Black Hills Power 10K 2011 Annual report

Black Hills Power 10-K2011 FY Annual report

Content analysis

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K



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

For the fiscal year ended December 31, 2011



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

	For the transition period from ___________________ to __________________

	Commission File Number 1-07978

BLACK HILLS POWER, INC.



Incorporated in South Dakota		IRS Identification Number 46-0111677
625 Ninth Street, Rapid City, South Dakota 57701

Registrant's telephone number, including area code: (605) 721-1700

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes x No ¨

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes x No ¨

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No ¨

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

This paragraph is not applicable to the Registrant. x

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

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

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

Yes ¨ No x

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

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

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



Class	Outstanding at February 29, 2012
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
	Safe Harbor for Forward Looking Information	5
	General and Regulations	7

ITEM 1A.	RISK FACTORS	11

ITEM 1B.	UNRESOLVED STAFF COMMENTS	17

ITEM 3.	LEGAL PROCEEDINGS	17

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

ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS	18

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	23

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	50

ITEM 9A.	CONTROLS AND PROCEDURES	50

ITEM 9B.	OTHER INFORMATION	52

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	52

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	52

	SIGNATURES	56

	INDEX TO EXHIBITS	57

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
ASC	Accounting Standards Codification
ASC 220	ASC 220, "Comprehensive Income"
ASC 310-10-50	ASC 310-10-50, "Disclosure About the Credit Quality of Financing Receivables and the Allowance for Credit Losses"
ASC 820	ASC 820 "Fair Value Measurements and Disclosures"
ASU 2011- 04	ASU 2011-04 "Fair Value Measurements"
ASU 2011- 05	ASU 2011-05 "Other Comprehensive Income"
ASU 2011- 12	ASU 2011-12 "Other Comprehensive Income"
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation, the Parent of Black Hills Power, Inc.
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills 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
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.
Enserco	Enserco Energy Inc., a wholly-owned subsidiary of Black Hills Non-Regulated Holdings, LLC. Black Hills Non-regulated Holdings divested of Enserco Energy Inc. on February 29, 2012 and was presented in discontinued operations throughout the Parent Annual Report filed on Form 10-K.
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gas
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.
IFRS	International Financial Reporting Standards
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
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
NOL	Net operating loss
NQDC	Non-Qualified Deferred Compensation Plan
PPA	Power Purchase Agreement
RMSA	Retiree 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
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

ITEMS 1 and 2. BUSINESS AND PROPERTIES

Safe Harbor for Forward Looking Information

This Annual Report on Form 10-K includes "forward-looking statements" as defined by the SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. These forward-looking statements are based on assumptions that we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the Risk Factors set forth in Item 1A of this Form 10-K and the other reports we file with the SEC from time to time, and the following:


•	Our ability to obtain adequate cost recovery for our electric utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel and purchased power and our ability to add power generation assets into regulatory rate base;


•	Our ability to successfully maintain or improve our corporate credit rating;


•	Our ability to obtain from utility commissions any requisite determination of prudency to support resource planning and development programs we propose to implement;


•	The timing and extent of scheduled and unscheduled outages;


•	The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;


•	Changes in business and financial reporting practices arising from the enactment of the Energy Policy Act of 2005 and subsequent rules and regulations promulgated thereunder;


•	Our ability to complete the permitting, construction, start-up and operation of power generating facilities in a cost-effective and timely manner;


•	Our ability to remedy any deficiencies that may be identified in the review of our internal controls;


•	Our ability to successfully complete labor negotiations with our union;


•	The timing, volatility and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost and availability of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our assets;


•	Our ability to effectively use derivative financial instruments to hedge commodity risks;


•	Our ability to minimize defaults on amounts due from customers and counterparty transactions;


•	Our ability to comply, or to make expenditures required to comply with changes in laws and regulations, particularly those relating to taxation, safety and protection of the environment and to recover those expenditures in customer rates, where applicable;


•	Liabilities related to environmental conditions, including remediation and reclamation obligations under environmental laws;


•	Federal and state laws concerning climate changes and air emissions, including emission reduction mandates and

renewable energy portfolio standards, which may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain;


•	Our ability to recover our borrowing costs, including debt service costs, in our customer rates;


•	Weather and other natural phenomena;


•	Macro- and micro-economic changes in the economy and energy industry, including the impact of (i) consolidations and changes in competition, (ii) changing conditions in the credit markets, and (iii) general economic and political conditions, including tax rates or policies and inflation rates;


•	Catastrophic events that could result from terrorism, cyber-attacks, or attempts to disrupt our business, or the business of third parties, that may impact operations in unpredictable ways and adversely affect financial results and liquidity;


•	The effect of accounting policies issued periodically by accounting standard-setting bodies;


•	The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions or events;


•	The outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements on our financial condition or results of operations;


•	Capital market conditions, which may affect our ability to raise capital on favorable terms;


•	Price risk due to marketable securities held as investments in benefit plans; and


•	Other factors discussed from time to time in our other filings with the SEC.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

General

We are a regulated electric utility serving customers in South Dakota, Wyoming and Montana. We are incorporated in South Dakota and began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation.

Unless the context otherwise requires, references in this Form 10-K to "the Company," "we," "us" and "our" refer to Black Hills Power, Inc.

We engage in the generation, transmission and distribution of electricity. We have 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, 2011, our ownership interests in electric generation plants were as follows:



Unit	Fuel Type	Location	Ownership Interest %		Owned Capacity (MW)	Year Installed
Wygen III⁽¹⁾	Coal	Gillette, WY	52	%	57.2	2010
Neil Simpson II	Coal	Gillette, WY	100	%	90.0	1995
Wyodak ⁽²⁾	Coal	Gillette, WY	20	%	72.4	1978
Osage ⁽³⁾	Coal	Osage, WY	100	%	34.5	1948-1952
Ben French	Coal	Rapid City, SD	100	%	25.0	1960
Neil Simpson I	Coal	Gillette, WY	100	%	21.8	1969
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 ⁽⁴⁾	Gas/Oil	Rapid City, SD	100	%	100.0	1977-1979
					490.9

_______________________

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

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

(3) Operations at the Osage plant were suspended October 1, 2010 due to the availability of more economical generation alternatives. The Osage plant will remain in our generation portfolio with all operating permits so it can resume full operations if needed.

(4) Upon expiration of the contract with PacifiCorp in June 2012, the capacity available under these units will be decreased to 80 MW.

Distribution and Transmission. Our distribution and transmission system serves approximately 68,200 electric customers, with an electric transmission system of 618 miles of high voltage lines (greater than 69 KV) and 2,999 miles of lower voltage lines. In addition, we jointly own 47 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 2011 were generated in South Dakota. We are subject to regulation by the SDPUC, the WPSC and the MTPSC.

The following are characteristics of our distribution and transmission businesses:


•	We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, 2011 was comprised of 30% commercial, 24% residential, 7% contract wholesale, 14% wholesale off-system, 11% industrial and 14% municipal sales and other revenue.

•

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


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


•	We have firm network transmission access to deliver power on PacifiCorp's system to Sheridan, Wyoming to serve our power sales contract with MDU through 2017, with the right to renew pursuant to the terms of PacifiCorp's transmission tariff.

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


•	MDU owns a 25% 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 MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU.

•

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 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. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:



2010-2017	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; and


•	A five-year PPA with MEAN which commenced in May 2010 whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.

Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide 491 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. We generated approximately 50% of our energy requirements in 2011 and purchased approximately 50% which was supplied under the following purchased power contracts:


•	A PPA with PacifiCorp expiring in 2023, involving the purchase by us of 50 MW of coal-fired baseload power;


•	A reserve capacity integration agreement with PacifiCorp expiring in June 2012, which makes available to us 100 MW of reserve capacity in connection with the utilization of the Ben French Combustion Turbine units;


•	A 20-year 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 20-year 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; and


•	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 2011 winter peak system load was 408 MW and our 2011 summer peak load was 452 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 301 MW of low-cost, coal-fired resources supports most of our native load requirements and positions us for wholesale off-system sales.

Shared Services Agreement. During 2010, we entered into 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.

Regulations

Rate Regulation

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 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 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.

•

Until April 1, 2010 South Dakota had three adjustment mechanisms: transmission, steam plant fuel (coal) and conditional energy cost adjustment. The transmission and steam plant fuel adjustment clauses required an annual adjustment to rates for actual costs, therefore any savings or increased costs were passed on to the South Dakota customers. The conditional energy cost adjustment related to purchased power and natural gas used to generate electricity. These costs were subject to calendar year $2.0 million and $1.0 million thresholds where Black Hills Power absorbed the first $2.0 million of increased costs or retained the first $1.0 million in savings. Beyond these thresholds, costs or savings were passed on to South Dakota customers through annual calendar-year filings.

In South Dakota beginning April 1, 2010, the steam plant fuel and conditional energy cost adjustments were combined into a single cost adjustment called the Fuel and Purchased Power Adjustment clause. The Fuel and Purchased Power Adjustment Clause provides for the direct recovery of increased fuel and purchased power costs incurred to serve South Dakota customers. As of April 1, 2010, the Fuel and Purchased Power Adjustment clause was modified in the rate case settlement to contain a power marketing operating income sharing mechanism in which South Dakota customers will receive a credit equal to 65% of power marketing operating income. The modification also adjusts the methodology to directly assign renewable resources and firm purchases to the customer load. In Wyoming beginning June 1, 2010, a similar Fuel and Purchase Power Cost Adjustment was instituted.


•	Additionally, in May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp operated Wyodak plant, went into effect June 1, 2011 and allows for recovery of all the costs associated with plant additions.

Rate Increase Settlement

South Dakota

On September 30, 2009, we filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the past four years. In March 2010, the SDPUC approved a 20% increase in interim revenues, subject to refund, effective April 1, 2010 for South Dakota customers. On July 7, 2010, the SDPUC approved a final revenue increase of $15.2 million, or 12.7%, and a base rate increase of $22 million, or 19.4% with an effective date of April 1, 2010. The approved capital structure and return on equity are confidential. A refund was provided to customers in the third quarter of 2010.

As part of the settlement stipulation, we agreed (1) to credit customers 65% of power marketing operating income with a minimum of $2.0 million per year; (2) that rates will include a South Dakota Surplus Energy Credit of $2.5 million in year one (fiscal year ending March 2011), $2.25 million in year two, $2.0 million in year three and zero thereafter; and (3) a moratorium until April 2013 for any base rate increases excluding any extraordinary events as defined in the stipulation agreement; while (4) the SDPUC agreed to adjust the power marketing sales portion of the Fuel and Purchased Power Adjustment clause to directly assign renewable resources and firm purchases to the customer load.

In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff for Black Hills Power. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp operated Wyodak plant, went into effect June 1, 2011 with an annual revenue increase of $3.1 million.

Wyoming

On October 19, 2009, we filed a rate case with the WPSC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. On May 4, 2010, we filed a settlement stipulation agreement with the WPSC for a $3.1 million increase in annual revenues. On May 13, 2010, WPSC approved these new rates based on a return on equity of 10.5% with a capital structure of 52% equity and 48% debt. Rates went into effect on June 1, 2010.

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, 2011, 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. 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.

•

Montana. Montana established a renewable portfolio standard that requires us to obtain a percentage of our retail electric sales in Montana from eligible renewable resources according to the following schedule: (i) 10% for compliance years 2010-2014 and (ii) 15% for compliance year 2015 and thereafter. Utilities can meet this standard by entering into long-term purchase contracts for electricity bundled with renewable-energy credits, by purchasing the renewable-energy credits separately, or by a combination of both. The law includes cost caps that limit the additional cost utilities must pay for renewable energy and allows cost recovery from ratepayers for contracts pre-approved by the MTPSC. We are currently in compliance with applicable standards.


•	Wyoming. Wyoming is also exploring the implementation of renewable energy portfolio standards but has not currently adopted standards.

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.

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, which impose emission limits, fuel requirements and monitoring requirements. The rule has an effective date of May 20, 2011 and a compliance deadline of March 21, 2014. This rule has a significant impact on our Neil Simpson I, Osage and Ben French facilities. Engineering evaluations have been completed as to the economic viability of continued operations of these units. It is our expectation that the Neil Simpson I, Osage and Ben French units will be closed prior to the March 21, 2014 compliance deadline.

On December 16, 2011, the EPA signed the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (Utility Maximum Achievable Control Technology Rule) which became effective on February 16, 2012. Affected units will have three years from the rule effective date to be in compliance, with a pathway defined to apply for a one year extension due to certain circumstances. Certain requirements of that regulation could have significant impacts on the Neil Simpson II, Wygen III and Wyodak plants. Neil Simpson II, Wygen III and the Wyodak plant are expected to be in compliance within the compliance time frame. Significant modifications may be required to ensure compliance at Neil Simpson II and we are working toward that goal. Preliminary estimates of capital requirements to comply with this rule are $30 million to $50 million.

In June 2011, the EPA was scheduled to issue proposed Electric Utility New Source Performance Standards for GHG. That publication date has been extended to mid-2012. As the regulations are not yet proposed, we cannot ascertain their impacts but we anticipate they may be applicable to Wygen III. In 2011, it was anticipated the EPA would expedite the issuance of a more stringent ozone ambient air standard. However, the President of the United States postponed this revision and placed it back on its normal review cycle, which is scheduled to occur in 2013. If the lower range of the proposed standard is selected, it is anticipated that Campbell County, Wyoming would be a non-attainment area. Under those conditions, the State of Wyoming may evaluate Neil Simpson II and Wygen III for further reductions in NO_x emissions.

In 2011, the State of Wyoming issued a letter addressing startup and shutdown emissions at Neil Simpson II, requiring the facility to include those emissions in consideration of compliance with the permitted emission limits. This represents a significant change in requirements from the original air permit issued in 1993. As this facility was not designed and built according to those requirements, we are currently undergoing engineering evaluations to determine methods and costs of compliance.

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 2 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2011 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.

We may not raise our retail rates without prior approval of the SDPUC, WPSC or the MTPSC. If we seek rate relief, we could experience delays, reduced or partial rate recovery, or disallowances in rate proceedings. 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 are, therefore, 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. 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 costs and transmission, as applicable) without having to file a rate case. To the extent we 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 negatively affect our results of operations, financial position or liquidity.

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.


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


•	Inability to recruit and retain skilled technical labor.


•	Labor relations.


•	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.

The global financial situation has affected our counterparty credit risk which could have an adverse effect on our results of operations, financial position or liquidity.

As a consequence of the global financial crisis in recent years, the creditworthiness of many of our contractual counterparties (particularly financial institutions) has deteriorated. Although we aggressively monitor and evaluate changes in our counterparties' credit quality and adjust the credit limits based upon such changes, our credit guidelines, controls and limits may not protect us from increasing counterparty credit risk. To the extent the financial crisis causes our credit exposure to contractual counterparties to increase materially, such increased exposure could have an adverse effect on our results of operations, financial position or liquidity.

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.

The continued recessionary environment and any future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our non-utility 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 "A3" by Moody's, "BBB+" by S&P and A- by Fitch. Any reduction in our ratings by the rating agencies could adversely affect our ability to refinance or repay 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 lead to lost revenues or increased expenses.

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;


•	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 all 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, especially in the case of 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 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 the variability of our net income in recent years has been attributable to off-system wholesale electricity sales. 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 operating results can be adversely affected by milder weather.

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 less revenues and income when weather conditions are cooler in the summer and warmer in the winter. Unusually mild summers and winters therefore could have an adverse effect on our results of operations, financial position and liquidity.

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; 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.

We strive to comply with all applicable environmental laws and regulations. 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.

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 climate change 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 or operations.

On May 20, 2011, 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 is March 21, 2014. Engineering evaluations have been completed and confirm the significant impact on our Neil Simpson I, Osage and Ben French facilities. We anticipate these units will be closed prior to the March 21, 2014 compliance deadline.

On December 16, 2011 EPA signed the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units, which became effective on February 16, 2012. Affected units will have three years from the rule effective date to be in compliance, with a pathway defined to apply for a one year extension due to certain circumstances. Certain requirements of that regulation could have significant impacts on the Neil Simpson II, Wygen III and Wyodak plants.

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. Existing permitted facilities will see monitoring reporting requirements incorporated into their operating permits upon renewal. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emissions control practices and technologies.

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 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. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by those non-regulated power plants. 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 business.

The Energy Policy Act of 2005 increased the FERC civil penalty authority for violation of FERC statutes, rules and orders. FERC can now impose penalties of $1.0 million per violation, per day, and other regulatory agencies that impose compliance requirements relative to our business also have civil penalty authority. In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the North American Electric Reliability Corporation, with similar penalty authority for violations. Many rules that were historically subject to voluntary compliance are now mandatory and subject to potential civil penalties for violations. If a serious 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.

Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, 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 financial results or liquidity.

•

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber-attacks 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.

•

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems are vulnerable to disability, failures or unauthorized access, including due to cyber-attacks. If our technology systems were to fail or be breached and be unable to recover in a timely way, we would be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised, which could have material adverse effect on our financial results.

•

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.

Ongoing changes in the United States electric utility industry, including state and federal regulatory changes, a potential increase in the number or geographic scale of our competitors or the imposition of price limitations to address market volatility, could adversely affect our results of operations, financial position or liquidity.

The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:


•	The Energy Policy Act of 2005 and the repeal of the Public Utility Holding Company Act of 1935;


•	Industry consolidation;


•	Consumer demands;


•	Transmission constraints;


•	Renewable resource supply requirements;


•	Resistance to the siting of utility infrastructure or to the granting of right-of-ways;


•	Technological advances; and


•	Greater availability of natural gas-fired power generation, and other factors.

FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses. Deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry, which could adversely affect our results of operations, financial position or liquidity.

In addition, the independent system operators who oversee many of the wholesale power markets have in the past imposed, and may in the future continue to impose price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.

Governmental authorities may assess penalties on us if it is determined that we have not complied with environmental laws and regulations which could affect our results of operations, financial position or liquidity.

If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us. Recent lawsuits by the EPA and various states filed against others within industries in which we operate highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities in particular.

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 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 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 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 became effective during our 2010 open enrollment period (November 1, 2010) while other provisions of the 2010 Acts will be effective in future years. Although the constitutional validity of the 2010 Acts is the subject of numerous lawsuits now pending in the federal courts, the outcome of which is uncertain, the 2010 Acts could require, among other things, changes to our current employee benefit plans and in our administrative and accounting processes. 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, and as the results of pending litigation become final.

We have disclosed a material weakness in our internal control over financial reporting, and if we do not adequately remediate this weakness or if we have other material weaknesses or significant deficiencies in our internal control over financial reporting our business and financial condition may be adversely affected.

Our management 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. As disclosed in Item 9A, management identified a material weakness in our internal control over financial reporting relating to accounting for income taxes. A material weakness is a deficiency, or combination of deficiencies, that result in a reasonable possibility that a material misstatement of a company's annual or interim financial statements will not be prevented or detected on a timely basis. As a result of this material weakness, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were not effective as of December 31, 2011. Management is taking measures to remediate the material weakness and to enhance our internal controls over financial reporting. If our remedial measures are insufficient to address the material weakness, or if additional material weaknesses or significant deficiencies in our internal control occur in the future, our financial statements may contain material misstatements or other errors and we could be required to restate our financial results. If we cannot produce reliable financial reports, we may be unable to obtain additional financing, and our business and financial condition could be harmed.

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 12, "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



For the years ended December 31,	2011			2010			2009
	(in thousands)

Revenue	$	245,631		$	229,763		$	207,079
Fuel and purchased power	93,222			87,757			91,349
Gross margin	152,409			142,006			115,730

Operating expenses	98,457			92,976			80,925
Gain on sale of operating assets	(768		)	(6,238		)	—
Operating income	54,720			55,268			34,805

Interest expense, net	(16,139		)	(16,513		)	(11,164		)
Other income	506			3,254			7,802
Income tax expense	(11,990		)	(10,741		)	(8,304		)
Net income	$	27,097		$	31,268		$	23,139

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



Electric Revenue
Customer Base	2011		Percentage Change		2010		Percentage Change		2009
Residential	$	59,826	12	%	$	53,549	10	%	$	48,586
Commercial	72,889		10	%	65,997		10	%	59,897
Industrial	25,723		14	%	22,621		13	%	20,014
Municipal	3,172		5	%	3,029		11	%	2,735
Total retail sales	161,610		11	%	145,196		11	%	131,232
Contract wholesale	18,105		(21	)%	22,996		(9	)%	25,358
Wholesale off-system	34,889		(4	)%	36,354		13	%	32,212
Total electric sales	214,604		5	%	204,546		8	%	188,802
Other revenue	31,027		23	%	25,217		38	%	18,277
Total revenue	$	245,631	7	%	$	229,763	11	%	$	207,079



Megawatt-Hours Sold
Customer Base	2011	Percentage Change		2010	Percentage Change		2009
Residential	550,935	1	%	547,193	3	%	529,825
Commercial	720,978	—	%	720,119	0	%	723,360
Industrial	408,337	7	%	382,562	8	%	353,041
Municipal	34,235	1	%	33,908	0	%	33,948
Total retail sales	1,714,485	2	%	1,683,782	3	%	1,640,174
Contract wholesale	349,520	(25	)%	468,782	(27	)%	645,297
Wholesale off-system	1,226,548	5	%	1,163,058	15	%	1,009,574
Total electric sales	3,290,553	(1	)%	3,315,622	1	%	3,295,045
Losses and company use	162,316	24	%	131,263	(18	)%	159,207
Total energy	3,452,869	—	%	3,446,885	0	%	3,454,252

We own approximately 491 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.



Regulated Power Plant Fleet Availability	2011			2010		2009
Coal-fired plants	88.8	%	^(a)	93.5	%	90.3	%
Other plants	95.8	%		95.7	%	97.7	%
Total availability	91.5	%		94.4	%	93.5	%

_____________________________


(a)	2011 reflects a planned major outage at the PacifiCorp-operated Wyodak plant.



Resources	2011	Percentage Change		2010	Percentage Change		2009
MWh generated:
Coal	1,717,008	(14	)%	1,987,037	15	%	1,721,074
Gas	15,221	(21	)%	19,269	(59	)%	46,723
	1,732,229	(14	)%	2,006,306	13	%	1,767,797

MWh purchased	1,720,640	19	%	1,440,579	(15	)%	1,686,455
Total resources	3,452,869	—	%	3,446,885	0	%	3,454,252



Heating and Cooling Degree Days	2011		2010		2009

Actual
Heating degree days	7,579		7,272		7,753
Cooling degree days	700		532		354

Variance from 30-year average
Heating degree days	5	%	1	%	8	%
Cooling degree days	17	%	(11	)%	(41	)%

2011 Compared to 2010

Gross margin increased $10.4 million primarily due to a $16.6 million increase related to the impact of the outcome of our rate cases and increased transmission margins partially offset by lower margins due to the termination of power sales contracts upon a customer's purchase of an ownership interest in the Wygen III generating facility.

Operations and maintenance increased $5.5 million primarily due to additional costs of $1.6 million associated with Wygen III which commenced commercial operation on April 1, 2010, and increased allocation of corporate costs partially offset by lower costs related to the suspension of operations at the Osage plant.

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party. The gain on sale of operating assets in 2010 represents the sale of a 23% ownership interest in the Wygen III generating facility to the City of Gillette, WY.

Interest expense, net decreased $0.4 million primarily due to lower interest expense primarily related to the repayment of higher rate debt during 2010, partially offset by a decrease in AFUDC associated with borrowed funds due to completed construction of Wygen III.

Other income, net decreased $2.7 million primarily due to a decrease of $2.0 million in AFUDC-equity due to the placement of Wygen III into commercial operation.

Income tax expense: The effective tax rate increased from the same period in the prior year due to a prior year tax benefit for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit resulting from a rate case settlement in 2010.

2010 Compared to 2009

Gross margin increased $26.3 million primarily due to an $18.5 million increase related to the impact of the outcome of our rate cases, an increase of $3.0 million in off-system sales margin resulting from a change in methodology used to allocate the lowest cost resource, and increased intercompany revenues of $2.4 million due to a new shared services agreement related to resources utilized by affiliated entities.

Operations and maintenance increased $12.1 million primarily due to additional costs of $6.8 million associated with Wygen III which commenced commercial operation on April 1, 2010, and costs of $2.0 million associated with a major overhaul at the Ben French plant.

Gain on sale of operating assets: A $6.2 million gain on sale was recognized on the sale of a 23% ownership interest in the Wygen III generating facility to the City of Gillette, WY.

Interest expense, net increased $5.3 million primarily due to higher net interest expense of $2.9 million compared to the same period in the prior year resulting from higher rates on long-term debt compared to rates on short-term debt and a decrease of $2.1 million in AFUDC-borrowed.

Other income decreased $4.5 million primarily due to a decrease of $3.1 million in AFUDC-equity associated with the construction of our Wygen III facility. Additionally, 2009 included a gain of $1.1 million from the sale of SO₂ emission credits and a gain of $0.5 million on the sale of a 25% ownership interest in the Wygen III facility.

Income tax expense: The effective tax rate for 2010 was comparable to the same period in the prior year.

Rate Increase Settlement

South Dakota

On September 30, 2009, we filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the past four years. In March 2010, the SDPUC approved a $24.1 million increase in interim rates, subject to refund, effective April 1, 2010 for South Dakota customers. On July 7, 2010, the SDPUC approved a final revenue increase of $15.2 million and a base rate increase of $22.0 million with an effective date of April 1, 2010. The approved capital structure and return on equity are confidential. A refund of $2.6 million was provided to customers in the third quarter of 2010.

As part of the settlement stipulation, we agreed (1) to credit customers 65% of power marketing operating income with a minimum of $2.0 million per year; (2) that rates will include a South Dakota Surplus Energy Credit of $2.5 million in year one (fiscal year ending March 2011), $2.25 million in fiscal year two, $2.0 million in fiscal year three and zero thereafter; and (3) a moratorium until April 2013 for any base rate increase excluding any extraordinary events as defined in the stipulation agreement; while (4) the SDPUC agreed to adjust the power marketing sales portion of the Fuel and Purchased Power Adjustment clause to directly assign renewable resources and firm purchases to the customer load.

Wyoming

Wygen III Power Plant Project

The 110 MW coal-fired electric generation facility was completed and commenced commercial operations on April 1, 2010. Total cost of construction was approximately $232.3 million, which includes AFUDC. In April 2009, we sold a 25% ownership interest to MDU. At closing, MDU made a payment to us for its 25% share of the costs to date for the on-going construction of the facility. MDU reimbursed us monthly for its 25% share of the total costs paid to complete the project. In July 2010, we sold an additional 23% ownership interest in Wygen III to the City of Gillette for $62.0 million. Under both agreements, we retain responsibility for operation of the facility with a life-of-plant site lease. MDU and the City of Gillette will pay us for administrative services and share in the costs of operating the plant for the life of the facility. We have a coal supply agreement in place with WRDC and WRDC has coal supply agreements with MDU and the City of Gillette for their share of the plant.

Critical Accounting Estimates

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

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

Impairment of Long-lived Assets

We evaluate for impairment, the carrying values of our long-lived assets whenever indicators of impairment exist.

For long-lived assets with finite lives, this evaluation is based upon our projections of anticipated future cash flows (undiscounted and without interest charges) from the assets being evaluated. If the sum of the anticipated future cash flows over the expected useful life of the assets is less than the assets' carrying value, then a permanent non-cash write-down equal to the difference between the assets' carrying value and the assets' fair value is required to be charged to earnings. In estimating future cash flows, we generally use a probability weighted average expected cash flow method with assumptions based on those used for internal budgets. The determination of future cash flows, and, if required, fair value of a long-lived asset is by its nature a highly subjective judgment. Significant assumptions are required in the forecast of future operating results used in the preparation of the long-term estimated cash flows. Changes in these estimates could have a material effect on the evaluation of our long-lived assets. There have been no impairments taken in 2011, 2010 or 2009.

Pension and Other Postretirement Benefits

The Company, as described in Note 9 to the Financial Statements in this Annual Report on Form 10-K, has a defined benefit pension plan and post-retirement healthcare plan. 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 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.

In July 2009, the Board of Directors froze our Defined Benefit Pension Plan to certain new participants and transferred certain existing participants to an age and service based defined contribution plan, effective January 1, 2010. Plan assets and obligations for the Black Hills Corporation Plan which covers eligible employees of Black Hills Power were revalued as of July 31, 2009 in conjunction with the curtailment of the plan. As a result, we recognized a pre-tax curtailment expense of approximately $0.2 million in the third quarter of 2009. In July 2009, the Board of Directors of Black Hills Corporation also approved amendments to the BHC Retiree Healthcare Plan. This plan covers eligible employees of Black Hills Power. Effective January 1, 2010, the amendment changed the plan from a cost sharing plan to an RMSA for non-union employees.

In September 2010, the bargaining unit participants in the Defined Benefit Pension Plan voted to freeze all new bargaining unit employees from participation in the Plan and to freeze the benefits of current bargaining unit participants except for the following group: those bargaining unit participants who are both 1) age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the pension plan and consequently fore-go the additional age and points based employer contribution under the Company's 401(k) retirement savings plan. As a result of this freeze, we recognized a pre-tax curtailment expense of less than $0.1 million in the fourth quarter of 2010. Pension Plan benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. These changes were effective January 1, 2011.

Valuation of Deferred Tax Assets

We use the liability method of accounting for income taxes. Under this method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. The amount of deferred tax assets recognized is limited to the amount of the benefit that is more likely than not to be realized.

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

Contingencies

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



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS



	Page

Report of Independent Registered Public Accounting Firm	24

Statements of Income for the three years ended December 31, 2011	25

Statements of Comprehensive Income for the three years ended December 31, 2011	26

Balance Sheets as of December 31, 2011 and 2010	27

Statements of Cash Flows for the three years ended December 31, 2011	28

Statements of Common Stockholder's Equity for the three years ended December 31, 2011	29

Notes to Financial Statements	30

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Black Hills Power, Inc.

Rapid City, South Dakota

We have audited the accompanying balance sheets of Black Hills Power, Inc. (the "Company") as of December 31, 2011 and 2010, and the related statements of income, statements of comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March __, 2012

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME



Years ended December 31,	2011			2010			2009
	(in thousands)

Revenue	$	245,631		$	229,763		$	207,079

Operating expenses:
Fuel and purchased power	93,222			87,757			91,349
Operations and maintenance	66,683			68,884			57,116
Gain on sale of operating assets	(768		)	(6,238		)	—
Depreciation and amortization	27,217			22,030			19,465
Taxes - property	4,557			2,062			4,344
Total operating expenses	190,911			174,495			172,274

Operating income	54,720			55,268			34,805

Other income (expense):
Interest expense	(16,712		)	(18,737		)	(15,779		)
AFUDC - borrowed	419			2,224			4,357
Interest income	154			318			258
AFUDC - equity	705			2,748			5,831
Other expense	(344		)	(35		)	—
Other income	145			223			1,971
Total other income (expense)	(15,633		)	(13,259		)	(3,362		)

Income from continuing operations before income taxes	39,087			42,009			31,443
Income tax expense	(11,990		)	(10,741		)	(8,304		)

Net income	$	27,097		$	31,268		$	23,139

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

BLACK HILLS POWER, INC.

STATEMENTS OF COMPREHENSIVE INCOME



Years ended December 31,	2011			2010			2009
	(in thousands)

Net income available for common stock	$	27,097		$	31,268		$	23,139

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments	(70		)	(94		)	98
Fair value adjustment on derivatives designated as cash flow hedges	—			4			(2		)
Reclassification adjustment of cash flow hedges settled and included in net income (loss)	42			41			40
Reclassification adjustment of cash flow hedges settled and included in regulatory assets or liabilities	—			—			—
Other comprehensive income (loss), net of tax	(28		)	(49		)	136

Comprehensive income (loss), net of tax	$	27,069		$	31,219		$	23,275

See Note 8 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



At December 31,	2011			2010
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	2,812		$	2,045
Receivables - customers, net	24,668			28,716
Receivables - affiliates	6,998			6,891
Other receivables, net	786			2,077
Money pool notes receivable	50,477			39,862
Materials, supplies and fuel	22,074			21,259
Regulatory assets, current	6,605			3,584
Other current assets	4,255			3,712
Total current assets	118,675			108,146

Investments	4,592			4,396

Property, plant and equipment	995,772			962,640
Less accumulated depreciation and amortization	(313,581		)	(304,800		)
Total property, plant and equipment, net	682,191			657,840

Other assets:
Regulatory assets, non-current	45,160			37,740
Other, non-current assets	3,812			3,610
Total other assets	48,972			41,350
TOTAL ASSETS	$	854,430		$	811,732

LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt	$	37		$	81
Accounts payable	12,560			14,828
Accounts payable - affiliates	18,598			12,562
Accrued liabilities	16,448			15,541
Regulatory liabilities, current	853			1,932
Deferred income tax liabilities, net, current	848			859
Total current liabilities	49,344			45,803

Long-term debt, net of current maturities	276,390			276,422

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	113,320			122,319
Regulatory liabilities, non-current	39,621			28,276
Benefit plan liabilities	31,097			19,581
Other, non-current liabilities	8,172			9,914
Total deferred credits and other liabilities	192,210			180,090

Commitments and contingencies (Notes 5, 9, 10 and 12)

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	274,785			247,688
Accumulated other comprehensive loss	(1,290		)	(1,262		)
Total stockholder's equity	336,486			309,417
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	854,430		$	811,732

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,	2011			2010			2009
	(in thousands)
Operating activities:
Net income	$	27,097		$	31,268		$	23,139
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	27,217			22,030			19,465
Deferred income taxes	(2,931		)	25,626			11,600
AFUDC - equity	(705		)	(2,748		)	(5,831		)
Gain on sale of operating assets	(768		)	(6,238		)	—
Employee benefits	2,406			4,030			4,234
Other adjustments	617			(4,335		)	240
Change in operating assets and liabilities -
Accounts receivable and other current assets	3,378			(14,541		)	13,233
Accounts payable and other current liabilities	989			(5,525		)	2,556
Regulatory assets	(1,211		)	3,883			(2,205		)
Regulatory liabilities	(1,964		)	3,562			586
Contributions to defined benefit pension plan	—			(8,798		)	—
Other operating activities	(2,691		)	2,389			(859		)
Net cash provided by operating activities	51,434			50,603			66,158

Investing activities:
Property, plant and equipment additions	(40,910		)	(78,602		)	(146,148		)
Proceeds from sale of operating assets	1,135			62,000			32,783
Notes receivable from affiliate companies, net	(10,615		)	17,875			(82,737		)
Other investing activities	(197		)	2,202			1,067
Net cash provided by (used in) investing activities	(50,587		)	3,475			(195,035		)

Financing activities:
Notes payable to affiliate companies, net	—			—			(45,184		)
Long-term debt - issuance	—			—			180,000
Long-term debt - repayments	(80		)	(52,566		)	(2,140		)
Other financing activities	—			(1,176		)	(2,094		)
Net cash provided by (used in) financing activities	(80		)	(53,742		)	130,582

Net change in cash and cash equivalents	767			336			1,705

Cash and cash equivalents:
Beginning of year	2,045			1,709			4
End of year	$	2,812		$	2,045		$	1,709

See Note 11 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



	2011			2010			2009
	(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	$	247,688		$	216,420		$	193,281
Net income available for common stock	27,097			31,268			23,139
Balance end of year	$	274,785		$	247,688		$	216,420

Accumulated other comprehensive loss:
Balance beginning of year	$	(1,262	)	$	(1,213	)	$	(1,349	)
Other comprehensive (loss) income, net of tax	(28		)	(49		)	136
Balance end of year	$	(1,290	)	$	(1,262	)	$	(1,213	)

Total stockholder's equity	$	336,486		$	309,417		$	278,198

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

NOTES TO FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

(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 4).

Use of Estimates

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.

Our regulatory assets and liabilities for which we recover the costs, but we do not earn a return were as follows as of December 31 (in thousands):



	Maximum Recovery Period	2011		2010
Regulatory assets:
Unamortized loss on reacquired debt	14 years	$	2,765	$	3,016
AFUDC	45 years	8,552		9,489
Employee benefit plans	13 years	27,602		18,049
Deferred energy costs	1 year	6,605		3,584
Flow through accounting	35 years	5,789		4,772
Other		452		2,414
Total regulatory assets		$	51,765	$	41,324

Regulatory liabilities:
Cost of removal for utility plant	53 years	$	23,347	$	15,429
Employee benefit plans	13 years	15,282		10,204
Other		1,845		4,575
Total regulatory liabilities		$	40,474	$	30,208

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

Deferred Energy Costs - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our electric utility customers in excess of current rates and which will be recovered 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 with respect to Black Hills Power 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.

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

Cost of Removal - 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. Liabilities will be settled and trued up following completion of the related activities.

Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirements. 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.

Allowance for Funds Used During Construction

AFUDC represents the approximate composite cost of borrowed funds and a return on capital used to finance a project.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable consist of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivables 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 potentially 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 the ability to pay.

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollected. 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):



	2011			2010
Accounts receivable trade	$	16,447		$	21,365
Unbilled revenues	8,364			7,581
Total accounts receivable - customers	24,811			28,946
Allowance for doubtful accounts	(143		)	(230		)
Net accounts receivable	$	24,668		$	28,716

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.

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. 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 are charged to operations as incurred.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.2% in 2011, 2.2% in 2010 and 2.8% in 2009.

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.

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 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.

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

It is our 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 currently in our regulated businesses 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.

(2) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

Other Comprehensive Income, ASU 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending ASC 220 to improve the comparability, consistency and transparency of reporting of comprehensive income. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU No. 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. In December 2011, FASB issued ASU 2011-12. ASU 2011-12 indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments for items reclassified from other comprehensive income to net income be presented on the face of the financial statements.

We have elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed the presentation of certain financial statements and provided additional details in notes to the financial statements, but did not have any other impact on our financial statements. See the accompanying Comprehensive Income Statement and additional disclosures in Note 8.

Fair Value Measurements and Disclosures, ASC 820

The ASC for Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosure requirements related to fair value measurements. This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement. We apply fair value measurements to certain assets and liabilities, primarily employee benefit plan assets and other miscellaneous financial instruments.

In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements, disclosure of inputs and techniques used in valuation and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements are required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for us January 1, 2010, except the disclosures related to purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which were effective January 1, 2011. The guidance requires additional disclosures, but did not impact our financial position, results of operations or cash flows. The additional disclosures are included in Note 9.

Recently Issued Accounting Standards and Legislation

Fair Value Measurement, ASU 2011-04

FASB issued an accounting standards update amending ASC 820 to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. This amendment changes the wording used to describe fair value and requires additional disclosures. We do not expect this amendment, which is effective for interim and annual periods beginning after December 31, 2011, to have an impact on our financial position, results of operations, or cash flows.

(3) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following (in thousands):



				December 31, 2011				December 31, 2010
				Weighted				Weighted
				Average				Average	Lives (in years)
	December 31, 2011			Useful Life (in years)	December 31, 2010			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	504,088		51	$	475,762		50	45	65
Transmission	115,063			47	116,056			43	40	60
Distribution	289,833			39	271,470			37	16	45
Plant acquisition adjustment	4,870			32	4,870			32	32	32
General	72,045			21	58,777			22	8	45
Construction work in progress	9,873				35,705
Total electric plant	995,772				962,640
Less accumulated depreciation and amortization	(313,581		)		(304,800		)
Electric plant net of accumulated depreciation and amortization	$	682,191			$	657,840

(4) 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 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 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 the Wygen III generation facility and are obligated to make payments for costs associated with administrative services and proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations.

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 Plant is included in the corresponding categories of operating expenses in the accompanying Statements of Income.

As of December 31, 2011, our interests in jointly-owned generating facilities and transmission systems included on our Balance Sheets were as follows (dollars in thousands):



Interest in jointly-owned facilities	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	109,007	$	718	$	46,104
Transmission Tie	$	19,648	$	—	$	4,061
Wygen III	$	129,791	$	249	$	5,328

(5) LONG-TERM DEBT

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



	Maturity Date	Fixed Interest Rate		December 31, 2011			December 31, 2010
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
Unamortized discount, First Mortgage Bonds due 2039				(115		)	(119		)
Pollution control revenue bonds due 2014	October 1, 2014	4.80	%	6,450			6,450
Pollution control revenue bonds due 2024	October 1, 2024	5.35	%	12,200			12,200
Series 94A Debt	June 1, 2024	3.00	%	2,855			2,855
Other	May 12, 2012	13.66	%	37			117

Total long-term debt				276,427			276,503
Less current maturities				(37		)	(81		)
Net long-term debt				$	276,390		$	276,422

Deferred finance costs of approximately $3.1 million were capitalized and are being amortized over the term of the debt. Amortization of deferred financing costs is included in Interest expense.

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, 2011.

Series AC Bonds

In February 2010, the Series 8.06% AC bonds matured. These were paid in full for $30.0 million of principal plus accrued interest of $1.2 million.

Series Y Bonds

In March 2010, we completed redemption of our Series Y 9.49% bonds in full. The bonds were originally due in 2018. A total of $2.7 million was paid on March 31, 2010, which includes the principal balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Balance Sheet and is being amortized over the remaining term of the original bonds.

Series Z Bonds

In June 2010, we completed redemption of our Series Z 9.35% bonds in full. The bonds were originally due in 2021. A total of $21.8 million was paid on June 1, 2010, which included the principal balance of $20.0 million plus accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Balance Sheet and is being amortized over the remaining term of the original bonds.

Long-term Debt Maturities

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



2012	$	37
2013	$	—
2014	$	6,450
2015	$	—
2016	$	—
Thereafter	$	270,055

(6) FAIR VALUE OF FINANCIAL INSTRUMENTS

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



	December 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents	$	2,812	$	2,812	$	2,045	$	2,045
Long-term debt, including current maturities	$	276,427	$	362,055	$	276,503	$	301,964

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

Cash and Cash Equivalents

The carrying amount approximates fair value due to the short maturity of these instruments.

Long-Term Debt

The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings. Our outstanding first mortgage bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for us to call and refinance the first mortgage bonds.

(7) INCOME TAXES

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



	December 31, 2011			December 31, 2010			December 31, 2009
Current	$	14,921		$	(14,885	)	$	(3,296	)
Deferred	(2,931		)	25,626			11,600
Total income tax expense	$	11,990		$	10,741		$	8,304

The temporary differences which gave rise to the net deferred tax liability were as follows (in thousands):



	December 31, 2011			December 31, 2010
Deferred tax assets, current:
Asset valuation reserve	$	491		$	217
Employee benefits	1,086			803
Rate refund	360			428
Total deferred tax assets, current	1,937			1,448

Deferred tax liabilities, current:
Prepaid expenses	(256		)	(251		)
Deferred costs	(2,529		)	(2,056		)
Total deferred tax liabilities, current	(2,785		)	(2,307		)

Net deferred tax assets (liabilities), current	$	(848	)	$	(859	)

Deferred tax assets, non-current:
Plant related differences	$	—		$	909
Regulatory liabilities	14,644			10,074
Employee benefits	3,922			3,547
Net operating loss	28,072			9,147
Items of other comprehensive income	263			225
Research and development credit	780			1,613
Other	1,155			—
Total deferred tax assets, non-current	48,836			25,515

Deferred tax liabilities, non-current:
Accelerated depreciation and other plant related differences	(148,254		)	(132,338		)
AFUDC	(5,559		)	(6,168		)
Regulatory assets	(5,019		)	(5,557		)
Employee benefits	(2,356		)	(2,983		)
Other	(968		)	(788		)
Total deferred tax liabilities, non-current	(162,156		)	(147,834		)

Net deferred tax assets (liabilities), non-current	$	(113,320	)	$	(122,319	)

Net deferred tax assets (liabilities)	$	(114,168	)	$	(123,178	)

The following table reconciles the change in the net deferred income tax assets (liabilities) from December 31, 2010 to December 31, 2011 and from December 31, 2009 to December 31, 2010 to deferred income tax expense (benefit) (in thousands):



	2011			2010
Change in deferred income tax assets (liabilities)	$	(9,010	)	$	25,118
Deferred taxes related to regulatory assets and liabilities	4,968			9,272
Deferred taxes associated with other comprehensive income	15			(2,141		)
Deferred taxes related to property basis differences	156			(4,713		)
Deferred taxes related to AFUDC	937			(1,910		)
Other	3			—
Deferred income tax expense (benefit) for the period	$	(2,931	)	$	25,626

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



	December 31, 2011		December 31, 2010		December 31, 2009
Federal statutory rate	35.0	%	35.0	%	35.0	%
Amortization of excess deferred and investment tax credits	(0.4	)	(0.6	)	(0.9	)
Equity AFUDC	(0.6	)	(2.0	)	(6.2	)
Flow through adjustments *	(3.4	)	(7.4	)	—
Other	0.1		0.6		(1.5	)
	30.7	%	25.6	%	26.4	%

The flow-through adjustments relate primarily to an accounting method change for tax purposes that was filed with the 2008 tax return and for which consent was received from the IRS in September 2009. The effect of the change allows us to take a current tax deduction for repair costs that were previously capitalized for tax purposes. These costs will 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. Due to this regulatory treatment, we recorded an income tax benefit that was attributable to the 2008 through 2010 tax years. For years prior to 2008, we did not record a regulatory asset for the repairs deduction as the tax benefit was not flowed through to customers.

The accounting standards for uncertain tax positions clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with accounting standards for income taxes. The accounting standards prescribe a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken. The impact of this implementation had no effect on our financial statements.

The following table reconciles the total amounts of unrecognized tax benefits at the beginning and end of the period (in thousands):



	2011			2010
Unrecognized tax benefits at January 1	$	3,094		$	3,877
Additions for prior year tax positions	795			130
Reductions for prior year tax positions	(294		)	(913		)

Unrecognized tax benefits at December 31	$	3,595		$	3,094

The reduction 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 $0.4 million.

It is our continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the year ended December 31, 2011 and 2010, the interest expense recognized related to income tax matters was not material to our financial results.

The Company files income tax returns in the United States federal jurisdiction as a member of the BHC consolidated group. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations prior to December 31, 2012.

At December 31, 2011, we have federal NOL carry forward of $80.2 million, of which $54.6 million will expire in 2030 and $25.6 million will expire in 2031. Ultimate usage of this NOL depends upon our future taxable income.

(8) COMPREHENSIVE INCOME

The following tables display each component of Other Comprehensive Income (Loss), after-tax, and the related tax effects for the years ended (in thousands):



	December 31, 2011
	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Minimum pension liability adjustment - net gain (loss)	$	(108	)	$	38		$	(70	)
Reclassification adjustments of cash flow hedges settled and included in net income	65			(23		)	42
Net change in fair value of derivatives designated as cash flow hedges	—			—			—
Other comprehensive income (loss)	$	(43	)	$	15		$	(28	)



	December 31, 2010
	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Minimum pension liability adjustment - net gain (loss)	$	(145	)	$	51		$	(94	)
Reclassification adjustments of cash flow hedges settled and included in net income	64			(23		)	41
Net change in fair value of derivatives designated as cash flow hedges	6			(2		)	4
Other comprehensive income (loss)	$	(75	)	$	26		$	(49	)



	December 31, 2009
	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Minimum pension liability adjustment - net gain (loss)	$	150		$	(52	)	$	98
Reclassification adjustments of cash flow hedges settled and included in net income	64			(24		)	40
Net change in fair value of derivatives designated as cash flow hedges	(5		)	3			(2		)
Other comprehensive income (loss)	$	209		$	(73	)	$	136

_____________

During 2002, we entered into a treasury lock to hedge a portion of a first mortgage bond. The treasury lock cash settled on the bond pricing date, and resulted in a $1.8 million loss. This treasury lock was treated as a cash flow hedge and accordingly the resulting loss is carried in Accumulated other comprehensive loss on the accompanying Balance Sheet and amortized over the life of the related bonds as additional interest expense.

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



	December 31, 2011			December 31, 2010
Derivatives designated as cash flow hedges	$	(801	)	$	(843	)
Employee benefit plans	(489		)	(419		)
Total accumulated other comprehensive loss	$	(1,290	)	$	(1,262	)

(9) EMPLOYEE BENEFIT PLANS

Funded Status of Benefit Plans

The funded status of postretirement benefit plan is required to be recognized in the statement of financial position. The funded status for 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.

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 noncontributory defined benefit pension plan ("Pension Plan") covering employees who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. Our funding policy is in accordance with the federal government's funding requirements. The Pension Plan's assets are held in trust and consist primarily of equity and fixed income investments. We use a December 31 measurement date for the Pension Plan.

As of January 1, 2012, the Pension Plan has been frozen to new employees and certain employees who did not meet age and service based criteria at the time the Plans were frozen. The benefits for the plans are based on years of service and calculations of average earnings during a specific time period prior to retirement. In July 2009, the Board of Directors approved a partial freeze to the Pension Plan for all participants with the exception of bargaining unit participants. The freeze eliminated new non-bargaining unit employees from participation in the Pension Plan and froze the benefits of current non-bargaining unit participants except certain eligible employees who met age and service based criteria. In September of 2010, our bargaining unit employees voted to freeze participation in the Pension Plan and to freeze the benefits of current bargaining unit participants except for certain eligible employees who met age and service based criteria. An additional age and points-based employer contribution under the Company's 401(k) retirement savings plan was established.

The Pension Plan's expected long-term rate of return on assets assumption is based upon the weighted average expected long-term rate of returns for each individual asset class. The asset class weighting is determined using the target allocation for each asset class in the Pension Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from adjusted long-term historical returns for the asset class. It is anticipated that long-term future returns will not achieve historical results. The expected long-term rate of return for equity investments was 8.75% and 9.25% for the 2011 and 2010 plan years, respectively.

Pension Plan Assets

Percentage of fair value of Pension Plan assets at December 31:



	2011		2010
Equity	69	%	68	%
Fixed income	28	%	29	%
Cash	3	%	3	%
Total	100	%	100	%

The Investment Policy for the Pension Plans is to seek to achieve the following long-term objectives: 1) a rate of return in excess of the annualized inflation rate based on a five-year moving average; 2) a rate of return that meets or exceeds the assumed actuarial rate of return as stated in the Plan's actuarial report; 3) a rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates on a moving three-year average, and 4) maintenance of sufficient income and liquidity to pay monthly retirement benefits. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity and fixed income assets.

The policy contains certain prohibitions on transactions in separately managed portfolios in which the Pension Plan may invest, including prohibitions on short sales.

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. We use a December 31 measurement date for the Supplemental Plans. Effective January 1, 2010, we eliminated a non-qualified pension plan in which some of our officers participated due to the partial freeze of our qualified pension plan. We also amended the NQDC, which was adopted in 1999. The NQDC is a non-qualified deferred compensation plan that provides executives with an opportunity to elect to defer compensation and receive benefits without reference to the limitations on contributions in the Plan or those imposed by the IRS. The amended NQDC provides for non-elective non-qualified restoration benefits to certain officers who are not eligible to continue accruing benefits under the Defined Benefit Pension Plans and associated non-qualified pension restoration plans. All contributions to the non-qualified plans are subject to a graded vesting schedule of 20% per year over five years with vesting credit beginning with service in the Plan on and after January 1, 2010.

Supplemental Plan Assets

The Supplemental Plans have no assets. We fund on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Plan

Employees who are participants in our Non-Pension Postretirement Healthcare Plan ("Healthcare Plan") and who retire on or after attaining age 55 after completing at least five years of service 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 use a December 31 measurement date for the Healthcare Plan. The Board of Directors approved an amendment to the Healthcare Plan which changed the structure of the Healthcare Plan for non-union employees to a RMSA structure which was effective January 1, 2010. In September 2010, the bargaining unit employees voted to change the structure of their benefits to an RMSA. This change was effective January 1, 2011. It has been 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

The Healthcare Plan has no assets. We fund on a cash basis as benefits are paid.

Plan Contributions and Estimated Cash Flows

Contributions made to the Supplemental Non-qualified Defined Benefit Retirement Plans and the Non-pension Defined Benefit Postretirement Plan are expected to be made in the form of benefit payments. Contributions to each of the plans were as follows (in thousands):



	2011		2010
Defined Benefit Plans
Defined Benefit Pension Plan	$	—	$	8,798
Non-pension Defined Benefit Postretirement Healthcare Plan	$	428	$	657
Supplemental Non-qualified Defined Benefit Plan	$	130	$	108

Defined Contribution Plans
Company Retirement Contribution	$	371	$	171
Matching Contributions	$	1,296	$	1,029

Contributions to our employee benefit plans to be made in 2012 are as follows (in thousands):



	2012
Defined Benefit Plans
Defined Benefit Pension Plan	$	—
Non-pension Defined Benefit Postretirement Healthcare Plan	$	658
Supplemental Non-qualified Defined Benefit Plan	$	154

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	December 31, 2011
	Level 1		Level 2		Level 3		Total Fair Value
Money market fund	$	40	$	—	$	—	$	40
Registered investment companies - equity	12,743		—		—		12,743
Registered investment companies - fixed income	12,603		—		—		12,603
Common collective trust	—		16,143		—		16,143
Insurance contracts	—		1,288		—		1,288
Structured products	—		2,200		—		2,200
Total investments measured at fair value	$	25,386	$	19,631	$	—	$	45,017



Defined Benefit Pension Plan	December 31, 2010
	Level 1		Level 2		Level 3		Total Fair Value
Registered investment companies - equity	$	15,090	$	—	$	—	$	15,090
Registered investment companies - fixed income	12,952		—		—		12,952
Common collective trust	—		19,104		—		19,104
Insurance contracts	—		1,082		—		1,082
Total investments measured at fair value	$	28,042	$	20,186	$	—	$	48,228

Registered Investment Companies: Investments are valued at the closing price reported on the active market on which the individual securities are traded.

Common Collective Trust: The Pension Plan owns units of the Common Collective Trust funds that they are utilizing in their portfolio. The value of each unit of any fund as of any valuation date shall be determined by calculating the total value of such fund's assets as of the close of business on such valuation date, deducting its total liabilities as of such time and date, and then dividing the so-determined net asset value of such fund by the total number of units of such fund outstanding the date of valuation.

Insurance Contract: These investments are valued on a cash basis on any given valuation date.

Structured Products: Investments are linked by derivatives to observable financial indexes and valued through present value models.

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 Plans						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2011			2010			2011			2010			2011			2010
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	57,753		$	55,615		$	2,152		$	1,690		$	7,517		$	9,432
Service cost	798			1,215			—			—			210			340
Interest cost	3,092			3,280			114			100			365			547
Actuarial loss (gain)	852			4,129			(30		)	54			(308		)	(88		)
Amendments	—			260			—			—			—			(2,270		)
Change in participant assumptions	—			—			—			—			171			—
Discount rate change	6,668			—			186			—			433			—
Benefits paid	(2,899		)	(2,472		)	(130		)	(109		)	(707		)	(658		)
Asset transfer (to) from affiliate	(707		)	(3,300		)	—			417			(40		)	(328		)
Plan curtailment reduction	—			(974		)	—			—			—			—
Medicare Part D adjustment	—			—			—			—			67			88
Plan participants' contributions	—			—			—			—			499			454
Net increase (decrease)	7,804			2,138			140			462			690			(1,915		)
Projected benefit obligation at end of year	$	65,557		$	57,753		$	2,292		$	2,152		$	8,207		$	7,517

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



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans
	2011			2010			2011		2010		2011		2010
Beginning market value of plan assets	$	48,228		$	39,040		$	—	$	—	$	—	$	—
Investment income	66			5,361			—		—		—		—
Benefits paid	(2,899		)	(2,472		)	—		—		—		—
Employer contributions	—			8,798			—		—		—		—
Asset transfer to affiliate	(378		)	(2,499		)	—		—		—		—
Ending market value of plan assets	$	45,017		$	48,228		$	—	$	—	$	—	$	—

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



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2011			2010			2011			2010			2011			2010
Regulatory asset (liability)	$	27,284		$	18,049		$	—		$	—		$	(590	)	$	(1,050	)
Current (liability)	$	—		$	—		$	(154	)	$	(141	)	$	(658	)	$	(428	)
Non-current (liability)	$	(20,540	)	$	(9,525	)	$	(3,060	)	$	(2,011	)	$	(7,497	)	$	(7,096	)

Accumulated Benefit Obligation



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans
	2011		2010		2011		2010		2011		2010
Accumulated benefit obligation	$	59,823	$	52,250	$	2,292	$	2,058	$	8,207	$	7,517

Components of Net Periodic Expense



	Defined Benefit Pension Plans									Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2011			2010			2009			2011		2010		2009		2011			2010			2009
Service cost	$	798		$	1,214		$	1,155		$	—	$	—	$	—	$	210		$	340		$	216
Interest cost	3,093			3,280			3,143			114		100		100		365			547			444
Expected return on assets	(3,619		)	(3,008		)	(2,780		)	—		—		—		—			—			—
Amortization of prior service cost	62			62			87			—		—		—		(314		)	(141		)	—
Amortization of transition obligation	—			—			—			—		—		—		—			171			51
Amortization of loss (gain)	—			—			—			—		—		—		—			—			—
Recognized net actuarial loss (gain)	1,486			1,378			1,586			48		30		43		163			—			—
Curtailment expense	—			57			189			—		—		—		—			—			—
Net periodic expense	$	1,820		$	2,983		$	3,380		$	162	$	130	$	143	$	424		$	917		$	711

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 Plans				Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2011		2010		2011			2010			2011		2010
Net loss	$	—	$	—	$	(489	)	$	(418	)	$	—	$	—
Prior service cost	—		—		—			—			—		—
Transition obligation	—		—		—			—			—		—
	$	—	$	—	$	(489	)	$	(418	)	$	—	$	—

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 2012 were as follows (in thousands):



	Defined Benefits Pension Plans		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Plans
Net loss	$	1,689	$	36	$	90
Prior service cost	37		—		(181		)
Transition obligation	—		—		—
Total net periodic benefit cost expected to be recognized during calendar year 2011	$	1,726	$	36	$	(90	)

Assumptions



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2011		2010		2009		2011		2010		2009		2011		2010		2009
Weighted-average assumptions used to determine benefit obligations:
Discount rate	4.65	%	5.50	%	6.05	%	4.70	%	5.50	%	6.10	%	4.35	%	5.00	%	5.90	%
Rate of increase in compensation levels	3.67	%	3.70	%	4.25	%	N/A		5.00	%	5.00	%	N/A		N/A		N/A

Weighted-average assumptions used to determine net periodic benefit cost for plan year:
Discount rate	5.50	%	6.05	%	6.25	%	5.00	%	6.10	%	6.20	%	5.00	%	5.90	%	6.10	%
Expected long-term rate of return on assets*	7.75	%	8.00	%	8.50	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.70	%	4.25	%	4.25	%	N/A		5.00	%	5.00	%	N/A		N/A		N/A

_____________________________


*	The expected rate of return on plan assets changed to 7.25% for the calculation of the 2012 net periodic pension cost.

The healthcare benefit obligation was determined at December 31, 2011, using an initial healthcare trend rate of 9.01% grading down to an ultimate rate of 4.5% in 2028, and at December 31, 2010, using an initial healthcare trend rate of 9.51% trending down to an ultimate rate of 4.5% in 2027.

The healthcare cost trend rate assumption has a significant effect on the amounts reported. A 1% increase or 1% decrease in the healthcare cost trend assumptions would affect the service and interest costs and the accumulated periodic postretirement benefit obligation as follows (dollars in thousands):



Change in Assumed Trend Rate	Service and Interest Costs			Accumulated Periodic Postretirement Benefit Obligation
1% increase	$	22		$	422
1% decrease	$	(19	)	$	(372	)

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



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Plans
2012	$	3,159	$	154	$	658
2013	$	3,223	$	113	$	702
2014	$	3,258	$	113	$	652
2015	$	3,323	$	113	$	635
2016	$	3,338	$	84	$	639
2017-2021	$	19,035	$	684	$	3,886

Defined Contribution Plan

The Parent sponsors a 401(k) retirement savings plan in which 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.

(10) RELATED-PARTY TRANSACTIONS

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):



	2011		2010
Related party accounts receivable	$	6,998	$	6,891
Related party accounts payable	$	18,598	$	12,562

Money Pool Notes Receivable and Notes Payable

We have a Utility Money Pool Agreement with the Parent, Cheyenne Light and Black Hills Utility Holdings. Under the agreement, we may borrow from the Parent. The Agreement restricts us from loaning funds to the Parent or to any of the Parent's non-utility subsidiaries; the Agreement does not restrict us from making dividends to the Parent. Borrowings under the agreement bear interest at the daily cost of external funds 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%.

Advances under this note bear interest at 2.75% above the daily LIBOR rate (3.05% at December 31, 2011). We had the following balances with the Utility Money Pool as of and for the years ended December 31 (in thousands):



	2011		2010		2009
Notes receivable (payable) with Utility Money Pool, net	$	50,477	$	39,862	$	57,737

Net interest income (expense)	$	1,414	$	467	$	(1,123	)

Other Balances and Transactions

We had the following related party transactions for the years ended December 31, 2011 and 2010 included in the corresponding captions in the accompanying Statements of Income:


•	We received revenues from Black Hills Wyoming, Inc. for electricity.


•	We received revenues from Cheyenne Light for the sale of electricity and dispatch services.


•	We recorded revenues relating to payments received pursuant to a natural gas swap entered into with Enserco.


•	We purchase coal from WRDC. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.


•	We purchase excess power generated by Cheyenne Light.


•	In order to fuel our combustion turbine, we purchase natural gas from Enserco. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.


•	In addition, we also pay the Parent and Black Hills Utility Holdings for allocated corporate support service costs incurred on our behalf.


•	We have two contracts with Cheyenne Light under which Cheyenne Light sells up to 40 MW of wind-generated, renewable energy to us. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.



	2011		2010		2009
	(in thousands)
Revenues:
Black Hills Wyoming for electricity	$	9	$	574	$	873
Cheyenne Light for electricity and dispatch services	$	957	$	1,200	$	1,823

Purchases:
Coal purchases from WRDC	$	21,319	$	13,569	$	16,284
Excess power purchased from Cheyenne Light	$	9,363	$	8,664	$	8,580
Natural gas from Enserco*	$	647	$	1,652	$	2,250
Corporate support services from Parent and Black Hills Utility Holdings	$	18,567	$	17,145	$	15,014
Renewable wind energy from Cheyenne Light	$	5,236	$	4,538	$	2,791

_________________


*	BHC sold Enserco on February 29, 2012.

We have funds on deposit from Black Hills Wyoming for transmission system reserve which are included in Other, non-current liabilities on the accompanying Balance Sheets. We have transmission system reserve balances as follows as of December 31 (in thousands):

Interest on the transmission system reserve deposit accrues quarterly at an average prime rate (3.25% at December 31, 2011). We paid interest for the years ended December 31 as follows (in thousands):



	2011		2010		2009
Interest expense on transmission deposit	$	67	$	65	$	70

(11) SUPPLEMENTAL CASH FLOW INFORMATION



Years ended December 31,	2011			2010			2009
	(in thousands)
Non-cash investing activities -
Property, plant and equipment financed with accrued liabilities	$	1,882		$	7,188		$	10,191
Money pool activity - net repayment of funds loaned	$	—		$	—		$	25,000
Non-cash financing activities -
Money pool activity - net repayment of funds borrowed	$	—		$	—		$	(25,000	)

Supplemental disclosure of cash flow information:
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(16,294	)	$	(19,554	)	$	(14,252	)
Income taxes	$	(15,347	)	$	15,805		$	3,700

(12) COMMITMENTS AND CONTINGENCIES

Partial Sale of Wygen III

On April 9, 2009, we sold to MDU a 25% ownership interest in our Wygen III generation facility. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility. Proceeds of $32.8 million were received of which $30.2 million was used to pay down a portion of Parent debt. MDU continued to reimburse us for its 25% of the total costs paid to complete the project. The Wygen III generation facility began commercial operations on April 1, 2010. In conjunction with the sales transaction, we also modified a 2004 PPA between us and MDU.

On July 14, 2010, we sold a 23% ownership interest in Wygen III to the City of Gillette for $62.0 million. The purchase terminates the current PPA with the City of Gillette, and the Wygen III Participation Agreement has been amended to include the City of Gillette. The Participation Agreement provides that the City of Gillette will pay us for administrative services and share in the costs of operating the plant for the life of the facility. The estimated amount of net fixed assets sold totaled $55.8 million. We recognized a gain on the sale of $6.2 million.

Power Purchase and Transmission Services Agreements

We have the following power purchase and transmission agreements as of December 31, 2011:


•	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;


•	Cheyenne Light entered into a PPA with 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;


•	Cheyenne Light entered into a PPA with 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; and


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

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



Contract	Contract Type	2011		2010		2009
PacifiCorp	Electric capacity and energy	$	12,515	$	12,936	$	11,862
PacifiCorp	Transmission access	$	1,215	$	1,215	$	1,215
Cheyenne Light	Happy Jack Wind Farm	$	1,955	$	2,815	$	2,078
Cheyenne Light	Silver Sage Wind Farm	$	3,281	$	1,723	$	713

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



2012	$	11,895
2013	$	11,895
2014	$	11,895
2015	$	11,895
2016	$	11,895
Thereafter	$	49,091

Long-Term Power Sales Agreements

We have the following power sales agreements as of December 31, 2011:


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

•

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


•	An agreement under which we supply energy and capacity to MEAN expiring on May 31, 2023. This contract is unit-contingent based on up to 10 MW from our Neil Simpson II and up to 10 MW from our Wygen III plants. The capacity purchase requirements decrease over the term of the agreement.


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

Legal Proceedings

We are subject to various legal proceedings, claims and litigation which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect our financial position, results of operations or cash flows.

(13) 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
2011
Operating revenues	$	59,194	$	56,098	$	64,940	$	65,399
Operating income	$	11,917	$	9,181	$	19,175	$	14,447
Net income	$	5,881	$	3,741	$	10,510	$	6,965

2010
Operating revenues	$	54,489	$	56,438	$	59,051	$	59,785
Operating income	$	9,361	$	10,510	$	21,092	$	14,305
Net income	$	5,934	$	4,102	$	14,078	$	7,154

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, 2011 and concluded that, because of the material weakness in our internal control over financial reporting related to accounting for income taxes discussed below, our disclosure controls and procedures were not effective as of December 31, 2011. Additional review, evaluation and oversight have been undertaken to ensure our financial statements were prepared in accordance with generally accepted accounting principles and as a result, our management, including our Chief Executive Officer and Chief Financial Officer, have concluded that the financial statements in this Form 10-K fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in conformity with accounting principles generally accepted in the United States.

Management's Report on Internal Control over Financial Reporting

We are 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, 2011, based on the criteria set forth in Internal Control - Integrated Framework 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, including consideration of the internal control deficiencies discussed below, we have concluded that our internal control over financial reporting was not effective as of December 31, 2011. Specifically, we determined that the following internal control deficiencies when considered in the aggregate constitute a material weakness in internal control over financial reporting related to accounting for income taxes.


•	The assessment of the impact of certain non-routine transactions on the accuracy of our year-end income tax provision was not effective.


•	Tax resources were not sufficient to effectively prepare and review the analysis of tax accounts.


•	Communication between the tax department and the Controller organization was not effective to ensure income tax accounting consequences were adequately considered.

A material weakness is a deficiency, or combination of deficiencies, that result in a reasonable possibility that a material misstatement of a company's annual or interim financial statements will not be prevented or detected on a timely basis. While the above noted deficiencies did not result in a material misstatement to our annual financial statements, these deficiencies could if not remediated, result in a material misstatement of future financial statements.

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

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2011, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

While no changes to our internal controls over financial reporting are noted during the quarter ended December 31, 2011, a material weakness was identified as set forth in “Management's Report on Internal Control over Financial Reporting” above. Management believes the measures described below will remediate the identified control deficiencies and enhance our internal controls over financial reporting:


•	Increase tax department resources to ensure completion and documentation of a more thorough analysis that supports our calculation of the effective tax rate and valuation of deferred tax assets and liabilities.


•	Implement formal periodic meetings among the Chief Financial Officer, Controller and the tax department to ensure adequate consideration of items that may impact income tax accounting.

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, 2011 and 2010 by our independent registered public accounting firm, Deloitte & Touche LLP (in thousands):



Deloitte & Touche LLP	2011		2010
Audit Fees	$	336	$	335
Tax Fees	22		157
Audit-related fees	—		48
Total	$	358	$	540

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, and 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 establish pre-approval fee levels for each category of services to be provided, including audit, audit-related, tax and other services. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee.



ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(a)	1.	Financial Statements

		Financial statements required by Item 15 are listed in the index included in Item 8 of Part II.

	2.	Schedules

Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2011, 2010 and 2009



		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, 2011, 2010 AND 2009

Description	Balance at beginning of year		Additions Charged to costs and expenses		Deductions			Balance at end of year
	(in thousands)
Allowance for doubtful accounts:
2011	$	230	$	551	$	(638	)	$	143
2010	$	259	$	499	$	(528	)	$	230
2009	$	370	$	316	$	(427	)	$	259

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 JPMorgan 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)).

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*	Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).

23	Independent Auditors' Consent

31.1	Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	Financials for XBRL Format

_________________________


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


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


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

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

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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		BLACK HILLS POWER, INC.

		By	/s/ DAVID R. EMERY
		David R. Emery, Chairman and
		Chief Executive Officer

Dated:	March 12, 2012

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	March 12, 2012
David R. Emery, Chairman and	Principal Executive Officer
Chief Executive Officer

/s/ ANTHONY S. CLEBERG	Principal Financial and	March 12, 2012
Anthony S. Cleberg, Executive Vice President	Accounting Officer
and Chief Financial Officer

/s/ DAVID C. EBERTZ	Director	March 12, 2012
David C. Ebertz

/s/ JACK W. EUGSTER	Director	March 12, 2012
Jack W. Eugster

/s/ JOHN R. HOWARD	Director	March 12, 2012
John R. Howard

/s/ STEVEN R. MILLS	Director	March 12, 2012
Stephen R. Mills

/s/ STEPHEN D. NEWLIN	Director	March 12, 2012
Stephen D. Newlin

/s/ GARY L. PECHOTA	Director	March 12, 2012
Gary L. Pechota

/s/ REBECCA B. ROBERTS	Director	March 12, 2012
Rebecca B. Roberts

/s/ WARREN L. ROBINSON	Director	March 12, 2012
Warren L. Robinson

/s/ JOHN B. VERING	Director	March 12, 2012
John B. Vering

/s/ THOMAS J. ZELLER	Director	March 12, 2012
Thomas J. Zeller

INDEX TO EXHIBITS



Exhibit Number	Description

3.1*	Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)).

3.2*	Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant's Form 10-K for 2000).

3.3*	Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999).

4.1*	Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan 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)).

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*	Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).

23	Independent Auditors' Consent

31.1	Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	Financial Statements for XBRL Format

_________________________


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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Transmission Deposit