Edgar Filing: BLACK HILLS CORP /SD/

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K

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

For the fiscal year ended December 31, 2008

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		IRS Identification Number 46-0458824
	625 Ninth Street
	Rapid City, South Dakota 57701

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

Securities registered pursuant to Section 12(b) of the Act:
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

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

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

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. o

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

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

Yes

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

At June 30, 2008

$1,218,945,373

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, 2009
Common stock, $1.00 par value	38,699,227 shares

Documents Incorporated by Reference

1.	Portions of the Registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2009 Annual Meeting of Stockholders to be held on May 19, 2009, are incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS

		Page

	GLOSSARY OF TERMS AND ABBREVIATIONS	3

	WEBSITE ACCESS TO REPORTS	8

	FORWARD-LOOKING INFORMATION	8

ITEMS 1. and 2.	BUSINESS AND PROPERTIES	11

ITEM 1A.	Risk Factors	42

ITEM 1B.	UNRESOLVED STAFF COMMENTS	52

ITEM 3.	LEGAL PROCEEDINGS	52

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	52

ITEM 4A.	EXECUTIVE OFFICERS OF THE REGISTRANT	53

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
	MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	55

ITEM 6.	SELECTED FINANCIAL DATA	57

ITEMS 7. and 7A.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
	AND RESULTS OF OPERATIONS AND QUANTITATIVE AND
	QUALITATIVE DISCLOSURES ABOUT MARKET RISK	59

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	109

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
	ACCOUNTING AND FINANCIAL DISCLOSURE	181

ITEM 9A.	CONTROLS AND PROCEDURES	181

ITEM 9B.	OTHER INFORMATION	181

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	182

ITEM 11.	EXECUTIVE COMPENSATION	182

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
	MANAGEMENT AND RELATED STOCKHOLDER MATTERS	182

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND	183
	DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	183

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	184

	SIGNATURES	190

	INDEX TO EXHIBITS	191

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
AOCI	Accumulated Other Comprehensive Income
Aquila	Aquila, Inc.
Aquila Transaction	Our July 14, 2008 acquisition of five utilities from Aquila
ARO	Asset Retirement Obligations
BART	Best Available Retrofit Technology
Basin Electric	Basin Electric Power Cooperative
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
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
BHER	Black Hills Energy Resources, Inc., a direct, wholly-owned subsidiary of
	Black Hills Non-regulated Holdings
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.
	including the gas and electric utility properties acquired from Aquila
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 the Company that was formerly known as Black Hills Energy, Inc.
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of
	the Company formed to acquire and own the utility properties acquired
	from Aquila, all which are now doing business as Black Hills Energy
Black Hills Wyoming	Black Hills Wyoming, Inc., a direct, wholly-owned subsidiary of Black
	Hills Electric Generation
Btu	British thermal unit
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned
	subsidiary of the Company
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
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, formed to hold the Colorado electric utility properties
	acquired from Aquila
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, formed to hold the Colorado gas utility properties
	acquired from Aquila
CPUC	Colorado Public Utilities Commission

CT	Combustion turbine
Dth	Dekatherms
Enserco	Enserco Energy Inc., a wholly-owned subsidiary of Black Hills
	Non-regulated Holdings
Enserco Facility	The $300 million uncommitted, secured line of credit that supports Enserco’s
	marketing and trading operations, which currently expires May 8, 2009
EPA	U. S. Environmental Protection Agency
EPA 2005	Energy Policy Act of 2005
ERISA	Employee Retirement Income Security Act
EWG	Exempt Wholesale Generator
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
Fortis	Fortis Capital Group
GAAP	Accounting principles generally accepted in the United States
GCA	Gas Cost Adjustment
Great Plains	Great Plains Energy Incorporated
Hastings	Hastings Fund Management Ltd
IGCC	Integrated Gasification Combined Cycle
IIF	IIF BH Investment LLC, a subsidiary of an investment entity advised by
	JPMorgan Asset Management
Indeck	Indeck Capital, Inc.
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, formed to hold the Iowa gas utility properties acquired from
	Aquila
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
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, formed to hold the Kansas gas utility properties acquired from
	Aquila
KCC	Kansas Corporation Commission
KWh	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Las Vegas II	Las Vegas II gas-fired power plant
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 public 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.
MTPSC	Montana Public Service Commission
MW	Megawatts

MWh	Megawatt-hours
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, formed to hold the Nebraska gas utility properties acquired
	from Aquila
NERC	North American Electric Reliability Corporation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
PCA	Power Cost Adjustment
PGA	Purchase Gas Adjustment
PSCo	Public Service Company of Colorado
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
RTO	Regional Transmission Organization
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
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
VIE	Variable Interest Entity
WDEQ	Wyoming Department of Environmental Quality
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, a direct, wholly-owned
	subsidiary of Black Hills Non-regulated Holdings

ACCOUNTING PRONOUNCEMENTS

APB	Accounting Principles Board
APB 25	APB Opinion No. 25, “Accounting for Stock Issued to Employees”
ARB	Accounting Research Bulletin
ARB No. 51	ARB No. 51, “Consolidated Financial Statements”
EITF	Emerging Issues Task Force
EITF 04-6	EITF Issue No. 04-6, “Accounting for Stripping Costs Incurred during
	Production in the Mining Industry”
EITF 87-24	EITF 87-24, “Allocation of Interest to Discontinued Operations”
EITF 91-6	EITF No. 91-6, “Revenue Recognition of Long-Term Power Sales Contracts”
EITF 98-10	EITF Issue No. 98-10, “Accounting for Contracts involving Energy Trading
	and Risk Management Activities”
EITF 99-19	EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as
	an Agent”
EITF 02-3	EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts
	Held for Trading Purposes and Contracts Involved in Energy Trading and
	Risk Management Activities”
FIN 39	FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain
	Contracts – an Interpretation of APB Opinion No. 10 and FASB
	Statement No. 105”
FIN 45	FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure
	Requirements for Guarantees, Including Indirect Guarantees of
	Indebtedness of Others”
FIN 46	FASB Interpretation No. 46, “Consolidation of Variable Interest Entities”
FIN 46(R)	FASB Interpretation No. 46, “Consolidation of Variable Interest Entities
	Revised”
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes –
	an Interpretation of FASB Statement 109”
FSP	FASB Staff Position
FSP FAS 157-1	FSP FAS 157-1, “Application of FASB Statement No. 157 to FASB
	Statement No. 13 and Other Accounting Pronouncements that Address
	Fair Value Measurement for Purposes of Lease Classification or
	Measurement under Statement 13”
FSP FAS 157-2	FSP FAS 157-2, “Effective Date of FASB Statement No. 157”
FSP FIN 39-1	FSP FIN 39-1, “Amendment of FASB Interpretation No. 39”
SEC Final Rule #33-8995	Modernization of Oil and Gas Reporting
SFAS	Statement of Financial Accounting Standards
SFAS 13	SFAS 13, “Accounting for Leases”
SFAS 69	SFAS 69, “Disclosures about Oil and Gas Producing Activities – an
	amendment of FASB Statements 19, 25, 33 and 39”
SFAS 71	SFAS 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 87	SFAS 87, “Employers’ Accounting for Pensions”
SFAS 109	SFAS 109, “Accounting for Income Taxes”
SFAS 123	SFAS 123, “Accounting for Stock-Based Compensation”
SFAS 123(R)	SFAS 123 (Revised 2004), “Share-Based Payment”
SFAS 132(R)	SFAS 132(R), “Employer’s Disclosures about Pensions and Other
	Postretirement Benefits – an amendment of FASB Statements No. 87, 88
	and 106”
SFAS 133	SFAS 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141(R)	SFAS 141 (Revised 2007), “Business Combinations”
SFAS 142	SFAS 142, “Goodwill and Other Intangible Assets”
SFAS 143	SFAS 143, “Accounting for Asset Retirement Obligations”
SFAS 144	SFAS 144, “Accounting for the Impairment of Long-lived Assets”

SFAS 157	SFAS 157, “Fair Value Measurements”
SFAS 158	SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other
	Postretirement Plans, an Amendment of FASB Statements No. 87, 88, 106
	and 132(R)”
SFAS 159	SFAS 159, “The Fair Value Option for Financial Assets and Financial
	Liabilities”
SFAS 160	SFAS 160, “Non-controlling Interest in Consolidated Financial Statements –
	an amendment of ARB No. 51”
SFAS 161	SFAS 161,“Disclosure about Derivative Instruments and Hedging
	Activities – an amendment of FASB Statement No. 133”

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 Officer, Corporate Governance Guidelines of our Board of Directors and Policy for Independent Directors. The information contained on our website is not part of this document.

Our Chief Executive Officer and Chief Financial Officer have filed with the SEC, as exhibits to our Annual Report on Form 10-K, the certifications required by Section 302 of the Sarbanes Oxley Act regarding the quality of our public disclosure. Our Chief Executive Officer certified to the New York Stock Exchange following our 2008 annual shareholder meeting that he was not aware of violations by us of the New York Stock Exchange corporate governance listing standards.

Each of the foregoing documents is available in print to any of our shareholders upon request by writing to Black Hills Corporation, Attention: Investor Relations, 625 Ninth Street, Rapid City, South Dakota 57701.

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. 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. However, 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:

• 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 and purchased power in our regulated utilities;

• Our ability to obtain permanent financing for the Aquila Transaction and other capital expenditures on reasonable terms;

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

• Our ability to receive regulatory approval from the CPUC for our proposed construction of new power generation facilities for Colorado Electric;

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

• Our ability to successfully maintain our corporate credit rating;

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

• 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 meet production targets 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;

• Our ability to accurately estimate demand from our customers for natural gas;

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

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

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

• 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;

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

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

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

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

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

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

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

• Changes in state laws or regulations that could cause us to curtail our independent power production or exploration and production activities;

• Weather and other natural phenomena;

• Macro- and micro-economic changes in the economy and energy industry, including the impact of (i) consolidations and changes in competition, (ii) changing conditions in the capital and credit markets, which affect our ability to raise capital on favorable terms, and (iii) general economic and political conditions, including tax rates or policies and inflation rates;

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

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

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

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

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 (the “Company,” “we,” “us,” “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 selling and marketing various forms of energy on an unregulated basis.

We operate principally in the United States with two major business groups: Utilities and Non-regulated Energy. Our Utilities Group is comprised of our Electric Utilities and 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, 2008, we had 2,122 employees, 686 of which 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 202,100 customers in South Dakota, Wyoming, Colorado and Montana and includes the operations of Cheyenne Light, a combination electric and gas utility, and its approximately 33,300 gas utility customers in Wyoming. Our Gas Utilities segment serves approximately 524,000 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities owns 630 MWs of generation and 7,909 miles of electric transmission and distribution lines, and our Gas Utilities owns 629 miles of intrastate gas transmission pipelines and 7,878 miles of gas distribution mains and service lines. Our Electric and Gas Utilities generated earnings from continuing operations of $43.9 million in the year ended December 31, 2008 and had total assets of $2.2 billion at December 31, 2008.

Prior to the third quarter of 2008, our Utilities Group consisted of two reporting segments: our Electric Utility segment (Black Hills Power) and our combination Electric and Gas Utility segment (Cheyenne Light). In the third quarter of 2008, we changed the reporting segments within our Utilities Group to reflect significant changes to our utility business resulting from the Aquila Transaction, through which we acquired four gas utility systems and one electric utility system.

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 markets natural gas, crude oil and related services, primarily in the Western and Mid-continent regions of the Unites 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.

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 20 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 202,100 customers in South Dakota, Wyoming, Colorado and Montana. They also distribute natural gas to approximately 33,300 natural gas utility customers served by Cheyenne Light 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 natural gas to approximately 524,000 customers in Colorado, Iowa, Kansas and Nebraska. We also release excess capacity to pipelines and other pipeline customers when we do not need such pipeline capacity for our Gas Utilities customers.

Since our three electric utilities and our four natural gas utilities have similar economic characteristics, we aggregate our electric utility operations into the Electric Utilities segment and our gas utility operations into the Gas Utilities segment.

Electric Utilities Segment

Capacity and Demand

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

By Entity	System Peak Demand (in MW)

	2008		2007		2006
	Summer	Winter	Summer	Winter	Summer	Winter

Black Hills Power	409	407	430	361	415	331
Cheyenne Light	166	168	163	152	155	146
Colorado Electric^(a)	306	298	—	—	—	—
Total Electric
Utilities	881	873	593	513	570	477

__________________________

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

Regulated Power Plants

As of December 31, 2008, our Electric Utilities’ ownership interests in electric generation plants were as follows:

			Ownership	Gross
	Fuel		Interest	Capacity	Year
Unit	Type	Location	%	(MW)	Installed

Black Hills Power⁽¹⁾:
Neil Simpson II	Coal	Gillette, WY	100	90.0	1995
Wyodak⁽²⁾	Coal	Gillette, WY	20	72.4	1978
Osage	Coal	Osage, WY	100	34.5	1948-1952
Ben French	Coal	Rapid City, SD	100	25.0	1960
Neil Simpson I	Coal	Gillette, WY	100	21.8	1969
Neil Simpson CT	Gas	Gillette, WY	100	40.0	2000
Lange CT	Gas	Rapid City, SD	100	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, SD	100	10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, SD	100	100.0	1977-1979
Cheyenne Light:
Wygen II	Coal	Gillette, WY	100	95.0	2008
Colorado Electric:
W.N. Clark #1-2	Coal	Canon City, CO	100	42.0	1955, 1959
Pueblo #6	Gas	Pueblo, CO	100	20.0	1949
Pueblo #5	Gas	Pueblo, CO	100	9.0	1941, 2001
AIP Diesel	Oil	Pueblo, CO	100	10.0	2001
Diesel #1-5	Oil	Pueblo, CO	100	10.0	1964
Diesel #1-5	Oil	Rocky Ford, CO	100	10.0	1964

________________________

(1)

During 2008, we began construction of Wygen III, a 110 MW mine-mouth coal-fired power plant. The plant is on schedule to be completed in mid-2010. We expect that Black Hills Power will operate the plant and own a 75% interest in the facility and MDU will own the remaining 25%. Our WRDC coal mine will furnish 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% (or 72.4 MW) by Black Hills Power. The baseload plant is operated by PacifiCorp and our WRDC coal mine furnishes all of the coal fuel supply for the plant.

The following table shows the Electric Utilities’ annual average cost of fuel utilized to generate electricity and the average price paid for purchased power per MWh during the last three years:

Fuel Source	2008⁽¹⁾		2007⁽²⁾		2006⁽²⁾
	($ per MWh)		($ per MWh)		($ per MWh)

Coal	$	11.41	$	8.94	$	7.87

Gas and Oil	$	87.57	$	68.04	$	75.77

Total Average Fuel Cost	$	13.18	$	11.84	$	9.94

Purchased Power	$	48.24	$	40.79	$	44.86

________________________

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

(2)	Excludes Colorado Electric, which we did not acquire until July 14, 2008.

Power Supply

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

	2008	2007	2006

Coal-fired	44%	42%	40%

Gas and Oil	1	2	1
Total Generated	45%	44%	41%

Purchased	55	56	59

Total	100%	100%	100%

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

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

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

• A long-term contract with PSCo expiring in 2011, whereby Colorado Electric purchases a majority of its power. The contract provides for 280 MW of capacity and energy in 2009, increasing 10 MW per year to 300 MW in 2011;

• Cheyenne Light’s power purchase agreements with Black Hills Wyoming that provide Cheyenne Light with 40 MW of energy and capacity from our Gillette CT under a 10-year power purchase agreement expiring in August 2011, and 60 MW of unit contingent capacity and energy from our Wygen I facility under a 10-year agreement expiring the first quarter of 2013;

• Cheyenne Light’s 20-year purchase power agreement with Happy Jack Wind Power, LLC, expiring in September 2028, providing up to 29.4 MW of renewable energy from the Happy Jack Wind Farm to Cheyenne Light. Cheyenne Light has sold 67% of the output of this facility to Black Hills Power. Cheyenne Light and Black Hills Power receive 100% of the renewable energy credits under the agreement; and

• Cheyenne Light and Black Hills Power’s Generation Dispatch Agreement that requires Black Hills Power to purchase all of Cheyenne Light’s excess energy.

Power Sales Agreements. Our Electric Utilities have various long-term power sales agreements. Key agreements include:

• An agreement under which we supply up to 74 MW of capacity and energy to MDU for the Sheridan, Wyoming electric service territory through the end of 2016. The sales to MDU have been integrated into Black Hills Power’s control area and are considered part of our firm native load. In accordance with the terms of the agreement, MDU has an option to participate in the ownership of the Wygen III plant that is currently being constructed. MDU has notified us of its intentions to exercise their option to participate in the Wygen III project and we expect to renegotiate the power sales agreement to reduce the energy and capacity supplied by us under the agreement;

• An agreement with the City of Gillette, Wyoming, to provide the City its first 23 MW of capacity and energy annually. The sales to the City of Gillette have been integrated into Black Hills Power’s control area and are considered part of our firm native load. The agreement renews automatically and requires a seven year notice of termination. As of December 31, 2008, neither party to the agreement had given a notice of termination; and

• An agreement under which Black Hills Power supplies 20 MW of energy and capacity to MEAN under a contract that expires in 2013. This contract is unit-contingent based on the availability of our Neil Simpson II plant.

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, 2008, Electric Utilities owned or leased the electric transmission and distribution lines shown below:

Utility	State	Transmission	Distribution
		(in Line Miles)	(in Line Miles)

Black Hills Power	SD, WY	497	2,834
Black Hills Power – Jointly Owned	SD, WY	47	—
Cheyenne Light	SD, WY	25	1,132
Colorado Electric	CO	195	3,179

Through Black Hills Power, we own 35% of a 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. Black Hills Power’s electric system is located in the WECC region, and the total transfer capacity of the tie is 400 MW – 200 MW from West to East, and 200 MW from East to West. This transmission tie allows us to buy and sell energy in the Eastern 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 the power price differentials between the two grids. Additionally, Black Hills Power’s system is capable of directly interconnecting up to 80 MW of generation or load to the Eastern transmission grid.

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 from 2007 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 2016, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.

Operating Statistics

The following tables summarize regulated sales revenues, sales quantities and customers for our Electric Utilities segment. 2008 reported amounts include Colorado Electric from its July 14, 2008 acquisition date through December 31, 2008, whereas 2007 and 2006 amounts do not include Colorado Electric:

Sales Revenues	2008		2007		2006
	(in thousands)
Residential:
Black Hills Power	$	46,854	$	45,657	$	40,491
Cheyenne Light		31,394		24,060		27,585
Colorado Electric		32,620		—		—
Total Residential		110,868		69,717		68,076

Commercial:
Black Hills Power		58,289		55,991		49,756
Cheyenne Light		51,609		38,871		44,785
Colorado Electric		28,531		—		—
Total Commercial		138,429		94,862		94,541

Industrial:
Black Hills Power		21,432		21,974		20,694
Cheyenne Light		9,716		7,306		8,540
Colorado Electric		16,280		—		—
Total Industrial		47,428		29,280		29,234

Municipal:
Black Hills Power		2,734		2,697		2,401
Cheyenne Light		973		797		832
Colorado Electric		2,289		—		—
Total Municipal		5,996		3,494		3,233

Contract Wholesale:
Black Hills Power		26,643		25,240		24,705

Off-system Wholesale:
Black Hills Power		63,770		35,210		42,489
Cheyenne Light		6,105		—		—
Colorado Electric		11,194		—		—
Total Off-system Wholesale		81,069		35,210		42,489

Other:
Black Hills Power		12,950		12,932		12,630
Cheyenne Light		394		208		421
Colorado Electric		1,346		—		—
Total Other		14,690		13,140		13,051

Total Sales Revenues	$	425,123	$	270,943	$	275,329

Quantities Generated and Purchased (MWh)	2008		2007		2006

Generated –
Coal-fired:
Black Hills Power		1,731,838		1,758,280		1,729,636
Cheyenne Light		740,051⁽¹⁾		—		—
Colorado Electric		138,424		—		—
Total Coal		2,610,313		1,758,280		1,729,636

Gas and Oil-fired:
Black Hills Power		61,801		90,618		54,299
Cheyenne Light		—		—		—
Colorado Electric		306		—		—
Total Gas and Oil		62,107		90,618		54,299

Total Generated:
Black Hills Power		1,793,639		1,848,898		1,783,935
Cheyenne Light		740,051		—		—
Colorado Electric		138,730		—		—
Total Generated		2,672,420		1,848,898		1,783,935

Purchased:
Black Hills Power		1,703,088		1,279,005		1,553,024
Cheyenne Light		590,622		1,047,782		978,613
Colorado Electric		1,028,029		—		—
Total Purchased		3,321,739		2,326,787		2,531,637

Total Generated and Purchased		5,994,159		4,175,685		4,315,572

__________________________

(1)	Represents the Wygen II plant that began providing electricity to Cheyenne Light customers on January 1, 2008.

Quantity Sold (MWh)	2008		2007		2006

Residential:
Black Hills Power		524,413		518,148		499,152
Cheyenne Light		255,345		251,313		249,888
Colorado Electric		284,294		—		—
Total Residential		1,064,052		769,461		749,040

Commercial:
Black Hills Power		699,734		690,702		667,220
Cheyenne Light		586,151		561,963		536,954
Colorado Electric		330,870		—		—
Total Commercial		1,616,755		1,252,665		1,204,174

Industrial:
Black Hills Power		414,421		434,627		433,019
Cheyenne Light		144,179		141,353		129,462
Colorado Electric		235,218		—		—
Total Industrial		793,818		575,980		562,481

Municipal:
Black Hills Power		34,368		34,661		32,961
Cheyenne Light		3,669		3,658		3,634
Colorado Electric		19,740		—		—
Total Municipal		57,777		38,319		36,595

Contract Wholesale:
Black Hills Power		665,795		652,931		647,444

Off-system Wholesale:
Black Hills Power		1,074,398		678,581		942,045
Cheyenne Light		246,542		—		—
Colorado Electric		230,333		—		—
Total Off-system Wholesale		1,551,273		678,581		942,045

Total Quantity Sold		5,749,470		3,967,937		4,141,779

Losses and Company Use:
Black Hills Power		83,598		118,253		115,118
Cheyenne Light		94,787		89,495		58,675
Colorado Electric		66,304		—		—
Total Losses and Company Use		244,689		207,748		173,793

Total Energy		5,994,159		4,175,685		4,315,572

Degree Days	2008		2007		2006

		Variance		Variance		Variance
		from		from		from
Heating Degree Days:	Actual	Normal	Actual	Normal	Actual	Normal
Actual –
Black Hills Power	7,676	6%	6,627	(7)%	6,472	(10)%
Cheyenne Light	7,435	1%	6,964	(6)%	6,789	(8)%
Colorado Electric	2,204	(5)%	—	—	—	—

Cooling Degree Days:
Actual –
Black Hills Power	482	(19)%	1,033	74%	931	56%
Cheyenne Light	372	36%	536	96%	486	78%
Colorado Electric	500	(12)%	—	—	—	—

Electric Customers at Year-End	2008		2007		2006

Residential:
Black Hills Power		53,765		53,057		52,521
Cheyenne Light		35,205		35,175		34,982
Colorado Electric		81,561		—		—
Total Residential		170,531		88,232		87,503

Commercial:
Black Hills Power		12,213		12,073		11,917
Cheyenne Light		4,563		4,381		4,136
Colorado Electric		11,155		—		—
Total Commercial		27,931		16,454		16,053

Industrial:
Black Hills Power		40		41		46
Cheyenne Light		2		2		2
Colorado Electric		93		—		—
Total Industrial		135		43		48

Contract Wholesale:
Black Hills Power		3		3		3

Other:
Black Hills Power		3,010		3,012		2,996
Cheyenne Light		6		6		6
Colorado Electric		480		—		—
Total Other		3,496		3,018		3,002

Total Customers at Year-End		202,096		107,750		106,609

Cheyenne Light Natural Gas Distribution

Cheyenne Light’s natural gas distribution system serves approximately 33,300 natural gas customers in Cheyenne and other portions of Laramie County, Wyoming. Our peak capacity was approximately 40 thousand Dth during the year ending December 31, 2008. The following table summarizes certain operating information of these natural gas distribution operations:

	2008		2007		2006

Sales Revenues (in thousands):
Residential	$	28,059	$	18,985	$	27,854
Commercial		13,751		9,437		14,640
Industrial		5,668		3,340		6,605
Other		818		706		927
Total Sales Revenues	$	48,296	$	32,468	$	50,026

Sales Margins (in thousands):
Residential	$	10,083	$	6,408	$	6,389
Commercial		3,177		2,268		2,258
Industrial		483		436		495
Other		818		707		927
Total Sales Margins	$	14,561	$	9,819	$	10,069

Volumes Sold (Dth):
Residential		2,582,248		2,380,945		2,325,229
Commercial		1,501,025		1,382,150		1,351,412
Industrial		689,945		664,807		711,126
Total Volumes Sold		4,773,218		4,427,902		4,387,767

Gas Utilities Segment

At December 31, 2008, Gas Utilities owned the gas transmission and distribution lines shown below:

	Intrastate Gas	Gas Distribution Mains and
State	Transmission Pipelines	Service Lines
	(in line miles)	(in line miles)

Colorado	122	857
Nebraska	51	3,438
Iowa	170	2,304
Kansas	286	1,279

The following tables summarize regulated Gas Utilities’ sales revenues, sales margins and volumes for the period of July 14, 2008 to December 31, 2008 and customers as of December 31, 2008:

	Sales Revenues		Sales Margins		Volumes Sold
	(in thousands)		(in thousands)		(Dth)

Residential:
Colorado	$	27,928	$	5,984		2,344,549
Nebraska		60,624		19,460		5,115,805
Iowa		47,338		16,335		4,126,150
Kansas		31,456		12,436		2,682,850
Total Residential		167,346		54,215		14,269,354

Commercial:
Colorado		6,356		1,131		563,169
Nebraska		20,705		4,952		2,133,433
Iowa		26,003		5,210		2,749,234
Kansas		10,092		2,693		1,063,356
Total Commercial		63,156		13,986		6,509,192

Industrial:
Colorado		1,495		232		164,112
Nebraska		1,640		173		248,256
Iowa		1,581		105		196,841
Kansas		14,667		1,041		1,586,306
Total Industrial		19,383		1,551		2,195,515

Transportation:
Colorado		278		278		347,822
Nebraska		4,703		4,703		12,930,165
Iowa		1,609		1,609		6,312,050
Kansas		2,409		2,409		7,215,038
Total Transportation		8,999		8,999		26,805,075

Other:
Colorado		39		39		—
Nebraska		907		907		320
Iowa		457		457		18,301
Kansas		1,600		1,177		60,917
Total Other		3,003		2,580		79,538

Total Regulated		261,887		81,331		49,858,674

Non-regulated Services		15,189		3,895		—

Total	$	277,076	$	85,226		49,858,674

Degree Days	2008
			Variance
			From
Heating Degree Days:	Actual		Normal

Colorado		2,376		(7)%
Nebraska		2,458		—
Iowa		2,909		3%
Kansas		1,897		(3)%

	December 31,
Gas Customers at Year-End	2008

Residential:
Colorado		64,601
Nebraska		177,432
Iowa		133,442
Kansas		96,593
Total Residential		472,068

Commercial:
Colorado		3,579
Nebraska		15,034
Iowa		15,467
Kansas		9,463
Total Commercial		43,543

Industrial:
Colorado		208
Nebraska		149
Iowa		84
Kansas		1,267
Total Industrial		1,708

Transportation:
Colorado		21
Nebraska		4,758
Iowa		397
Kansas		1,174
Total Transportation		6,350

Other:
Colorado		—
Nebraska		2
Iowa		69
Kansas		8
Total Other		79

Total Customers at Year-End		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 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 utilities. Conversely, 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 of the first and fourth quarters.

Competition

We generally have limited competition for the retail distribution of electricity and natural gas in our service areas. In the past, various restructuring and competitive initiatives have been discussed in the states in which our utilities operate, but none have been implemented. 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. In Colorado, our electric utility is subject to rules which require competitive bidding for generation supply. Accordingly, we face competition from other utilities and IPP companies for the right to provide generation for Colorado Electric.

Regulation and Rates

State Regulation

Our utilities are subject to the jurisdiction of the public utilities commissions in the states in which they operate. The commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. 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 have cost adjustments that allow them to pass the prudently-incurred cost of gas through to the customer. In Kansas and Nebraska, we are also allowed to recover a portion of uncollectible accounts through the cost adjustments. In Kansas we have also established a weather normalization tariff that provides a pass-through mechanism for weather margin variability from the level used to establish base rates to be paid by the customer.

We produce and distribute power in four states. The regulatory provisions for recovering power costs vary by state. In South Dakota, Wyoming, Montana and Colorado, 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 below the threshold.

In South Dakota, we have three adjustment mechanisms: transmission, steam plant fuel and conditional energy cost adjustment. The transmission and steam plant fuel adjustment clauses will either pass along or give credits back to South Dakota customers based on actual costs incurred on a yearly basis. The conditional energy cost adjustment relates to purchased power and natural gas used to generate electricity. These costs are subject to $2.0 million and $1.0 million cost bands where Black Hills Power absorbs the first $2.0 million of increased costs or retains the first $1.0 million in savings. Beyond these thresholds, costs or refunds begin to be passed on to South Dakota customers through annual calendar-year filings.

In Colorado, we have a cost adjustment for increases or decreases to 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 a return on new transmission investment and recover operations and maintenance costs related to transmission.

The above mechanisms allow the utilities to collect, or refund, the difference between the costs of commodities imbedded in our base rates and the actual costs of the commodities 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 in which 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, 2008, 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. In 2005, 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.

• Colorado. In 2007, the Colorado legislature 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) at least 10% of its retail sales by 2010; (ii) 15% of retail sales by 2015; and (iii) 20% of retail sales by 2020. Of these amounts, 4% must be generated from solar renewable resources with one-half of the solar resources being located at customer facilities. The new 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.

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 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.

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.

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.

The following summarizes our recent rate case activity:

	Type of	Date	Date	Amount		Amount
	Service	Requested	Effective	Requested		Approved
				(in millions)

Kansas Gas⁽¹⁾	Gas	11/2006	6/2007	$	7.2	$	5.1
Nebraska Gas⁽²⁾	Gas	11/2006	9/2007	$	16.3	$	9.2
Cheyenne Light⁽³⁾	Electric	3/2007	1/2008	$	8.4	$	6.7
Cheyenne Light⁽⁴⁾	Gas	3/2007	1/2008	$	4.6	$	4.4
Iowa Gas⁽⁵⁾	Gas	6/2008	Pending	$	13.6		Pending
Colorado Gas⁽⁶⁾	Gas	6/2008	Pending	$	2.8		Pending

___________________________

(1)

In April 2007, Kansas Gas entered into an agreement that resulted in a “black box” settlement of $5.1 million, with a residential customer charge of $16 per month that will recover approximately 65% of the margin through the customer charge. The KCC approved the settlement in May 2007, and the new rates were implemented on June 1, 2007.

(2)

In November 2006, Nebraska Gas filed for a $16.3 million rate increase. Interim rates were implemented in February 2007 and, in July 2007, the NPSC granted a $9.2 million increase in annual revenues based on an equity return of 10.4% on a capital structure of 51% equity and 49% debt. Nebraska Gas appealed the decision, and the district court affirmed the NPSC order in February 2008. Because Nebraska Gas collected interim rates subject to refund, it was required to refund to customers the difference between the higher interim rates and the final rates plus interest (approximately $5.6 million).

(3)

In November 2007, the WPSC granted Cheyenne Light a $6.7 million increase in annual electric utility revenues based on an equity return of 10.9% on a capital structure of 54% equity and 46% debt. The new rates were implemented on January 1, 2008. The WPSC also placed the Wygen II power plant into rate base and approved a pass-through mechanism for Cheyenne Light’s electric business. Under the pass-through mechanism, the annual increase or decrease for transmission, fuel and purchased power costs is passed through to customers, subject to a $1.0 million threshold. Under its tariff, Cheyenne Light collects or refunds 95% of the increase or decrease that exceeds the $1.0 million threshold; for changes below the threshold, Cheyenne Light absorbs the increase or retains the savings.

(4)	In November 2007, the WPSC granted Cheyenne Light a $4.4 million increase in annual gas utility revenues based on an equity return of 10.9% on a capital structure of 54% equity and 46% debt. The new rates were implemented on January 1, 2008.

(5)

In June 2008, Iowa Gas filed for a $13.6 million rate increase. The proposed increase is based on an equity return of 11.5% on a capital structure of 52% equity and 48% debt. Interim rates with increases totaling $9.5 million annually were implemented on June 13, 2008. On August 12, 2008, the IUB issued an order that extended the usual ten month time limit for consideration of the general rate increase by three months, from April 2, 2009 to July 2, 2009. The IUB has until July 2, 2009 to issue a decision on our rate request. If interim rates exceed final approved rates, the difference plus interest will be refunded or credited to customers.

(6)

In June 2008, Colorado Gas filed for a $2.8 million rate increase. On February 4, 2009, a settlement of the rate case (of which all parties either supported or did not oppose) was presented to an administrative law judge. The settlement provides for an increase of $1.4 million, a return on equity of 10.25% and a capital structure of 50.48% equity and 49.52% debt. The administrative law judge will make a recommendation regarding the settlement to the CPUC and it will make the final decision on the settlement. The CPUC has until June 16, 2009 to issue a decision on our rate request, but as part of the settlement, the parties requested an expeditious approval to allow for an earlier effective date.

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. In that regard, our public utility subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.

Our Electric Utilities and our non-regulated subsidiary, Black Hills Wyoming, are authorized by FERC to make wholesale sales of electric capacity and energy at market-based rates under tariffs on file with FERC. As a condition of their market-based rate authority, each files Electric Quarterly Reports with FERC. Black Hills Power owns and operates FERC-jurisdictional interstate transmission facilities and provide 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.

On September 29, 2008, Black Hills Power requested FERC approval to revise the method used to determine the revenue component of the utility’s open access transmission tariff, and increase the utility’s annual transmission revenue requirement by approximately $4.5 million. The proposed revenue requirement is based on an equity return of 10.95%. On December 12, 2008, Black Hills Power filed a settlement agreement with FERC. The settlement agreement was reached with the only two interveners in the rate case. The settlement sought annual transmission revenue of $3.8 million based on an equity return of 10.80%, 57% equity and 43% debt. The capital structure will remain fixed as annual filings are made based on actual capital dollars and expenses. The revised method used to determine the annual transmission revenue requirement is referred to as a formulaic rate. Using the formulaic rate, we forecast capital additions for the upcoming year and are allowed to earn a return on assets as they are placed in service. The rate also includes a true-up of the previous year’s capital forecast and allows an adjustment to collect the actual operations and maintenance expenses for the previous year. FERC approved the settlement agreements in February 2009 with a January 1, 2009 effective date.

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 holding company systems. As a holding company with a centralized service company subsidiary, Black Hills Service Company, we are subject to FERC’s authority under PUHCA 2005.

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 require (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; (iii) the protection of plant and animal species and minimization of noise emissions; and, (iv) safety and health standards, practices and procedures that apply to the workplace and to the operation of our facilities.

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. The following table does not reflect any costs for complying with future laws or regulations and also does not reflect costs relating to additional power generation facilities at our Colorado Electric utility that are pending regulatory approvals that cannot be reasonably estimated at this time.

Environmental Expenditures	Total
	(in millions)

2009	$	17.4
2010		5.9
2011		12.9
Total	$	36.2

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 permits. All of our facilities that are required to have NPDES permits have those permits in place and are in compliance with discharge limitations. 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.

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 and particulate matter. In addition, CO₂ is included as a potential emission that may be subject to regulation in the future. 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 and Wyodak plants. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2038. 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 our generating stations obtain operating permits. All of our existing facilities have received Title V permits, with the exception of Wygen II. As a new plant, this facility is allowed to operate under its construction permit until the Title V permit is issued by the state. The Title V application was submitted in 2008, with the permit expected in 2009.

Multi-pollutant regulations

Approximately 38% of our electric generating capacity is coal-fired. In 2005, the EPA issued CAMR regulations with respect to SO₂, NOx, and mercury emissions from certain power plants that burn fossil fuels. These new rules implement emission limits, monitoring and cap and trade requirements beginning as early as 2009.

In February 2008, the United States Court of Appeals for the D.C. Circuit overturned the CAMR regulations; however, under this ruling, the EPA must either properly remove mercury from regulation under the hazardous air pollutant provisions of the Clean Air Act or develop standards requiring maximum achievable control technology for mercury emissions. Moreover, although this ruling impacts federal CAMR requirements, it does not necessarily impact state mercury legislation and rules. 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 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. We will also be adding mercury monitors to Neil Simpson II.

In July 2008, a three-judge panel of the United States Court of Appeals for the D.C. Circuit vacated CAIR and remanded the rule to the EPA for revision consistent with the court’s decision. The EPA subsequently requested a rehearing, and in December 2008, the court partially reversed its July 2008 ruling. Under the December 2008 ruling, the program’s pollution control requirements remain in place while the EPA rewrites the CAIR rules in accordance with the July 2008 decision.

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 greenhouse gas emissions.

Global Climate Change

We utilize a diversified energy portfolio that includes a fuel mix of coal, natural gas and wind sources. Of these fuel mixes, coal-fired power plants are the most significant sources of CO₂ emissions. We believe it is possible that greenhouse gases may be regulated in the near future. Although we cannot predict specifically how greenhouse gases will be regulated, any federally mandated greenhouse gas reductions or limits on CO₂ emissions could have a material impact on our financial position or results of operations. In addition to legislative activity, climate proposals have been proposed in various states and climate change issues are the subject of a number of lawsuits the outcome of which could impact the utility industry. For example, in November 2007, the Governor of Colorado published a Colorado Climate Action Plan that calls for reduction in greenhouse gas emissions of 20% by 2020, with additional reductions by 2050. We will continue to review greenhouse gas impacts as legislation or regulation develops and litigation is resolved.

In connection with climate change 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 developed in other 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 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 wastes from flue gas and sulfur removal from the Wyodak, Neil Simpson I, Ben French, Neil Simpson II and Wygen II plants are deposited in mined areas at the WRDC coal mine. These disposal areas are located below some shallow water aquifers in the mine. The State of Wyoming is currently re-evaluating this practice and may, in the future, 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 wastes from the burning of coal are classified as hazardous material, but the wastes do contain minute traces of metals that could be perceived as polluting if such metals leached into underground water. Investigations concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground water quality. The Osage power plant has an on-site ash impoundment that is near capacity and will be gradually transferring disposal to the Wyodak coal mine. The 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 to be responsible for any such costs related to the solid waste from its 80% ownership interest in the Wyodak plant.

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.

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 (MGP) sites. From our review of data provided by Aquila and subsequent discussions with contractors, we estimate that investigative and remedial action costs will be in the range of $1.4 million to $3.7 million. The acquisition also provided for a $1.0 million insurance recovery, which will be used to help offset the remediation costs of these sites. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or 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 as to responsibility from other potentially responsible parties when and where permitted.

Non-regulated Energy Group

Our Non-regulated Energy Group, which operates through various subsidiaries, produces and sells electric capacity and energy through ownership of a diversified portfolio of generating plants; produces coal, natural gas and crude oil primarily in the Rocky Mountain region; and markets and stores natural gas and crude oil. 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, 2008, the principal assets of our Oil and Gas segment included (i) operating interests in oil and natural gas properties, including 562 gross and 525 net wells in the San Juan Basin of New Mexico and Colorado (including significant holdings within the tribal lands of the Jicarilla Apache and Southern Ute Nations), the Powder River and Big Horn Basins of Wyoming, the Piceance Basin of Colorado, and the Nebraska section of the Denver Julesberg Basin; (ii) non-operated interests in oil and natural gas properties including 534 gross and 76 net wells located in California, Colorado, Louisiana, Montana, North Dakota, Oklahoma, Texas and Wyoming; and (iii) a 44.7% ownership interest in the Newcastle gas processing plant and associated gathering system located in Weston County, Wyoming. The plant, which is 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, 2008, we had total reserves of approximately 186 Bcfe, of which natural gas comprised 83% and oil comprised 17% of total reserves. The majority of our reserves are located in select oil and natural gas producing basins in the Rocky Mountain region. Approximately 31% of our reserves are located in the San Juan Basin of northwestern New Mexico, primarily in the East Blanco Field of Rio Arriba County, 20% are located in the Powder River Basin of Wyoming, primarily in the Finn-Shurley Field of Weston and Niobrara counties and 30% are located in the Piceance Basin of western Colorado.

Summary Oil and Gas Reserve Data

The following tables set forth summary information concerning our estimated proved developed and undeveloped oil and gas reserves and the 10% discounted present value of estimated future net revenues as of December 31, 2008 and 2007. The 2008 and 2007 information presented is based on reports prepared by Cawley, Gillespie & Associates, Inc., an independent consulting and engineering firm located in Fort Worth, Texas. Reserves were determined consistent with SEC requirements using year-end product prices, 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. Additional information on our oil and gas reserves and related financial data can be found in Note 22 to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Proved Developed Reserves:	December 31, 2008			December 31, 2007
	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(Mbbl)	(MMcf)	(MMcfe)*	(Mbbl)	(MMcf)	(MMcfe)*

Wyoming	4,167	14,486	39,488	4,954	15,164	44,888
New Mexico	13	43,799	43,877	3	45,646	45,664
Colorado	1	22,563	22,569	—	23,497	23,497
Montana	26	2,231	2,387	35	3,034	3,244
Oklahoma	5	4,080	4,110	9	3,411	3,465
North Dakota	216	298	1,594	90	133	673
Other states	1	1,244	1,250	4	1,637	1,661
Total Proved Developed
Reserves	4,429	88,701	115,275	5,095	92,522	123,092

_________________________

*Oil Bbls are multiplied by six to convert to Mcfe.

Proved Undeveloped Reserves:	December 31, 2008			December 31, 2007
	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(Mbbl)	(MMcf)	(MMcfe)	(Mbbl)	(MMcf)	(MMcfe)

Wyoming	444	5,327	7,991	555	1,655	4,985
New Mexico	—	13,352	13,352	—	24,293	24,293
Colorado	—	39,466	39,466	—	49,221	49,221
Montana	—	4,474	4,474	—	2,453	2,453
Oklahoma	9	2,604	2,658	9	2,573	2,627
North Dakota	303	508	2,326	148	247	1,135
Total Proved Undeveloped
Reserves	756	65,731	70,267	712	80,442	84,714

Total Proved Reserves:	December 31, 2008			December 31, 2007
	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(Mbbl)	(MMcf)	(MMcfe)	(Mbbl)	(MMcf)	(MMcfe)

Wyoming	4,611	19,813	47,479	5,509	16,819	49,873
New Mexico	13	57,151	57,229	3	69,939	69,957
Colorado	1	62,029	62,035	—	72,718	72,718
Montana	26	6,705	6,861	35	5,487	5,697
Oklahoma	14	6,684	6,768	18	5,984	6,092
North Dakota	519	806	3,920	238	380	1,808
Other states	1	1,244	1,250	4	1,637	1,661
Total Proved Reserves	5,185	154,432	185,542	5,807	172,964	207,806

	December 31, 2008		December 31, 2007

Proved developed reserves as a percentage
of total proved reserves on an MMcfe basis		62%		59%

Proved undeveloped reserves as a
percentage of total proved reserves on
an MMcfe basis		38%		41%

Present value of estimated future net
revenues, before tax (in thousands)	$	195,960	$	424,849

The following table reflects average wellhead pricing used in the determination of the present value of estimated future net revenues, before tax:

	December 31, 2008		December 31, 2007

Gas per Mcf	$	4.44	$	5.88

Oil per Bbl	$	32.74	$	83.23

Drilling Activity

The following tables reflect the wells completed through our drilling activities for the last three years. In 2008, we participated in drilling 82 gross (31.38 net) development and exploratory wells, with a net well success rate of approximately 89%. A development well is a well drilled within a proved area of a reservoir known to be productive. An exploratory well is a well drilled to find and/or produce oil or gas in an unproved area, to find a new reservoir in a previously productive field or to extend a known reservoir. Gross wells represent the total wells we participated in, regardless of our ownership interest, while net wells represent our fractional ownership interests within those wells.

Year ended December 31,	2008		2007		2006
Net Development wells	Productive	Dry	Productive	Dry	Productive	Dry

Wyoming	3.88	—	3.67	—	28.20	—
New Mexico	6.70	1.00	17.30	—	21.00	1.00
Montana	5.82	—	8.98	0.45	3.42	0.02
North Dakota	0.31	0.14	—	2.00	—	—
Other states	7.84	2.18	2.35	—	0.20	1.00
Total	24.55	3.32	32.30	2.45	52.82	2.02

Year ended December 31,	2008		2007		2006
Net Exploratory wells	Productive	Dry	Productive	Dry	Productive	Dry

Wyoming	0.75	—	0.61	—	0.04	—
New Mexico	2.00	—	1.60	—	1.00	—
Montana	—	—	0.27	0.25	2.35	0.50
North Dakota	0.76	—	0.37	—	—	—
Other states	—	—	—	—	1.28	—
Total	3.51	—	2.85	0.25	4.67	0.50

As of December 31, 2008, we were participating in the drilling of 12 gross (4.28 net) wells, which had been commenced but not yet completed.

Recompletion Activity

Recompletion activities for the year ended December 31, 2008 were not material to the overall operations of this segment.

Productive Wells

The following table summarizes our gross and net productive wells at December 31, 2008:

	Gross Wells			Net Wells

	Oil	Natural Gas	Total	Oil	Natural Gas	Total

Wyoming	395	146	541	310.45	6.61	317.06
New Mexico	2	152	154	1.91	148.30	150.21
Colorado	1	80	81	—	58.81	58.81
Montana	3	187	190	0.49	41.23	41.72
North Dakota	12	—	12	1.78	—	1.78
Oklahoma	—	67	67	—	10.54	10.54
Other states	1	50	51	0.01	21.71	21.72
Total	414	682	1,096	314.64	287.20	601.84

Acreage

The following table summarizes our undeveloped, developed and total acreage by state as of December 31, 2008 (in thousands):

	Undeveloped		Developed		Total
	Gross	Net	Gross	Net	Gross	Net

Wyoming	50,869	37,407	25,070	15,846	75,939	53,253
New Mexico	39,268	39,091	25,274	22,773	64,542	61,864
Colorado	46,276	33,769	38,512	32,496	84,788	66,265
Montana	719,287	128,943	102,472	18,877	821,759	147,820
Oklahoma	19,297	3,586	21,204	3,296	40,501	6,882
North Dakota	29,090	3,958	5,799	940	34,889	4,898
Other states	38,002	27,769	60,656	47,415	98,658	75,184
Total	942,089	274,523	278,987	141,643	1,221,076	416,166

Competition. The oil and gas industry is highly competitive. We compete with a substantial number of companies ranging from those that have greater financial resources, personnel, facilities and in some cases technical expertise, to the multitude of smaller, aggressive new start-up companies. Many of these companies explore for, produce and market oil and natural gas. The primary areas in which we encounter considerable competition are in recruiting and maintaining high quality staff, locating and acquiring leasehold acreage for drilling and development activity, locating and acquiring producing oil and gas properties, locating and obtaining sufficient drilling rig and contractor services and securing purchasers and transportation for the oil and natural gas we produce.

Seasonality of Business. Weather conditions affect the demand for, and prices of, natural gas and can also temporarily inhibit production and delay drilling activities, which in turn impacts our overall business plan. The demand for natural gas is typically higher in the fourth and first quarters of our fiscal year, resulting in higher natural gas prices. Due to these seasonal fluctuations, results of operations on a quarterly basis may not reflect results which may be realized on an annual basis.

Regulation. Crude oil and natural gas development and production activities are subject to various laws and regulations governing a wide variety of matters. Regulations often require multiple permits and bonds to drill or operate wells, and establish rules regarding the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, the timing of when drilling and construction activities can be conducted relative to various wildlife stipulations and the plugging and abandoning of wells. We are also subject to various mineral conservation laws and regulations, including the regulation of the size of drilling and spacing/proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration, when voluntary pooling of lands and leases cannot be accomplished. The effect of these regulations may limit the number of wells or the locations where we can drill.

Various federal agencies within the United States Department of the Interior, particularly the Bureau of Land Management, the Minerals Management Service and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to oil and natural gas operations on tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. Each Native American tribe is a sovereign nation possessing the power to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on tribal lands. One or more of these factors may increase our cost of doing business on tribal lands and impact the viability of our gas, oil and gathering operations on such lands.

In addition to being subject to federal and tribal regulations, we must also comply with state and county regulations, which have been going through significant change over the past two years. In 2008, new state regulations were implemented in New Mexico which increased the regulatory requirements associated with drilling pits. Also in 2008, new county regulations were proposed which could potentially add additional county approvals to the permitting process. In 2007, Colorado legislation changed the structure of the oil and gas commission, which has developed and approved significant changes to oil and gas regulations for implementation in 2009. Changes such as these have increased, and will continue to increase, costs and add uncertainty with respect to the timing and receipt of permits.

Environmental. Our operations are subject to various federal, state and local laws and regulations relating to the discharge of materials into, and the protection of the environment. We must account for the cost of complying with environmental regulations in planning, designing, drilling, operating and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures (such as spill prevention, control and countermeasure plans, storm water pollution prevention plans, state air quality permits and underground injection control disposal permits), chemical storage and use and the remediation of petroleum-product contamination. Certain states, such as Colorado, impose storm water requirements more stringent than EPA’s and are actively implementing and enforcing these requirements. We take a proactive role in working with these agencies to ensure compliance.

Under state, federal and tribal laws, we could also be required to remove or remediate previously disposed waste, including waste disposed of or released by us, or prior owners or operators, in accordance with current laws, or to otherwise suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or clean up to prevent future contamination. We generate waste that is already subject to the RCRA and comparable state statutes. The EPA and various state agencies limit the disposal options for those wastes. It is possible that certain oil and gas wastes which are currently exempt from treatment as RCRA wastes may in the future be designated as wastes under RCRA or other applicable statutes.

Global Climate Change. The Oil and Gas segment is impacted by regulation in the state of New Mexico where legislation was passed requiring the tracking and reporting of greenhouse gas emissions, beginning with calendar year 2008. We anticipate other states may implement such programs in the future.

Power Generation Segment

Our Power Generation segment, which operates through Black Hills Electric Generation and its subsidiaries, acquires, develops and operates unregulated power plants. We held varying interests in independent power plants operating in Wyoming and Idaho with a total net ownership of 141 MW as of December 31, 2008. We also hold investment interests in power-related funds with a net ownership interest of 3.0 MW.

During 2008, we sold seven IPP plants with 974 MW of capacity to affiliates of Hastings and IIF for a purchase price of $840 million, subject to customary adjustments. We completed the sale in July 2008 and received net cash proceeds of $756 million, including the effects of estimated working capital adjustments and other costs and net of the required payoff of $67.5 million of project debt. Results of the IPP Transaction are reported as discontinued operations. See Notes 1 and 16 to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Portfolio Management

We sell capacity and energy under a combination of mid- to long-term contracts, which mitigates the impact of a potential downturn in future power prices. We currently sell approximately 99% of our unregulated generating capacity under contracts having terms greater than one year. We sell additional power into the wholesale power markets from our generating capacity when it is available and economical.

As of December 31, 2008, the power plant ownership interests held by our Power Generation segment included:

				Owned
	Fuel		Ownership	Capacity	Start
IPP	Type	Location	Interest	(MW)	Date

Gillette CT	Gas	Gillette, Wyoming	100%	40.0	2001
Wygen I⁽¹⁾	Coal	Gillette, Wyoming	100%	90.0	2003
Glenns Ferry Cogeneration	Gas	Glenns Ferry, Idaho	50%	5.5	1996
Rupert Cogeneration	Gas	Rupert, Idaho	50%	5.5	1996
Ontario Cogeneration⁽²⁾	Gas	Ontario, California	100%	—	1984

_________________________

(1)	In January 2009, a 23.5% ownership interest in this plant was sold to MEAN.

(2)	The Ontario Cogeneration plant was decommissioned during 2008.

Gillette CT. The Gillette CT is a simple-cycle, gas-fired combustion turbine located at our Gillette energy complex. The facility’s energy and capacity is sold to Cheyenne Light under a 10-year power purchase agreement that expires in August 2011.

Wygen I. The Wygen I facility is a mine-mouth, coal-fired plant with a total nameplate capacity of 90 MW located at our Gillette energy complex. We sell 60 MW of unit contingent capacity and energy from this plant to Cheyenne Light under a 10-year agreement that expires in the first quarter of 2013.

In August 2008, we entered into a definitive agreement to sell a 23.5% undivided ownership interest in Wygen I to MEAN and completed the sale in January 2009. In connection with this sale transaction, we entered into agreements with MEAN under which it will make payments for costs associated with administrative services, plant operations and coal supply provided by our Coal Mining subsidiary during the life of the facility. We also terminated a 10-year power purchase agreement under which MEAN was obligated to purchase 20 MW of power annually from Wygen I. We retain responsibility for plant operations following the transaction.

Idaho Cogeneration Facilities. Through partnership investments, we own a 50% interest in two QFs in Rupert and Glenns Ferry, Idaho. Rupert and Glenns Ferry are both 11 MW combined-cycle, gas-fired plants. We account for our investment in the partnerships under the equity method of accounting. Electrical output from the facilities is sold to the Idaho Power Company under 20-year Firm Energy Agreements, which expire in 2016. Steam production is sold to Idaho Fresh-Pak, Inc. under agreements that expire in late 2016. The Rupert facility operated normally through 2008 with no adverse conditions. The steam host at Glenns Ferry suspended operations in late 2007, and the plant did not operate in 2008. The facility maintained revenues through the sale of the contracted gas supplies. The steam host suspension prevented the facility from meeting its QF commitment for 2008. An application for a waiver of QF qualifying standards was submitted to FERC in late 2008. Absent FERC approval of the waiver or a contract with a new steam host, the continued suspension of the current steam host could have an adverse effect on the facility’s operation, including its ability to meet QF requirements and the performance requirements under the related energy sales agreement in 2009. The Idaho partnerships have reserved their contractual rights with the steam host, as the steam host is jointly and severally liable under the Firm Energy Agreements with Idaho Power.

Competition. The independent power industry is replete with strong and capable competitors, some of which may have more extensive operating experience, larger staffs or greater financial resources than we possess.

With respect to the merchant power sector, the FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity, and foster competition within the wholesale electricity markets. In addition, although the deregulation efforts that caused some vertically integrated utilities to separate their generation, transmission, and distribution businesses have slowed considerably since the merchant energy crisis in 2001. Our Power Generation business could face greater competition if utilities are permitted to robustly invest in power generation assets. However, regulatory pressures for utilities to competitively bid generation resources may provide upside opportunity for independent power in some regions.

Regulation. Many of the environmental laws and regulations applicable to our Electric Utilities also apply to our Power Generation operations. See the discussion under the “Environmental” and “Regulation” captions for the Utilities Group for additional information on certain laws and regulations described below.

PURPA. The enactment of PURPA in 1978 provided incentives for the development of qualifying cogeneration facilities and small power production facilities that utilized certain alternative or renewable fuels. Prior to the enactment of the EPA 2005, FERC’s regulations under PURPA required that electric utilities (i) purchase power generated by QFs at a price based on the purchasing utility’s full avoided cost of producing power, (ii) sell back-up, interruptible, maintenance and supplemental power to the QF on a non-discriminatory basis, and (iii) interconnect with any QF in its service territory, and, if required, transmit power if they do not purchase it. Our Glenns Ferry and Rupert facilities are QFs. The enactment of the EPA 2005 did not affect the existing contracts for these facilities because they operate under contracts governed by laws in effect prior to EPA 2005. In order to secure the benefits of contracts entered pursuant to PURPA, our QFs must comply with certain operating requirements established by FERC, or secure a waiver of these requirements. If we fail to do so, we could incur contractual liability to the electric utility that purchases power generated by the QF.

The Energy Policy Act of 1992. The passage of the Energy Policy Act of 1992 encouraged independent power production by providing certain exemptions from regulation for EWGs. EWGs are exclusively in the business of owning or operating, or both owning and operating, eligible power facilities and selling electric energy at wholesale. EWGs are subject to FERC regulation, including rate regulation. We own two EWGs, including Wygen I and Gillette CT. All of our EWGs have been granted market-based rate authority, which allows FERC to waive certain accounting, record-keeping and reporting requirements imposed on public utilities with cost-based rates.

Clean Air Act. The Clean Air Act impacts our Power Generation business in a manner similar to the impact disclosed for our Electric Utilities. Our Gillette CT and Wygen I facilities are subject to Titles IV and V of the Clean Air Act and have the required permits in place. As a result of SO₂ allowances credited to us from the installation of sulfur removal equipment at our jointly owned Wyodak plant, we hold sufficient allowances for our Gillette CT and Wygen plants through 2038, without purchasing additional allowances.

Clean Water Act. The Clean Water Act impacts our Power Generation business in a manner similar to the impact described above for our Electric Utilities. Each of our facilities required to have NPDES permits have those permits and are in compliance with discharge limitations. Also, as the EPA regulates surface water oil pollution prevention through its oil pollution prevention regulations, each of our facilities regulated under this program have the requisite plans in place.

Solid Waste Disposal. We dispose of all Wygen I coal ash and scrubber wastes in mined areas at our WRDC coal mine under the terms and conditions of a state permit. The factors discussed under this caption for the Utilities Group also impact our Power Generation segment in a similar manner.

Global Climate Change. The factors discussed under this caption for the Utilities Group also apply to our Power Generation segment.

Coal Mining Segment

Our Coal Mining segment operates through our WRDC subsidiary. We mine and process low-sulfur coal at our coal mine near Gillette, Wyoming. The WRDC coal mine, which we acquired in 1956 from Homestake Gold Mining Company, is located in the Powder River Basin, which contains one of the largest coal reserves in the United States. We produced approximately 6 million tons of coal in 2008. In a basin characterized by thick coal seams, our overburden ratio, a comparison of the amount of dirt removed to a ton of coal uncovered, has historically approximated a 1:1 ratio. In recent years this has trended towards a 2:1 ratio, where it is expected to remain for the next several years.

Mining rights to the coal are based on four federal leases and one state lease. We pay royalties of 12.5% and 9.0%, respectively, of the selling price on all federal and state coal. As of December 31, 2008, we had coal reserves of approximately 274 million tons, based on internal engineering studies. The reserve life is equal to approximately 42 years at expected production levels.

Substantially all of our coal production is currently sold under long-term contracts to:

• Our electric utilities, Black Hills Power and Cheyenne Light;

• The 362 MW Wyodak power plant owned 80% by PacifiCorp and 20% by Black Hills Power;

• PacifiCorp for the Dave Johnston power plant located near Casper, Wyoming and served by rail;

• Our non-regulated mine-mouth power plant, Wygen I; and

• Certain regional industrial customers served by truck.

Our Coal Mining segment sells coal to Black Hills Power and Cheyenne Light for all of their requirements under agreements that limit earnings from the related coal sales to a specified return on our coal mine’s cost-depreciated investment base. The return is 4% (400 basis points) above A-rated utility bonds, to be applied to our coal mining investment base as determined each year. Black Hills Power made a commitment to the SDPUC, the WPSC and the City of Gillette, Wyoming that coal for Black Hills Power’s operating plants would be furnished and priced as provided by that agreement for the life of the Neil Simpson II plant, which was placed into service in 1995. The agreement with Cheyenne Light provides coal for the life of the Wygen II plant, which was placed into service January 1, 2008.

The price for unprocessed coal sold to PacifiCorp for its 80% interest in the Wyodak plant is determined by a coal supply agreement which was executed in 2001 and terminates in 2022. The price for coal sold to PacifiCorp for its Dave Johnston plant is determined by a coal supply agreement which was executed in 2007 and terminates in 2011.

We expect to increase our coal production to supply for additional mine-mouth generating capacity related to the 110 MW Wygen III plant, which is currently being constructed and is expected to utilize approximately 0.6 million tons of coal per year when the plant begins commercial operations in 2010.

Competition. Our primary strategy is to sell the majority of our coal production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically our off-site sales have been to consumers within a close proximity to our mine. Due to the economic limitations on transporting our lower-heat content coal, we do not actively promote the sale of our coal to distant markets.

Environmental Regulation. The construction and operation of coal mines are subject to extensive environmental protection and land use regulation in the United States. These laws and regulations often require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies.

Mine Reclamation. Under applicable law, we must submit applications to, and receive approval from, the WDEQ for any mining and reclamation plan that provides for orderly mining, reclamation, and restoration of our WRDC coal mine. We have an approved mining permit and are in compliance with other permitting programs administered by various regulatory agencies. Based on extensive reclamation studies, we have accrued approximately $17.7 million for reclamation costs as of December 31, 2008. If additional requirements or changes to current requirements are imposed in the future, we may experience a material increase in reclamation costs.

Energy Marketing Segment

Through our subsidiary, Enserco, we market natural gas and crude oil in specific regions of the United States and Canada. Our marketing operations are headquartered in Golden, Colorado, with a satellite sales office in Calgary, Alberta, Canada. Our gas and oil marketing efforts are concentrated in the Rocky Mountain, Western and Mid-continent regions of the United States and in Canada. The customers of our Energy Marketing segment include natural gas distribution companies, electric utilities, industrial users, oil and gas producers, other energy marketers and retail gas users.

Our average daily marketing physical volumes for the year ended December 31, 2008 were approximately 1.9 million MMBtu of gas and approximately 7,900 Bbls of oil.

Our Energy Marketing operations focus primarily on producer services and wholesale natural gas marketing. The business scope is comprised of the purchase, sale, storage and transportation of natural gas and crude oil, as well as a variety of services including asset optimization, price risk management and customized offerings to producer and end-use clients.

We operate our marketing business through the following strategies:

§ Producer Services

• Natural gas

• Crude oil

§ Wholesale Trading

• Transportation

• Storage

• Proprietary

Our total gross margin recognized for each of the following years was derived from our marketing strategies according to the following approximate percentages (rounded to the nearest 5%):

	2008	2007	2006

Wholesale trading (storage)	15%	30%	25%
Wholesale trading (transportation)	30%	30%	25%

Producer services (natural gas)	10%	5%	5%
Producer services (crude oil)	15%	10%	5%
Subtotal	70%	75%	60%
Wholesale trading (proprietary and other)	30%	25%	40%
Total gross margin	100%	100%	100%

We have various long-term natural gas transportation and storage positions in our marketing portfolio that enhance our potential for long-term earnings growth by providing strong upside potential and definable downside risk. A substantial portion of these contractual positions include a right-of-first-refusal provision that provides us the opportunity to extend or renew favorable positions as their terms expire.

The total volumes of transportation capacity rights we held at December 31, 2008 were as follows:

	Term Until Expiration

	Less than 2	2 to 4	Greater than 4
	Years	Years	Years
Region	(2009 and 2010)	(2011 – 2013)	(2014 and beyond)	Total Volume
	(Bcf of natural gas)

Rockies	46.5	32.2	46.7	125.4
West	47.9	10.5	18.6	77.0
MidContinent	69.0	1.8	—	70.8
Total Capacity	163.4	44.5	65.3	273.2

The firm storage capacity rights we held at December 31, 2008 included:

Region	Volume (Bcf)	Term

MidContinent/Upper Midwest	1.0	01/09 – 03/09
MidContinent/Upper Midwest	1.0	01/09 – 06/10
MidContinent/Upper Midwest	1.0	01/09 – 03/12
MidContinent/Upper Midwest	1.0	01/09 – 03/13
MidContinent/Upper Midwest	1.0	01/09 – 03/17
West/Northwest	0.3	01/09 – 03/09
West/Northwest	0.5	04/09 – 03/10

Competition. The energy marketing industry is characterized by numerous large, strong and capable competitors, some of which may have more extensive operating experience, larger staffs or greater financial resources than we possess.

Seasonality. Weather conditions affect the demand for natural gas and can be a source of volatility in natural gas prices. Both are typically higher in the fourth and first quarters of our fiscal year, resulting in higher margins. Due to these seasonal fluctuations, results of operations on a quarterly basis may not reflect results which may be realized on an annual basis.

Working Capital Practices. The natural gas storage part of the business requires significant working capital investment in the form of inventory. Those investment levels are typically highest in the second and third quarters of our fiscal year.

Regulation. Various aspects of our marketing activities are regulated by the FERC. During 2007, following an internal review of natural gas marketing activities conducted within the Energy Marketing segment, we identified possible instances of noncompliance with regulatory requirements applicable to those activities. We notified the staff of FERC of our findings. We have also evaluated public announcements of civil penalties that have been levied against other companies for violations of similar FERC regulatory requirements. We believe we have adequately reserved for the estimated potential penalty that could be levied on us. Although the outcome of any legal or regulatory proceedings resulting from these matters cannot be predicted with any certainty, the final resolution of these matters could have a material impact on our consolidated net income of any particular period, but is not expected to have a material impact upon our overall consolidated financial position.

Other Properties

We own an eight-story, 47,000 square foot office building in Rapid City, South Dakota, where our corporate headquarters is located. Also in Rapid City, we own a second office building consisting of approximately 19,900 square feet and a warehouse building and shop with approximately 25,200 square feet. In Cheyenne, Wyoming, we own a business office with approximately 13,400 square feet, and a service center and garage with an aggregate of approximately 28,300 square feet.

In addition to our owned properties, we lease the following properties:

Utilities Group:

• Approximately 22,200 square feet of office space in Rapid City, South Dakota;

• Approximately 8,800 square feet for a customer call center in Rapid City, South Dakota;

• Approximately 68,700 square feet of office space in Omaha, Nebraska; and

• Approximately 38,700 square feet for a customer call center in Lincoln, Nebraska.

Non-regulated Energy Group:

• Approximately 36,200 square feet of office space in Golden, Colorado.

Substantially all of the tangible utility properties of Black Hills Power and Cheyenne Light are subject to liens securing first mortgage bonds issued by Black Hills Power and Cheyenne Light, respectively.

Employees

At December 31, 2008, we had 2,122 full-time employees. We have experienced no labor stoppages or significant labor disputes in recent years. The following table sets forth the number of employees by business group:

	Number of Employees

Corporate	573
Utilities	1,283
Non-regulated Energy	266
Total	2,122

At December 31, 2008, 686, or 32% of our employees (all within the Utilities Group), were covered by collective bargaining agreements, including:

			Expiration Date of
	Number of		Collective Bargaining
Subsidiary	Employees	Union Affiliation	Agreement

Black Hills Power	175	IBEW Local 1250	March 31, 2009
Cheyenne Light	69	IBEW Local 111	June 30, 2011
Colorado Electric	162	IBEW Local 667	April 17, 2010
Iowa Gas	137	IBEW Local 204	April 27, 2010
Kansas Gas	23	Communications Workers of	December 31, 2011
		America, AFL-CIO Local 6407
Nebraska Gas	120	IBEW Local 244	December 31, 2009

At December 31, 2008, approximately 23% of our Utilities Group employees were eligible for retirement or early retirement.

ITEM 1A.

RISK FACTORS

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

The recent global financial crisis has made the credit markets less accessible and created a shortage of available credit. We may, therefore, be unable to obtain the financing needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.

Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt and equity offerings and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the Federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.

Recent financial distress within the global economy has caused significant disruption in the credit markets. Among other things, long-term interest rates on debt securities have increased significantly and the volume of equity and debt security issuances has decreased. Recent actions taken by the United States government, the Federal Reserve and other governmental and regulatory bodies may be insufficient to stabilize these markets. The longer such conditions persist, the more significant the implications become for us, including the possibility that adequate capital may not be available (or available on reasonable commercial terms) for us to refinance indebtedness remaining under the Acquisition Facility. In addition, on behalf of Enserco we are seeking to replace the existing uncommitted Enserco Facility with a committed credit line, also secured by Enserco’s assets, to maintain credit support for the purchase and sale of natural gas and crude oil, including the issuance of letters of credit. If we are unable to timely refinance the Acquisition Facility or further extend its December 29, 2009 maturity date or replace the existing uncommitted Enserco Facility with a committed credit line, or both, we could be required to consider additional measures to conserve or raise capital. Among other things, alternatives could include deferring portions of our planned capital expenditure program, selling assets, issuing equity, reducing or eliminating our dividend, or curtailing certain business activities, including our marketing operations. Moreover, if we cannot complete capital conservation or capital raising alternatives at sufficient levels on a timely basis, we may not be able to repay the Acquisition Facility on the December 29, 2009 maturity date. The failure to consummate these anticipated refinancings, and any actions taken in lieu of such refinancings, could have a material adverse effect on our results of operations, cash flows and financial condition.

In addition, given that we are a holding company and that our utility assets are owned by our subsidiaries, if we are unable to adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility subsidiaries are adequately capitalized to provide safe and reliable service. Possible additional measures would be evaluated in the context of market conditions then-prevailing, prudent financial management and any applicable regulatory requirements.

The recent global financial crisis has also increased our counterparty credit risk.

As a consequence of the global financial crisis, the creditworthiness of many of our contractual counterparties (particularly financial institutions) has deteriorated. As the creditworthiness of our counterparties deteriorates, we face increased exposure to counterparty credit default.

We have established guidelines, controls and limits to manage and mitigate credit risk. For our energy marketing, production and generation activities, we seek to mitigate our credit risk by conducting a majority of our business with investment grade companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining netting agreements and securing our credit exposure with less creditworthy counterparties through parent company guarantees, prepayments, letters of credit and other security agreements. Although we aggressively monitor and evaluate changes in our counterparties’ credit status and adjust the credit limits based upon changes in the customer’s creditworthiness, our credit guidelines, controls and limits may not protect us from increasing counterparty credit risk under today’s stressed financial conditions. To the extent the financial crisis causes our credit exposure to contractual counterparties to increase materially, such increased exposure could have a material adverse effect on our results of operations, cash flows and financial condition.

National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows.

A prolonged recession may lead to an increase in late payments from retail and commercial utility customers, as well as our non-utility customers (including marketing counterparties). If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

We may not be able to effectively integrate the utility operations acquired from Aquila into our existing businesses and operations, or achieve the anticipated results of the Aquila Transaction.

We expect the Aquila Transaction to produce various benefits. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties, such as pending and future rate cases, operational and financial synergies and our ability to receive regulatory approval from the CPUC for our proposed construction of rate-based generation to meet the long-term energy supply needs of our Colorado Electric customers. We cannot provide assurance that the businesses we acquired from Aquila will be integrated in an efficient and effective manner or that they will be profitable after our integration efforts have been completed.

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

Our issuer credit rating is “Baa3” (stable outlook) by Moody’s; “BBB-” (stable outlook) by S&P; and “BBB” (stable outlook) by Fitch. Although we believe the IPP Transaction and Aquila Transaction have strengthened our financial profile and creditworthiness, we cannot assure that our credit ratings will not be lowered. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt (including the Acquisition Facility) and to complete new financings on acceptable terms, or at all. A downgrade could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities.

Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and are, therefore, not recoverable.

Our regulated electricity and natural gas utility operations are subject to cost-of-service regulation and earnings oversight. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

To some degree, each of our gas and electric utilities in South Dakota, Wyoming, Colorado, Montana, Nebraska, Iowa and Kansas are permitted to recover certain costs (such as increased fuel and purchased power costs, as applicable) without having to file a rate case. To the extent we pass through such costs to our customers and a state public utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could negatively affect our revenues, cash flows and results of operations.

We could incur additional and substantial write-downs of the carrying value of our natural gas and oil properties, which would adversely impact our earnings.

We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating future net revenues, current spot prices and costs, as of the end of the appropriate quarterly period, are used. Such prices and costs are utilized except when different prices and costs are fixed and determinable from applicable contracts for the remaining term of those contracts. Two primary factors in the ceiling test are natural gas and oil reserve levels and current spot oil and gas prices, both of which impact the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves, or an increase or decrease in prices, can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense.

We recorded non-cash impairment charges in the fourth quarter of 2008 due to the full cost ceiling limitations in an amount of $59.0 million after-tax and we may have to record additional non-cash impairment charges in 2009 if current commodity prices persist. See Note 12 to Consolidated Financial Statements in this Annual Report on Form 10-K. The SEC recently adopted new reporting and accounting requirements for oil and gas companies that will change the way we test for potential ceiling test impairments (i.e., testing will be based on 12-month average commodity prices rather than a single date spot price as of the test date). The new requirements are effective January 1, 2010 and are proposed to apply to the Annual Report on Form 10-K for 2009.

We have deferred a substantial amount of gain associated with the assets sold in the IPP Transaction. If the Internal Revenue Service successfully challenges this deferral, our results of operations, financial position or liquidity could be adversely affected.

We expect to defer tax payments of approximately $185 million as a result of the IPP Transaction and the Aquila Transaction. We cannot be certain that the IRS will accept our position. If the IRS successfully sought to assert a contrary position, we could be required to pay a significant amount of these deferred taxes earlier than currently forecasted.

Estimates of the quantity and value of our proved oil and gas reserves may change materially due to numerous uncertainties inherent in estimating oil and natural gas reserves.

There are many uncertainties inherent in estimating quantities of proved reserves and their values. The process of estimating oil and natural gas reserves requires interpretation of available technical data and various assumptions, including assumptions relating to economic factors. Significant inaccuracies in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. The accuracy of reserve estimates is a function of the quality of available data, engineering and geological interpretations and judgment, and the assumptions used regarding quantities of recoverable oil and gas reserves, future capital expenditures and prices for oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from those assumed in our estimates. These variances may be significant. Any significant variance from the assumptions used could cause the actual quantity of our reserves, and future net cash flow, to be materially different from our estimates. In addition, results of drilling, testing and production, changes in future capital expenditures and fluctuations in oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions. The SEC has proposed revised reporting guidelines for reserves that will apply to the Annual Report on Form 10-K for the period ending December 31, 2009, however there is the possibility of delaying the compliance date until the FASB has issued final accounting standards in line with the revised SEC rules. Key revisions include changes to the oil and gas pricing used to estimate reserves, the use of new technology for determining reserves and authorization for optional disclosure of probable and possible reserves.

Estimates of the quality and quantity of our coal reserves may change materially due to numerous uncertainties inherent in three dimensional structural modeling.

There are many uncertainties inherent in estimating quantities of coal reserves. The process of coal volume estimation requires interpretations of drill hole log data and subsequent computer modeling of the intersected deposit. Significant inaccuracies in interpretation or modeling could materially affect the quantity and quality of our reserve estimates. The accuracy of reserve estimates is a function of engineering and geological interpretation and judgment of known data, assumptions used regarding structural limits and mining extents, conditions encountered during actual reserve recovery and undetected deposit anomalies. Variance from the assumptions used and drill hole modeling density could result in additions or deletions from our volume estimates. In addition, future environmental, economic or geologic changes may occur or become known that require reserve revisions either upward or downward from prior reserve estimates.

Our current or future development, expansion and acquisition activities may not be successful, which could impair our ability to execute our growth strategy.

Execution of our future growth plan is dependent on successful ongoing and future acquisition, development and expansion activities. We can provide no assurance that we will be able to complete acquisitions or development projects we undertake or continue to develop attractive opportunities for growth. Factors that could cause our activities to be unsuccessful include:

• Our inability to obtain required governmental permits and approvals;

• Our inability to obtain financing on acceptable terms, or at all;

• The possibility that one or more rating agencies would downgrade our issuer credit rating to below investment grade, thus increasing our cost of doing business;

• Our inability to successfully integrate any businesses we acquire;

• Our inability to retain management or other key personnel;

• Our inability to negotiate acceptable acquisition, construction, fuel supply, power sales or other material agreements;

• The trend of utilities building their own generation or looking for developers to develop and build projects for sale to utilities under turnkey arrangements;

• Lower than anticipated increases in the demand for power in our target markets;

• Changes in federal, state, local or tribal laws and regulations;

• Fuel prices or fuel supply constraints;

• Pipeline capacity and transmission constraints; and

• Competition.

We can provide no assurance that results from any acquisition will conform to our expectations. There may be additional risks associated with the operation of any newly acquired assets.

Successful acquisitions are subject to a number of uncertainties, many of which are beyond our control. Factors which may cause our actual results to differ materially from expected results include:

• Delay in, and restrictions imposed as part of, any required governmental or regulatory approvals;

• The loss of management or other key personnel;

• The diversion of our management’s attention from other business segments; and

• Integration and operational issues.

Construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve significant risks which could reduce revenues or increase expenses.

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

• The inability to obtain required governmental permits and approvals;

• Contract restrictions upon the timing of scheduled outages;

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

• The unavailability or increased cost of equipment and labor supply;

• Supply interruptions, work stoppages and labor disputes;

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

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

• Weather interferences;

• Unexpected engineering, environmental and geological problems; and

• Unanticipated cost overruns.

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

Our operating results can be adversely affected by milder weather.

Our utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, and demand for natural gas is extremely sensitive to winter weather effects on heating requirements. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon winter weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler in the summer and warmer in the winter. Unusually mild summers and winters therefore could have an adverse effect on our financial condition and results of operations.

Because prices for our products and services and operating costs for our business are volatile, our revenues and expenses may fluctuate.

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

The success of our oil and gas operations is affected by the prevailing market prices of oil and natural gas. Oil and natural gas prices and markets historically have also been, and are likely to continue to be, volatile. A decrease in oil or natural gas prices would not only reduce revenues and profits, but would also reduce the quantities of reserves that are commercially recoverable, and may result in charges to earnings for impairment of the net capitalized cost of these assets. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of additional factors that are beyond our control. A decline in oil and natural gas price volatility could also affect our revenues and returns from Energy Marketing, which historically tend to increase when markets are volatile.

Our mining operation requires a reliable supply of replacement parts, explosives, fuel, tires and steel-related products. If the cost of any of these increase significantly, or if a source of these supplies or mining equipment was unavailable to meet our replacement demands, our profitability could be lower than our current expectations. In recent years, industry-wide demand growth has exceeded supply growth for certain surface mining equipment and off-the-road tires. As a result, lead times for some items have generally increased to several months and prices for these items have increased significantly.

Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results.

We use various contracts and derivatives, including futures, forwards, options and swaps, to manage commodity price and financial market risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the items being hedged. The difference in accounting can result in volatility in reported results, even though the expected profit margin may be essentially unchanged from the dates the transactions were consummated.

Our use of derivative financial instruments could result in material financial losses.

From time to time, we have sought to limit a portion of the adverse effects resulting from changes in natural gas and crude oil commodity prices, and interest and foreign exchange rates by using derivative financial instruments and other hedging mechanisms and by the activities we conduct in our trading operations. To the extent that we hedge our commodity price and interest rate exposures, we forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though monitored by management, our hedging and trading activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is economically imperfect, commodity prices or interest rates move unfavorably related to our physical or financial positions, or hedging policies and procedures are not followed.

Our Energy Marketing and Utility operations rely on storage and transportation assets owned by third parties to satisfy their obligations.

Our energy marketing operations involve contracts to buy and sell natural gas, crude oil and other commodities, many of which are settled by physical delivery. We depend on pipelines and other storage and transportation facilities owned by third parties to satisfy our delivery obligations under these contracts. Our Gas Utilities also rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to ratepayers and to hedge commodity costs. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.

Our business is subject to substantial governmental regulation and permitting requirements as well as environmental liabilities, including those we assumed in connection with certain acquisitions. We may be adversely affected if we fail to achieve or maintain compliance with existing or future regulations or requirements, or by the potentially high cost of complying with such requirements or addressing environmental liabilities.

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