Edgar Filing: BLACK HILLS CORP /SD/

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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, 2010


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 Rapid City, South Dakota 57701	IRS Identification Number 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. ®

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, 2010 $1,102,103,935

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, 2011
Common stock, $1.00 par value	39,262,118	shares

Documents Incorporated by Reference

Portions of the Registrant's Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2011 Annual Meeting of Stockholders to be held on May 25, 2011, 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	7

		FORWARD-LOOKING INFORMATION	7
Part I
	ITEMS 1. and 2.	BUSINESS AND PROPERTIES	10

	ITEM 1A.	RISK FACTORS	54

	ITEM 1B.	UNRESOLVED STAFF COMMENTS	65

	ITEM 3.	LEGAL PROCEEDINGS	65

	ITEM 4.	SPECIALIZED DISCLOSURES (UNDER PROPOSED RULES)	65
Part II
	ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	65

	ITEM 6.	SELECTED FINANCIAL DATA	67

	ITEMS 7. and 7A.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	69

	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	124

	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	205

	ITEM 9A.	CONTROLS AND PROCEDURES	205

	ITEM 9B.	OTHER INFORMATION	206
Part III
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	207

	ITEM 11.	EXECUTIVE COMPENSATION	208

	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	208

	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	208

	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	208

	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	209

		SIGNATURES	225

		INDEX TO EXHIBITS	226

GLOSSARY OF TERMS AND ABBREVIATIONS

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


Acquisition Facility	Our $1.0 billion single-draw, senior unsecured facility from which a $383 million draw was used to provide part of the funding for our Aquila Transaction
AFUDC	Allowance for Funds Used During Construction
Annexation Agreement	Agreement with the City of Pueblo, Colorado under which the City of Pueblo annexed the property on which Colorado Electric and Black Hills Colorado IPP are constructing their generation facilities
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
BHC Pension Plan	The Pension Plan of Black Hills Corporation
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 Corporation Plan	Black Hills Corporation Retirement Savings Plan
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
Btu	British thermal unit
CAMR	Clean Air Mercury Rule
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
Cheyenne Light Plan	Cheyenne Light, Fuel and Power Company Retirement Savings 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
CPUC	Colorado Public Utilities Commission
CT	Combustion turbine
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
EDF	EDF Trading North America, LLC
Enserco	Enserco Energy Inc., a wholly-owned subsidiary of Black Hills Non-regulated Holdings
Enserco Credit Facility	The $250 million committed stand alone credit facility that supports Enserco's marketing and trading operations, which currently expires May 7, 2012
EPA	U. S. Environmental Protection Agency
Equity forward shares	Public offering of 4,000,000 shares of Black Hills Corporation common stock connected with an Equity Forward Agreement
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
Forward Agreement	Equity Forward Agreement with J. P. Morgan connected to a public offering of 4,000,000 million shares of Black Hills Corporation common stock
Forward Agreements	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
FTC	Federal Trade Commission
GAAP	Accounting principles generally accepted in the United States of America
GCA	Gas Cost Adjustment
GHG	Greenhouse gases
GIS	Geographic information system
Global Settlement	Settlement with the 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
GSRS	Gas System Reliability Surcharge
Happy Jack	Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Hastings	Hastings Fund Management Ltd
ICE	Intercontinental Exchange
IGCC	Integrated Gasification Combined Cycle
IIF	IIF BH Investment LLC, a subsidiary of an investment entity advised by JPMorgan 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 production
IPP Transaction	The July 11, 2008 sale of seven of our IPP plants to affiliates of Hastings and IIF
IRS	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
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
NCREIF	National Council of Real Estate Investment Fiduciaries
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
NOx	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
NYMEX	New York Mercantile Exchange
OCA	Office of Consumer Advocate
OPEC	Organization of the Petroleum Exporting Countries
PCA	Power Cost Adjustment


PGA	Purchased Gas Adjustment
PPA	Purchase Power 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
QF	Qualifying Facility
RCRA	Resource Conservation and Recovery Act
Revolving Credit Facility	Our $500 million credit facility used to fund working capital needs, issuance of letters of credit and other corporate purposes, expiring April 14, 2013.
RMSA	Retiree Medical Savings Account
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.
Valencia	Valencia Power, LLC, a former subsidiary of Black Hills Non-regulated Holdings that was sold as part of our IPP Transaction
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 310-10-50	ASC 310-10-50, "Receivables - Disclosures"
ASC 715	ASC 715, "Compensation - Retirement Benefits"
ASC 805	ASC 805, "Business Combinations"
ASC 810	ASC 810, "Consolidations"
ASC 810-10-15	ASC 810-10-15, "Consolidation of Variable Interest Entities"
ASC 815	ASC 815, "Derivatives and Hedging"
ASC 820	ASC 820, "Fair Value Measurements and Disclosures"
ASC 932-10-S99	ASC 932-10-S99, "Extractive Activities - Oil and Gas, SEC Materials"
ASC 940-325-S99	ASC 940-325-S99, "Financial Services - Broker and Dealers, Investments - Other"

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 or foreign exchange 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 arising from the enactment of the Energy Policy Act of 2005 and subsequent rules and regulations promulgated thereunder;


•	The effect of Dodd-Frank and the regulations to be adopted thereunder on our use of derivative instruments in connection with our energy marketing activities and to hedge our expected production of 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 independent power production or exploration and production activities;


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


•	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, currency exchange rate 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;


•	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 whom 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 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, Coal Mining, and Energy Marketing segments, as shown below. At December 31, 2010, we had 2,124 employees, 705 of whom were represented by union locals.


Business Group	Financial Segment

Utilities	Electric Utilities
	Gas Utilities

Non-regulated Energy	Oil and Gas
	Power Generation
	Coal Mining
	Energy Marketing

Our Electric Utilities segment generates, transmits and distributes electricity to approximately 201,000 customers in South Dakota, Wyoming, Colorado and Montana and includes the operations of Cheyenne Light, a combination electric and gas utility, and its approximately 34,500 gas utility customers in Wyoming. Our Gas Utilities segment serves approximately 527,000 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 687 MWs of generation and 8,038 miles of electric transmission and distribution lines, and our Gas Utilities own 626 miles of intrastate gas transmission pipelines and 19,638 miles of gas distribution mains and service lines. Our Electric and Gas Utilities generated income from continuing operations of $74.6 million for the year ended December 31, 2010 and had total assets of $2.6 billion at December 31, 2010.

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 Coal Mining segment produces coal at our coal mine near Gillette, Wyoming, and our Energy Marketing segment is engaged in marketing of natural gas, crude oil, coal, power, environmental products and related services, in the United States and Canada. Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy primarily under long-term contracts. In 2008, we sold seven IPP plants previously reported in our Power Generation segment, which resulted in the operations of these plants being reported as discontinued operations. Our Non-regulated Energy Group generated income from continuing operations of $13.6 million in the year ended December 31, 2010 and had total assets of $1.1 billion at December 31, 2010.

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, particularly Note 17 to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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 201,000 customers in South Dakota, Wyoming, Colorado and Montana. Additionally, Cheyenne Light distributes natural gas to approximately 34,500 natural gas utility customers in Wyoming. Our electric generating facilities and purchased power contracts supply electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including affiliates.

We conduct natural gas utility operations on a state-by-state basis through our Colorado Gas, Iowa Gas, Kansas Gas, and Nebraska Gas subsidiaries. Our Gas Utilities distribute and transport natural gas to our customers through our distribution network to approximately 527,000 customers in Colorado, Iowa, Kansas and Nebraska. We also provide related services that include appliance repairs, gas technical services and the sale of temporarily-available, contractual pipeline capacity from our suppliers.

In addition to our regulated operations, we also provide services through our Service Guard product line to approximately 63,000 customers in Colorado, Iowa, Kansas and Nebraska. Service Guard primarily provides appliance repair services through company technicians and third party service providers.

Electric Utilities Segment

Capacity and Demand

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


	System Peak Demand (in MW)

	2010		2009		2008
	Summer	Winter	Summer	Winter	Summer		Winter

Black Hills Power	396	377	387	392	409		407
Cheyenne Light	176	164	169	171	166		168
Colorado Electric	384	289	365	296	306	^(a)	298	^(a)
Total Electric Utilities Peak Demands	956	830	921	859	881		873

__________________________

(a) For the period July 14, 2008 to December 31, 2008.

Regulated Power Plants

As of December 31, 2010, our Electric Utilities' ownership interests in electric generation plants were as follows:


Unit	Fuel Type	Location	Ownership Interest %		Owned 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	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 ⁽⁴⁾:
W.N. Clark #1-2⁽⁵⁾	Coal	Canon City, CO	100.0	%	42.0	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					686.9

________________________

(1) Construction of Wygen III, a 110 MW mine-mouth coal-fired power plant was completed in April 2010. Black Hills Power operates the plant and owns a 52% interest in the facility, MDU owns a 25% interest and the City of Gillette owns a 23% interest. Our WRDC coal mine furnishes all of the coal fuel supply for the plant.

(2) Wyodak is a 362 MW mine-mouth coal-fired plant 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 coal fuel supply for the plant.

(3) Operations at the Osage plant were suspended October 1, 2010 due to the availability of more economical generation alternatives.

(4) The construction of two 90 MW gas-fired power generation facilities is underway to support the customers of Colorado Electric. These facilities are expected to be completed by December 31, 2011.

(5) In December 2010, Colorado Electric received a final order from CPUC which approved the retirement of its W.N. Clark coal-fired generation facility by December 31, 2013 and granted a presumption of need in the amount of 42 MW for replacement of the plant. Colorado Electric will file a Certificate of Public Convenience and Necessity to provide justification for an additional 50 MW of generating capacity to allow the construction of a third 92 MW GE LMS100 natural gas-fired generator at the Pueblo Airport Generation Station where two 90 MW facilities are currently under construction.

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	2010		2009		2008⁽¹⁾

Coal	$	12.77	$	13.99	$	11.41

Gas and Oil	$	131.28	$	85.52	$	88.60

Total Average Fuel Cost	$	13.57	$	15.22	$	13.18

Purchased Power⁽²⁾	$	30.23	$	28.93	$	38.06

________________________

(1) 2008 includes Colorado Electric from July 14, 2008 through December 31, 2008.

(2) Includes Happy Jack commencing in October 2008, and Silver Sage commencing in October 2009.

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	2010		2009		2008

Coal-fired	42	%	39	%	44	%

Gas and Oil	—		1		1
Total Generated	42		40		45

Purchased	58		60		55
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 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 PSCo expiring at the end of 2011, whereby Colorado Electric purchases a majority of its power. The contract provides for 300 MW of capacity and energy in 2011;


•	Colorado Electric's 20-year PPA with Black Hills Colorado IPP, beginning on January 1, 2012 and expiring in 2031, which will provide 200 MW of power to Colorado Electric from Black Hills Colorado IPP's combined-cycle turbines, which are currently under construction;


•	Cheyenne Light's PPA with Black Hills Wyoming expiring in August 2011 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 which is equivalent to the estimated initial per MW price of new construction of the Wygen III facility. This 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, provides 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:

•

In conjunction with MDU's April 2009 purchase of a 25% ownership interest in Wygen III, an agreement to supply 74 MW of capacity and energy through 2016 was modified. The sales to MDU have been integrated into Black Hills Power's control area and are considered part of our firm native load. MWs from the Wygen III unit are deemed to supply a portion of the required 74 MW. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU;

•

Black Hills Power's agreement with the City of Gillette to dispatch the City of Gillette's 23% of Wygen III's net generating capacity for the life of the plant. Upon the City of Gillette's July 2010 purchase of a 23% ownership interest in Wygen III, a seven year PPA with the City of Gillette that went into effect in April 2010, was terminated. The City of Gillette's 23 MW of Wygen III capacity has been integrated into Black Hills Power's control area and are considered part of our firm native load. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement Black Hills Power will also provide the City of Gillette their operating component of spinning reserves;


•	Black Hills Power's agreement to supply 20 MW of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:


2010-2017	20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019	15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021	12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023	10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II;


•	Black Hills Power's five-year PPA with MEAN which commenced in May 2010 whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III; 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. The agreements become effective on March 14, 2011, and terminate prior agreements under which Cheyenne Light supplies Basin Electric with 80 MW of energy and capacity, and Basin Electric supplies Cheyenne Light with 80 MW of energy and capacity.

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, 2010, our regulated 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	565	2,933
Black Hills Power - Jointly Owned ⁽¹⁾	SD, WY	47	—
Cheyenne Light	SD, WY	25	1,176
Colorado Electric	CO	260	3,032

(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.

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 used by an affiliate entity. This agreement commenced during 2010.

Operating Statistics

The following tables summarize sales revenues, quantities and customers for our Electric Utilities. Amounts shown for 2008 include Colorado Electric from our July 14, 2008 acquisition date through December 31, 2008.


Sales Revenues (in thousands)
	2010		2009		2008
Residential:
Black Hills Power	$	53,549	$	48,586	$	46,854
Cheyenne Light	29,506		29,198		31,394
Colorado Electric	76,596		66,548		32,620
Total Residential	159,651		144,332		110,868

Commercial:
Black Hills Power	65,997		59,897		58,289
Cheyenne Light	52,765		51,280		51,609
Colorado Electric	66,490		56,002		28,531
Total Commercial	185,252		167,179		138,429

Industrial:
Black Hills Power	22,621		20,014		21,432
Cheyenne Light	10,542		11,121		9,716
Colorado Electric	28,812		31,067		16,280
Total Industrial	61,975		62,202		47,428

Municipal:
Black Hills Power	3,029		2,735		2,734
Cheyenne Light	1,293		932		973
Colorado Electric	10,443		4,408		2,289
Total Municipal	14,765		8,075		5,996

Contract Wholesale:
Black Hills Power	22,996		25,358		26,643

Off-system Wholesale:
Black Hills Power	36,354		32,212		63,770
Cheyenne Light	9,750		8,565		6,105
Colorado Electric	10,859		14,008		11,194
Total Off-system Wholesale	56,963		54,785		81,069

Other Sales Revenue:
Black Hills Power	25,217		18,277		12,950
Cheyenne Light	3,230		718		394
Colorado Electric	2,374		4,226		1,346
Total Other Sales Revenue	30,821		23,221		14,690

Total Sales Revenues	$	532,423	$	485,152	$	425,123

Quantities Generated and Purchased (MWh)


	2010	2009	2008
Generated -
Coal-fired:
Black Hills Power	1,987,037	1,721,074	1,731,838
Cheyenne Light	734,241	766,943	740,051
Colorado Electric	257,896	252,603	138,424
Total Coal	2,979,174	2,740,620	2,610,313

Gas and Oil-fired:
Black Hills Power	19,269	46,723	61,801
Cheyenne Light	—	—	—
Colorado Electric	930	2,705	306
Total Gas and Oil	20,199	49,428	62,107

Total Generated:
Black Hills Power	2,006,306	1,767,797	1,793,639
Cheyenne Light	734,241	766,943	740,051
Colorado Electric	258,826	255,308	138,730
Total Generated	2,999,373	2,790,048	2,672,420

Purchased -
Black Hills Power	1,440,579	1,686,455	1,703,088
Cheyenne Light	696,756	651,201	590,622
Colorado Electric	1,969,896	1,991,058	1,028,029
Total Purchased	4,107,231	4,328,714	3,321,739

Total Generated and Purchased	7,106,604	7,118,762	5,994,159


Quantity (MWh)
	2010	2009	2008
Residential:
Black Hills Power	547,193	529,825	524,413
Cheyenne Light	261,607	255,134	255,345
Colorado Electric	628,553	589,526	284,294
Total Residential	1,437,353	1,374,485	1,064,052

Commercial:
Black Hills Power	720,119	723,360	699,734
Cheyenne Light	603,323	583,986	586,151
Colorado Electric	726,005	666,563	330,870
Total Commercial	2,049,447	1,973,909	1,616,755

Industrial:
Black Hills Power	382,562	353,041	414,421
Cheyenne Light	161,082	174,792	144,179
Colorado Electric	347,673	452,584	235,218
Total Industrial	891,317	980,417	793,818

Municipal:
Black Hills Power	33,908	33,948	34,368
Cheyenne Light	6,477	3,456	3,669
Colorado Electric	113,689	37,244	19,740
Total Municipal	154,074	74,648	57,777

Contract Wholesale:
Black Hills Power	468,782	645,297	665,795

Off-system Wholesale:
Black Hills Power	1,163,058	1,009,574	1,074,398
Cheyenne Light	311,524	309,122	246,542
Colorado Electric	274,942	373,495	230,333
Total Off-system Wholesale	1,749,524	1,692,191	1,551,273

Total Quantity Sold:
Black Hills Power	3,315,622	3,295,045	3,413,129
Cheyenne Light	1,344,013	1,326,490	1,235,886
Colorado Electric	2,090,862	2,119,412	1,100,455
Total Quantity Sold	6,750,497	6,740,947	5,749,470

Losses and Company Use:
Black Hills Power	131,263	159,207	83,598
Cheyenne Light	86,984	91,654	94,787
Colorado Electric	137,860	126,954	66,304
Total Losses and Company Use	356,107	377,815	244,689

Total Energy	7,106,604	7,118,762	5,994,159

Degree Days


	2010			2009			2008
	Actual	Variance from 30-Year Average		Actual	Variance from 30-Year Average		Actual	Variance from 30-Year Average
Heating Degree Days:
Actual -
Black Hills Power	7,272	1	%	7,753	8	%	7,676	6	%
Cheyenne Light	7,033	(5	)%	7,411	—	%	7,435	1	%
Colorado Electric	5,518	(1	)%	5,546	(1	)%	2,204	(5	)%

Cooling Degree Days:
Actual -
Black Hills Power	532	(11	)%	354	(41	)%	482	(19	)%
Cheyenne Light	345	26	%	203	(26	)%	372	36	%
Colorado Electric	1,074	16	%	804	(13	)%	500	(12	)%

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.

Electric Customers at Year-End


	2010	2009	2008
Residential:
Black Hills Power	54,811	54,470	53,765
Cheyenne Light	34,913	35,943	35,205
Colorado Electric	81,902	81,622	81,561
Total Residential	171,626	172,035	170,531

Commercial:
Black Hills Power	12,779	12,261	12,213
Cheyenne Light	4,132	4,932	4,563
Colorado Electric	11,185	11,101	11,155
Total Commercial	28,096	28,294	27,931

Industrial:
Black Hills Power	40	38	40
Cheyenne Light	2	2	2
Colorado Electric	63	90	93
Total Industrial	105	130	135

Contract Wholesale:
Black Hills Power	3	3	3

Other Electric Customers:
Black Hills Power	309	143	3,010
Cheyenne Light	254	13	6
Colorado Electric	510	499	480
Total Other Electric Customers	1,073	655	3,496

Total Customers:
Black Hills Power	67,942	66,915	69,031
Cheyenne Light	39,301	40,890	39,776
Colorado Electric	93,660	93,312	93,289
Total Customers	200,903	201,117	202,096

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:


	2010		2009		2008

Sales Revenues (in thousands):
Residential	$	22,562	$	21,495	$	28,059
Commercial	10,801		9,821		13,751
Industrial	3,425		3,537		5,668
Other Sales Revenues	803		760		818
Total Sales Revenues	$	37,591	$	35,613	$	48,296

Sales Margins (in thousands):
Residential	$	10,004	$	10,219	$	10,083
Commercial	3,376		3,266		3,177
Industrial	427		509		483
Other Sales Margins	720		760		818
Total Sales Margins	$	14,527	$	14,754	$	14,561

Volumes Sold (Dth):
Residential	2,636,839		2,516,699		2,582,248
Commercial	1,572,638		1,502,002		1,501,025
Industrial	667,062		722,776		689,945
Total Volumes Sold	4,876,539		4,741,477		4,773,218

Customers	34,461		33,942		33,243

Gas Utilities Segment

At December 31, 2010, 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	122	2,967	871
Nebraska	51	3,406	3,462
Iowa	170	2,753	2,313
Kansas	283	2,578	1,288
Total	626	11,704	7,934

Operating Statistics

The following tables summarize revenues, sales margins, volumes, degree days and customers for our Gas Utilities. Amounts shown for 2008 include Gas Utilities from our July 14, 2008 acquisition date through December 31, 2008.


Revenues (in thousands)	2010		2009		2008

Residential:
Colorado	$	55,211	$	62,732	$	27,928
Nebraska	120,365		127,120		60,624
Iowa	105,255		113,781		47,338
Kansas	69,859		70,848		31,456
Total Residential	350,690		374,481		167,346

Commercial:
Colorado	11,880		13,357		6,356
Nebraska	40,720		43,472		20,705
Iowa	46,762		54,587		26,003
Kansas	21,953		22,629		10,092
Total Commercial	121,315		134,045		63,156

Industrial:
Colorado	1,409		1,348		1,495
Nebraska	3,126		3,425		1,640
Iowa	2,243		2,191		1,581
Kansas	14,312		11,057		14,667
Total Industrial	21,090		18,021		19,383

Other Sales Revenue:
Colorado	97		100		39
Nebraska	1,960		2,077		907
Iowa	836		1,073		457
Kansas	3,451		3,213		1,600
Total Other Sales Revenue	6,344		6,463		3,003

Total Distribution:
Colorado	68,597		77,537		35,818
Nebraska	166,171		176,094		83,876
Iowa	155,096		171,632		75,379
Kansas	109,575		107,747		57,815
Total Distribution	499,439		533,010		252,888

Transportation:
Colorado	784		732		278
Nebraska	11,289		10,569		4,703
Iowa	3,708		3,876		1,609
Kansas	5,471		5,389		2,409
Total Transportation	21,252		20,566		8,999

Total Regulated:
Colorado	69,381		78,269		36,096
Nebraska	177,460		186,663		88,579
Iowa	158,804		175,508		76,988
Kansas	115,046		113,136		60,224
Total Regulated Revenues	520,691		553,576		261,887

Non-regulated Services	30,016		26,736		15,189

Total Revenues	$	550,707	$	580,312	$	277,076


Sales Margins (in thousands)	2010		2009		2008

Residential:
Colorado	$	18,153	$	17,443	$	5,984
Nebraska	49,074		44,638		19,460
Iowa	44,269		42,734		16,335
Kansas	29,591		28,999		12,436
Total Residential	141,087		133,814		54,215

Commercial:
Colorado	3,215		3,176		1,131
Nebraska	11,965		11,785		4,952
Iowa	11,616		12,749		5,210
Kansas	6,544		6,484		2,693
Total Commercial	33,340		34,194		13,986

Industrial:
Colorado	360		375		232
Nebraska	379		431		173
Iowa	235		244		105
Kansas	1,878		1,766		1,041
Total Industrial	2,852		2,816		1,551

Other Sales Margins:
Colorado	97		101		39
Nebraska	1,960		2,077		907
Iowa	836		1,073		457
Kansas	2,722		2,312		1,177
Total Other Sales Margins	5,615		5,563		2,580

Total Distribution:
Colorado	21,825		21,095		7,386
Nebraska	63,378		58,931		25,492
Iowa	56,956		56,800		22,107
Kansas	40,735		39,561		17,347
Total Distribution	182,894		176,387		72,332

Transportation:
Colorado	784		732		278
Nebraska	11,289		10,569		4,703
Iowa	3,708		3,876		1,609
Kansas	5,470		5,389		2,409
Total Transportation	21,251		20,566		8,999

Total Regulated:
Colorado	22,609		21,827		7,664
Nebraska	74,667		69,500		30,195
Iowa	60,664		60,676		23,716
Kansas	46,205		44,950		19,756
Total Regulated Sales Margins	204,145		196,953		81,331

Non-regulated Services	12,845		11,643		3,895

Total Sales Margins	$	216,990	$	208,596	$	85,226


Volumes (in Dth)	2010	2009	2008

Residential:
Colorado	6,284,559	6,355,275	2,344,549
Nebraska	12,210,574	12,619,682	5,115,805
Iowa	10,556,045	10,976,268	4,126,150
Kansas	6,926,928	6,878,243	2,682,850
Total Residential	35,978,106	36,829,468	14,269,354

Commercial:
Colorado	1,473,924	1,444,360	563,169
Nebraska	5,009,105	5,189,630	2,133,433
Iowa	6,061,954	6,597,035	2,749,234
Kansas	2,673,805	2,696,870	1,063,356
Total Commercial	15,218,788	15,927,895	6,509,192

Industrial:
Colorado	259,985	263,134	164,112
Nebraska	544,457	581,892	248,256
Iowa	354,435	333,324	196,841
Kansas	2,718,767	2,524,126	1,586,306
Total Industrial	3,877,644	3,702,476	2,195,515

Other Volumes:
Colorado	—	—	—
Nebraska	1,341	1,400	320
Iowa	69,306	68,290	18,301
Kansas	120,445	141,909	60,917
Total Other Volumes	191,092	211,599	79,538

Total Distribution:
Colorado	8,018,468	8,062,769	3,071,830
Nebraska	17,765,477	18,392,604	7,497,814
Iowa	17,041,740	17,974,917	7,090,526
Kansas	12,439,945	12,241,148	5,393,429
Total Distribution	55,265,630	56,671,438	23,053,599

Transportation:
Colorado	808,859	807,999	347,822
Nebraska	27,327,173	25,311,501	12,930,165
Iowa	17,422,525	14,915,602	6,312,050
Kansas	14,320,893	14,069,182	7,215,038
Total Transportation	59,879,450	55,104,284	26,805,075

Total Volumes:
Colorado	8,827,327	8,870,768	3,419,652
Nebraska	45,092,650	43,704,105	20,427,979
Iowa	34,464,265	32,890,519	13,402,576
Kansas	26,760,838	26,310,330	12,608,467
Total Volumes	115,145,080	111,775,722	49,858,674

Degree Days


	2010			2009			2008
	Actual	Variance From 30-Year Average		Actual	Variance From 30-Year Average		Actual *	Variance From 30-Year Average *
Heating Degree Days:
Colorado	5,803	(9	)%	6,299	2	%	2,376	(7	)%
Nebraska	6,222	(5	)%	6,238	5	%	2,458	—	%
Iowa	6,934	(1	)%	7,279	6	%	2,909	3	%
Kansas	4,918	—	%	4,989	—	%	1,897	(3	)%
Combined	6,101	(3	)%	6,285	(11	)%	2,471	—	%

___________

* Gas Utilities acquired on July 14, 2008.

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. For service areas that have weather normalization operations, normal degree days are used instead of actual degree days in computing the total number of heating degree days. The combined heating degree days are calculated based on a weighted average of total customers by state.

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


Customers	2010	2009	2008

Residential:
Colorado	66,766	65,586	64,601
Nebraska	176,244	179,873	177,432
Iowa	134,782	133,712	133,442
Kansas	97,844	97,446	96,593
Total Residential	475,636	476,617	472,068

Commercial:
Colorado	3,620	3,590	3,579
Nebraska	15,221	15,218	15,034
Iowa	15,300	15,403	15,467
Kansas	9,469	9,510	9,463
Total Commercial	43,610	43,721	43,543

Industrial:
Colorado	208	207	208
Nebraska	149	149	149
Iowa	93	90	84
Kansas	1,394	1,351	1,267
Total Industrial	1,844	1,797	1,708

Transportation:
Colorado	22	22	21
Nebraska	4,270	4,579	4,758
Iowa	392	389	397
Kansas	1,054	1,077	1,174
Total Transportation	5,738	6,067	6,350

Other:
Colorado	—	—	—
Nebraska	2	2	2
Iowa	68	71	69
Kansas	8	8	8
Total Other	78	81	79

Total Customers:
Colorado	70,616	69,405	68,409
Nebraska	195,886	199,821	197,375
Iowa	150,635	149,665	149,459
Kansas	109,769	109,392	108,505
Total Customers	526,906	528,283	523,748

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 in comparison to other investor-owned electric utilities. 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 revenues are normally recognized in the heating season consisting of the first and fourth quarters.

Competition

We face competition from other utilities and non-affiliated IPP companies for the right to provide power and capacity for Colorado Electric. However, 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.

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 our utilities are allowed to charge for their 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 through to the customer. In Kansas and Nebraska, we are also allowed to recover the portion of uncollectible accounts related to gas costs through the gas cost adjustments. In Kansas, we 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. In Kansas, we also have 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.

We produce and distribute power in four states. The regulatory provisions for recovering the costs to produce electricity vary by state. 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 changes above or below the threshold.

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

In South Dakota beginning April 1, 2010, the steam plant fuel and conditional energy cost adjustment 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 Colorado, we have a cost adjustment for increases or decreases in purchased power and fuel costs and a transmission cost adjustment. The cost adjustment 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 transmission cost adjustment 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.

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.

The above mechanisms allow the utilities 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, such as the transmission cost adjustment in Colorado, the utility has the opportunity to earn its authorized return on new capital investment.

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, 2010, we were subject to the following renewable energy portfolio standards or objectives:

•

South Dakota. South Dakota has adopted a renewable portfolio objective that encourages utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources by 2015. Absent a specific renewable energy mandate in South Dakota, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers.

•

Montana. Montana established a renewable portfolio standard that requires 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.

•

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 renewable resources with one-half of the renewable 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. Our current strategy is to incorporate renewable energy as required to comply with the standards.

Wyoming is also exploring the implementation of renewable energy portfolio 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 the Aquila Transaction, 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 two of our non-regulated subsidiaries, Black Hills Wyoming and Enserco, 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, enforce 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	9/2008	1/2009	$	4.5	$	3.8	10.8	%	57.0	%	43.0	%
Black Hills Power ⁽⁴⁾	Electric	9/2009	4/2010	$	32.0	$	15.2	Global Settlement		Global Settlement		Global Settlement
Black Hills Power⁽⁵⁾	Electric	10/2009	6/2010	$	3.8	$	3.1	10.5	%	52.0	%	48.0	%
Colorado Electric ⁽⁶⁾	Electric	1/2010	8/2010	$	22.9	$	17.9	10.5	%	52.0	%	48.0	%

(1)

On December 1, 2009, Nebraska Gas filed with the NPSC a $12.1 million rate case requesting a gas revenue increase to recover operating costs and distribution system investments. The proposed increase in revenue was approximately 6.5%. Interim rates, subject to refund for the entire amount of the proposed increase, went into effect on March 1, 2010. On August 18, 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 plan for refund has been approved by the NPSC. An appeal was filed by the OCA relating to the entire rate case decision. However, the NPSC denied this appeal. Subsequently, the OCA filed an appeal in September 2010 appealing a portion of the Commission's order addressing our affiliate transactions. The appeal is still outstanding.

(2)

On June 8, 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)

On February 10, 2009, FERC approved a formulaic approach to the method used to determine the revenue component of Black Hills Power's open access transmission tariff, and increased the utility's annual transmission revenue requirement by approximately $3.8 million. The revenue requirement is based on an equity return of 10.8%, and a capital structure consisting of 57% equity and 43% debt. New annual rates went into effect on January 1, 2009.

(4)

On September 30, 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 past four years. In March 2010, the SDPUC approved a $24.1 million increase in interim rates, subject to refund, effective April 1, 2010 for South Dakota customers. On July 7, 2010, the SDPUC approved a final revenue increase of $15.2 million and a base rate increase of $22.0 million with an effective date of April 1, 2010. The approved capital structure and return on equity are confidential. A refund 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 margins 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 ending March 2011), $2.25 million in fiscal year two, $2.0 million in fiscal year three and zero thereafter; and (3) a moratorium until April 2013 for any base rate increase excluding any extraordinary events as defined in the stipulation agreement; while (4) the SDPUC agreed to adjust the 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

(5)

On October 19, 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.

(6)

On January 6, 2010, Colorado Electric filed a rate case with CPUC requesting a $22.9 million electric revenue increase to recover increased operating expenses associated with 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 margins 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 has therefore required that the off-system sales margins earned beginning August 6, 2010 be deferred on the balance sheet until settlement of the sharing mechanism. Colorado Electric is preparing a proposal for a sharing mechanism to be filed with the CPUC.

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. The ultimate cost could be significantly different from the amounts estimated.


Environmental Expenditure Estimates	Total (in millions)

2011	$	12.7
2012	3.8
2013	0.6
Total	$	17.1

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 late in 2011, 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, NOx, mercury particulate matter, and as of June 23, 2010, Greenhouse Gases. 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 that year. 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 2040. 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 II and Wygen III. Those facilities are allowed to operate under their construction permit until the Title V permits are issued by the state. The Title V application for Wygen II was submitted in 2008, with the permit expected early in 2011. The Wygen III Title V application was submitted in January 2011, with the permit expected in late 2011. Both applications were filed in accordance with regulatory requirements.

On April 29, 2010, the EPA published proposed Industrial and Commercial Boiler regulations, which provide for hazardous air pollutant-related emission limits and monitoring requirements for both major and area sources of hazardous air pollutants. The final rule has a court ordered deadline of February 21, 2011 and we will evaluate once final. If issued as proposed, will have a significant impact on our Neil Simpson I, Osage, Ben French and W.N. Clark facilities. The regulation currently has a three year compliance window and will require engineering evaluations to determine economic viability of continued operations of these units. In our current opinion, the regulations as proposed on April 29, 2010 will lead to retirement of these units within three years of the effective date of the final rule.

The EPA is obligated under a court-approved consent decree to sign a proposed electric utility hazardous air pollutant rule (Utility MACT) by March 16, 2011 and sign its notice of final rule making by November 16, 2011. It is anticipated that affected units will have three years from the rule effective date to be in compliance. In 2010, we participated in the EPA's effort to gather data for rule development. Certain requirements of that regulation could have significant impacts on the Neil Simpson II, Wygen II, Wygen III and Wyodak plants.

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. 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 greenhouse gases, 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 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 within three years of promulgation of the EPA's proposed Industrial and Commercial Boiler Hazardous Air Pollutant Regulation, or in the absence of such regulation, to retire the units by the end of 2017. 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 which, after legislative approval, will be a state regulation and will be submitted to EPA Region VIII for approval.

In June 2011, the EPA is scheduled to issue proposed Electric Utility New Source Performance Standards for greenhouse gases. As the regulations are not yet proposed we cannot ascertain their impacts but we anticipate they will be applicable to Wygen III. In 2011 it is anticipated the EPA will finalize a more stringent ozone ambient air standard. 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 would evaluate Neil Simpson II, Wygen II and Wygen III for further reductions in NO_x emissions.

Mercury regulations

Approximately 60% of our electric generating capacity is coal-fired. The EPA is scheduled to propose the Utility MACT rule by March 16, 2011 which will, among other pollutants, address mercury emissions at Neil Simpson II, Wygen II and Wygen III.

The effects of any new rules regarding mercury reduction cannot be determined at this time and may require us to make significant investments at our power generating facilities. 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 assets that includes wind sources and a fuel mix of coal and natural gas. Of these fuels, coal-fired power plants are the most significant sources of CO₂ emissions. Although we cannot predict specifically how, if or when, greenhouse gases 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, we will be reporting 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, greenhouse gas 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 and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.

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. Federal legislation for renewable energy portfolio standards is also under consideration. We anticipate significant additional costs to comply with any federally 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. We have suspended operations at the Osage power plant as of October 1, 2010. It has an on-site ash impoundment that is near capacity. An application to close the impoundment was filed with the State of Wyoming on November 3, 2010 and any future ash disposal will be at the Wyodak coal mine. Our W.N. Clark plant sends coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages. Agreements are in place that require PacifiCorp and MEAN to be responsible for any such costs related to the solid waste from their ownership interest in the Wyodak plant and Wygen I plant, respectively.

Additional unexpected material costs could also result in the future if any regulator determines that solid waste from the burning of coal contains a hazardous material that requires special treatment, including previously disposed solid waste. In that event, the regulatory authority could hold entities that disposed of such waste responsible for remedial treatment. On June 21, 2010, the EPA published in the Federal Register the proposed coal combustion residuals regulations. The regulations are complex and contain various options for ash management that the EPA will be selecting from to form the final version of the rule. We cannot determine the likely impact on our operations until the final version of the rule is known, which is currently expected to be mid-2011. However, if ash becomes subject to regulations as a hazardous waste, implementation requirements could have a material impact on our financial position or results of operations.

Past Operations

Some federal and state laws authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment.

As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites. In 2010, we undertook a third party review to obtain an updated estimate of remedial costs. From that review, obligations are estimated at between $3.6 million and $6.8 million. The acquisition also provided for a $1.0 million insurance recovery, now valued at $1.1 million, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

We have received rate orders that enable us to recover environmental cleanup costs in certain jurisdictions. In other jurisdictions, there is regulatory precedent for recovery of these costs. We are also pursuing recovery or agreements with other potentially responsible parties when and where permitted.

Non-regulated Energy Group

Our Non-regulated Energy Group, which operates through various subsidiaries, produces natural gas and crude oil primarily in the Rocky Mountain region; produces and sells electric capacity and energy through ownership of a portfolio of generating plants; produces and stores coal; and engages in natural gas, crude oil, coal, power and environmental marketing. The Non-regulated Energy Group consists of four business segments for reporting purposes:


•	Oil and Gas;


•	Power Generation;


•	Coal Mining; and


•	Energy Marketing.

Oil and Gas Segment

Our Oil and Gas segment, which conducts business through BHEP and its subsidiaries, acquires, explores for, develops and produces natural gas and crude oil for sale into commodity markets. As of December 31, 2010, the principal assets of our Oil and Gas segment included: (i) operating interests in oil and natural gas properties, including properties in the San Juan Basin (primarily New Mexico, including holdings within the tribal lands of the Jicarilla Apache and Southern Ute Nations), the Powder River Basin (Wyoming) and the Piceance Basin (primarily in Colorado); (ii) non-operated interests in oil and natural gas properties including wells located in the Williston (Bakken Shale primarily in North Dakota), Wind River (Wyoming), Bearpaw Uplift (Montana), Arkoma (Oklahoma), Anadarko (Texas) and Sacramento (California) basins; and (iii) a 44.7% ownership interest in the Newcastle gas processing plant and associated gathering system located in Weston County, Wyoming. The plant, operated by Western Gas Partners, LP, is adjacent to our producing properties in that area, and BHEP's production accounts for the majority of the facility's throughput. We also own natural gas gathering, compression and treating facilities serving the operated San Juan and Piceance Basin properties and working interests in similar facilities serving our non-operated Montana and Wyoming properties.

At December 31, 2010, we had total reserves of approximately 131 Bcfe, of which natural gas comprised 73% and oil comprised 27% of total reserves. The majority of our reserves are located in select oil and natural gas producing basins in the Rocky Mountain region. Approximately 28% of our reserves are located in the San Juan Basin of northwestern New Mexico, primarily in the East Blanco Field of Rio Arriba County, 26% are located in the Powder River Basin of Wyoming, primarily in the Finn-Shurley Field of Weston and Niobrara counties and 25% are located in the Piceance Basin of western Colorado.

Delivery Commitments

None of our oil and gas production is sold under long-term product delivery commitments.

Summary Oil and Gas Reserve Data

The summary information presented concerning our estimated proved developed and undeveloped oil and gas reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by CG&A, an independent consulting and engineering firm located in Fort Worth, Texas. Reserves in 2010 and 2009 were determined consistent with SEC requirements using a 12-month average price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Estimates of economically recoverable reserves and future net revenues are based on a number of variables, which may differ from actual results. Our 2008 reserves were determined based on the previous guidelines utilizing the price on the last day of the reporting period. (Oil (in Mbbl) is multiplied by six to convert to MMcfe). Additional information on our oil and gas reserves, related financial data and the SEC requirements can be found in Note 21 to the Consolidated Financial Statements in this Annual Report on Form 10-K.

The Company believes it maintains adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interest and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans. The Company's internal engineers and our independent reserve engineering firm, CG&A, work independently and concurrently to develop reserve volume estimates. Current revenue and expense information is obtained from the Company's accounting records, which are subject to external quarterly reviews, annual audits and internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. The Company's current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated in the reserve database as well and verified to ensure their accuracy and completeness. Once the reserve database has been entirely updated with current information, and all relevant technical support materials have been assembled, CG&A meets with the Company's technical personnel to review field performance and future development plans in order to further verify their validity. Following these reviews the reserve database, including updated cost, price and ownership data, is furnished to CG&A so that they can prepare their independent reserve estimates and final report. Access to the Company's reserve database is restricted to specific members of the engineering department.

CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas and has over 22 years of practical experience in petroleum engineering and over 20 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

BHEP's Manager of Planning and Analysis is the technical person primarily responsible for overseeing our third party reserve estimates. He has over 30 years of Exploration and Production industry experience as a geologist. He has over 20 years of experience working closely with internal and third party qualified reserve estimators in major and mid-sized oil and gas companies. He holds a Bachelor of Science degree in Geology and a Masters in Business Administration.

The following tables set forth summary information concerning our estimated proved developed and undeveloped reserves, by basin, as of December 31, 2010, 2009 and 2008:


Proved Reserves		December 31, 2010
	Total	Piceance	San Juan		Williston	Powder River	Other
Developed -
Natural Gas (MMcf)	67,656	11,475	36,281		679	10,180	9,041
Oil (Mbbl)	4,434	—	11		508	3,891	24
Total Developed (MMcfe)	94,260	11,475	36,347	</