Edgar Filing: BLACK HILLS CORP /SD/

BKH 10K 12 31 2011

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



o	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 001-31303

BLACK HILLS CORPORATION



Incorporated in South Dakota	625 Ninth Street	IRS Identification Number
	Rapid City, South Dakota 57701	46-0458824
Registrant's telephone number, including area code (605) 721-1700

Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common stock of $1.00 par value		New York Stock Exchange

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 o

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 o No x

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 o

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 o

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. 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 x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

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

Yes o No x

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

At June 30, 2011 $1,169,775,169

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



Class	Outstanding at January 31, 2012
Common stock, $1.00 par value	43,929,272	shares

Documents Incorporated by Reference

Portions of the Registrant's Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2012 Annual Meeting of Stockholders to be held on May 23, 2012, are incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS



			Page
		GLOSSARY OF TERMS AND ABBREVIATIONS	3

		ACCOUNTING PRONOUNCEMENTS	6

		WEBSITE ACCESS TO REPORTS	8

		FORWARD-LOOKING INFORMATION	8
Part I
	ITEMS 1. and 2.	BUSINESS AND PROPERTIES	11

	ITEM 1A.	RISK FACTORS	53

	ITEM 1B.	UNRESOLVED STAFF COMMENTS	66

	ITEM 3.	LEGAL PROCEEDINGS	67

	ITEM 4.	SPECIALIZED DISCLOSURES	67
Part II
	ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	68

	ITEM 6.	SELECTED FINANCIAL DATA	70

	ITEMS 7. and 7A.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	73

	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	123

	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	193

	ITEM 9A.	CONTROLS AND PROCEDURES	193

	ITEM 9B.	OTHER INFORMATION	195
Part III
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	196

	ITEM 11.	EXECUTIVE COMPENSATION	197

	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	197

	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	197

	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	197

	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	198

		SIGNATURES	212

		INDEX TO EXHIBITS	213

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
Aquila	Aquila, Inc.
Aquila Transaction	Our July 14, 2008 acquisition of five utilities from Aquila
ARO	Asset Retirement Obligations
Basin Electric	Basin Electric Power Cooperative
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BHC	Black Hills Corporation; the Company
BHCCP	Black Hills Corporation Credit Policy
BHCRPP	Black Hills Corporation Risk Policies and Procedures
BHEP	Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Colorado IPP	Black Hills Colorado IPP, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation
Black Hills Energy	The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
BLM	United States Bureau of Land Management
Btu	British thermal unit
CFTC	United States Commodity Futures Trading Commission
CG&A	Cawley, Gillespie & Associates, Inc., an independent consulting and engineering firm
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
Cheyenne Light Pension Plan	The Cheyenne Light, Fuel and Power Company Pension Plan



City of Gillette	The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase of 23% of Wygen III power plant for the City of Gillette
CO₂	Carbon dioxide
Colorado Electric	Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas	Black Hills Colorado Gas Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Cooling Degree Day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CT	Combustion turbine
DC	Direct current
De-designated interest rate swaps	The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under the accounting for derivatives and hedges but subsequently de-designated in December 2008
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE	United States Department of Energy
Dth	Dekatherms
EBITDA	Earnings before interest, taxes, depreciation and amortization, a Non-GAAP measurement
ECA	Energy Cost Adjustment
Enserco	Enserco Energy Inc., a wholly-owned subsidiary of Black Hills Non-regulated Holdings, which is presented in discontinued operations throughout this Annual Report filed on Form 10-K
EPA	United States Environmental Protection Agency
EPA Region VIII	EPA Region VIII (Mountains and Plains) located in Denver, Colorado serving Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming and 27 Tribal Nations
Equity Forward Agreement	Equity Forward Agreement with J. P. Morgan connected to a public offering of 4,413,519 million shares of Black Hills Corporation common stock, including the over-allotment shares
ERISA	Employee Retirement Income Security Act
EWG	Exempt Wholesale Generator
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
FTC	Federal Trade Commission
GAAP	Accounting principles generally accepted in the United States of America
GCA	Gas Cost Adjustment
GE	General Electric Company
GHG	Greenhouse gases
Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
Happy Jack	Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Hastings	Hastings Fund Management Ltd



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.
IGCC	Integrated Gasification Combined Cycle
IIF	IIF BH Investment LLC, a subsidiary of an investment entity advised by J.P. Morgan Asset Management



Iowa Gas	Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP	Independent power producer
IPP Transaction	The July 11, 2008 sale of seven of our IPP plants to affiliates of Hastings and IIF
IRS	United States Internal Revenue Service
IUB	Iowa Utilities Board
J.P. Morgan	J.P. Morgan Securities LLC
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.
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
KCC	Kansas Corporation Commission
kV	Kilovolt
KW	Kilowatt
KWh	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
MACT	Maximum Achievable Control Technology
MAPP	Mid-Continent Area Power Pool
MATS	Utility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
Mbbl	Thousand barrels of oil
Mcf	Thousand cubic feet
Mcfe	Thousand cubic feet equivalent
MDU	Montana Dakota Utilities Co., a regulated utility division of MDU Resources Group, Inc.
MEAN	Municipal Energy Agency of Nebraska
MMBtu	Million British thermal units
MMcf	Million cubic feet
MMcfe	Million cubic feet equivalent
Moody's	Moody's Investors Service, Inc.
MSHA	Mine Safety and Health Administration
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
Native load	Energy required to serve customers within our service territory
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NERC	North American Electric Reliability Corporation
NGL	Natural Gas Liquids
NO_x	Nitrogen oxide



NOL	Net operating loss
NPA	Nebraska Power Association
NPDES	National Pollutant Discharge Elimination System
NPSC	Nebraska Public Service Commission
NQDC	Non-Qualified Deferred Compensation Plan initially adopted in 1999
NYMEX	New York Mercantile Exchange
OCA	Office of Consumer Advocate
OPEC	Organization of the Petroleum Exporting Countries
OSHA	Occupational Safety & Health Administration
PCA	Power Cost Adjustment
Peak demand	Peak demand represents the highest point of customer usage for a single hour
PGA	Purchased Gas Adjustment
PPA	Power Purchase Agreement
PPACA	Patient Protection and Affordable Care Act of 2010
PSCo	Public Service Company of Colorado
PUD	Proved undeveloped reserves
PUHCA 2005	Public Utility Holding Company Act of 2005
PURPA	Public Utility Regulatory Policies Act of 1978
RCRA	Resource Conservation and Recovery Act
Revolving Credit Facility	Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, originally expiring April 14, 2013. We entered into a new facility in February 2012 which expires in 2017.
S&S	Significant and Substantial as defined by Mine Safety Act
SCADA	Supervisory Control and Data Acquisition
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO₂	Sulfur dioxide
S&P	Standard & Poor's, a division of The McGraw-Hill Companies, Inc.
TCA	Transmission Cost Adjustment
Twin Eagle	Twin Eagle Resource Management, LLC
VEBA	Voluntary Employee Benefit Association
VIE	Variable Interest Entity
WDEQ	Wyoming Department of Environmental Quality
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

ACCOUNTING PRONOUNCEMENTS



ASC	Accounting Standards Codification
ASC 220	ASC 220, "Comprehensive Income"
ASC 820	ASC 820, "Fair Value Measurements and Disclosures"
ASC 932-10-S99	ASC 932-10-S99, "Extractive Activities - Oil and Gas, SEC Materials"
ASU	Accounting Standards Update
ASU 2011-04	ASU 2011-04, "Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS"
ASU 2011-05	ASU 2011-05, "Comprehensive Income: Presentation of Comprehensive Income"
ASU 2011-08	ASU 2011-08, "Intangibles - Goodwill and Other: Testing Goodwill for Impairment"
ASU 2011-12	ASU 2011-12, "Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05"
IFRS	International Financial Reporting Standards

Website Access to Reports

The reports we file with the SEC are available free of charge at our website www.blackhillscorp.com as soon as reasonably practicable after they are filed. In addition, the charters of our Audit, Governance and Compensation Committees are located on our website along with our Code of Business Conduct, Code of Ethics for our Chief Executive Officer and Senior Finance Officers, Corporate Governance Guidelines of the Board of Directors and Policy for Director Independence. The information contained on our website is not part of this document.

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:


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


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


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


•	Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emissions 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, or which could require closure of one or more of our generating units;


•	Changes in business, regulatory compliance and financial reporting practices and subsequent rules and regulations;


•	The effect of Dodd-Frank and the regulations to be adopted thereunder on our use of derivative instruments in connection with our activities to hedge our expected production of crude oil and natural gas and on our use of interest rate derivative instruments;


•	Changes in state laws or regulations that could cause us to curtail our business activities;


•	Our ability to successfully integrate and profitably operate any future acquisitions;


•	Our ability to successfully complete the sale of Enserco Energy Inc. to Twin Eagle Resource Management, LLC for net cash proceeds of approximately $160 million to $170 million, subject to working capital and other closing adjustments;


•	Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel, transportation, transmission and purchased power in our regulated utilities;


•	Our ability to receive regulatory approval to recover in rate base our expenditures for new power generation facilities or other utility infrastructure;


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


•	The extent of our success in connecting natural gas supplies to gathering, processing and pipeline systems;


•	Our ability to minimize losses related to defaults on amounts due from customers and counterparties, including counterparties to trading and other commercial transactions;


•	The timing and extent of scheduled and unscheduled outages of power generation facilities;


•	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 accurately estimate demand from our customers for natural gas;


•	Weather and other natural phenomena;

•

Our ability to meet forecasted production volumes for our oil and gas properties, which may be dependent upon issuance by federal, state and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force and equipment, or the possibility of reductions in our drilling program resulting from the current economic climate and commodity prices, which also may prevent us from maintaining production rates and replacing reserves for our oil and gas properties;


•	The amount of collateral required to be posted from time to time in our transactions;


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


•	Our ability to provide accurate estimates of proved oil and gas reserves, coal reserves and future production rates and associated costs;


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


•	Our ability to successfully maintain our corporate credit rating;


•	The impact of the pending sale of Enserco Energy Inc., our non-regulated energy marketing business, on reducing our risk profile, improving our credit metrics and enhancing our ability to produce more stable cash flows and earnings;


•	Our ability to access revolving credit capacity and comply with loan covenants;


•	Capital market conditions and market uncertainties related to interest rates, which may affect our ability to raise capital on favorable terms;


•	The amount and timing of capital deployment in new investment opportunities or for the repurchase of debt or stock;


•	Our ability to continue paying our regular quarterly dividend;


•	Our ability to obtain permanent financing for capital expenditures on reasonable terms either through long-term debt or issuance of equity;


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


•	The accounting treatment and earnings impact associated with interest rate swaps;


•	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;


•	The possibility that we may be required to take impairment charges under the SEC's full cost ceiling test for the accumulated costs of our natural gas and oil reserves;


•	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;


•	Additional liabilities for environmental conditions, including remediation and reclamation obligations, under environmental laws;


•	Our ability to successfully complete labor negotiations with labor unions with which we have collective bargaining agreements and for which we are currently in, or are soon to be in, contract renewal negotiations; and


•	The cost and effect on our business, including insurance, resulting from terrorist actions and cyber-attacks or responses to such actions or events.

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.

PART I


ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

History and Organization

Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the "Company," "we," "us" and "our"), is a diversified energy company headquartered in Rapid City, South Dakota. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility service in 1941. It was formed through the purchase and combination of several existing electric utilities and related assets, some of which had served customers in the Black Hills region since 1883. In 1956, the Company began producing, selling and marketing various forms of energy through its non-regulated business.

We operate principally in the United States with two major business groups: Utilities and Non-regulated Energy. Our Utilities Group is comprised of our regulated Electric Utilities and regulated Gas Utilities segments, and our Non-regulated Energy Group is comprised of our Oil and Gas, Power Generation, and Coal Mining segments.

For more than 15 years, we have also owned and operated an energy marketing business, Enserco, which engages in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. In the fourth quarter of 2011, we made the decision to sell Enserco, which constitutes our entire non-regulated Energy Marketing segment. On January 18, 2012, we entered into a definitive agreement to sell all of the outstanding stock of Enserco, which resulted in the Energy Marketing segment being reported as discontinued operations. This transaction is expected to close in the first quarter of 2012. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment to discontinued operations on a consistent basis. See Note 23 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.



Business Group	Financial Segment
Utilities	Electric Utilities
	Gas Utilities

Non-regulated Energy	Oil and Gas
	Power Generation
	Coal Mining

Our Electric Utilities segment generates, transmits and distributes electricity to approximately 201,500 electric customers in South Dakota, Wyoming, Colorado and Montana and includes the operations of Cheyenne Light, a combination electric and gas utility, and its approximately 34,800 gas utility customers in Wyoming. Our Gas Utilities segment serves approximately 528,800 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 865 MWs of generation and 8,496 miles of electric transmission and distribution lines, and our Gas Utilities own 624 miles of intrastate gas transmission pipelines and 19,747 miles of gas distribution mains and service lines. Our Electric and Gas Utilities generated net income of $81.9 million for the year ended December 31, 2011 and had total assets of $3.0 billion at December 31, 2011.

Our Oil and Gas segment engages in the exploration, development and production of crude oil and natural gas, primarily in the Rocky Mountain region. Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy primarily to other utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, Wyoming. Our Non-regulated Energy Group generated net income of $0.9 million for the year ended December 31, 2011 and had total assets of $0.6 billion at December 31, 2011.

Segment Financial Information

We discuss our business strategy and other prospective information in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations. Financial information regarding our business segments is incorporated herein by reference to Item 8 - Financial Statements and Supplementary Data, and particularly Note 17 to the Consolidated Financial Statements, in this Annual Report on Form 10-K.

Discontinued Operations in the accompanying financial information includes the results of our Energy Marketing segment.

Business Group Overview

Utilities Group

We conduct electric utility operations and combination electric and gas utility operations through three subsidiaries: Black Hills Power (South Dakota, Wyoming and Montana), Cheyenne Light (Wyoming), and Colorado Electric (Colorado). Our Electric Utilities generate, transmit and distribute electricity to approximately 201,500 customers in South Dakota, Wyoming, Colorado and Montana. Additionally, Cheyenne Light distributes natural gas to approximately 34,800 natural gas utility customers in Wyoming. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

We conduct natural gas utility operations on a state-by-state basis through our Colorado Gas, Nebraska Gas, Iowa Gas and Kansas Gas subsidiaries. Our Gas Utilities distribute and transport natural gas through our distribution network to approximately 528,800 customers in Colorado, Nebraska, Iowa and Kansas. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

In addition to our regulated operations, we also provide non-regulated services through our Service Guard and Tech Services product lines. Service Guard primarily provides appliance repair services to approximately 63,000 residential customers through company technicians and third party service providers in Colorado, Iowa, Kansas and Nebraska most typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing customer-owned gas infrastructure facilities, typically through one-time contracts, with a limited number of on-going monthly maintenance agreements.

Electric Utilities Segment

Capacity and Demand

System peak demands for the Electric Utilities for each of the last three years are listed below:



	System Peak Demand (in MW)

	2011		2010		2009
	Summer	Winter	Summer	Winter	Summer	Winter

Black Hills Power	452	408	396	377	387	392
Cheyenne Light	181	175	176	164	169	171
Colorado Electric	392	297	384	289	365	296
Total Electric Utilities Peak Demands	1,025	880	956	830	921	859

Regulated Power Plants

As of December 31, 2011, our Electric Utilities' ownership interests in electric generation plants were as follows:



Unit	Fuel Type	Location	Ownership Interest %	Owned/Leased Capacity (MW)	Year Installed
Black Hills Power:
Wygen III⁽¹⁾	Coal	Gillette, WY	52.0%	57.2	2010
Neil Simpson II	Coal	Gillette, WY	100.0%	90.0	1995
Wyodak ⁽²⁾	Coal	Gillette, WY	20.0%	72.4	1978
Osage ⁽³⁾	Coal	Osage, WY	100.0%	34.5	1948-1952
Ben French	Coal	Rapid City, SD	100.0%	25.0	1960
Neil Simpson I	Coal	Gillette, WY	100.0%	21.8	1969
Neil Simpson CT	Gas	Gillette, WY	100.0%	40.0	2000
Lange CT	Gas	Rapid City, SD	100.0%	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, SD	100.0%	10.0	1965
Ben French CTs #1-4 ⁽⁴⁾	Gas/Oil	Rapid City, SD	100.0%	100.0	1977-1979
Cheyenne Light:
Wygen II	Coal	Gillette, WY	100.0%	95.0	2008
Colorado Electric:
Pueblo Airport Generation	Gas	Pueblo, CO	100.0%	180.0	2011
Capital Lease - Colorado IPP⁽⁵⁾	Gas	Pueblo, CO	—%	200.0	2011
W.N. Clark #1-2⁽⁶⁾	Coal	Canon City, CO	100.0%	40.0	1955, 1959
Pueblo #6	Gas	Pueblo, CO	100.0%	20.0	1949
Pueblo #5	Gas	Pueblo, CO	100.0%	9.0	1941, 2001
AIP Diesel	Oil	Pueblo, CO	100.0%	10.0	2001
Diesel #1-5	Oil	Pueblo, CO	100.0%	10.0	1964
Diesel #1-5	Oil	Rocky Ford, CO	100.0%	10.0	1964
Total MW Owned Capacity				1,064.9

________________________


(1)	Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by Black Hills Power. Black Hills Power has a 52% ownership interest in Wygen III, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our WRDC coal mine furnishes all of the fuel supply for the plant.


(2)	Wyodak, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by Black Hills Power. This baseload plant is operated by PacifiCorp and our WRDC coal mine furnishes all of the 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.


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


(5)	Colorado Electric entered into a 20-year PPA with Black Hills Colorado IPP for 200 MW of power from their gas-fired plants. This PPA, accounted for as a capital lease, was effective on January 1, 2012 upon completion of construction of the plants.


(6)	In December 2010, Colorado Electric received a final order from the CPUC that approved the retirement of its W.N. Clark coal-fired generation facility by December 31, 2013.

The following table shows the Electric Utilities' annual average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per MWh (dollars per MWh):



Fuel Source	2011		2010		2009
Coal	$	15.89	$	12.77	$	13.99

Gas and Oil	$	150.00	$	131.28	$	85.52

Total Average Fuel Cost	$	16.77	$	13.57	$	15.22

Purchased Power - Coal, Gas and Oil	$	28.80	$	29.57	$	28.44

Purchased Power - Renewable Sources	$	46.71	$	45.76	$	43.66

The following table shows our Electric Utilities' power supply, by resource as a percent of the total power supply for our energy needs:



Power Supply	2011		2010		2009
Coal-fired	38	%	42	%	39	%
Gas and Oil	—		—		1
Total Generated	38		42		40
Purchased	62		58		60
Total	100	%	100	%	100	%

Purchased Power. Various agreements have been executed to support our Electric Utilities' capacity and energy needs beyond our regulated power plants' generation. Key contracts include:


•	Black Hills Power's PPA with PacifiCorp expiring in 2023, which provides for the purchase of 50 MW of coal-fired baseload power;


•	Black Hills Power's reserve capacity integration agreement with PacifiCorp expiring in June 2012, which makes available 100 MW of reserve capacity in connection with the utilization of the Ben French CT units;


•	Colorado Electric's PPA with Black Hills Colorado IPP expiring in 2031, which provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP's combined-cycle turbines;


•	Colorado Electric's PPA with PSCo expiring at December 31, 2012, whereby Colorado Electric purchases 50 MW of economy energy;


•	Colorado Electric's PPA with Cargill expiring at December 31, 2013, whereby Colorado Electric purchases 50 MW of economy energy;


•	Cheyenne Light's PPA with Black Hills Wyoming expiring in August 2014, whereby Black Hills Wyoming provides 40 MW of energy and capacity from its Gillette CT;

•

Cheyenne Light's PPA with Black Hills Wyoming expiring December 31, 2022, whereby Black Hills Wyoming provides 60 MW of unit-contingent capacity and energy from its Wygen I facility. The PPA includes an option for Cheyenne Light to purchase Black Hills Wyoming's ownership interest in the Wygen I facility between 2013 and 2019. The purchase price related to the option is $2.55 million per MW. This option price is reduced annually by an amount of annual depreciation assuming a facility life of 35 years;


•	Cheyenne Light's 20-year PPA with Duke Energy expiring in 2028, which provides up to 29.4 MW of wind energy from the Happy Jack Wind Farm to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 50% of the facility's output to Black Hills Power;


•	Cheyenne Light and Black Hills Power's Generation Dispatch Agreement requires Black Hills Power to purchase all of Cheyenne Light's excess energy; and


•	Cheyenne Light's 20-year PPA with Duke Energy expiring in 2029, which provides up to 30 MW of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 20 MW of energy from Silver Sage to Black Hills Power.

Power Sales Agreements. Our Electric Utilities have various long-term power sales agreements. Key agreements 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, Black Hills Power 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, Black Hills Power 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, Black Hills Power will also provide the City of Gillette their operating component of spinning reserves;


•	Black Hills Power's agreement to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchase over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:



2012-2017	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;


•	Black Hills Power's PPA with MEAN, whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III through May 2015; and


•	Cheyenne Light's agreement with Basin Electric, whereby Cheyenne Light will supply 40 MW of capacity and energy through March 31, 2013 and a separate agreement whereby Cheyenne Light will receive 40 MW of capacity and energy from Basin Electric through March 31, 2013.

Transmission and Distribution. Through our Electric Utilities, we own electric transmission systems composed of high voltage transmission lines (greater than 69 kV) and low voltage lines (69 or fewer kV). We also jointly own high voltage lines with Basin Electric and Powder River Energy Corporation.

At December 31, 2011, our Electric Utilities owned or leased the electric transmission and distribution lines shown below:



Utility	State	Transmission (in Line Miles)	Distribution (in Line Miles)
Black Hills Power	SD, WY	618	2,999
Black Hills Power - Jointly Owned ⁽¹⁾	SD, WY	47	—
Cheyenne Light	SD, WY	25	1,235
Colorado Electric	CO	243	3,329

(1)

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

Black Hills Power has 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.

Black Hills Power also has 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.

In order to serve Cheyenne Light's existing load, Cheyenne Light has a network transmission agreement with Loveland Area Project.

Shared Services Agreement. Black Hills Power, Cheyenne Light, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity charges for the use of assets by the affiliate entity. Black Hills Colorado IPP and Colorado Electric are also parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric assets.

Operating Statistics

The following tables summarize sales revenue, quantities and customers for our Electric Utilities:



Revenue - Electric (in thousands)	2011		2010		2009

Residential:
Black Hills Power	$	59,826	$	53,549	$	48,586
Cheyenne Light	31,287		29,506		29,198
Colorado Electric	84,646		76,596		66,548
Total Residential	175,759		159,651		144,332

Commercial:
Black Hills Power	72,889		65,997		59,897
Cheyenne Light	55,331		52,765		51,280
Colorado Electric	73,355		66,490		56,002
Total Commercial	201,575		185,252		167,179

Industrial:
Black Hills Power	25,723		22,621		20,014
Cheyenne Light	11,629		10,542		11,121
Colorado Electric	33,332		28,812		31,067
Total Industrial	70,684		61,975		62,202

Municipal:
Black Hills Power	3,172		3,029		2,735
Cheyenne Light	1,765		1,293		932
Colorado Electric	12,912		10,443		4,408
Total Municipal	17,849		14,765		8,075

Subtotal Retail Revenue - Electric	465,867		421,643		381,788

Contract Wholesale:
Black Hills Power	18,105		22,996		25,358

Off-system Wholesale:
Black Hills Power	34,889		36,354		32,212
Cheyenne Light	9,371		9,750		8,565
Colorado Electric *	13,018		10,859		14,008
Total Off-system Wholesale	57,278		56,963		54,785

Other Revenue:
Black Hills Power	31,027		25,217		18,277
Cheyenne Light	2,449		3,230		718
Colorado Electric	2,787		2,374		4,226
Total Other Revenue	36,263		30,821		23,221

Total Revenue - Electric	$	577,513	$	532,423	$	485,152

_____________________


*	Off-system sales revenue had been deferred by Colorado Electric from August 2010 until December 2011, when the CPUC approved a sharing mechanism as part of the rate case settlement allowing Colorado Electric a 25% share of off-system sales operating income. Revenue in 2011 represents off-system sales from August 2010 through December 2011.



Quantities Generated and Purchased (MWh)	2011	2010	2009

Generated -
Coal-fired:
Black Hills Power	1,717,008	1,987,037	1,721,074
Cheyenne Light	674,518	734,241	766,943
Colorado Electric	268,317	257,896	252,603
Total Coal	2,659,843	2,979,174	2,740,620

Gas and Oil-fired:
Black Hills Power	15,221	19,269	46,723
Cheyenne Light	—	—	—
Colorado Electric	2,342	930	2,705
Total Gas and Oil	17,563	20,199	49,428

Total Generated:
Black Hills Power	1,732,229	2,006,306	1,767,797
Cheyenne Light	674,518	734,241	766,943
Colorado Electric	270,659	258,826	255,308
Total Generated	2,677,406	2,999,373	2,790,048

Purchased -
Black Hills Power	1,720,640	1,440,579	1,686,455
Cheyenne Light	745,983	696,756	651,201
Colorado Electric	1,948,321	1,969,896	1,991,058
Total Purchased ^(a)	4,414,944	4,107,231	4,328,714

Total Generated and Purchased	7,092,350	7,106,604	7,118,762

_______________

(a) Includes 189,255 MWh, 167,520 MWh, and 105,830 MWh in 2011, 2010 and 2009, respectively of wind power purchased.



Quantities (MWh)	2011	2010	2009

Residential:
Black Hills Power	550,935	547,193	529,825
Cheyenne Light	264,492	261,607	255,134
Colorado Electric	629,752	628,553	589,526
Total Residential	1,445,179	1,437,353	1,374,485

Commercial:
Black Hills Power	720,978	720,119	723,360
Cheyenne Light	601,162	603,323	583,986
Colorado Electric	720,060	726,005	666,563
Total Commercial	2,042,200	2,049,447	1,973,909

Industrial:
Black Hills Power	408,337	382,562	353,041
Cheyenne Light	172,840	161,082	174,792
Colorado Electric	351,862	347,673	452,584
Total Industrial	933,039	891,317	980,417

Municipal:
Black Hills Power	34,235	33,908	33,948
Cheyenne Light	9,827	6,477	3,456
Colorado Electric	126,320	113,689	37,244
Total Municipal	170,382	154,074	74,648

Subtotal Retail Quantities Sold	4,590,800	4,532,191	4,403,459

Contract Wholesale:
Black Hills Power	349,520	468,782	645,297

Off-system Wholesale:
Black Hills Power	1,226,548	1,163,058	1,009,574
Cheyenne Light	278,528	311,524	309,122
Colorado Electric	282,929	274,942	373,495
Total Off-system Wholesale	1,788,005	1,749,524	1,692,191

Total Quantity Sold:
Black Hills Power	3,290,553	3,315,622	3,295,045
Cheyenne Light	1,326,849	1,344,013	1,326,490
Colorado Electric	2,110,923	2,090,862	2,119,412
Total Quantity Sold	6,728,325	6,750,497	6,740,947

Losses and Company Use:
Black Hills Power	162,316	131,263	159,207
Cheyenne Light	93,652	86,984	91,654
Colorado Electric	108,057	137,860	126,954
Total Losses and Company Use	364,025	356,107	377,815

Total Energy	7,092,350	7,106,604	7,118,762



Customers at End of Year	2011	2010	2009
Residential:
Black Hills Power	54,955	54,811	54,470
Cheyenne Light	35,159	34,913	35,943
Colorado Electric	81,811	81,902	81,622
Total Residential	171,925	171,626	172,035

Commercial:
Black Hills Power	12,864	12,779	12,261
Cheyenne Light	4,277	4,132	4,932
Colorado Electric	11,206	11,185	11,101
Total Commercial	28,347	28,096	28,294

Industrial:
Black Hills Power	45	40	38
Cheyenne Light	2	2	2
Colorado Electric	68	63	90
Total Industrial	115	105	130

Other Electric Customers:
Black Hills Power	311	309	143
Cheyenne Light	243	254	13
Colorado Electric	506	510	499
Total Other Electric Customers	1,060	1,073	655

Subtotal Retail Customers	201,447	200,900	201,114

Contract Wholesale:
Black Hills Power	3	3	3

Total Customers:
Black Hills Power	68,178	67,942	66,915
Cheyenne Light	39,681	39,301	40,890
Colorado Electric	93,591	93,660	93,312
Total Customers at Year-End	201,450	200,903	201,117



Degree Days	2011		2010		2009
	Actual	Variance from 30-Year Average	Actual	Variance from 30-Year Average	Actual	Variance from 30-Year Average
Heating Degree Days:
Black Hills Power	7,579	5%	7,272	1%	7,753	8%
Cheyenne Light	7,321	(1)%	7,033	(5)%	7,411	—%
Colorado Electric	5,749	3%	5,518	(1)%	5,546	(1)%

Cooling Degree Days:
Black Hills Power	700	17%	532	(11)%	354	(41)%
Cheyenne Light	431	58%	345	26%	203	(26)%
Colorado Electric	1,259	37%	1,074	16%	804	(13)%

Cheyenne Light Natural Gas Distribution

Cheyenne Light's natural gas distribution system serves natural gas customers in Cheyenne and other portions of Laramie County, Wyoming. The following table summarizes certain operating information:



	2011		2010		2009

Revenue - Gas (in thousands):
Residential	$	22,044	$	22,562	$	21,495
Commercial	10,264		10,801		9,821
Industrial	3,597		3,425		3,537
Other Sales Revenue	913		803		760
Total Revenue - Gas	$	36,818	$	37,591	$	35,613

Gross Margin (in thousands):
Residential	$	10,426	$	10,004	$	10,219
Commercial	3,345		3,376		3,266
Industrial	504		427		509
Other Gross Margin	545		720		760
Total Gross Margin	$	14,820	$	14,527	$	14,754

Volumes Sold (Dth):
Residential	2,585,056		2,636,839		2,516,699
Commercial	1,538,616		1,572,638		1,502,002
Industrial	689,935		667,062		722,776
Total Volumes Sold	4,813,607		4,876,539		4,741,477

Customers at Year-End	34,807		34,461		33,942

Gas Utilities Segment

At December 31, 2011, our Gas Utilities owned the gas transmission and distribution lines by state shown below (in line miles):



	Intrastate Gas Transmission Pipelines	Gas Distribution Mains	Gas Distribution Service Lines

Colorado	124	2,987	886
Nebraska	44	3,432	3,481
Iowa	170	2,762	2,321
Kansas	286	2,582	1,296
Total	624	11,763	7,984

Operating Statistics

The following tables summarize revenue, gross margin, volumes, degree days and customers for our Gas Utilities:



Revenue (in thousands)	2011		2010		2009

Residential:
Colorado	$	58,102	$	55,211	$	62,732
Nebraska	125,493		120,365		127,120
Iowa	106,292		105,255		113,781
Kansas	65,185		69,859		70,848
Total Residential	355,072		350,690		374,481

Commercial:
Colorado	12,172		11,880		13,357
Nebraska	40,659		40,720		43,472
Iowa	46,179		46,762		54,587
Kansas	20,362		21,953		22,629
Total Commercial	119,372		121,315		134,045

Industrial:
Colorado	2,063		1,409		1,348
Nebraska	860		3,126		3,425
Iowa	2,521		2,243		2,191
Kansas	19,571		14,312		11,057
Total Industrial	25,015		21,090		18,021

Other Sales Revenue:
Colorado	96		97		100
Nebraska	1,971		1,960		2,077
Iowa	550		836		1,073
Kansas	3,031		3,451		3,213
Total Other Sales Revenue	5,648		6,344		6,463

Total Distribution:
Colorado	72,433		68,597		77,537
Nebraska	168,983		166,171		176,094
Iowa	155,542		155,096		171,632
Kansas	108,149		109,575		107,747
Total Distribution	505,107		499,439		533,010

Transportation:
Colorado	846		784		732
Nebraska	11,175		11,289		10,569
Iowa	3,935		3,708		3,876
Kansas	5,909		5,471		5,389
Total Transportation	21,865		21,252		20,566

Total Regulated:
Colorado	73,279		69,381		78,269
Nebraska	180,158		177,460		186,663
Iowa	159,477		158,804		175,508
Kansas	114,058		115,046		113,136
Total Regulated Revenue	526,972		520,691		553,576

Non-regulated Services	27,612		30,016		26,736

Total Revenue	$	554,584	$	550,707	$	580,312



Gross Margin (in thousands)	2011		2010		2009

Residential:
Colorado	$	17,711	$	18,153	$	17,443
Nebraska	51,640		49,074		44,638
Iowa	47,491		44,269		42,734
Kansas	29,701		29,591		28,999
Total Residential	146,543		141,087		133,814

Commercial:
Colorado	2,960		3,215		3,176
Nebraska	11,643		11,965		11,785
Iowa	11,702		11,616		12,749
Kansas	6,603		6,544		6,484
Total Commercial	32,908		33,340		34,194

Industrial:
Colorado	450		360		375
Nebraska	217		379		431
Iowa	288		235		244
Kansas	2,373		1,878		1,766
Total Industrial	3,328		2,852		2,816

Other Sales Margins:
Colorado	96		97		101
Nebraska	1,971		1,960		2,077
Iowa	549		836		1,073
Kansas	2,455		2,722		2,312
Total Other Sales Margins	5,071		5,615		5,563

Total Distribution:
Colorado	21,217		21,825		21,095
Nebraska	65,471		63,378		58,931
Iowa	60,030		56,956		56,800
Kansas	41,132		40,735		39,561
Total Distribution	187,850		182,894		176,387

Transportation:
Colorado	846		784		732
Nebraska	11,175		11,289		10,569
Iowa	3,935		3,708		3,876
Kansas	5,909		5,470		5,389
Total Transportation	21,865		21,251		20,566

Total Regulated:
Colorado	22,063		22,609		21,827
Nebraska	76,646		74,667		69,500
Iowa	63,965		60,664		60,676
Kansas	47,041		46,205		44,950
Total Regulated Gross Margin	209,715		204,145		196,953

Non-regulated Services	12,908		12,845		11,643

Total Gross Margin	$	222,623	$	216,990	$	208,596



Volumes (in Dth)	2011	2010	2009

Residential:
Colorado	6,437,860	6,284,559	6,355,275
Nebraska	12,076,979	12,210,574	12,619,682
Iowa	10,490,129	10,556,045	10,976,268
Kansas	6,853,163	6,926,928	6,878,243
Total Residential	35,858,131	35,978,106	36,829,468

Commercial:
Colorado	1,472,747	1,473,924	1,444,360
Nebraska	4,833,604	5,009,105	5,189,630
Iowa	6,192,167	6,061,954	6,597,035
Kansas	2,676,439	2,673,805	2,696,870
Total Commercial	15,174,957	15,218,788	15,927,895

Industrial:
Colorado	344,576	259,985	263,134
Nebraska	120,779	544,457	581,892
Iowa	409,723	354,435	333,324
Kansas	3,743,735	2,718,767	2,524,126
Total Industrial	4,618,813	3,877,644	3,702,476

Other Volumes:
Colorado	—	—	—
Nebraska	—	1,341	1,400
Iowa	—	69,306	68,290
Kansas	112,253	120,445	141,909
Total Other Volumes	112,253	191,092	211,599

Total Distribution:
Colorado	8,255,183	8,018,468	8,062,769
Nebraska	17,031,362	17,765,477	18,392,604
Iowa	17,092,019	17,041,740	17,974,917
Kansas	13,385,590	12,439,945	12,241,148
Total Distribution	55,764,154	55,265,630	56,671,438

Transportation:
Colorado	869,570	808,859	807,999
Nebraska	24,972,560	27,327,173	25,311,501
Iowa	18,358,692	17,422,525	14,915,602
Kansas	15,015,310	14,320,893	14,069,182
Total Transportation	59,216,132	59,879,450	55,104,284

Total Volumes:
Colorado	9,124,753	8,827,327	8,870,768
Nebraska	42,003,922	45,092,650	43,704,105
Iowa	35,450,711	34,464,265	32,890,519
Kansas	28,400,900	26,760,838	26,310,330
Total Volumes	114,980,286	115,145,080	111,775,722

Degree Days



	2011		2010		2009
	Actual	Variance From 30-Year Average	Actual	Variance From 30-Year Average	Actual	Variance From 30-Year Average
Heating Degree Days ^(a):
Colorado	5,991	(7)%	5,803	(9)%	6,299	2%
Nebraska	6,190	(4)%	6,222	(5)%	6,238	5%
Iowa	7,013	(1)%	6,934	(1)%	7,279	6%
Kansas ^(b)	4,954	(1)%	4,918	—%	4,989	—%
Combined	6,143	(3)%	6,101	(3)%	6,285	(11)%

________________


(a)	The combined heating degree days are calculated based on a weighted average of total customers by state.


(b)	In Kansas where we have a weather normalization mechanism, normal degree days are used instead of actual degree days in computing the total number of heating degree days.

The following table summarizes the Gas Utilities' customers as of December 31:



Customers	2011	2010	2009

Residential:
Colorado	67,496	66,766	65,586
Nebraska	176,386	176,244	179,873
Iowa	135,161	134,782	133,712
Kansas	98,043	97,844	97,446
Total Residential	477,086	475,636	476,617

Commercial:
Colorado	3,678	3,620	3,590
Nebraska	15,664	15,221	15,218
Iowa	15,398	15,300	15,403
Kansas	9,453	9,469	9,510
Total Commercial	44,193	43,610	43,721

Industrial:
Colorado	209	208	207
Nebraska	141	149	149
Iowa	94	93	90
Kansas	1,365	1,394	1,351
Total Industrial	1,809	1,844	1,797

Transportation:
Colorado	30	22	22
Nebraska	4,128	4,270	4,579
Iowa	393	392	389
Kansas	1,142	1,054	1,077
Total Transportation	5,693	5,738	6,067

Other:
Colorado	—	—	—
Nebraska	—	2	2
Iowa	—	68	71
Kansas	7	8	8
Total Other	7	78	81

Total Customers:
Colorado	71,413	70,616	69,405
Nebraska	196,319	195,886	199,821
Iowa	151,046	150,635	149,665
Kansas	110,010	109,769	109,392
Total Customers at Year-End	528,788	526,906	528,283

Business Characteristics

Seasonal Variations of Business

Our Electric Utilities and Gas Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as market price. In particular, demand is often greater in the summer and winter months for cooling and heating, respectively. Because our Electric Utilities have a diverse customer and revenue base and we have historically optimized the utilization of our electric power supply resources, the impact on our operations may not be as significant when weather conditions are warmer in the winter and cooler in the summer. Conversely, for our Gas Utilities, natural gas is used primarily for residential and commercial heating, so the demand for this product depends heavily upon weather patterns throughout our service territories, and as a result, a significant amount of natural gas revenue is normally recognized in the heating season consisting of the first and fourth quarters.

Competition

We generally have limited competition for the retail distribution of electricity and natural gas in our service areas. In the past, various restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate, but none of these initiatives have been adopted to date, with the exception of Montana. Although we face competition from independent marketers for the sale of natural gas to our industrial and commercial customers, in instances where independent marketers displace us as the seller of natural gas, we still collect a distribution charge for transporting the gas through our distribution network. In Colorado, our electric utility is subject to rules which require competitive bidding for generation supply. Because of these rules, we face competition from other utilities and non-affiliated IPP companies for the right to provide electric energy and capacity for Colorado Electric when resource plans require additional resources.

Regulation and Rates

State Regulation

Our utilities are subject to the jurisdiction of the public utilities commissions in the states where they operate. The commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. The public utility commissions determine the rates we are allowed to charge for our utility services. Rate decisions are influenced by many factors, including the cost of providing service, capital expenditures, the prudence of our costs, views concerning appropriate rates of return, the rates of other utilities, general economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities, and the creation of liens on property located in their state to secure bonds or other securities.

We distribute natural gas in five states. All of our Gas Utilities, and Cheyenne Light's natural gas distribution, have gas cost adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to the customer. In Kansas and Nebraska, we are allowed to recover the portion of uncollectible accounts related to gas costs through the gas cost adjustments. In Kansas, we also have a weather normalization tariff that provides a pass-through mechanism for weather margin variability that occurs from the level used to establish base rates to be paid by the customer as well as tariffs that provide for more timely recovery for certain capital expenditures and fluctuations in property taxes. In Nebraska, legislation was passed in 2009 to authorize the NPSC to provide for more timely recovery from our customers for certain capital expenditures between rate cases. In October 2011, the IUB adopted rules that allow rate-regulated natural gas utilities to implement automatic adjustment mechanisms for recovery of certain costs, primarily safety-related and government-mandated investment in infrastructure, between general rate proceedings.

We produce and/or distribute power in four states. The regulatory provisions for recovering the costs to produce electricity vary by state. Certain states have approved specific mechanisms which allow the utility operating in that state to collect, or refund, the difference between the cost of commodities and certain services embedded in our base rates and the actual cost of the commodities and certain services without filing a general rate case. In some instances, the utility has the opportunity to earn its authorized return on new capital investment. The mechanisms we have in place are:

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In South Dakota, Wyoming, Colorado and Montana, we have cost adjustment mechanisms for our Electric Utilities that serve a purpose similar to the cost adjustment mechanisms in our Gas Utilities. At Cheyenne Light, our pass-through mechanism relating to transmission, fuel and purchased power costs is subject to a $1.0 million threshold: we collect or refund 95% of the increase or decrease that exceeds the $1.0 million threshold, and we absorb the increase or retain the savings for costs below the threshold as well as the 5% not collected or refunded above the threshold.

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Until April 1, 2010, South Dakota had three adjustment mechanisms: transmission, steam plant fuel (coal) and conditional ECA. 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 ECA 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 ECA 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.


•	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 recovers all the costs associated with plant additions.

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In Colorado, we have an ECA for increases or decreases in purchased power and fuel costs and a TCA for transmission cost adjustments. The ECA clause provides for the direct recovery of increased purchased power and fuel costs or the issuance of credits for decreases in purchased power and fuel costs. The TCA is a rider to the customer's bill which allows the utility to earn an authorized return on new transmission investment and recovery of operations and maintenance costs related to transmission.


•	Effective January 1, 2012, the CPUC approved adjustments to the ECA. These adjustments allow for the recovery of transmission expenses paid to other providers, symmetrical interest, and the sharing of off-system sales margins, less certain operating costs, where the customer receives 75% through 2013. This sharing percentage increases to 90% to the customer in 2014.

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In Colorado, beginning in November 2010, the CPUC approved the implementation of a Purchased Capacity Cost Adjustment, the purpose of which is to recover the increase in capacity cost related to Colorado Electric's purchase power agreement with PSCo. This Purchase Capacity Cost Adjustment expired on January 1, 2012 in conjunction with expiration of the PPA with PSCo and the commencement of Colorado Electric's PPA with Colorado IPP.

Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage our Electric Utilities 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:

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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.

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Montana. Montana established a renewable portfolio standard that requires Black Hills Power to obtain a percentage of its retail electric sales in Montana from eligible renewable resources according to the following schedule: (i) 5% for compliance years 2008-2009; (ii) 10% for compliance years 2010-2014; and (iii) 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.

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Colorado. Colorado has adopted a renewable energy standard that requires our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 12% of retail sales from 2011 to 2014; (ii) 20% of retail sales from 2015 to 2019; and (iii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The law limits the net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) to 2% and encourages the CPUC to consider earlier and timely cost recovery for utility investment in renewable resources, including the use of a forward rider mechanism. We are currently in compliance with these standards, and our current strategy is to incorporate renewable energy as required to comply with the 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.

In connection with our acquisition of the Gas Utilities, the CPUC, NPSC, IUB and KCC approved orders or settlement agreements providing that, among other things, (i) our utilities in those jurisdictions cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and (ii) neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. In addition to the restrictions described above, each state in which we conduct utility operations imposes restrictions on affiliate transactions, including inter-company loans.

Federal Regulation

Energy Policy Act. Black Hills Corporation is a holding company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and holding companies regulated by FERC under the Federal Power Act and PUHCA 2005.

Federal Power Act. The Federal Power Act gives FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC's jurisdiction must maintain tariffs and rate schedules on file with FERC that govern the rates, terms, and conditions for the provision of FERC-jurisdictional wholesale power and transmission services. Public utilities are also subject to accounting, record-keeping, and reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and their affiliates. Our public utility subsidiaries provide FERC-jurisdictional services subject to FERC's oversight.

Our Electric Utilities and our non-regulated subsidiaries, Black Hills Colorado Electric and Black Hills Wyoming, are authorized by FERC to make wholesale sales of electric capacity and energy at market-based rates under tariffs on file with FERC. As a condition of their market-based rate authority, each files Electric Quarterly Reports with FERC. Black Hills Power owns and operates FERC-jurisdictional interstate transmission facilities and provides open access transmission service under tariffs on file with FERC. Our Electric Utilities are subject to routine audit by FERC with respect to their compliance with FERC's regulations.

The Federal Power Act gave FERC authority to certify and oversee a national electric reliability organization with authority to promulgate and enforce mandatory reliability standards applicable to all users, owners, and operators of the bulk-power system. FERC has certified NERC as the electric reliability organization. NERC has promulgated mandatory reliability standards, and NERC, in conjunction with regional reliability organizations that operate under FERC's and NERC's authority and oversight, enforces those mandatory reliability standards.

PUHCA 2005. PUHCA 2005 gives FERC authority with respect to the books and records of a utility holding company. As a utility holding company with centralized service company subsidiaries, Black Hills Service Company and Black Hills Utility Holdings, we are subject to FERC's authority under PUHCA 2005.

The following summarizes our recent state and federal rate case and surcharge activity (dollars in millions):



										Approved Capital Structure
	Type of Service	Date Requested	Date Effective	Amount Requested		Amount Approved		Return on Equity		Equity		Debt
Nebraska Gas⁽¹⁾	Gas	12/2009	9/2010	$	12.1	$	8.3	10.1	%	52.0	%	48.0	%
Iowa Gas	Gas	6/2008	7/2009	$	13.6	$	10.8	10.1	%	51.4	%	48.6	%
Iowa Gas ⁽²⁾	Gas	6/2010	2/2011	$	4.7	$	3.4	Global Settlement		Global Settlement		Global Settlement
Colorado Gas	Gas	6/2008	4/2009	$	2.7	$	1.4	10.3	%	50.5	%	49.5	%
Kansas Gas	Gas	5/2009	10/2009	$	0.5	$	0.5	10.2	%	50.7	%	49.3	%
Black Hills Power ⁽³⁾	Electric	9/2009	4/2010	$	32.0	$	15.2	Global Settlement		Global Settlement		Global Settlement
Black Hills Power⁽⁴⁾	Electric	10/2009	6/2010	$	3.8	$	3.1	10.5	%	52.0	%	48.0	%
Black Hills Power ⁽⁵⁾	Electric	1/2011	6/2011	Not Applicable		$	3.1	Not Applicable		Not Applicable		Not Applicable
Colorado Electric ⁽⁶⁾	Electric	1/2010	8/2010	$	22.9	$	17.9	10.5	%	52.0	%	48.0	%
Colorado Electric ⁽⁷⁾	Electric	4/2011	1/2012	$	40.2	$	28.0	9.8%-10.2%		49.1	%	50.9	%
Cheyenne Light ⁽⁸⁾	Electric/Gas	12/2011	pending	$	8.5	pending		pending		pending		pending

(1)

In December 2009, Nebraska Gas filed a rate case with the NPSC and interim rates went into effect on March 1, 2010. In August 2010, NPSC issued a decision approving an annual revenue increase of approximately $8.3 million, based on a return on equity of 10.1% with a capital structure of 52% equity effective September 1, 2010. A refund to customers for the difference between interim rates and approved rates was completed in the first quarter of 2011. The Nebraska Public Advocate has filed an appeal with the District Court which has been denied. Subsequently, the Nebraska Public Advocate has filed a notice of appeal in the Court of Appeals. This appeal is still outstanding.

(2)

In June 2010, Iowa Gas filed a request with the IUB for a $4.7 million revenue increase to recover the cost of capital investments made in our gas distribution system and other expense increases incurred since December 2008. Interim rates, subject to refund, equal to a $2.6 million increase in revenues went into effect on June 18, 2010. In August 2010, we reached a settlement with the OCA for a revenue increase of $3.4 million. This settlement agreement was modified and re-filed on January 11, 2011. The modified settlement excludes the integrity investment tracker and the three-year rate moratorium included in the original settlement agreement filed on September 1, 2010, which was not approved by the IUB. Approval from the IUB was received on February 10, 2011.

(3)

In September 2009, Black Hills Power 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 previous 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 was provided to customers in the third quarter of 2010.

As part of the settlement stipulation, Black Hills Power agreed: (1) to credit customers 65% of off-system sales operating income with a minimum credit 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 ended 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 off-system sales portion of the Fuel and Purchased Power Adjustment Clause for the methodology to directly assign renewable resources and firm purchases to the customer load.

(4)

In October 2009, Black Hills Power filed a rate case with the WPSC requesting a $3.8 million 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, Black Hills Power 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. New rates went into effect on June 1, 2010.


(5)	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.

(6)

In January 2010, Colorado Electric filed a rate case with the CPUC requesting an electric revenue increase primarily related to the recovery of rising costs from electricity supply contracts, as well as recovery for investment in equipment and electricity distribution facilities necessary to maintain and strengthen the reliability of the electric delivery system in Colorado. On August 5, 2010, the CPUC approved a settlement agreement for $17.9 million in annual revenues with a return on equity of 10.5% and a capital structure of 52% equity and 48% debt. New rates were effective August 6, 2010.

Included in the rate case order was a provision that off-system sales margin be shared with customers commencing August 6, 2010. The percentage of margin to be shared with the customers was not resolved at the time of the rate case settlement. The CPUC required that the off-system gross margin earned beginning August 6, 2010 be deferred. The determination of a sharing mechanism for off-system sales was considered as part of the rate case filed with the CPUC by Colorado Electric discussed below.

(7)

In April 2011, Colorado Electric filed a request with the CPUC for an annual revenue increase of $40.2 million, or 18.8%, to recover costs and a return on capital associated with the 180 MW generating facility that commenced commercial operation on January 1, 2012, associated infrastructure assets and other utility expenses, including the PPA with Colorado IPP. On December 22, 2011, the CPUC issued an order approving an annual base rate increase of $10.5 million with a rate of return ranging from 9.8% to 10.2% with a capital structure of 49.1% equity and 50.9% debt. New rates were effective January 1, 2012. In addition, approximately $17.5 million of other costs including fuel, purchased power and new transmission will be recovered through normal cost adjustment mechanisms.

The provisions of the order also provided for a sharing mechanism for off-system sales. Colorado Electric has agreed to credit customers 75% for off-system sales margin less certain operating costs, with Colorado Electric retaining 25% through December 31, 2013. The customers' sharing percentage increases to 90% starting in 2014.


(8)	On December 1, 2011, Cheyenne Light filed requests for electric and natural gas revenue increases with the WPSC to recover investment in infrastructure and other costs. Cheyenne Light is seeking a $5.9 million increase in annual electric revenue and a $2.6 million increase in annual natural gas revenue.

Environmental Matters

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.

Based on current regulations, technology and plans, the following table contains our current estimates of capital expenditures expected to be incurred over the next three years to comply with current environmental laws and regulations as described below, including regulations that cover water, air, soil and other pollutants but excluding the cost of new generation. The ultimate cost could be significantly different from the amounts estimated.



Environmental Expenditure Estimates	Total (in millions)
2012	$	12
2013	39
2014	13
Total	$	64

Water Issues

Our facilities are subject to a variety of state and federal regulations governing existing and potential water/wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through NPDES and stormwater permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. We are not aware of any proposed regulations that will have a significant impact on our operations. Additionally, the EPA regulates surface water oil pollution through its oil pollution prevention regulations. All of our facilities under this program have their required plans in place. Also, the EPA is scheduled to issue updated regulations for wastewater discharge for electric generating units in early 2012, which could have a significant impact on all of our generating fleet.

Air Emissions

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

Clean Air Act

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

Title IV applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen II, Wygen III and Wyodak plants. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2041. For future plants, we plan to secure the requisite number of allowances by reducing SO₂ emissions through the use of low sulfur fuels, installation of "back end" control technology, use of banked allowances, and if necessary, the purchase of allowances on the open market. We expect to integrate the cost of obtaining the required number of allowances needed for future projects into our overall financial analysis of such new projects.

Title V of the Clean Air Act requires that all of our generating facilities obtain operating permits. All of our existing facilities have received Title V permits, with the exception of Wygen III. Wygen III is allowed to operate under its construction permit until the Title V permit is issued by the state. The Title V application for Wygen III was submitted in January 2011, with the permit expected in 2012. The application was filed in accordance with regulatory requirements.

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. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than December 31, 2013. 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 MACT 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 II, Wygen III and Wyodak plants. Neil Simpson II, Wygen 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.

On June 23, 2010, the EPA published in the Federal Register the GHG Tailoring Rule, implementing regulations of GHG for permitting purposes. This rule will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Existing permitted facilities will see monitoring and 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 emission control practices and technologies. As Wyoming state law prohibits regulation of GHG, the EPA will review and develop requirements for that portion of a new source construction permit or for a major modification of an existing source. It is anticipated this additional process will add several months to the permitting process. In addition, unlike a Wyoming issued permit, an appeal of an EPA issued GHG air permit to construct requires an automatic stay to the project, meaning that construction cannot commence until the appeal is resolved. This aspect adds considerable risk to new construction projects as well as to major modifications to existing projects.

In the 2010 legislative session, the State of Colorado passed House Bill 1365, the Colorado Clean Air Clean Jobs Act, a coordinated utility plan to reduce air emissions from coal fired power plants and promote the use of natural gas and other low emitting resources. This act has a significant impact on our W.N. Clark facility and on October 29, 2010, Colorado Electric filed testimony with the CPUC that included a proposal recommending retirement of the W.N. Clark facility. On December 15, 2010, the CPUC issued an order approving closure of the W.N. Clark plant by December 31, 2013. On January 7, 2011, the State Air Quality Control Commission adopted the CPUC order into the Colorado State Implementation Plan and following legislative approval, that plan was submitted in May 2011 to the EPA Region VIII for approval.

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, Wygen 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. We anticipate that the State of Wyoming will eventually issue the same requirements for Wygen I and Wygen II.

Regional Haze

In January 2011, the states of Wyoming and South Dakota submitted their plans to EPA Region VIII, identifying NO_x, SO₂ and particulate matter emission reductions intended to meet the Class I Areas (National Parks and Wilderness Areas) visibility improvement requirements under the EPA's Regional Haze Program. Although none of our South Dakota or Wyoming power plants were included in those plans, we anticipate that within the next five years, Ben French, Neil Simpson I and Osage will be included. This is based on recent activity by EPA Region VIII, where they have rejected at least in part, states' emission reduction plans. Colorado submitted a revised plan to the EPA in May 2011, addressing the additional required emission reductions, which for the first time included our W.N. Clark facility. In 2011, the EPA partially rejected North Dakota's Regional Haze Plan, and issued a Federal Implementation Plan, dictating new lower emission limits for certain facilities. As Ben French, Neil Simpson 1 and Osage have no SO₂ or NO_x post combustion emission controls and are in close proximity to the two Class I Areas in western South Dakota, we fully expect they will be brought into the program. This could occur in the very near future, if the EPA rejects the South Dakota and/or Wyoming Plans, or it could occur in five years, when the plans undergo the required five year review to assess visibility improvement progress. Costs to comply will be significant and have been included as part of the engineering review conducted to assess impacts of the EPA's Industrial and Commercial Boiler Area Source regulations. It is our expectation Ben French, Osage and Neil Simpson I will be closed prior to March 21, 2014.

Mercury Regulations

Approximately 50% of our electric generating capacity is coal-fired. 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 (MATS) and this regulation became effective 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. This rule will address mercury emissions, among other pollutants, at Neil Simpson II, Wygen II and Wygen III.

The MATS rule will require significant investments at our power generating facilities. Of our affected units, it is anticipated that Neil Simpson II will require the most extensive investments. The state air permit for Wygen II and Wygen III provides mercury emission limits and monitoring requirements with which we are in compliance. Wygen II has been utilized for study and review of mercury emission control technology and has mercury monitors in place. In 2009, we added mercury monitors to our Neil Simpson II plant. The Wygen III plant, which commenced operations in 2010, also has mercury monitors. Federal multi-pollutant legislation is also being considered that would require reductions similar to the EPA rules and may add requirements for the reduction of GHG emissions.

Greenhouse Gas Regulations

We utilize a diversified energy portfolio of power generation assets that includes a fuel mix of coal and natural gas as well as wind sources, and minimal quantities of both solar and hydroelectric power. Of these generation resources, coal-fired power plants are the most significant sources of CO₂ emissions. Although we cannot predict specifically how, if or when, GHG will be regulated, any federally mandated GHG reductions or limits on CO₂ emissions could have a material impact on our financial position, results of operations, or cash flows. In 2011, the EPA's GHG Tailoring Rule went into effect, requiring GHG emissions to be addressed in new major source construction permits and to be addressed upon renewal of Title V Operating Permits. As there are no emission standards or caps currently in place, we cannot predict how this requirement will impact our existing facilities upon permit renewal. In 2011, we reported 2010 GHG emissions from our Power Generation and Gas Utilities in order to comply with the EPA's GHG Annual Inventory regulation, issued in 2009. In addition to federal legislative activity, GHG regulations have been proposed in various states and alleged climate change issues are the subject of a number of lawsuits, the outcome of which could impact the utility industry. We will continue to review GHG impacts as legislation or regulation develops and litigation is resolved.

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

In connection with GHG initiatives, many states have enacted, and others are considering, renewable energy portfolio standards that require electric utilities to meet certain thresholds for the production or use of renewable energy. Colorado Electric is subject to renewable energy portfolio standards in Colorado. Black Hills Power is subject to mandatory renewable energy portfolio standards in Montana and voluntary standards in South Dakota. In the near future, we expect similar (if not more challenging) renewable energy portfolio standards to be mandated at the federal level or in other state jurisdictions in which we operate. We anticipate significant additional costs to comply with any federal or state mandated renewable energy standards, which we would expect to pass on to our customers. However, we cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Under appropriate state permits, we dispose of all solid wastes collected as a result of burning coal at our power plants in approved solid waste disposal sites. Ash and waste from flue gas and sulfur removal from the Wyodak, Neil Simpson I, Ben French, Neil Simpson II, Wygen II and Wygen III plants are deposited in mined areas at the WRDC coal mine. These disposal areas are located below some shallow water aquifers in the mine. In 2009, the State of Wyoming confirmed their past approval of this practice but may re-evaluate and limit ash disposal to mined areas that are above future groundwater aquifers. This change would increase disposal costs, which cannot be quantified until the exact requirements are known. None of the solid waste from the burning of coal is currently classified as hazardous material, but the waste does contain minute traces of metals that could be perceived as polluting if such metals leached into underground water. We conducted investigations which concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground water quality.

As of October 1, 2010, we suspended operations at the Osage power plant. It has an on-site ash impoundment that is near capacity. An application to close the impoundment was