$	805,294			$	761,710

__________________


(a)	The plant acquisition adjustment is included in rate base and is being recovered with 16 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 - 200 MW West to East and 200 MW from East to West. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

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

We own 55 MW of Cheyenne Prairie, a 95 MW gas-fired power generation facility located in Cheyenne, Wyoming. Cheyenne Light owns the remaining 40 MW. This facility was placed into commercial operations on October 1, 2014. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

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

As of December 31, 2014, 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	$	110,123	$	1,201	$	53,816
Transmission Tie	$	19,648	$	—	$	4,976
Wygen III	$	136,220	$	29	$	13,811
Cheyenne Prairie	$	89,617	$	—	$	657

(4) LONG-TERM DEBT

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



	Maturity Date	Interest Rate		2014			2013
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			—
Unamortized discount, First Mortgage Bonds due 2039				(103		)	(107		)
Pollution control revenue bonds due 2024	October 1, 2024	5.35	%	—			12,200
Series 94A Debt^(a)	June 1, 2024	0.75	%	2,855			2,855
Long-term debt				$	342,752		$	269,948

___________________


(a)	Variable interest rate at December 31, 2014.

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

Net deferred financing costs of approximately $3.3 million and $2.8 million were recorded on the accompanying Balance Sheets in Other, non-current assets at December 31, 2014 and 2013, 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 $0.2 million for the years ended December 31, 2014, 2013 and 2012, 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, 2014.

Long-term Debt Maturities

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



2015	$	—
2016	$	—
2017	$	—
2018	$	—
2019	$	—
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):



	2014				2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents ^(a)	$	6,620	$	6,620	$	2,259	$	2,259
Long-term debt, including current maturities ^(b)	$	342,752	$	430,497	$	269,948	$	317,531

_______________


(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 to the Financial Statements.

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):



	2014			2013			2012
Current	$	(6	)	$	(163	)	$	(10,319	)
Deferred	16,518			13,582			24,628
Total income tax expense	$	16,512		$	13,419		$	14,309

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



	2014			2013
Deferred tax assets:
Employee benefits	$	4,995		$	4,567
Net operating loss	14,794			4,197
Regulatory liabilities	10,824			6,398
Other	2,864			2,193
Total deferred tax assets	33,477			17,355

Deferred tax liabilities:
Accelerated depreciation and other plant related differences	(184,478		)	(161,990		)
AFUDC	(8,365		)	(8,190		)
Regulatory assets	(3,910		)	(3,540		)
Employee benefits	(3,723		)	(3,467		)
Deferred costs	(11,324		)	(4,240		)
Other	(1,058		)	(1,067		)
Total deferred tax liabilities	(212,858		)	(182,494		)

Net deferred tax assets (liabilities)	$	(179,381	)	$	(165,139	)

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



	2014		2013		2012
Federal statutory rate	35.0	%	35.0	%	35.0	%
Amortization of excess deferred and investment tax credits	(0.3	)	(0.3	)	(0.3	)
Equity AFUDC	(0.1	)	—		(0.1	)
Flow through adjustments ^(a)	(1.9	)	(2.5	)	(3.5	)
Prior year deferred adjustment ^(b)	—		—		3.6
Tax credits	(0.2	)	(0.8	)	—
Other	0.5		(0.6	)	(0.1	)
	33.0	%	30.8	%	34.6	%

_________________________

(a)

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


(b)	The adjustment was a non-recurring unfavorable true-up attributable to property related deferred income taxes. The removal of the impact of such an adjustment is more appropriately reflective of the effective rate on a recurring basis.

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):



	2014			2013
Unrecognized tax benefits at January 1	$	2,443		$	2,078
Additions for prior year tax positions	434			—
Reductions for prior year tax positions	(1,254		)	(155		)
Additions for current year tax positions	—			520
Unrecognized tax benefits at December 31	$	1,623		$	2,443

The reductions for prior year tax positions relate to the reversal through otherwise allowed tax depreciation. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.5 million.

It is our continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 2014 and 2013, the interest expense recognized was not material to our financial results.

We file income tax returns in the United States federal jurisdictions as a member of the BHC consolidated group. We do not anticipate that total unrecognized tax benefits will significantly change due to settlement of any audits or the expiration of statutes of limitations prior to December 31, 2015.

At December 31, 2014, we have federal NOL carry forward of $42 million, a portion of which will expire in 2031. Ultimate usage of this NOL depends upon our ability to generate future taxable income, which is expected to occur within the prescribed carryforward period.

(7) COMPREHENSIVE INCOME

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



	Derivatives Designated as Cash Flow Hedges	Amounts Reclassified from AOCI
		2014			2013
Gains and Losses on cash flow hedges
Interest rate swaps gain (loss)	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	(364		)	(23		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	(300	)	$	41

Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	45		$	66
Income tax	Income tax benefit (expense)	(16		)	(23		)
Total reclassification adjustments related to defined benefit plans, net of tax		$	29		$	43

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, 2013	$	(719	)	$	(478	)	$	(1,197	)
Other comprehensive income (loss)	(299		)	(323		)	(622		)
As of December 31, 2014	$	(1,018	)	$	(801	)	$	(1,819	)


	Interest Rate Swaps			Employee Benefit Plans			Total

As of December 31, 2012	$	(760	)	$	(660	)	$	(1,420	)
Other comprehensive income (loss)	41			182			223
As of December 31, 2013	$	(719	)	$	(478	)	$	(1,197	)

(8) EMPLOYEE BENEFIT PLANS

Funded Status of Benefit Plans

The funded status of the postretirement benefit plan is required to be recognized in the statement of financial position. The funded status for the pension plan is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. The measurement date of the plans is December 31, our year-end balance sheet date. As of December 31, 2014, the unfunded status of our Defined Benefit Pension Plan was $12 million, the unfunded status of our Supplemental Non-qualified Defined Benefit Plans was $3.6 million and the unfunded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $6.0 million.

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

Defined Benefit Pension Plan

We have a defined benefit pension plan (“Pension Plan”) covering certain eligible employees. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan has been frozen to new employees and certain employees who did not meet age and service based criteria.

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

The BHC Board of Directors have approved the Plans’ investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plans’ beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Plans’ benefit payment obligations. The Pension Plans’ assets consist primarily of equity, fixed income and hedged investments. The expected long-term rate of return for investments was 6.75% and 7.25% for the 2014 and 2013 plan years, respectively. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements.

Pension Plan Assets

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



	2014		2013
Equity securities	27	%	26	%
Real estate	5		4
Fixed income funds	58		58
Cash and cash equivalents	2		1
Hedge funds	8		11
Total	100	%	100	%

Supplemental Non-qualified Defined Benefit Retirement Plans

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

Supplemental Plan Assets

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

Non-pension Defined Benefit Postretirement Healthcare Plan

Employees who are participants in our Non-Pension Postretirement Healthcare Plan (“Healthcare Plan”) and who retire on or after attaining minimum age and years of service requirements are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Healthcare Plan periodically. We are not pre-funding our retiree medical plan. We have determined that the Healthcare Plan’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

Plan Assets

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

Plan Contributions and Estimated Cash Flows

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



	2014		2013
Defined Benefit Plans
Defined Benefit Pension Plan	$	1,696	$	2,299
Non-pension Defined Benefit Postretirement Healthcare Plan	$	399	$	578
Supplemental Non-qualified Defined Benefit Plan	$	217	$	217

Defined Contribution Plans
Company Retirement Contribution	$	638	$	421
Matching Contributions	$	1,377	$	1,301

Although we are not required we expect to contribute approximately $1.7 million to our Defined Benefit Pension Plan in 2015.

Fair Value Measurements

As required by accounting standards for fair value measurements, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis as of December 31 (in thousands):



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



Defined Benefit Pension Plan	2013
	Level 1		Level 2		Level 3		Total Fair Value
AXA Equitable General Fixed Income	$	—	$	213	$	—	$	213
Common Collective Trust - Cash and Cash Equivalents	—		252		—		252
Common Collective Trust - Equity	—		14,833		—		14,833
Common Collective Trust - Fixed Income	—		32,742		—		32,742
Common Collective Trust - Real Estate	—		682		1,718		2,400
Hedge Funds	—		—		5,965		5,965
Total investments measured at fair value	$	—	$	48,722	$	7,683	$	56,405

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

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

Common Collective Trust - Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments, and rely on these reports for pricing the units of the fund. Certain of the funds’ assets contain participant withdrawal policy and, therefore, are categorized as Level 3. The funds without participant withdrawal limitations are categorized as Level 2.

Hedge Funds: Hedge funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. Generally, shares may be redeemed at the end of each quarter, after a lockup period of one-year, with a 65 day notice and are limited to a percentage of total net asset value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds. The Plan’s investment in the hedge fund is categorized as Level 3.

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



	2014
Balance, beginning of period	$	7,683
Transfers	—
Purchase	98
Unrealized gain (loss)	461
Realized gain (loss)	76
Settlements	(1,461		)
Balance, end of period	$	6,857

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



	Fair Value at		Valuation	Level 3	Range (Weighted)
	December 31, 2014		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate ^(a)	$	1,918	Market Approach	Redemption Restriction	N/A
Hedge Funds ^(b)	$	4,939	Market Approach	Redemption Restriction	N/A

_____________

(a)

The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. As part of the Trustee's valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with the professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the Trustee along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The fund does contain a participant withdrawal policy.

(b)

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

Plan Reconciliations

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

Benefit Obligations



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2014			2013			2014			2013			2014			2013
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	60,223		$	69,820		$	3,131		$	3,427		$	5,850		$	6,766
Service cost	704			852			—			—			222			216
Interest cost	2,991			2,969			146			133			241			239
Actuarial loss (gain)	11,879			(7,818		)	540			(212		)	115			(459		)
Amendments ^(a)	—			—			—			—			—			(342		)
Benefits paid	(4,452		)	(4,850		)	(218		)	(217		)	(488		)	(1,045		)
Asset transfer (to) from affiliate	(167		)	(750		)	—			—			24			(75		)
Medicare Part D adjustment	—			—			—			—			(15		)	82
Plan participants’ contributions	—			—			—			—			89			468
Projected benefit obligation at end of year	$	71,178		$	60,223		$	3,599		$	3,131		$	6,038		$	5,850

_______________


(a)	Reflects Board of Directors approval of increase to Company’s contribution to RMSA account.

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



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2014			2013			2014		2013		2014		2013
Beginning market value of plan assets	$	56,405		$	53,465		$	—	$	—	$	—	$	—
Investment income	5,462			6,070			—		—		—		—
Benefits paid	(4,452		)	(4,850		)	—		—		—		—
Employer contributions	1,696			2,299			—		—		—		—
Asset transfer to affiliate	(13		)	(579		)	—		—		—		—
Ending market value of plan assets	$	59,098		$	56,405		$	—	$	—	$	—	$	—

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
	2014			2013			2014			2013			2014			2013
Regulatory asset (liability)	$	22,717		$	13,735		$	—		$	—		$	2,306		$	2,781
Current liability	$	—		$	—		$	(217	)	$	(216	)	$	(519	)	$	(491	)
Non-current liability	$	(12,080	)	$	(3,818	)	$	(3,382	)	$	(2,915	)	$	(5,519	)	$	(5,372	)

Accumulated Benefit Obligation (in thousands)



	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2014		2013		2014		2013		2014		2013
Accumulated benefit obligation	$	65,699	$	55,283	$	3,599	$	3,131	$	6,038	$	5,850

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
	2014			2013			2012			2014		2013		2012		2014			2013			2012
Service cost	$	704		$	852		$	765		$	—	$	—	$	—	$	222		$	216		$	214
Interest cost	2,991			2,969			2,969			146		133		104		241			239			343
Expected return on assets	(3,702		)	(3,764		)	(3,139		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	43			43			57			—		—		—		(335		)	(278		)	(278		)
Amortization of transition obligation	—			2,609			—			—		—		—		—			—			—
Recognized net actuarial loss (gain)	940			—			2,599			45		66		55		—			9			139
Net periodic expense	$	976		$	2,709		$	3,251		$	191	$	199	$	159	$	128		$	186		$	418

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
	2014		2013		2014			2013			2014		2013
Net loss	$	—	$	—	$	(801	)	$	(479	)	$	—	$	—
Prior service cost	—		—		—			—			—		—
Total accumulated other comprehensive income (loss)	$	—	$	—	$	(801	)	$	(479	)	$	—	$	—

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 2015 are as follows (in thousands):



	Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
Net gain (loss)	$	1,428	$	61	$	—
Prior service cost	27		—		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2015	$	1,455	$	61	$	(218	)

Assumptions



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2014		2013		2012		2014		2013		2012		2014		2013		2012
Weighted-average assumptions used to determine benefit obligations:
Discount rate	4.25	%	5.10	%	4.35	%	3.98	%	4.68	%	4.25	%	3.70	%	4.45	%	3.65	%
Rate of increase in compensation levels	3.86	%	3.86	%	3.91	%	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	5.10	%	4.35	%	4.65	%	4.68	%	3.88	%	4.70	%	4.45	%	3.65	%	4.35	%
Expected long-term rate of return on assets ^(a)	6.75	%	7.25	%	7.25	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.86	%	3.91	%	3.67	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________


(a)	The expected rate of return on plan assets is 6.75% for the calculation of the 2015 net periodic pension cost.

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



	2014		2013
Healthcare trend rate pre-65
Trend for next year	7.50	%	7.50	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027

Healthcare trend rate post-65
Trend for next year	6.25	%	6.25	%
Ultimate trend rate	4.50	%	4.50	%
Year Ultimate Trend Reached	2024		2026

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	$	8		$	195
1% decrease	$	(8	)	$	(178	)

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



	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
2015	$	3,303	$	217	$	519
2016	$	3,330	$	217	$	509
2017	$	3,455	$	248	$	502
2018	$	3,575	$	246	$	569
2019	$	3,749	$	244	$	610
2020-2024	$	21,109	$	1,547	$	2,847

Defined Contribution Plan

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

(9) RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

In 2014, no non-cash dividends were made to our Parent. We recorded a non-cash dividend to our Parent for approximately $8 million in 2013 and decreased the utility money pool note receivable, net for approximately $8 million, in 2013.

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):



	2014		2013
Receivable - affiliates	$	5,350	$	4,934
Accounts payable - affiliates	$	19,242	$	21,082

Money Pool Notes Receivable and Notes Payable

We have a Utility Money Pool Agreement (the Agreement) with BHC, Cheyenne Light and Black Hills Utility Holdings. Under the agreement, we may borrow from BHC however the Agreement restricts us from loaning funds to BHC or to any of BHCs’ non-utility subsidiaries. The Agreement does not restrict us from making dividends to BHC. Borrowings under the agreement bear interest at the weighted average daily cost of our parent company’s credit facility borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one month LIBOR rate plus 1.0%.

The cost of borrowing under the Utility Money Pool was 1.36% at December 31, 2014.

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

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



	2014		2013		2012
Net interest income (expense)	$	304	$	505	$	617

Other Balances and Transactions

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

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

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

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

Related-party Gas Transportation Service Agreement

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

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



	2014		2013		2012
	(in thousands)
Revenues:
Energy sold to Cheyenne Light	$	1,894	$	1,338	$	2,372
Rent from electric properties	$	4,102	$	3,627	$	2,661

Purchases:
Purchase of coal from WRDC	$	16,861	$	18,542	$	20,690
Purchase of excess energy from Cheyenne Light	$	3,033	$	3,640	$	3,139
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	1,959	$	1,886	$	1,988
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	3,200	$	3,207	$	3,269
Corporate support services from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	32,332	$	30,738	$	24,163

(10) SUPPLEMENTAL CASH FLOW INFORMATION



Years ended December 31,	2014			2013			2012
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	4,234		$	13,590		$	3,969
Non-cash decrease to money pool note receivable, net	$	—		$	(8,000	)	$	(43,984	)
Non-cash dividend to Parent company	$	—		$	8,000		$	43,984

Supplemental disclosure of cash flow information:
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(19,573	)	$	(19,174	)	$	(17,099	)
Income taxes	$	—		$	219		$	7,176

(11) COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

We have the following power purchase and transmission agreements, not including related party agreements, as of December 31, 2014 (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. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants;

A firm point-to-point transmission access agreement to deliver up to 50 MW of power on PacifiCorp’s transmission system to wholesale customers in the western region through December 31, 2023; and

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

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



Contract	Contract Type	2014		2013		2012
PacifiCorp	Electric capacity and energy	$	13,943	$	13,026	$	13,224
PacifiCorp	Transmission access	$	1,227	$	1,384	$	1,215
Thunder Creek	Gas transport capacity	$	633	$	633	$	633

Future Contractual Obligations

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



2015	$	12,443
2016	$	12,443
2017	$	12,443
2018	$	6,135
2019	$	6,037
Thereafter	$	21,998

Long-Term Power Sales Agreements

We have the following power sales agreements as of December 31, 2014:

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 on April 1, 2015. Under this contract, MEAN purchases 5 MW of unit-contingent energy and capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A fire investigator retained by the Weston County Fire Protection District concluded that the fire was caused by the failure of a transmission structure owned, operated and maintained by Black Hills Power. On April 16, 2013, a large group of private landowners filed suit in the United States District Court for the District of Wyoming. There are approximately 36 Plaintiff groups (including property jointly owned by multiple family members or entities), or approximately 73 individually named private plaintiffs. In addition, the State of Wyoming has intervened in the lawsuit. Both the private landowners and the State of Wyoming assert claims for damages against us. The claims include allegations of negligence, negligence per se, common law nuisance and trespass. In addition to claims for compensatory damages, the lawsuit seeks recovery of punitive damages. We have denied and will vigorously defend all claims arising out of the fire. We cannot predict the outcome of our investigation, the viability of alleged claims or the outcome of the litigation.

Civil litigation of this kind, however, is likely to lead to settlement negotiations, including negotiations prompted by pre-trial civil court procedures. We believe such negotiations would effect a settlement of all claims. Regardless of whether the litigation is determined at trial or through settlement, we expect to incur significant investigation, legal and expert services expenses associated with the litigation. We maintain insurance coverage to limit our exposure to losses due to civil liability claims, and related litigation expense. We expect this coverage to limit our exposure and we will pursue recoveries to the maximum extent available under the policies. The deductible applicable to some types of claims arising out of this fire is $1.0 million. Based upon information currently available, we believe that a loss associated with settlement of pending claims is probable. Accordingly, as of September 30, 2014, we recorded a loss contingency liability related to these claims and we recorded a receivable for costs we believe are reimbursable and probable of recovery under our insurance coverage. Both of these entries reflect our reasonable estimate of probable future litigation expense and settlement costs; we did not base these contingencies on any determination that it is probable we would be found liable for these claims were they to be litigated.

Given the uncertainty of litigation, however, a loss related to the fire, the litigation and related claims in excess of the loss we have determined to be probable is reasonably possible. We cannot reasonably estimate the amount of such possible loss because our investigation and review of damage claims documentation is ongoing, and there are significant factual and legal issues to be resolved. Further claims may be presented by these claimants and other parties. We have received claims seeking recovery for fire suppression, reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate, currently totaling $55 million. We are not yet able to reasonably estimate the amount of any reasonable possible losses in excess of the amount we have accrued. Based upon information currently available, however, management does not expect the outcome of the claims to have a material adverse effect upon our financial condition, results of operations or cash flows.

Legal Proceedings

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

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

Environmental Matters

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

Air

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

Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen III and Wyodak plants. Title IV of the Clean Air Act created an SO₂ allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2044.

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. While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Our Osage plant, at which operations have been suspended, has an on-site ash impoundment that is near capacity. An application to close the impoundment was approved by the State of Wyoming on April 13, 2012. Site closure work was completed in 2013 and 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 and post closure monitoring will continue for 30 years.

(12) QUARTERLY HISTORICAL DATA (Unaudited)

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



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2014
Operating revenues	$	71,267	$	60,741	$	67,729	$	68,751
Operating income	$	17,546	$	13,782	$	19,007	$	18,779
Net income	$	8,643	$	6,230	$	9,916	$	8,773

2013
Operating revenues	$	59,817	$	60,832	$	67,268	$	66,110
Operating income	$	12,503	$	14,293	$	18,704	$	16,844
Net income	$	5,582	$	6,652	$	9,298	$	8,641


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, 2014. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

Management’s Report on Internal Control over Financial Reporting is presented on Page 26 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	2014		2013
Audit Fees	$	337	$	345
Tax Fees	7		4
Audit-related fees	—		—
Total	$	344	$	349

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 and state tax compliance and advice, review of tax returns, and federal and state tax planning.

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

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

~~ITEM 15.~~



ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

~~3. Exhibits~~



(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, 2014, 2013 and 2012



		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:
2014	$	220	$	699	$	(658	)	$	261
2013	$	102	$	754	$	(636	)	$	220
2012	$	143	$	503	$	(544	)	$	102


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 ~~Rule 13a - 14(a)~~Rule13a-14(a) of the Securities Exchange Act of ~~1934.~~1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Chief Financial Officer pursuant to ~~Rule 13a - 14(a)~~Rule13a-14(a) of the Securities Exchange Act of ~~1934.~~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.

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:~~By	/~~S/ ANTHONY S. CLEBERG~~s/ DAVID R. EMERY
		David R. Emery, Chairman and
		Chief Executive Officer

~~Anthony S. Cleberg,~~Dated:	February 26, 2015

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



/s/ DAVID R. EMERY	Director and	February 26, 2015
David R. Emery, Chairman and	Principal Executive ~~Vice President~~Officer
Chief Executive Officer

/s/ RICHARD W. KINZLEY	Director and	February 26, 2015
Richard W. Kinzley, Senior Vice President	Principal Financial and
and Chief Financial Officer	Accounting Officer
~~Dated:~~	~~April 2, 2012~~
/s/ ROXANN R. BASHAM	Director	February 26, 2015
Roxann R. Basham

/s/ JEFFREY B. BERZINA	Director	February 26, 2015
Jeffrey B. Berzina

/s/ SCOTT A. BUCHHOLZ	Director	February 26, 2015
Scott A. Buchholz

/s/ ANTHONY S. CLEBERG	Director	February 26, 2015
Anthony S. Cleberg

/s/ LINDEN R. EVANS	Director	February 26, 2015
Linden R. Evans

/s/ STEVEN J. HELMERS	Director	February 26, 2015
Steven J. Helmers

/s/ BRIAN G. IVERSON	Director	February 26, 2015
Brian G. Iverson

/s/ ROBERT A. MYERS	Director	February 26, 2015
Robert A. Myers

INDEX TO EXHIBITS

~~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 ~~Rule 13a - 14(a)~~Rule13a-14(a) of the Securities Exchange Act of ~~1934.~~1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Chief Financial Officer pursuant to ~~Rule 13a - 14(a)~~Rule13a-14(a) of the Securities Exchange Act of ~~1934.~~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