BKH 10-K Annual Report Dec. 31, 2012

BLACK HILLS CORP /SD/

10-Ks and 10-Qs

10-Q	Quarter ended Sept. 30, 2025
10-Q	Quarter ended June 30, 2025
10-Q	Quarter ended March 31, 2025
10-K	Fiscal year ended Dec. 31, 2024
10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-Q	Quarter ended March 31, 2024
10-K	Fiscal year ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-Q	Quarter ended March 31, 2023
10-K	Fiscal year ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-Q	Quarter ended March 31, 2022
10-K	Fiscal year ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-Q	Quarter ended March 31, 2021
10-K	Fiscal year ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-Q	Quarter ended March 31, 2020
10-K	Fiscal year ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-Q	Quarter ended March 31, 2019
10-K	Fiscal year ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-Q	Quarter ended March 31, 2018
10-K	Fiscal year ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-Q	Quarter ended March 31, 2017
10-K	Fiscal year ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-Q	Quarter ended March 31, 2016
10-K	Fiscal year ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-Q	Quarter ended March 31, 2015
10-K	Fiscal year ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-Q	Quarter ended March 31, 2014
10-K	Fiscal year ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-Q	Quarter ended March 31, 2013
10-K	Fiscal year ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-Q	Quarter ended March 31, 2012
10-K	Fiscal year ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-Q	Quarter ended March 31, 2011
10-K	Fiscal year ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-Q	Quarter ended March 31, 2010
10-K	Fiscal year ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on March 14, 2025
DEF 14A	Filed on March 12, 2025
DEF 14A	Filed on March 15, 2024
DEF 14A	Filed on March 15, 2023
DEF 14A	Filed on April 26, 2022
DEF 14A	Filed on March 17, 2022
DEF 14A	Filed on March 18, 2021
DEF 14A	Filed on March 13, 2020
DEF 14A	Filed on March 15, 2019
DEF 14A	Filed on March 15, 2018
DEF 14A	Filed on March 16, 2017
DEF 14A	Filed on March 17, 2016
DEF 14A	Filed on March 19, 2015
DEF 14A	Filed on March 20, 2014
DEF 14A	Filed on March 14, 2013
DEF 14A	Filed on March 22, 2012
DEF 14A	Filed on April 13, 2011
DEF 14A	Filed on April 13, 2010

10-K 1 bkh10k12312012.htm 10-K BKH 10K 12 31 2012

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K



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

For the fiscal year ended December 31, 2012



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

For the transition period from ___________________ to __________________

Commission File Number 001-31303

BLACK HILLS CORPORATION



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

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

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

Yes x No o

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

Yes o No x

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

Yes x No o

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

Yes x No o

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

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

Yes o No x

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

At June 30, 2012 $1,400,316,896

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, 2013
Common stock, $1.00 par value	44,222,903	shares

Documents Incorporated by Reference

Portions of the Registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2013 Annual Meeting of Stockholders to be held on April 23, 2013 , 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	6

		FORWARD-LOOKING INFORMATION	6
Part I
	ITEMS 1. and 2.	BUSINESS AND PROPERTIES	7

	ITEM 1A.	RISK FACTORS	48

	ITEM 1B.	UNRESOLVED STAFF COMMENTS	60

	ITEM 3.	LEGAL PROCEEDINGS	60

	ITEM 4.	SPECIALIZED DISCLOSURES	60
Part II
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	61

	ITEM 6.	SELECTED FINANCIAL DATA	62

	ITEMS 7. and 7A.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	65

	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	110

	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	182

	ITEM 9A.	CONTROLS AND PROCEDURES	182

	ITEM 9B.	OTHER INFORMATION	183
Part III
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	184

	ITEM 11.	EXECUTIVE COMPENSATION	185

	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	185

	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	185

	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	185

	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	186

		SIGNATURES	197

		INDEX TO EXHIBITS	198

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC	Allowance for Funds Used During Construction
AltaGas	AltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd.
AOCI	Accumulated Other Comprehensive Income
Aquila Transaction	Our July 14, 2008 acquisition of five utilities from Aquila, Inc.
ARO	Asset Retirement Obligations
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by the FASB
ATRA	American Taxpayer Relief Act of 2012
Basin Electric	Basin Electric Power Cooperative
Bbl	Barrel
Bcfe	Billion cubic feet equivalent
BHC	Black Hills Corporation; the Company
BHEP	Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Colorado IPP	Black Hills Colorado IPP, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation
Black Hills Energy	The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
BLM	United States Bureau of Land Management
Btu	British thermal unit
CFTC	United States Commodity Futures Trading Commission
CG&A	Cawley, Gillespie & Associates, Inc., an independent consulting and engineering firm
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
Cheyenne Light Pension Plan	The Cheyenne Light, Fuel and Power Company Pension Plan
Cheyenne Prairie	Cheyenne Prairie Generating Station currently being constructed in Cheyenne, Wyo. by Cheyenne Light and Black Hills Power. Construction is expected to be completed for this 132 megawatt facility in 2014.
City of Gillette	The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase of 23 percent of Wygen III power plant for the City of Gillette
CO ₂	Carbon dioxide
Colorado Electric	Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas	Black Hills Colorado Gas Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Cooling Degree Day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.



CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CT	Combustion turbine
CVA	Credit Valuation Adjustment
DC	Direct current
De-designated interest rate swaps	The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under the accounting for derivatives and hedges but subsequently de-designated in December 2008
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE	United States Department of Energy
DSM	Demand Side Management
Dth	Dekatherms
EBITDA	Earnings before interest, taxes, depreciation and amortization, a non-GAAP measurement
ECA	Energy Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers.
Economy Energy	Electricity purchased by one utility from another utility to take the place of electricity that would have cost more to produce on the utility’s own system
Enserco	Enserco Energy Inc., a formerly wholly-owned subsidiary of Black Hills Non-regulated Holdings, which is presented in discontinued operations throughout this Annual Report filed on Form 10-K
EPA	United States Environmental Protection Agency
EPA Region VIII	EPA Region VIII (Mountains and Plains) located in Denver serving Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming and 27 Tribal Nations
Equity Forward Agreement	Equity Forward Agreement with J. P. Morgan connected to a public offering of 4,413,519 million shares of Black Hills Corporation common stock, including the over-allotment shares
EWG	Exempt Wholesale Generator
FASB	Financial Accounting Standards Board
FDIC	Federal Depository Insurance Corporation
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
GCA	Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to the customer.
GHG	Greenhouse gases
Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
Happy Jack	Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Hastings	Hastings Fund Management Ltd
Heating Degree Day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
Idaho Cogeneration Facility	Partnership investment owned 50 percent by Black Hills Electric Generation, sold Jan. 18, 2011
IFRS	International Financial Reporting Standards
IIF	IIF BH Investment LLC, a subsidiary of an investment entity advised by J.P. Morgan Asset Management
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP	Independent power producer
IPP Transaction	The July 11, 2008 sale of seven of our IPP plants to affiliates of Hastings and IIF



IRS	United States Internal Revenue Service



IUB	Iowa Utilities Board
J.P. Morgan	J.P. Morgan Securities LLC
JPB	Consolidated Wyoming Municipalities Electric Power System Joint Powers Board. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
kV	Kilovolt
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Loveland Area Project	Part of the Western Area Power Association transmission system
MACT	Maximum Achievable Control Technology
MAPP	Mid-Continent Area Power Pool
MATS	Utility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
Mbbl	Thousand barrels of oil
Mcf	Thousand cubic feet
Mcfe	Thousand cubic feet equivalent
MDU	Montana Dakota Utilities Co., a regulated utility division of MDU Resources Group, Inc.
MEAN	Municipal Energy Agency of Nebraska
MGP	Manufactured Gas Plants
MMBtu	Million British thermal units
MMcf	Million cubic feet
MMcfe	Million cubic feet equivalent
Moody’s	Moody’s Investors Service, Inc.
MSHA	Mine Safety and Health Administration
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
NA	Not Applicable
Native load	Energy required to serve customers within our service territory
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NERC	North American Electric Reliability Corporation
NGL	Natural Gas Liquids (Gallon equals 7 Mcfe)
NO _x	Nitrogen oxide
NOL	Net operating loss
NPDES	National Pollutant Discharge Elimination System
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
OPEC	Organization of the Petroleum Exporting Countries
OSHA	Occupational Safety & Health Administration
PPA	Power Purchase Agreement
PPACA	Patient Protection and Affordable Care Act of 2010
PSCo	Public Service Company of Colorado
PUD	Proved undeveloped reserves
PUHCA 2005	Public Utility Holding Company Act of 2005
RCRA	Resource Conservation and Recovery Act
REPA	Renewable Energy Purchase Agreement



Revolving Credit Facility	Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2017
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO ₂	Sulfur dioxide
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
Spinning Reserve	Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission outages.
System Peak Demand	Represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100 percent of plants regardless of joint ownership.
TCA	Transmission Cost Adjustment -- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
ug/m ³	Micrograms per Cubic Meter of Air
Twin Eagle	Twin Eagle Resource Management, LLC
VEBA	Voluntary Employee Benefit Association
VOC	Volatile Organic Compounds
WDEQ	Wyoming Department of Environmental Quality
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

Website Access to Reports

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

Forward-Looking Information

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

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

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

PART I


ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

History and Organization

Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”), is a diversified energy company headquartered in Rapid City, S.D. 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, we began producing, selling and marketing various forms of energy through non-regulated businesses.

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

For more than 15 years, we also owned and operated Enserco, an energy marketing business that engaged in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. On Feb. 29, 2012, we sold Enserco, representing our entire Energy Marketing segment, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment as discontinued operations. See Note 23 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.



Business Group	Financial Segment
Utilities	Electric Utilities
	Gas Utilities

Non-regulated Energy	Power Generation
	Coal Mining
	Oil and Gas

Our Electric Utilities segment generates, transmits and distributes electricity to approximately 202,000 electric customers in South Dakota, Wyoming, Colorado and Montana and also distributes natural gas to approximately 35,000 gas utility customers of Cheyenne Light in Cheyenne, Wyo. Our Gas Utilities segment serves approximately 532,000 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 859 megawatts of generation and 8,530 miles of electric transmission and distribution lines, and our Gas Utilities own 624 miles of intrastate gas transmission pipelines and 19,979 miles of gas distribution mains and service lines. Our Utilities Group generated net income of $79.6 million for the year ended December 31, 2012 and had total assets of $3.2 billion at December 31, 2012 .

Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy primarily to our utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, Wyo. 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 Non-regulated Energy Group generated net income of $24.7 million for the year ended December 31, 2012 and had total assets of $0.5 billion at December 31, 2012 .

Segment Financial Information

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

Discontinued Operations in the accompanying financial information includes the results of our Energy Marketing segment sold in February 2012.

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 202,000 customers; and also distribute natural gas to approximately 35,000 natural gas utility customers of Cheyenne Light in Cheyenne, Wyo. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

We conduct natural gas utility operations on a state-by-state basis through our Colorado Gas, Nebraska Gas, Iowa Gas and Kansas Gas subsidiaries. Our Gas Utilities distribute and transport natural gas through our distribution network to approximately 532,000 customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

We also provide non-regulated services through our Service Guard and Tech Services product lines. Service Guard primarily provides appliance repair services to approximately 62,000 residential customers through company technicians and third party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing customer-owned gas infrastructure facilities, typically through one-time contracts, with a limited number of on-going monthly maintenance agreements.

Electric Utilities Segment

Capacity and Demand

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



	System Peak Demand (in megawatts)

	2012		2011		2010
	Summer	Winter	Summer	Winter	Summer	Winter

Black Hills Power	449	362	452	408	396	377
Cheyenne Light	187	174	181	175	176	164
Colorado Electric	400	284	392	297	384	289
Total Electric Utilities Peak Demands	1,036	820	1,025	880	956	830

Regulated Power Plants

As of December 31, 2012 , our Electric Utilities’ ownership interests in electric generation plants were as follows:



Unit	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Black Hills Power:
Wygen III ⁽¹⁾	Coal	Gillette, Wyo.	52.0%	57.2	2010
Neil Simpson II	Coal	Gillette, Wyo.	100.0%	90.0	1995
Wyodak ⁽²⁾	Coal	Gillette, Wyo.	20.0%	72.4	1978
Osage ⁽³⁾	Coal	Osage, Wyo.	100.0%	34.5	1948-1952
Ben French ⁽³⁾	Coal	Rapid City, S.D.	100.0%	25.0	1960
Neil Simpson I ⁽³⁾	Coal	Gillette, Wyo.	100.0%	21.8	1969
Neil Simpson CT	Gas	Gillette, Wyo.	100.0%	40.0	2000
Lange CT	Gas	Rapid City, S.D.	100.0%	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, S.D.	100.0%	10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, S.D.	100.0%	80.0	1977-1979
Cheyenne Light:
Wygen II	Coal	Gillette, Wyo.	100.0%	95.0	2008
Colorado Electric ⁽⁴⁾ :
Busch Ranch Wind Farm ⁽⁵⁾	Wind	Pueblo, Colo.	50.0%	14.5	2012
Pueblo Airport Generation	Gas	Pueblo, Colo.	100.0%	180.0	2011
W.N. Clark #1-2 ⁽⁶⁾	Coal	Canon City, Colo.	100.0%	40.0	1955, 1959
Pueblo #5 ⁽³⁾	Gas	Pueblo, Colo.	100.0%	9.0	1941, 2001
Pueblo #6 ⁽³⁾	Gas	Pueblo, Colo.	100.0%	20.0	1949
AIP Diesel	Oil	Pueblo, Colo.	100.0%	10.0	2001
Diesel #1-5	Oil	Pueblo, Colo.	100.0%	10.0	1964
Diesel #1-5	Oil	Rocky Ford, Colo.	100.0%	10.0	1964
Total Megawatt Capacity				859.4

________________________


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


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

(3)

Operations at Osage were suspended Oct. 1, 2010, Ben French was suspended on Aug. 31, 2012 and Pueblo Unit #5 and Pueblo Unit #6 were suspended as of Dec. 31, 2012 due to the availability of more economical generation alternatives when evaluating costs to retrofit these plants to comply with environmental standards, including EPA regulations. Osage, Ben French and Neil Simpson I will be retired on or before March 21, 2014. While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.


(4)	Colorado Electric entered into a 20-year PPA with Black Hills Colorado IPP for 200 megawatts of power from their gas-fired plants. This PPA, accounted for as a capital lease, was effective on Jan. 1, 2012.


(5)	Busch Ranch Wind Farm, a 29 megawatt wind farm, is operated by Colorado Electric. Colorado Electric has a 50 percent ownership interest in the wind farm and AltaGas owns the remaining 50 percent. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 megawatts of power from the wind farm. The wind farm became operational Oct. 16, 2012.

(6)

In December 2010, Colorado Electric received a final order from the CPUC that approved the retirement of its W.N. Clark coal-fired generation facility by Dec. 31, 2013. Operations were suspended at this facility on Dec. 31, 2012. While the net book value of the W.N. Clark plant is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.

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



Fuel Source (dollars per megawatt-hour)	2012			2011		2010
Coal	$	14.42		$	15.89	$	12.77

Gas and Oil	$	52.08	^(a)	$	150.00	$	131.28

Total Average Fuel Cost	$	16.05		$	16.77	$	13.57

Purchased Power - Coal, Gas and Oil	$	26.70		$	28.80	$	29.57

Purchased Power - Renewable Sources	$	47.45		$	46.71	$	45.76

__________


(a)	With the commencement of operations of the 180 megawatt gas-fired units in Pueblo, Colo., and the low price of natural gas compared to oil, the average cost of fuel per MWh decreased.

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



Power Supply	2012		2011		2010
Coal	37	%	38	%	42	%
Gas, Oil and Wind	2		—		—
Total Generated	39		38		42
Purchased	61		62		58
Total	100	%	100	%	100	%

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


•	Black Hills Power’s PPA with PacifiCorp expiring on Dec. 31, 2023, which provides for the purchase of 50 megawatts of coal-fired baseload power;


•	Colorado Electric’s PPA with Black Hills Colorado IPP expiring on Dec. 31, 2031, which provides 200 megawatts of energy and capacity to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease;


•	Colorado Electric’s PPA with Cargill expiring on Dec. 31, 2013, whereby Colorado Electric purchases 50 megawatts of economy energy;


•	Colorado Electric’s PPA with AltaGas expiring on Oct. 16, 2037, which provides up to 14.5 megawatts of wind energy from AltaGas’ owned interest in the Busch Ranch Wind Project;


•	Cheyenne Light’s PPA with Black Hills Wyoming expiring on Aug. 31, 2014, whereby Black Hills Wyoming provides 40 megawatts of energy and capacity from its Gillette CT;

•

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


•	Cheyenne Light’s 20-year PPA with Duke Energy expiring on Sept. 3, 2028, which provides up to 29.4 megawatts of wind energy from the Happy Jack Wind Farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50 percent of the facility’s output to Black Hills Power;


•	Cheyenne Light’s 20-year PPA with Duke Energy expiring on Sept. 30, 2029, which provides up to 30 megawatts of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 20 megawatts of energy from Silver Sage to Black Hills Power; and


•	Cheyenne Light and Black Hills Power’s Generation Dispatch Agreement 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:


•	MDU owns a 25 percent ownership interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, Black Hills Power will provide MDU with 25 megawatts from its other generation facilities or from system purchases with reimbursement of costs by MDU;

•

The City of Gillette owns a 23 percent ownership interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, Black Hills Power will provide the City of Gillette with its first 23 megawatts from its other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, Black Hills Power will also provide the City of Gillette its operating component of spinning reserves;


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



2013-2017	20 megawatts - 10 megawatts contingent on Wygen III and 10 megawatts contingent on Neil Simpson II
2018-2019	15 megawatts - 10 megawatts contingent on Wygen III and 5 megawatts contingent on Neil Simpson II
2020-2021	12 megawatts - 6 megawatts contingent on Wygen III and 6 megawatts contingent on Neil Simpson II
2022-2023	10 megawatts - 5 megawatts contingent on Wygen III and 5 megawatts contingent on Neil Simpson II;


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


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

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

At December 31, 2012 , our Electric Utilities owned the electric transmission and distribution lines shown below:



Utility	State	Transmission (in Line Miles)	Distribution (in Line Miles)
Black Hills Power	South Dakota, Wyoming	592	3,059
Black Hills Power - Jointly Owned ⁽¹⁾	South Dakota, Wyoming	44	—
Cheyenne Light	South Dakota, Wyoming	25	1,229
Colorado Electric	Colorado	236	3,345

(1)

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

Black Hills Power has firm point-to-point transmission access to deliver up to 50 megawatts of power on PacifiCorp’s transmission system to wholesale customers in the WECC region through 2023.

Black Hills Power also has firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyo. to serve our power sales contract with MDU through 2017, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.

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

Operating Agreements. Our Electric Utilities have the following material operating agreements:

•

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

•

Jointly Owned Facilities - Black Hills Power, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby Black Hills Power charges the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant. Colorado Electric and AltaGas are parties to a shared joint ownership agreement whereby Colorado Electric charges AltaGas for operations and maintenance for their share of the Busch Ranch Wind Farm.

Operating Statistics

The following tables summarize degree days, revenue, quantities generated and purchased, quantities sold, and customers for our Electric Utilities:



Degree Days	2012		2011		2010
	Actual	Variance from 30-Year Average	Actual	Variance from 30-Year Average	Actual	Variance from 30-Year Average
Heating Degree Days:
Black Hills Power	6,206	(13)%	7,579	5%	7,272	1%
Cheyenne Light	6,304	(11)%	7,321	(1)%	7,033	(5)%
Colorado Electric	4,921	(13)%	5,749	3%	5,518	(1)%

Cooling Degree Days:
Black Hills Power	937	47%	700	17%	532	(11)%
Cheyenne Light	568	63%	431	58%	345	26%
Colorado Electric	1,322	47%	1,259	37%	1,074	16%



Revenue - Electric (in thousands)	2012		2011		2010

Residential:
Black Hills Power	$	58,523	$	59,826	$	53,549
Cheyenne Light	32,053		31,287		29,506
Colorado Electric ^(a)	91,550		84,646		76,596
Total Residential	182,126		175,759		159,651

Commercial:
Black Hills Power	73,858		72,889		65,997
Cheyenne Light	55,600		55,331		52,765
Colorado Electric	82,849		73,355		66,490
Total Commercial	212,307		201,575		185,252

Industrial:
Black Hills Power	25,656		25,723		22,621
Cheyenne Light	16,105		11,629		10,542
Colorado Electric	37,540		33,332		28,812
Total Industrial	79,301		70,684		61,975

Municipal:
Black Hills Power	3,268		3,172		3,029
Cheyenne Light	1,807		1,765		1,293
Colorado Electric	13,373		12,912		10,443
Total Municipal	18,448		17,849		14,765

Subtotal Retail Revenue - Electric	492,182		465,867		421,643

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	20,290		18,105		22,996

Off-system/Power Marketing Wholesale:
Black Hills Power	31,905		34,889		36,354
Cheyenne Light	8,365		9,371		9,750
Colorado Electric ^(b)	6,003		13,018		10,859
Total Off-system/Power Marketing Wholesale	46,273		57,278		56,963

Other Revenue ^(c) :
Black Hills Power	29,809		31,027		25,217
Cheyenne Light	2,336		2,449		3,230
Colorado Electric	4,652		2,787		2,374
Total Other Revenue	36,797		36,263		30,821

Total Revenue - Electric	$	595,542	$	577,513	$	532,423

_____________________


(a)	2012 includes a $2.1 million construction savings incentive.


(b)	Off-system sales revenue during part of 2010 was deferred until a sharing mechanism was approved by the CPUC in December 2011. As a result, Colorado Electric had deferred $8.4 million in off-system revenue during 2010 which was all recognized in December 2011.


(c)	Other revenue primarily consists of transmission revenue.



Quantities Generated and Purchased (megawatt-hour)	2012	2011	2010

Generated -
Coal-fired:
Black Hills Power	1,796,936	1,717,008	1,987,037
Cheyenne Light	587,832	674,518	734,241
Colorado Electric	235,080	268,317	257,896
Total Coal - fired	2,619,848	2,659,843	2,979,174

Gas, Oil and Wind:
Black Hills Power	33,183	15,221	19,269
Cheyenne Light	—	—	—
Colorado Electric	84,874	2,342	930
Total Gas, Oil and Wind	118,057	17,563	20,199

Total Generated:
Black Hills Power	1,830,119	1,732,229	2,006,306
Cheyenne Light	587,832	674,518	734,241
Colorado Electric	319,954	270,659	258,826
Total Generated	2,737,905	2,677,406	2,999,373

Purchased -
Black Hills Power	1,678,090	1,720,640	1,440,579
Cheyenne Light	807,659	745,983	696,756
Colorado Electric	1,794,229	1,948,321	1,969,896
Total Purchased ^(a)	4,279,978	4,414,944	4,107,231

Total Generated and Purchased	7,017,883	7,092,350	7,106,604

_______________


(a)	Includes wind power of 199,079 MWh, 189,255 MWh and 167,520 MWh in 2012, 2011 and 2010, respectively.



Quantities (megawatt-hour)	2012	2011	2010

Residential:
Black Hills Power	532,342	550,935	547,193
Cheyenne Light	261,792	264,492	261,607
Colorado Electric	614,521	629,752	628,553
Total Residential	1,408,655	1,445,179	1,437,353

Commercial:
Black Hills Power	731,785	720,978	720,119
Cheyenne Light	577,141	601,162	603,323
Colorado Electric	723,216	720,060	726,005
Total Commercial	2,032,142	2,042,200	2,049,447

Industrial:
Black Hills Power	407,301	408,337	382,562
Cheyenne Light	224,448	172,840	161,082
Colorado Electric	358,490	351,862	347,673
Total Industrial	990,239	933,039	891,317

Municipal:
Black Hills Power	35,933	34,235	33,908
Cheyenne Light	9,631	9,827	6,477
Colorado Electric	121,480	126,320	113,689
Total Municipal	167,044	170,382	154,074

Subtotal Retail Quantity Sold	4,598,080	4,590,800	4,532,191

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	340,036	349,520	468,782

Off-system Wholesale:
Black Hills Power	1,263,457	1,226,548	1,163,058
Cheyenne Light	229,062	278,528	311,524
Colorado Electric	160,430	282,929	274,942
Total Off-system Wholesale	1,652,949	1,788,005	1,749,524

Total Quantity Sold:
Black Hills Power	3,310,854	3,290,553	3,315,622
Cheyenne Light	1,302,074	1,326,849	1,344,013
Colorado Electric	1,978,137	2,110,923	2,090,862
Total Quantity Sold	6,591,065	6,728,325	6,750,497

Losses and Company Use:
Black Hills Power	197,355	162,316	131,263
Cheyenne Light	93,417	93,652	86,984
Colorado Electric	136,046	108,057	137,860
Total Losses and Company Use	426,818	364,025	356,107

Total Energy Sold	7,017,883	7,092,350	7,106,604



Customers at End of Year	2012	2011	2010
Residential:
Black Hills Power	55,296	54,955	54,811
Cheyenne Light	35,438	35,159	34,913
Colorado Electric	81,795	81,811	81,902
Total Residential	172,529	171,925	171,626

Commercial:
Black Hills Power	12,857	12,864	12,779
Cheyenne Light	4,276	4,277	4,132
Colorado Electric	11,220	11,206	11,185
Total Commercial	28,353	28,347	28,096

Industrial:
Black Hills Power	44	45	40
Cheyenne Light	2	2	2
Colorado Electric	61	68	63
Total Industrial	107	115	105

Other Electric Customers:
Black Hills Power	308	311	309
Cheyenne Light	240	243	254
Colorado Electric	475	506	510
Total Other Electric Customers	1,023	1,060	1,073

Subtotal Retail Customers	202,012	201,447	200,900

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	3	3	3

Total Customers:
Black Hills Power	68,508	68,178	67,942
Cheyenne Light	39,956	39,681	39,301
Colorado Electric	93,551	93,591	93,660
Total Electric Customers at Year-End	202,015	201,450	200,903

Cheyenne Light Natural Gas Distribution

Included in the Electric Utilities is Cheyenne Light’s natural gas distribution system. The following table summarizes certain operating information for the natural gas distribution operations of Cheyenne Light:



	2012		2011		2010
Revenue - Gas (in thousands):
Residential	$	19,327	$	22,044	$	22,562
Commercial	8,613		10,264		10,801
Industrial	2,715		3,597		3,425
Other Sales Revenue	769		913		803
Total Revenue - Gas	$	31,424	$	36,818	$	37,591

Gross Margin - Gas (in thousands):
Residential	$	10,712	$	10,426	$	10,004
Commercial	2,963		3,345		3,376
Industrial	551		504		427
Other Gross Margin	766		545		720
Total Gross Margin - Gas	$	14,992	$	14,820	$	14,527

Quantities Sold (Dth):
Residential	2,215,858		2,585,056		2,636,839
Commercial	1,447,522		1,538,616		1,572,638
Industrial	598,408		689,935		667,062
Total Quantities Sold	4,261,788		4,813,607		4,876,539

Gas Customers at Year-End	35,021		34,807		34,461

Gas Utilities Segment

At Dec. 31, 2012 , our Gas Utilities owned the gas transmission and distribution lines by state shown below (in line miles):



	Intrastate Gas Transmission Pipelines	Gas Distribution Mains	Gas Distribution Service Lines
Colorado	124	3,005	896
Nebraska	44	3,451	3,494
Iowa	170	2,747	2,422
Kansas	286	2,664	1,300
Total	624	11,867	8,112

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

Degree Days



	2012		2011		2010
	Actual	Variance From 30-Year Average	Actual	Variance From 30-Year Average	Actual	Variance From 30-Year Average
Heating Degree Days:
Colorado	5,186	(18)%	5,991	(7)%	5,803	(9)%
Nebraska	5,198	(15)%	6,190	(1)%	6,222	—%
Iowa	6,093	(10)%	7,013	(4)%	6,934	(5)%
Kansas ^(a)	4,190	(15)%	4,954	(1)%	4,918	(1)%
Combined ^(b)	5,518	(13)%	6,455	(3)%	6,410	(3)%

________________


(a)	Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross margins.


(b)	The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism.

Operating Statistics



Revenue (in thousands)	2012		2011		2010

Residential:
Colorado	$	48,406	$	58,102	$	55,211
Nebraska	98,339		125,493		120,365
Iowa	82,669		106,292		105,255
Kansas	55,096		65,185		69,859
Total Residential	284,510		355,072		350,690

Commercial:
Colorado	9,558		12,172		11,880
Nebraska	30,894		40,659		40,720
Iowa	36,550		46,179		46,762
Kansas	15,677		20,362		21,953
Total Commercial	92,679		119,372		121,315

Industrial:
Colorado	1,963		2,063		1,409
Nebraska	876		860		3,126
Iowa	2,458		2,521		2,243
Kansas	13,614		19,571		14,312
Total Industrial	18,911		25,015		21,090

Other Sales Revenue:
Colorado	181		96		97
Nebraska	2,066		1,971		1,960
Iowa	452		550		836
Kansas	5,124		3,031		3,451
Total Other Sales Revenue	7,823		5,648		6,344

Distribution:
Colorado	60,108		72,433		68,597
Nebraska	132,175		168,983		166,171
Iowa	122,129		155,542		155,096
Kansas	89,511		108,149		109,575
Total Distribution	403,923		505,107		499,439

Transportation:
Colorado	866		846		784
Nebraska	10,589		11,175		11,289
Iowa	4,128		3,935		3,708
Kansas	5,762		5,909		5,471
Total Transportation	21,345		21,865		21,252

Total Regulated Revenue	425,268		526,972		520,691

Non-regulated Services	28,813		27,612		30,016

Total Revenue	$	454,081	$	554,584	$	550,707



Gross Margin (in thousands)	2012		2011		2010

Residential:
Colorado	$	16,400	$	17,711	$	18,153
Nebraska	46,982		51,640		49,074
Iowa	39,561		47,491		44,269
Kansas	28,734		29,701		29,591
Total Residential	131,677		146,543		141,087

Commercial:
Colorado	2,680		2,960		3,215
Nebraska	10,201		11,643		11,965
Iowa	11,071		11,702		11,616
Kansas	6,097		6,603		6,544
Total Commercial	30,049		32,908		33,340

Industrial:
Colorado	581		450		360
Nebraska	249		217		379
Iowa	257		288		235
Kansas	2,362		2,373		1,878
Total Industrial	3,449		3,328		2,852

Other Sales Margins:
Colorado	181		96		97
Nebraska	2,066		1,971		1,960
Iowa	452		549		836
Kansas	4,787		2,455		2,722
Total Other Sales Margins	7,486		5,071		5,615

Distribution:
Colorado	19,842		21,217		21,825
Nebraska	59,498		65,471		63,378
Iowa	51,341		60,030		56,956
Kansas	41,980		41,132		40,735
Total Distribution	172,661		187,850		182,894

Transportation:
Colorado	866		846		784
Nebraska	10,589		11,175		11,289
Iowa	4,128		3,935		3,708
Kansas	5,762		5,909		5,470
Total Transportation	21,345		21,865		21,251

Total Regulated Gross Margin:
Colorado	20,708		22,063		22,609
Nebraska	70,087		76,646		74,667
Iowa	55,469		63,965		60,664
Kansas	47,742		47,041		46,205
Total Regulated Gross Margin	194,006		209,715		204,145

Non-regulated Services	14,726		12,908		12,845

Total Gross Margin	$	208,732	$	222,623	$	216,990



Quantities Sold (in Dth)	2012	2011	2010

Residential:
Colorado	5,869,817	6,437,860	6,284,559
Nebraska	9,555,073	12,076,979	12,210,574
Iowa	8,732,301	10,490,129	10,556,045
Kansas	5,681,199	6,853,163	6,926,928
Total Residential	29,838,390	35,858,131	35,978,106

Commercial:
Colorado	1,284,082	1,472,747	1,473,924
Nebraska	3,952,067	4,833,604	5,009,105
Iowa	5,304,162	6,192,167	6,061,954
Kansas	2,121,063	2,676,439	2,673,805
Total Commercial	12,661,374	15,174,957	15,218,788

Industrial:
Colorado	463,566	344,576	259,985
Nebraska	158,445	120,779	544,457
Iowa	492,633	409,723	354,435
Kansas	3,675,678	3,743,735	2,718,767
Total Industrial	4,790,322	4,618,813	3,877,644

Other:
Colorado	—	—	—
Nebraska	—	—	1,341
Iowa	—	—	69,306
Kansas	68,419	112,253	120,445
Total Other	68,419	112,253	191,092

Distribution:
Colorado	7,617,465	8,255,183	8,018,468
Nebraska	13,665,585	17,031,362	17,765,477
Iowa	14,529,096	17,092,019	17,041,740
Kansas	11,546,359	13,385,590	12,439,945
Total Distribution	47,358,505	55,764,154	55,265,630

Transportation:
Colorado	850,156	869,570	808,859
Nebraska	26,649,759	24,972,560	27,327,173
Iowa	18,294,228	18,358,692	17,422,525
Kansas	14,686,679	15,015,310	14,320,893
Total Transportation	60,480,822	59,216,132	59,879,450

Total Volumes Sold:
Colorado	8,467,621	9,124,753	8,827,327
Nebraska	40,315,344	42,003,922	45,092,650
Iowa	32,823,324	35,450,711	34,464,265
Kansas	26,233,038	28,400,900	26,760,838
Total Quantities Sold	107,839,327	114,980,286	115,145,080



Customers	2012	2011	2010

Residential:
Colorado	68,927	67,496	66,766
Nebraska	176,953	176,386	176,244
Iowa	135,897	135,161	134,782
Kansas	98,516	98,043	97,844
Total Residential	480,293	477,086	475,636

Commercial:
Colorado	3,681	3,678	3,620
Nebraska	15,626	15,664	15,221
Iowa	15,398	15,398	15,300
Kansas	9,584	9,453	9,469
Total Commercial	44,289	44,193	43,610

Industrial:
Colorado	213	209	208
Nebraska	136	141	149
Iowa	94	94	93
Kansas	1,261	1,365	1,394
Total Industrial	1,704	1,809	1,844

Transportation:
Colorado	36	30	22
Nebraska	4,115	4,128	4,270
Iowa	412	393	392
Kansas	1,166	1,142	1,054
Total Transportation	5,729	5,693	5,738

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

Total Customers:
Colorado	72,857	71,413	70,616
Nebraska	196,830	196,319	195,886
Iowa	151,801	151,046	150,635
Kansas	110,534	110,010	109,769
Total Customers at Year-End	532,022	528,788	526,906

Utilities Group Business Characteristics

Seasonal Variations of Business

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

Competition

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

Rates and Regulation

Current Rates

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

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



Subsidiary	Jurisdic-tion	Authorized Rate of Return on Equity	Authorized Return on Rate Base	Capital Structure Debt/Equity	Effective Date	Tariff and Rate Matters	Percentage of Power Marketing Activity Shared with Customers
Electric Utilities:
Black Hills Power	SD	Global Settlement	8.6%	Global Settlement	4/2010	ECA, TCA, Energy Efficiency Cost Recovery/DSM	65%
	SD		8.16%		6/2011	Environmental Improvement Cost Recovery Adjustment Tariff	NA
	WY	10.5%	8.6%	48%/52%	6/2010	ECA, TCA	50% subject to symmetrical deadband
	MT	15.0%	11.7%	47%/53%	1983	ECA	NA
	FERC	10.8%	9.1%	43%/57%	2/2009	FERC Transmission Tariff	NA
Cheyenne Light - Electric	WY	9.6%	8.0%	46%/54%	7/2012	ECA, Energy Efficiency Cost Recovery/ DSM, Rate Base Recovery on Acquisition Adjustment	NA
Cheyenne Light - Gas	WY	9.6%	8.0%	46%/54%	7/2012	GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery of Acquisition Adjustment	NA
Colorado Electric	CO	9.8%-10.2%	8.5%	50.9%/49.1%	1/2012	ECA, TCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment	75% through 2013; 90% thereafter

Gas Utilities:
Colorado Gas	CO	9.6%	8.4%	50%/50%	12/2012	GCA, Energy Efficiency Cost Recovery/ DSM	NA
Nebraska Gas	NE	10.1%	9.1%	48%/52%	9/2010	GCA, Cost of Bad Debt Collected through GCA	NA
Kansas Gas	KS	Global Settlement	Global Settlement	49.3%/50.7%	10/2007	GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA	NA
Iowa Gas	IA	Global Settlement	Global Settlement	Global Settlement	2/2011	GCA, Energy Efficiency Cost Recovery/DSM	NA

We produce and/or distribute energy in four states; Colorado, Montana, South Dakota and Wyoming. The regulatory provisions for recovering the costs to supply electricity vary by state. In all states we have cost adjustment mechanisms for our Electric Utilities that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers. These mechanisms allow the utility operating in that state to collect, or refund, the difference between the cost of commodities and certain services embedded in our base rates and the actual cost of the commodities and certain services without filing a general rate case. Some states in which our utilities operate also allow the utility operating in that state to automatically adjust rates periodically for the cost of new transmission or environmental improvements and, in some instances, the utility has the opportunity to earn its authorized return on new capital investment immediately with these adjustments. Some of the mechanisms we have in place include the following:

•

In October 2012, the WPSC approved Cheyenne Prairie’s construction financing rider which allows for recovery of construction financing costs from customers during the construction period in lieu of traditional AFUDC. The rider was implemented Nov. 1, 2012 and will allow Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately 60 percent of the total project cost that relates to Wyoming customers, while also saving customers money over the long-term. This will increase gross margin by approximately $5.5 million and $7.8 million in 2013 and 2014, respectively.

•

In Wyoming, Cheyenne Light has annual cost adjustment mechanisms that allow us to pass the prudently-incurred cost of fuel and purchased power through to electric customers. Until July 1, 2012 at Cheyenne Light, our pass-through mechanism relating to transmission and the ECA was subject to a $1.0 million threshold: we collected or refunded 95 percent of the increase or decrease that exceeded the $1.0 million threshold, and we absorbed the increase or retained the savings for costs below the threshold as well as the 5 percent not collected or refunded above the threshold. Effective July 1, 2012, the $1.0 million threshold was eliminated and the sharing mechanism was modified to 85 percent to the customer.

•

In South Dakota, beginning April 1, 2010, Black Hills Power has an annual adjustment clause which provides for the direct recovery of increased fuel and purchased power incurred to serve South Dakota customers. Additionally, as of April 1, 2010, the ECA was modified in the rate case settlement to contain an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 65 percent of off-system power marketing operating income. The modification also adjusts the methodology to directly assign renewable resources and firm purchases to the customer load. In Wyoming beginning June 1, 2010 a similar Fuel and Purchased Power Cost Adjustment was instituted.


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


•	We have an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of Black Hills Power’s open access transmission tariff. The revenue requirement is based on an equity return of 10.8 percent, a capital structure of 57 percent equity and 43 percent debt, and a return on rate base which is adjusted annually.

•

In Colorado, we have an ECA for semi-annual increases or decreases in purchased power and fuel costs and a TCA for transmission costs. The ECA provides for the direct recovery of increased purchased power and fuel costs or the issuance of credits for decreases in purchased power, environmental generation and fuel costs. The TCA is an annual rider to the customer’s bill which allows the utility to earn an authorized return on new transmission investment and recovery of operations and maintenance costs related to transmission. Effective Jan. 1, 2012, the CPUC approved adjustments to the ECA. These adjustments allow for the recovery of transmission expenses paid to other providers, symmetrical interest, and the sharing of off-system sales margins, less certain operating costs, where the customer receives 75 percent through 2013. This sharing percentage increases to 90 percent to the customer in 2014 and thereafter.

We distribute natural gas in five states; Colorado, Iowa, Nebraska, Kansas and Wyoming. All of our Gas Utilities and Cheyenne Light’s natural gas distribution, have GCAs that allow us to pass the prudently-incurred cost of gas and certain services through to the customer. Some of the mechanisms we have in place are:


•	In Kansas, we have a weather normalization tariff that provides a pass-through mechanism for weather margin variability that occurs from the level used to establish base rates to be paid by the customer, as well as tariffs that provide for more timely recovery for certain capital expenditures and fluctuations in property taxes.


•	In Kansas and Nebraska, we are allowed to recover the portion of uncollectible accounts related to gas costs through GCAs.

Pending Rates

The following summarizes certain state and federal rate cases, riders and surcharges with activity occurring in 2012 (dollars in millions):



	Type of Service	Date Requested	Revenue Amount Requested
Iowa Gas ⁽¹⁾	Gas	12/2012	$	0.9
Black Hills Power ⁽²⁾	Electric	12/2012	$	13.7
Black Hills Power ⁽³⁾	Electric	12/2012	$	9.2

(1)

I owa Gas filed a request for a Capital Infrastructure Automatic Adjustment Mechanism with the IUB in December 2012. If approved, the adjustment could result in a revenue increase of $0.9 million in 2013 which reflects a request for recovery of costs since our prior rate case in 2010. Also if approved, an adjustment request will be required to be filed annually thereafter and subsequent filings will vary in size based on eligible infrastructure replacements and the timing of future general rate case filings. The filing is currently under review by the IUB.

(2)

In December 2012, Black Hills Power filed a rate case with the SDPUC requesting an electric revenue increase of $13.7 million, or 9.94 percent, to recover investment in distribution and transmission lines, generation plant upgrades, environmental compliance and increased operating costs. Black Hills Power has requested an effective date of April 1, 2013. A decision is anticipated during the third quarter of 2013. If the SDPUC has not reached a decision within 180 days, interim rates will go into effect June 16, 2013.

(3)

In December 2012, Black Hills Power filed a request with the SDPUC to use a construction financing rider during the construction of Cheyenne Prairie in lieu of traditional AFUDC. This rider would be similar to the one approved by the WPSC for Cheyenne Light and Black Hills Power for Wyoming customers. On Jan. 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013, subject to refund. The rider will allow Black Hills Power to earn and collect a rate of return during the construction period on its approximately 40 percent share of the total project cost that relates to South Dakota customers, while also saving customers money over the long-term. If approved, this will increase gross margin by approximately $3.6 million and $5.6 million in 2013 and 2014, respectively. We anticipate a final ruling by the SDPUC on this rider during the third quarter of 2013.

Other State Regulations

Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage our Electric Utilities to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. At Dec. 31, 2012 , we were subject to the following renewable energy portfolio standards or objectives:

•

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

•

Montana . Montana established a renewable portfolio standard that requires Black Hills Power to obtain a percentage of its retail electric sales in Montana from eligible renewable resources according to the following schedule: (i) 10 percent for compliance through 2014; and (ii) 15 percent 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 customers for contracts pre-approved by the MTPSC. We are currently in compliance with applicable standards, and our current strategy is to incorporate renewable energy as required to comply with the standards.

•

South Dakota . South Dakota has adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10 percent 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.


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

Mandatory portfolio standards have increased, and may continue to increase the power supply costs of our Electric Utility operations. Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to secure full recovery of the costs we pay to be in compliance with standards or objectives. We cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.

Federal Regulation

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

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

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

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

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

Environmental Matters

We are subject to numerous federal, state and local laws and regulations relating to the protection of the environment and the safety and health of personnel and the public. These laws and regulations affect a broad range of our utility activities, and generally regulate: (i) the protection of air and water quality; (ii) the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of, and emergency response in connection with hazardous and toxic materials and wastes, including asbestos; and (iii) the protection of plant and animal species and minimization of noise emissions.

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



Environmental Expenditure Estimates	Total (in millions)
2013	$	3.3
2014	2.1
2015	0.8
Total	$	6.2

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 and stormwater permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA was scheduled to propose updated regulations for wastewater discharge from power generators by Dec. 14, 2012, with a scheduled implementation date of May 2014. However, in December 2012, the proposed rule deadline was extended to April 19, 2013. These rules may have a significant impact on our coal-fired units. 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, SO ₂ , NO _x , mercury particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Clean Air Act

Title IV of the Clean Air Act created an SO ₂ allowance trading program as part of the federal acid rain program. Each allowance gives the owner the right to emit one ton of SO ₂ , and certain facilities are allocated allowances based on their historical operating data. At the end of each year, each emitting unit must have enough allowances to cover its emissions for the year just ended. Allowances may be traded so affected units that expect to emit more SO ₂ 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 II, Lange CT, Wygen II, Wygen III and Wyodak plants. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2042. For future plants, we plan to secure the requisite number of allowances by reducing SO ₂ emissions through the use of low sulfur fuels, installation of “back end” control technology, use of banked allowances, and if necessary, the purchase of allowances on the open market. We expect to integrate the cost of obtaining the required number of allowances needed for future projects into our overall financial analysis of such new projects.

Title V of the Clean Air Act requires that all of our generating facilities obtain operating permits. All of our existing facilities have received Title V permits, with the exception of Wygen III. Wygen III is allowed to operate under its construction permit until the Title V permit is issued by the state. The Title V application for Wygen III was submitted in January 2011, with the permit expected in 2013. The application was filed in accordance with regulatory requirements.

In 2011, the EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates on Dec. 21, 2012, which impose emission limits, fuel requirements and monitoring requirements. The rule has a compliance deadline of March 21, 2014. In anticipation of this rule and our evaluation of costs to retrofit these plants, we suspended operations at the Osage plant in October 2010 and as a result of this rule, we suspended operations at the Ben French facility on Aug. 31, 2012 with plans to retire Osage, Ben French and Neil Simpson I on or before March 21, 2014. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than Dec. 31, 2013. This facility suspended operations Dec. 31, 2012.

On February 16, 2012, the EPA published in the Federal Register the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), with an effective date of April 16, 2012. This rule imposes requirements for mercury, acid gases, metals and other pollutants. Affected units will have three years from the rule effective date to be in compliance, with a pathway defined to apply for a one year extension due to certain circumstances. The current state air permits for Wygen II and Wygen III provide mercury emission limits and monitoring requirements with which we are in compliance. Wygen II has been utilized for internal study and review of mercury emission control technology and has mercury monitors in place. In 2009, we added mercury monitors to our Neil Simpson II plant. The Wygen III plant, which commenced operations in 2010, also has mercury monitors. Neil Simpson II, Wygen II, Wygen III and the Wyodak plant are expected to be in compliance by the compliance deadline, without incurring significant costs.

On June 23, 2010, the EPA published in the Federal Register the GHG Tailoring Rule, implementing regulations of GHG for permitting purposes. This rule will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Existing permitted facilities will see monitoring and reporting requirements incorporated into their operating permits upon renewal. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emission control practices and technologies. As Wyoming state law prohibits regulation of GHG, the EPA will review and develop requirements for that portion of a new source construction permit or for a major modification of an existing source. This additional process will increase the time and expense for the permitting process. In addition, unlike a Wyoming issued permit, an appeal of an EPA issued GHG air permit to construct requires an automatic stay to the project, meaning that construction cannot commence until the appeal is resolved. This aspect adds considerable risk to new construction projects as well as to major modifications to existing projects. Wyoming has been working to modify this statute and implement GHG regulations. It is anticipated that EPA will approve Wyoming’s GHG program by the spring of 2014.

On April 13, 2012, the EPA proposed Electric Utility New Source Performance Standards for GHG. These standards will apply to Cheyenne Prairie. They are scheduled to be final in the first half of 2013 and, as proposed, would not have a significant impact on this project. However, until we can evaluate the final version, we cannot be certain of this assumption.

In August 2012, the EPA proposed revisions to the Electric Utility New Source Performance Standards for stationary combustion turbines. This rule is expected to be finalized in 2013 and, as proposed, will be applicable to the Pueblo Airport Generating Station, Cheyenne Prairie and eventually all the combustion turbines in our fleet. Among other things, the rule seeks to eliminate startup exemptions and clearly define overhauls for impact on the EPA’s New Source Review regulations, with the intention of eventually bringing all units under the applicability of this rule. The primary impact is expected to be on our older existing units, which will eventually be required to meet tighter NO _x emission limitations.

By May 3, 2013, all our diesel generator engines must comply with the EPA’s Stationary Reciprocating Internal Combustion Engine Hazardous Air Pollutant regulations. Evaluations have been completed and emission control equipment is being installed to meet that deadline.

The EPA is expected to propose a more stringent ozone ambient air standard in 2013. If the lower range of the proposed standard is selected, it is anticipated that Campbell County, Wyoming would be a non-attainment area. Under those conditions, the State of Wyoming may evaluate Neil Simpson II, Wygen II and Wygen III for further reductions in NO _x emissions. On Dec. 14, 2012 EPA signed revisions to the Particulate Matter 2.5 annual ambient air quality standard, lowering the annual limit from 15 to 12 ug/m ³ . EPA's website indicates that all counties where we currently have power generation facilities are expected to be able to comply with the new standard. This action is expected to result in more restrictive particulate matter emission limitations on any new construction and major modifications to our existing units.

In 2011, the State of Wyoming issued a letter requiring Neil Simpson II to include startup and shutdown SO ₂ & NO _x emissions when evaluating compliance with permitted emission limits. This represented a significant change from requirements in the original 1993 air permit. Some minor engineered design changes were made to enable improved scrubber performance during startup and those changes have been successful in enabling the unit to meet the new requirements. The unit was previously fitted with state of the art low NO _x burners that enable compliance with this new requirement. In the future the State of Wyoming may require similar changes to Wygen I and Wygen II.

Regional Haze

In January 2011, the states of Wyoming and South Dakota submitted their plans to EPA Region VIII, identifying NO _x , SO ₂ and particulate matter emission reductions intended to meet the Class I Areas (National Parks and Wilderness Areas) visibility improvement requirements under the EPA’s Regional Haze Program. Although none of our South Dakota or Wyoming power plants were included in those plans, we anticipate that in the next required revisions due in 2016, some of our plants will be included. It is our expectation Ben French, Osage and Neil Simpson I will be permanently retired on or prior to March 21, 2014; however, if not retired, it is highly probable these plants along with Neil Simpson II, will be included in revised regulations.

In the 2010 legislative session, the State of Colorado passed House Bill 1365, the Colorado Clean Air Clean Jobs Act, a coordinated utility plan to reduce air emissions from coal fired power plants and promote the use of natural gas and other low emitting resources. One of the intents of this Act was to require utilities to consider a spectrum of regulations when evaluating their emission reduction plans, with the final package ultimately comprising Colorado's Regional Haze Plan that would be submitted to EPA for approval. This Act had a significant impact on our W.N. Clark facility and on Dec. 15, 2010, the CPUC issued an order approving closure of the W.N. Clark plant by Dec. 31, 2013. On Jan. 7, 2011, the State Air Quality Control Commission adopted the CPUC order into the Colorado State Implementation Plan and in the Dec. 31, 2012 Federal Register, EPA Region VIII gave full approval to that plan, establishing the closure of W.N. Clark as a federally approved state regulation and as such is now federally enforceable.

A number of our power plants have been subject to new state and EPA regulations issued in the last couple of years. As the result of these regulations and the associated costs to retrofit many of our older generating plants, we have announced the suspension of operations and planned retirements for the following plants:



Plant	Company	Megawatts		Type of Plant	Date Suspended	Planned Retirement Date	Age of Plant (in years)
Osage	Black Hills Power		34.5	Coal	Oct. 1, 2010	March 21, 2014	64
Ben French	Black Hills Power		25.0	Coal	Aug. 31, 2012	March 21, 2014	52
Neil Simpson I	Black Hills Power		21.8	Coal	NA	March 21, 2014	43
W.N. Clark	Colorado Electric		42.0	Coal	Dec. 31, 2012	Dec. 31, 2013	57
Pueblo Unit #5	Colorado Electric		9.0	Gas	Dec. 31, 2012	to be determined	71
Pueblo Unit #6	Colorado Electric		20.0	Gas	Dec. 31, 2012	to be determined	63
	Total MW		152.3

In addition Neil Simpson II is expected to be included in the Wyoming Regional Haze Plan update due to the EPA in 2016. The Wyodak Power Plant is included in EPA's currently proposed Regional Haze Federal Implementation Plan, which includes additional NOx controls.

Greenhouse Gas Regulations

We utilize a diversified energy portfolio of power generation assets that include a fuel mix of coal, natural gas and wind sources, and minimal quantities of both solar and hydroelectric power. Of these generation resources, coal-fired power plants are the most significant sources of CO ₂ emissions. The EPA is intending to finalize the first GHG emission standards sometime in the first half of 2013, which will be applicable to new steam electric generating units, as described above. This rule, with its very low proposed CO ₂ emissions standards, effectively prohibits new coal-fired power plants from being constructed until carbon capture and sequestration becomes technically and economically feasible. The EPA will also be developing GHG emission standards for existing steam electric generating units. We expect the EPA to issue a proposed rule in 2013 and while we cannot predict the terms of the regulation, any federally mandated GHG reductions or limits on CO ₂ emissions at our existing plants could have a material impact on our customer rates, financial position, results of operations and/or cash flows. In 2011, the EPA’s GHG Tailoring Rule went into effect, requiring GHG emissions to be addressed in new major source construction permits and to be addressed upon renewal of Title V Operating Permits. Since there are no emission standards or caps currently in place, we cannot predict how this requirement will impact our existing facilities upon permit renewal. In 2012, we reported 2011 GHG emissions from our Power Generation and Gas Utilities in order to comply with the EPA’s GHG Annual Inventory regulation, issued in 2009. In addition to federal legislative activity, GHG regulations have been proposed in various states and alleged climate change issues are the subject of a number of lawsuits, the outcome of which could impact the utility industry. We will continue to review GHG impacts as legislation or regulation develops and litigation is resolved.

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

Solid Waste Disposal

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

As of Oct. 1, 2010, we suspended operations at the Osage power plant and it is scheduled to be retired on or before March 21, 2014. This plant has an on-site ash impoundment that is near capacity. An application to close the impoundment was filed with the State of Wyoming on Nov. 3, 2010 and approved on April 13, 2012. Site closure work is underway with post closure monitoring to continue for 30 years. If Osage should ever re-start, ash disposal will be at our WRDC coal mine.

As of Aug. 31, 2012, we suspended operations at Ben French which is scheduled to close on or before March 21, 2014. We have also announced plans to close Neil Simpson I on or before March 21, 2014.

Our W.N. Clark plant which suspended operations on Dec. 31, 2012 and is scheduled to be retired by Dec. 31, 2013, 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. For our Pueblo Airport Generation site in Pueblo, CO, we have posted a bond with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility.

Agreements are in place that require PacifiCorp and MEAN to be responsible for any costs related to the solid waste from their ownership interest in the Wyodak plant and Wygen I plant, respectively. As operator of Wygen III, Black Hills Power has a similar agreement in place for any such costs related to solid waste from Wygen III. Under their separate but related operating agreement, Black Hills Power, MDU and the City of Gillette each share the costs for solid waste from Wygen III according to their respective ownership interests.

Additional unexpected material costs could also result in the future if any regulatory agency determines that solid waste from the burning of coal contains a hazardous material that requires special treatment, including previously disposed solid waste. In that event, the regulatory authority could hold entities that disposed of such waste responsible for remedial treatment. On June 21, 2010, the EPA published in the Federal Register the proposed coal combustion residuals regulations. The regulations are complex and contain various options for ash management that the EPA will be selecting from to form the final version of the rule. We cannot determine the likely impact on our operations until the final version of the rule is known, which appears to be scheduled for some time in 2013. However, if ash becomes subject to regulations as a hazardous waste, implementation requirements could have a material impact on our financial position, results of operations or cash flows.

Manufactured Gas Processing

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

As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for a $1.0 million insurance recovery, now valued at $1.1 million, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operator of the Nebraska MGPs. Under this agreement, Nebraska Gas received $1.9 million from the successor to the operator for Nebraska Gas to remediate two sites in Nebraska (Blair and Plattsmouth) and the successor would be responsible for remediation activity at the two remaining sites in Nebraska (Columbus and Norfolk). Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth in Nebraska’s Voluntary Cleanup Program. Site remediation was completed in September 2012, however there is a potential for additional minimal remediation work at Plattsmouth. If required, it is expected to be completed by mid-2013. Both Nebraska sites will be required to monitor groundwater quality for a minimum two year period.

As of Dec. 31, 2012, we estimate a range of approximately $2.9 million to $6.3 million to remediate these MGP sites in both Nebraska and Iowa.

Prior to Black Hills Corporation’s ownership, Aquila received rate orders that enabled recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of these current and future costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted.

Non-regulated Energy Group

Our Non-regulated Energy Group, which operates through various subsidiaries, produces and sells electric capacity and energy through a portfolio of generating plants, produces and sells coal from our mine located in the Powder River Basin in Wyoming and acquires, explores for, develops and produces natural gas and crude oil primarily in the Rocky Mountain region. The Non-regulated Energy Group consists of three business segments for reporting purposes:


•	Power Generation


•	Coal Mining


•	Oil and Gas

For more than 15 years, we also owned and operated Enserco, an energy marketing business that engaged in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. On Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment as discontinued operations.

Power Generation Segment

Our Power Generation segment, which operates through Black Hills Electric Generation and its subsidiaries, acquires, develops and operates our non-regulated power plants. As of Dec. 31, 2012 , we held varying interests in independent power plants operating in Wyoming and Colorado with a total net ownership of 309 MW.

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 a substantial majority of our non-regulated generating capacity under contracts having terms greater than one year.

As of Dec. 31, 2012 , the power plant ownership interests held by our Power Generation segment included:



Power Plants	Fuel Type	Location	Ownership Interest	Owned Capacity (MW)	In Service Date
Gillette CT	Gas	Gillette, Wyo.	100.0%	40.0	2001
Wygen I	Coal	Gillette, Wyo.	76.5%	68.9	2003
Pueblo Airport Generation ⁽¹⁾	Gas	Pueblo, Colo.	100.0%	200.0	2012
				308.9

_________________________


(1)	Black Hills Colorado IPP owns and operates this facility. This facility provides capacity and energy to Colorado Electric under a 20-year PPA with Colorado Electric. This PPA is accounted for as a capital lease.

Black Hills Wyoming - Gillette CT. The Gillette CT is a simple-cycle, gas-fired combustion turbine located at our Gillette, Wyo. energy complex. The facility’s energy and capacity is sold to Cheyenne Light under a 3-year PPA that expires in August 2014. We are exploring various alternatives for the Gillette CT following expiration of its contract with Cheyenne Light, including contracting or selling the unit to another party. We sell excess power from our generating capacity into the wholesale power markets when it is available and economical.

Black Hills Wyoming - Wygen I. The Wygen I generation facility is a mine-mouth, coal-fired power plant with a total capacity of 90 megawatts located at our Gillette, Wyo. energy complex. We own 76.5 percent of the plant. We sell 60 megawatts of unit contingent capacity and energy from this plant to Cheyenne Light under a PPA that expires on Dec. 31, 2022 . The PPA includes an option for Cheyenne Light to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility between 2013 and 2019. The purchase price in the contract related to the option is $2.6 million per megawatt reduced annually by an amount of annual depreciation assuming a facility life of 35 years. We expect Cheyenne Light to exercise its option to purchase sometime during the next several years. We sell excess power from our generating capacity into the wholesale power markets when it is available and economical.

Black Hills Colorado IPP - Pueblo Airport Generation . The Pueblo Airport Generation facility consists of two 100 megawatt combined-cycle gas-fired power generation plants located at a site shared with Colorado Electric. The plants commenced operation on Jan. 1, 2012, and the assets are accounted for as a capital lease under a 20-year PPA with Colorado Electric. Under the PPA with Colorado Electric, Colorado Electric has the ability to utilize our generating plants to sell energy in the wholesale power markets when it is available and economical.

Operating Agreement. Black Hills Wyoming and MEAN are parties to a shared joint ownership agreement, whereby Black Hills Wyoming charges MEAN for administrative services, plant operations and maintenance for their share of the Wygen I generating facility for the life of the plant.

Competition. The independent power industry consists of many strong and capable competitors, some of which may have more extensive operating experience, or greater financial resources than we possess.

With respect to the merchant power sector, 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. Our Power Generation business could face greater competition if utilities are permitted to robustly invest in power generation assets. However, state regulatory rules requiring utilities to competitively bid generation resources may provide opportunity for independent power producers in some regions.

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

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 three EWGs: Gillette CT, Wygen I and 200 megawatts at the Pueblo Airport Generating Facility. 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, Wygen I and Pueblo Airport Generating facilities are subject to Titles IV and V of the Clean Air Act and have the required permits in place or have applications submitted in accordance with regulatory time lines. As a result of SO ₂ 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 I plants through 2042, without purchasing additional allowances. The EPA’s MACT rule described in the Utilities Group section will apply to Wygen I.

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 that is 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.

Greenhouse Gas Regulations. The EPA’s GHG Tailoring Rule described in the Utilities Group section will apply to the Gillette CT, Wygen I and the Pueblo Airport Generating units upon a major modification, upon operating permit renewal or in the case of Pueblo Airport Generating Facility, upon initial issuance of the Title V operating permit.

Coal Mining Segment

Our Coal Mining segment operates through our WRDC subsidiary. We surface mine, process and sell low-sulfur sub-bituminous coal at our coal mine near Gillette, Wyo. The WRDC coal mine, which we acquired in 1956 from Homestake Gold Mining Company, is located in the Powder River Basin. The Powder River Basin contains one of the largest coal reserves in the United States. We produced approximately 4.2 million tons of coal in 2012 .

Surface mining involves removing the topsoil, then drilling and blasting the overburden (earth and rock covering the coal) with explosives. We then remove the overburden with equipment. Once exposed, we drill, fracture and systematically remove the coal using haul trucks and conveyors to transport the coal to the mine-mouth generating facility. We reclaim disturbed areas as part of our normal mining activities by back-filling the pit with overburden removed during the mining process. Once we have replaced the overburden and topsoil, we re-establish vegetation and plant life in accordance with our Post Mining Topography plan.

In a basin characterized by thick coal seams, our overburden ratio, a comparison of the cubic yards of dirt removed to a ton of coal uncovered, had in recent years trended upwards. The overburden ratio decreased in the second half of 2012 when we relocated mining operations to an area of the mine with lower overburden. We expect a lower overburden ratio for the next several years.

Mining rights to the coal are based on four federal leases and one state lease. The federal leases expire between Sept. 30, 2015 - March 31, 2021 and the state lease expires on Aug. 1, 2013. The duration of the leases vary; however, the lease terms generally are extended to the exhaustion of economically recoverable reserves, as long as active mining continues. We pay federal and state royalties of 12.5 percent and 9.0 percent, respectively, of the selling price of all coal. As of Dec. 31, 2012 , we estimated our recoverable coal reserves to be approximately 232.3 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering studies. The recoverable coal reserve life is equal to approximately 46 years at the current expected production levels. Our recoverable coal reserve estimates are periodically updated to reflect past coal production and other geological and mining data. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. Our recoverable coal reserves include reserves that can be economically and legally extracted at the time of their determination. We use various assumptions in preparing our estimate of recoverable coal reserves. See Risk Factors under Coal Mining for further details.

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


•	our electric utilities, Black Hills Power and Cheyenne Light. During 2012, Black Hills Power suspended operations at the 25 megawatt Ben French plant effective on Aug. 31, 2012 and announced the retirement of the Ben French plant and the 21.8 megawatt Neil Simpson I plant effective March 21, 2014 to which we sell approximately 120,000 and 130,000 tons of coal per year, respectively;


•	the 362 megawatt Wyodak power plant owned 80 percent by PacifiCorp and 20 percent by Black Hills Power. PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustments for planned outages. This contract expires at the end of December 2022;


•	the 110 megawatt Wygen III power plant owned 52 percent by Black Hills Power, 25 percent by MDU and 23 percent by the City of Gillette to which we sell approximately 600,000 tons of coal each year. This contract expires June 1, 2060;


•	the 90 megawatt Wygen I power plant owned 76.5 percent by Black Hills Wyoming and 23.5 percent by MEAN to which we sell approximately 600,000 tons of coal each year. This contract expires at the end of June 2038; and


•	certain regional industrial customers served by truck to which we sell approximately 165,000 tons of coal each year. These contracts are short-term and have a 1-3 year time range.

Our Coal Mining segment sells coal to Black Hills Power and Cheyenne Light for all of their requirements under cost-based agreements that regulate earnings from these affiliate coal sales to a specified return on our coal mine’s cost-depreciated investment base. The return is 4 percent 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 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 and through June 1, 2060 for Wygen III. The agreement with Cheyenne Light provides coal for the life of the Wygen II plant.

The price for unprocessed coal sold to PacifiCorp for its 80 percent interest in the Wyodak plant is determined by the coal supply agreement described above. The agreement includes price adjustments in 2014 and 2019, which essentially allow us to retain the economic advantage of the mine's location adjacent to the plant. The price adjustments will be based on the market price of coal plus considerations for the avoided costs of rail transportation and a coal unloading facility which PacifiCorp would have to incur if it purchased coal from another mine.

WRDC supplies coal to Black Hills Wyoming for the Wygen I generating facility for requirements under an agreement using a base price that includes price escalators and quality adjustments through June 30, 2038 and includes actual costs per ton plus a margin equal to the yield for Moody’s A-Rated 10-Year Corporate Bond Index plus 4 percent with the base price being adjusted on a 5-year interval. The agreement stipulates that WRDC will supply coal to the 90 megawatt Wygen 1 plant through June 30, 2038.

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, off-site sales have been to consumers within a close proximity to the mine. Rail transport market opportunities for WRDC coal are limited due to the lower heating value (Btu) of the coal, combined with the fact that the Wyodak coal mine is served by only one railroad, resulting in less competitive transportation rates. Management continues to explore the limited market opportunities for our product.

Additionally, coal competes with other energy sources, such as natural gas, wind, solar and hydropower. Costs and other factors relating to these alternative fuels, such as safety, environmental considerations and availability affect the overall demand for coal as a fuel.

Environmental Regulation. The construction and operation of coal mines are subject to 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. Many of the environmental issues and regulations discussed under the Utilities Group also apply to our Coal Mining segment.

Operations at WRDC must regularly address issues arising due to the proximity of the mine disturbance boundary to the City of Gillette and to related residential and industrial development. Homeowner complaints and challenges to the permits may occur as mining operations move closer to residential development areas. Specific concerns could include fugitive dust emissions and vibration and nitrous oxide fumes from blasting. To mitigate these concerns, WRDC is actively pursuing the establishment of buffer zones through land purchases and long-term leases.

Ash is the inorganic residue remaining after the combustion of coal. Ash from our South Dakota and Wyoming power plants, as well as PacifiCorp’s Wyodak power plant, is disposed of in the mine and is utilized for backfill to meet permitted post-mining contour requirements. The EPA has proposed national disposal regulations that include multiple options, one of which regulates coal ash as a hazardous waste. The public comment period ended in November 2010, and a final rule is expected in 2013. While the proposed combustion residuals regulations do not address mine backfill, it is widely expected that the U.S. Office of Surface Mining will collaborate with the EPA to address mine backfill in the near future. If the ash is regulated as a hazardous waste, the implementation requirements of more stringent management, handling, storage, transportation and disposal requirements will likely increase the cost of ash disposal for the power plants and/or increase backfill costs for the coal mine.

Mine Reclamation. Reclamation is required during production and after mining has been completed. 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 the WRDC mine. We have approved mining permits and are in compliance with other permitting programs administered by various regulatory agencies. The WRDC coal mine is permitted to operate under a five year mining permit issued by the State of Wyoming. The current permit expires in 2016. Based on extensive reclamation studies, we have accrued approximately $20.3 million for reclamation costs as of Dec. 31, 2012 . Mining regulatory requirements continue to increase, which impose additional cost on the mining process.

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 primarily in the Rocky Mountain region.

As of Dec. 31, 2012 , the principal assets of our Oil and Gas segment included: (i) operating interests in crude oil and natural gas properties, including properties in the San Juan Basin (including holdings primarily on the tribal lands of the Jicarilla Apache Nation in New Mexico and Southern Ute Nation in Colorado), the Powder River Basin (Wyoming) and the Piceance Basin (Colorado); (ii) non-operated interests in crude oil and natural gas properties including wells located in the Williston (Bakken Shale in North Dakota), Wind River (Wyoming), Bear Paw Uplift (Montana), Arkoma (Oklahoma), Anadarko (Texas) and Sacramento (California) basins; and (iii) a 44.7 percent ownership interest in the Newcastle gas processing plant and associated gathering system located in Weston County, Wyoming. The plant, operated by Western Gas Partners, LP, is adjacent to our producing properties in that area, and BHEP’s production accounts for the majority of the facility’s throughput. We also own natural gas gathering, compression and treating facilities serving the operated San Juan and Piceance Basin properties and working interests in similar facilities serving our non-operated Montana and Wyoming properties.

At Dec. 31, 2012 , we had total reserves of approximately 81 Bcfe, of which natural gas comprised 69 percent and crude oil comprised 31 percent . The majority of our reserves are located in select crude oil and natural gas producing basins in the Rocky Mountain region. Approximately 36 percent of our reserves are located in the San Juan Basin of northwestern New Mexico, primarily in the East Blanco Field of Rio Arriba County; 35 percent are located in the Powder River Basin of Wyoming, primarily in the Finn-Shurley Field of Weston and Niobrara counties; and 15 percent are located in the Piceance Basin of western Colorado, primarily in Mesa county.

Effective July 1, 2012 we sold approximately 85 percent of our Bakken and Three Forks shale assets in the Williston Basin in North Dakota, including approximately 73 gross wells and 28,000 net leasehold acres.

Summary Oil and Gas Reserve Data

The summary information presented for our estimated proved developed and undeveloped crude oil and natural gas reserves and the 10 percent discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates, an independent consulting and engineering firm located in Fort Worth, Texas. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Estimates of economically recoverable reserves and future net revenues are based on a number of variables, which may differ from actual results. Reserves for crude oil and natural gas are reported separately and then combined for a total MMcfe (where oil in Mbbl is converted to an MMcfe basis by multiplying Mbbl by six).

The SEC definition of “reliable technology” allows the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to book PUD locations that are more than one location away from a producing well. We elected to only include PUDs which are one location away from a producing well in our volume reserve estimate. Companies are allowed, but not required, to disclose probable and possible reserves. We have elected not to report these additional reserve categories. Additional information on our oil and gas reserves, related financial data and the SEC requirements can be found in Note 21 to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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

CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas and has over 24 years of practical experience in petroleum engineering and over 22 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

BHEP’s Manager of Planning and Analysis is the technical person primarily responsible for overseeing our third party reserve estimates. He has over 32 years of exploration and production industry experience as a geologist and financial analyst. He has over 22 years of experience working closely with internal and third party qualified reserve estimators in major and mid-sized oil and gas companies. He holds a Bachelor of Science degree in Geology and a Masters in Business Administration.

Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.

The following tables set forth summary information concerning our estimated proved developed and undeveloped reserves, by basin, as of Dec. 31, 2012 , 2011 and 2010 :



Proved Reserves		Dec. 31, 2012
	Total	Piceance	San Juan	Williston ^(a)	Powder River	Other
Developed -
Natural Gas (MMcf)	54,086	11,813	28,159	820	7,555	5,739
Oil (Mbbl)	3,851	7	12	489	3,321	22
Total Developed (MMcfe)	77,192	11,855	28,231	3,754	27,481	5,871

Undeveloped -
Natural Gas (MMcf)	1,901	335	457	279	186	644
Oil (Mbbl)	265	—	—	187	78	—
Total Undeveloped (MMcfe)	3,491	335	457	1,401	654	644

Total MMcfe	80,683	12,190	28,688	5,155	28,135	6,515

__________


(a)	Reflects sale of the majority of our Williston Basin assets during 2012 .



Proved Reserves		Dec. 31, 2011
	Total	Piceance	San Juan	Williston	Powder River	Other
Developed -
Natural Gas (MMcf)	71,867	15,598	36,463	1,954	8,926	8,926
Oil (Mbbl)	4,830	—	12	1,247	3,549	22
Total Developed (MMcfe)	100,847	15,598	36,535	9,436	30,220	9,058

Undeveloped -
Natural Gas (MMcf)	24,031	12,765	8,132	2,102	—	1,032
Oil (Mbbl)	1,394	—	—	1,394	—	—
Total Undeveloped (MMcfe)	32,395	12,765	8,132	10,466	—	1,032

Total MMcfe	133,242	28,363	44,667	19,902	30,220	10,090



Proved Reserves		Dec. 31, 2010
	Total	Piceance	San Juan	Williston	Powder River	Other
Developed -
Natural Gas (MMcf)	67,656	11,475	36,281	679	10,180	9,041
Oil (Mbbl)	4,434	—	11	508	3,891	24
Total Developed (MMcfe)	94,260	11,475	36,347	3,727	33,526	9,185

Undeveloped -
Natural Gas (MMcf)	27,800	21,777	620	1,820	—	3,583
Oil (Mbbl)	1,506	—	—	1,506	—	—
Total Undeveloped (MMcfe)	36,836	21,777	620	10,856	—	3,583

Total MMcfe	131,096	33,252	36,967	14,583	33,526	12,768

Change in Proved Reserves

The following tables summarize the change in quantities of proved developed and undeveloped reserves by basin, estimated using SEC-defined product prices, as of Dec. 31, 2012 , 2011 and 2010 :



Crude Oil	Dec. 31, 2012
(in Mbbl)	Total		Piceance	San Juan		Williston		Powder River		Other
Balance at beginning of year	6,223		—	12		2,641		3,549		21
Production	(560	)	—	(1	)	(338	)	(218	)	(3	)
Additions - acquisitions (sales)	(2,025	)	—	—		(1,983	)	(42	)	—
Additions - extensions and discoveries	449		5	—		401		43		—
Revisions to previous estimates	29		2	1		(45	)	67		4
Balance at end of year	4,116		7	12		676		3,399		22



Natural Gas	Dec. 31, 2012
(in MMcf)	Total		Piceance		San Juan		Williston		Powder River		Other
Balance at beginning of year	95,904		28,363		44,595		4,056		8,926		9,964
Production	(8,686	)	(1,718	)	(4,926	)	(427	)	(446	)	(1,169	)
Additions - acquisitions (sales)	(3,070	)	—		—		(3,070	)	—		—
Additions - extensions and discoveries	2,898		1,884		235		648		85		46
Revisions to previous estimates	(31,061	)	(16,377	)	(11,286	)	(104	)	(830	)	(2,464	)
Balance at end of year	55,985		12,152		28,618		1,103		7,735		6,377



	December 31, 2012
Total MMcfe ^(a)	Total		Piceance		San Juan		Williston ^(b)		Powder River		Other
Balance at beginning of year	133,242		28,363		44,667		19,902		30,220		10,090
Production	(12,046	)	(1,718	)	(4,932	)	(2,455	)	(1,754	)	(1,187	)
Additions - acquisitions (sales)	(15,220	)	—		—		(14,968	)	(252	)	—
Additions - extensions and discoveries	5,592		1,914		235		3,054		343		46
Revisions to previous estimates ^(c)	(30,885	)	(16,369	)	(11,282	)	(378	)	(422	)	(2,434	)
Balance at end of year	80,683		12,190		28,688		5,155		28,135		6,515

_____________________


(a)	Production for reserve calculations does not include volumes for NGLs.


(b)	Reflects sale of the majority of our Williston Basin assets during 2012.

(c)

Revisions to previous estimates for 2012 were primarily due to commodity price changes. Included in the total revisions is (27,051) MMcfe due to lower commodity prices, (2,422) MMcfe for dropped PUD locations due to the SEC requirement that PUD locations must be developed within five years or must be removed from PUD reserves, which was partially offset by positive performance revisions of 1,565 MMcfe in various basins.



Crude Oil	Dec. 31, 2011
(in Mbbl)	Total		Piceance	San Juan		Williston		Powder River		Other
Balance at beginning of year	5,940		—	11		2,014		3,891		24
Production	(452	)	—	(2	)	(182	)	(264	)	(4	)
Additions - acquisitions (sales)	(84	)	—	—		—		(84	)	—
Additions - extensions and discoveries	927		—	—		927		—		—
Revisions to previous estimates	(108	)	—	3		(118	)	6		1
Balance at end of year	6,223		—	12		2,641		3,549		21



Natural Gas	Dec. 31, 2011
(in MMcf)	Total		Piceance		San Juan		Williston		Powder River		Other
Balance at beginning of year	95,456		33,252		36,901		2,499		10,180		12,624
Production	(8,526	)	(1,077	)	(5,063	)	(173	)	(516	)	(1,697	)
Additions - acquisitions (sales)	—		—		—		—		—		—
Additions - extensions and discoveries	29,664		16,797		11,109		1,460		—		298
Revisions to previous estimates	(20,690	)	(20,609	)	1,648		270		(738	)	(1,261	)
Balance at end of year	95,904		28,363		44,595		4,056		8,926		9,964



	Dec. 31, 2011
Total MMcfe ^(a)	Total		Piceance		San Juan		Williston		Powder River		Other
Balance at beginning of year	131,096		33,252		36,967		14,583		33,526		12,768
Production	(11,238	)	(1,077	)	(5,075	)	(1,265	)	(2,100	)	(1,721	)
Additions - acquisitions (sales)	(504	)	—		—		—		(504	)	—
Additions - extensions and discoveries	35,226		16,797		11,109		7,022		—		298
Revisions to previous estimates ^(b)	(21,338	)	(20,609	)	1,666		(438	)	(702	)	(1,255	)
Balance at end of year	133,242		28,363		44,667		19,902		30,220		10,090

_________________


(a)	Production for reserve calculations does not include volumes for NGLs.

(b)

Revisions to previous estimates for 2011 were primarily due to the SEC requirement that PUD locations must be developed within five years or must be removed from proved undeveloped reserves. Included in the total revisions are (23,647) MMcfe for dropped PUD locations due to five year aging of reserves which was offset by positive performance revisions of 2,315 MMcfe in various basins. Revisions due to cost and commodity pricing were less than one percent of total reserve quantities.



Crude Oil	Dec. 31, 2010
(in Mbbl)	Total		Piceance	San Juan		Williston		Powder River		Other
Balance at beginning of year	5,274		—	7		678		4,552		37
Production	(376	)	—	(2	)	(84	)	(280	)	(10	)
Additions - acquisitions	(13	)	—	—		—		—		(13	)
Additions - extensions and discoveries	1,145		—	—		1,099		46		—
Revisions to previous estimates	(90	)	—	6		321		(427	)	10
Balance at end of year	5,940		—	11		2,014		3,891		24



Natural Gas	Dec. 31, 2010
(in MMcf)	Total		Piceance		San Juan		Williston	Powder River		Other
Balance at beginning of year	87,660		19,301		42,306		1,005	11,171		13,877
Production	(8,484	)	(1,077	)	(5,056	)	—	(314	)	(2,037	)
Additions - acquisitions	(377	)	—		—		—	—		(377	)
Additions - extensions and discoveries	1,710		—		372		1,334	—		4
Revisions to previous estimates	14,947		15,028		(721	)	160	(677	)	1,157
Balance at end of year	95,456		33,252		36,901		2,499	10,180		12,624



	Dec. 31, 2010
Total MMcfe ^(a)	Total		Piceance		San Juan		Williston		Powder River		Other
Balance at beginning of year	119,304		19,301		42,348		5,073		38,483		14,099
Production	(10,740	)	(1,077	)	(5,068	)	(504	)	(1,994	)	(2,097	)
Additions - acquisitions	(455	)	—		—		—		—		(455	)
Additions - extensions and discoveries	8,580		—		372		7,928		276		4
Revisions to previous estimates ^(b)	14,407		15,028		(685	)	2,086		(3,239	)	1,217
Balance at end of year	131,096		33,252		36,967		14,583		33,526		12,768

_______________


(a)	Production for reserve calculations does not include volumes for NGLs.


(b)	Revisions to previous estimates for 2010 are primarily due to price changes.

Production Volumes



	Year ended Dec. 31, 2012
Location	Oil (in Bbl)	Natural Gas (Mcfe) ^(a)	Total (Mcfe)
San Juan	1,423	4,923,589	4,932,127
Piceance	—	1,751,494	1,751,494
Powder River	218,455	837,552	2,148,282
Williston ^(b)	337,579	427,258	2,452,732
All other properties	2,514	1,244,228	1,259,313
Total Volume	559,971	9,184,121	12,543,948

___________________


(a)	Includes NGLs.


(b)	Reflects sale of the majority of our Williston Basin assets during 2012.



	Year ended Dec. 31, 2011
Location	Oil (in Bbl)	Natural Gas (Mcfe) ^(a)	Total (Mcfe)
San Juan	1,746	5,062,662	5,073,138
Piceance	—	1,111,421	1,111,421
Powder River	264,358	942,573	2,528,721
Williston	181,580	172,949	1,262,429
All other properties	4,139	1,761,788	1,786,622
Total Volume	451,823	9,051,393	11,762,331

___________________


(a)	Includes NGLs.



	Year ended Dec. 31, 2010
Location	Oil (in Bbl)	Natural Gas (Mcfe) ^(a)	Total (Mcfe)
San Juan	2,403	5,055,635	5,070,053
Piceance	—	1,111,724	1,111,724
Powder River	280,351	842,385	2,524,491
Williston	84,472	—	506,832
All other properties	8,419	2,036,755	2,087,269
Total Volume	375,645	9,046,499	11,300,369

___________________


(a)	Includes NGLs.

Other Information



	As of Dec. 31, 2012			As of Dec. 31, 2011
Proved developed reserves as a percentage of total proved reserves on an MMcfe basis	98		%	76		%

Proved undeveloped reserves as a percentage of total proved reserves on an MMcfe basis ^(a)	2		%	24		%

Present value of estimated future net revenues, before tax, discounted at 10 percent (in thousands)	$	151,255		$	255,087

___________________


(a)	The decrease to proved undeveloped reserves is primarily due to commodity price changes. See Note 21 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.

The following table reflects average wellhead pricing used in the determination of the reserves:



	Dec. 31, 2012
	Total		Piceance		San Juan		Williston		Powder River		Other
Gas per Mcf	$	2.24	$	2.51	$	1.90	$	2.05	$	3.09	$	2.27

Oil per Bbl	$	85.31	$	94.71	$	87.47	$	83.34	$	85.73	$	76.13



	Dec. 31, 2011
	Total		Piceance		San Juan		Williston		Powder River		Other
Gas per Mcf	$	3.59	$	3.73	$	3.37	$	3.07	$	4.36	$	3.83

Oil per Bbl	$	88.49	$	—	$	80.80	$	85.05	$	91.09	$	84.61



	Dec. 31, 2010
	Total		Piceance		San Juan		Williston		Powder River		Other
Gas per Mcf	$	3.45	$	3.21	$	3.50	$	3.57	$	3.62	$	3.79

Oil per Bbl	$	70.82	$	—	$	66.36	$	69.32	$	71.62	$	68.52

Drilling Activity

In 2012 , we participated in drilling 52 gross (4 net) development and exploratory wells, with a net well success rate of 95 percent. 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 the sum of our fractional ownership interests within those wells.

The following tables reflect the wells completed through our drilling activities for the last three years.



Year ended Dec. 31,	2012		2011		2010
Net Development Wells	Productive	Dry	Productive	Dry	Productive	Dry
Piceance	—	—	—	—	—	—
San Juan	—	—	1.00	—	5.60	—
Williston	1.80	—	1.73	—	0.67	—
Powder River	0.74	0.19	—	—	2.66	—
Other	—	—	3.59	—	—	—
Total net development wells	2.54	0.19	6.32	—	8.93	—



Year ended Dec. 31,	2012		2011		2010
Net Exploratory Wells	Productive	Dry	Productive	Dry	Productive	Dry
Piceance	0.86	—	0.99	—	—	—
San Juan	—	—	0.80	—	—	—
Williston	—	—	—	—	—	—
Powder River	—	—	—	—	—	—
Other	—	—	0.25	1.70	—	—
Total net exploratory wells	0.86	—	2.04	1.70	—	—

As of Dec. 31, 2012 , we were participating in the drilling of 16 gross (0.50 net) wells, which had been commenced but not yet completed.

Recompletion Activity

Recompletion activities for the years ended Dec. 31, 2012 , 2011 and 2010 were insignificant to our overall oil and gas operations.

Productive Wells

The following table summarizes our gross and net productive wells at December 31, 2012 , 2011 and 2010 :



		Dec. 31, 2012
	Total	Piceance	San Juan	Williston	Powder River	Other
Gross Productive:
Crude Oil	438	—	2	53	379	4
Natural Gas	762	68	212	—	27	455
Total	1,200	68	214	53	406	459

Net Productive:
Crude Oil	286.52	—	1.91	2.44	281.77	0.40
Natural Gas	326.57	54.76	197.96	—	10.05	63.80
Total	613.09	54.76	199.87	2.44	291.82	64.20



		Dec. 31, 2011
	Total	Piceance	San Juan	Williston	Powder River	Other
Gross Productive:
Crude Oil	462	—	2	56	398	6
Natural Gas	757	66	218	—	1	472
Total	1,219	66	220	56	399	478

Net Productive:
Crude Oil	299.10	—	1.91	3.97	292.45	0.77
Natural Gas	322.57	53.63	201.40	—	0.06	67.48
Total	621.67	53.63	203.31	3.97	292.51	68.25



		Dec. 31, 2010
	Total	Piceance	San Juan	Williston	Powder River	Other
Gross Productive:
Crude Oil	463	1	2	38	418	4
Natural Gas	828	88	225	—	7	508
Total	1,291	89	227	38	425	512

Net Productive:
Crude Oil	312.09	—	1.91	2.46	307.23	0.49
Natural Gas	355.90	66.23	214.82	—	0.73	74.12
Total	667.99	66.23	216.73	2.46	307.96	74.61

Acreage

The following table summarizes our undeveloped, developed and total acreage by location as of Dec. 31, 2012 :



	Undeveloped			Developed		Total
	Gross		Net ^(a)	Gross	Net	Gross	Net
Piceance	69,562		47,588	37,326	33,226	106,888	80,814
San Juan	40,677		39,273	25,213	23,024	65,890	62,297
Williston ^(b)	3,670	^(b)	524	12,860	1,853	16,530	2,377
Powder River	130,871		72,436	31,612	16,425	162,483	88,861
Bear Paw Uplift (MT)	355,103		96,913	106,650	19,796	461,753	116,709
Other	23,281		11,902	27,524	4,798	50,805	16,700
Total	623,164		268,636	241,185	99,122	864,349	367,758

_________________

(a)

Approximately 13.3 percent (129,316 gross and 35,724 net acres), 7.3 percent (71,758 gross and 19,716 net acres) and 15.9 percent (81,944 gross and 42,796 net acres) of our undeveloped acreage could expire in 2013 , 2014 and 2015 , respectively, if production is not established on the leases or further action is not taken to extend the associated lease terms. Decisions on extending leases are based on expected exploration or development potential under the prevailing economic conditions.


(b)	Reflects the sale of the majority of our Williston Basin assets during 2012.

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 a multitude of smaller, aggressive new start-up companies. Many of these companies explore for, produce and market crude 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, receiving economical costs for drilling and other oil and gas 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, which sometimes results 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.

Delivery Commitments. In 2012, we entered into a ten-year gas gathering contract for natural gas production from our properties in the Piceance Basin in Colorado, under which we pay a gathering fee per Mcf. The contract requires us to deliver a minimum of 20,000 Mcf per day. The gatherer is in the process of building the necessary infrastructure to handle the committed volumes. The agreement becomes effective when the infrastructure is placed in commercial service, which we estimate to be mid-2013. We believe that our reserves dedicated to the gathering system, and the projected volumes are adequate to satisfy our delivery commitments under this agreement.

Operating 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, complete or operate wells, and establish rules regarding the location of wells, well construction, surface use and restoration of properties on which wells are drilled, timing of when drilling and construction activities can be conducted relative to various wildlife and plant stipulations and 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 crude 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 Office of Natural Resources Revenue and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to crude oil and natural gas operations and administration of royalties on federal onshore and 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 expansion and 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 last several years. New regulations have increased costs and added uncertainty with respect to the timing and receipt of permits. We expect additional changes of this nature to occur in the future.

Environmental Regulations. 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 the 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 activities 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 regulation as RCRA wastes may in the future be designated as wastes under RCRA or other applicable statutes.

Hydraulic fracturing is an essential and common practice, which has been used extensively for decades in the oil and gas industry to enhance the production of natural gas and/or oil from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques on our crude oil and natural gas properties. Hydraulic fracturing involves using mostly water, sand, and a small amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to enhance flow of hydrocarbons into the well-bore. The process is regulated by state oil and natural gas commissions; however, the EPA does assert federal regulatory authority over certain hydraulic fracturing activities when diesel comprises part of the fracturing fluid. In addition, several agencies of the federal government including the EPA and the BLM are conducting studies of the fracturing stimulation process, which may result in additional regulations. In the event federal, state, local or municipal legal restrictions are adopted in areas where we are conducting, or plan to conduct operations, we may incur additional costs to comply with such regulations, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from utilizing fracture stimulation which may effectively preclude the drilling of wells. Also in 2012, the U.S. Department of the Interior proposed rules regulating the use of hydraulic fracturing. Action on these proposed rules is expected in 2013. All of these new or proposed regulations are expected to result in additional costs to our operations.

In 2011 and 2012, the EPA issued several air quality regulations that impact our operations. Those include emission standards for reciprocating internal combustion engines, new source performance standards for VOCs and SO ₂ and hazardous air pollutant standards for oil and natural gas production, as well as natural gas transmission and storage.

Our policy is to meet or exceed all applicable local, state, tribal and federal regulatory requirements when drilling, casing, and cementing oil and gas wells that we operate. We follow industry best practices for each project to ensure safety and minimize environmental impacts. Effective wellbore construction and casing design, in accordance with established recommended practices and engineering designs is important to ensure mechanical integrity and isolation from ground water aquifers throughout drilling, hydraulic fracturing and production operations. We place priority on drilling practices that ensure well control throughout the construction and completion phases.

Our wells are constructed using one or more layers of steel casing and cement to form a continuous barrier between fluids in the well and the subsurface strata. The only subsurface strata connected to the inside of the wellbore are the intervals that we perforate for the purpose of producing oil and gas. We isolate potential sources of ground water by cementing our surface and/or protection casing back to surface. In areas where additional protection may be necessary or required by regulations, we will cement the intermediate and or production casing string(s) back to surface. The casing is pressure-tested to ensure integrity. We may also run a cement bond log to determine the quality of the bond between the cement and the casing and the cement and the subsurface strata. Surface and/or protection casing string pressures are monitored when a well is stimulated. We also conduct a combination of tests during the life of the well to verify wellbore integrity. Our wells are designed to prevent natural gas and other produced fluids from migrating or leaking for the life of the well. We have qualified companies monitoring the pressure response to ensure that rate and pressure of fracturing treatment proceeds as planned. Unexpected changes in the rate or pressure are immediately evaluated and necessary action taken. We use the most effective and efficient water management options available. The handling, storage, and disposal of produced water meets or exceeds all applicable state, local, tribal and federal regulatory standards and requirements.

Greenhouse Gas Regulations. The EPA published an amendment to its GHG reporting requirements in the November 2010 Federal Register, adding Petroleum and Natural Gas Systems to the mandatory annual reporting requirements. Initial data gathering commenced on Jan. 1, 2011, with the first annual report submitted to the EPA in 2012. This is a permanent program, with GHG emission reports now due to the EPA on an annual basis. The Oil and Gas segment is also impacted by GHG regulation in the state of New Mexico. Other states may implement their own such programs in the future.

Other Properties

We own or lease several facilities throughout our service territories. Our owned facilities consist of:


•	In Rapid City, S.D., we own an eight-story, 67,000 square foot office building where our corporate headquarters is located, an office building consisting of approximately 36,000 square feet, and a warehouse building and shop with approximately 30,410 square feet.


•	In Pueblo, Colo., we own approximately 22,600 square feet for a service center and approximately 25,700 square feet for a warehouse.


•	In Cheyenne, Wyo., we own a business office with approximately 13,400 square feet, and a service center and garage with an aggregate of approximately 24,400 square feet.


•	In Papillion, Nebr., we own an office building consisting of approximately 36,600 square feet.


•	In Nebraska, Iowa, Colorado and Kansas we own various office, service center and warehouse space totaling over 196,200 square feet utilized by our Gas Utilities.


•	In South Dakota, Wyoming, Colorado and Montana we own various office, service center and warehouse space totaling approximately 56,000 square feet utilized by our Electric Utilities.


•	In our service territories, we also own other offices and warehouses.

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


•	Approximately 8,800 square feet for an operations and customer call center in Rapid City, S.D.;


•	Approximately 37,600 square feet for a customer call center in Lincoln, Nebr.;


•	Approximately 47,400 square feet of office space in Denver, Colo., of which 10,100 square feet is subleased to a third party;


•	Approximately 111,000 square feet of various office, service center and warehouse space leased by the Gas Utilities;


•	Approximately 3,600 square feet of various office, service center and warehouse space leased by the Electric Utilities; and


•	Other offices and warehouse facilities located within our service areas.

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. Similarly, the assets of Black Hills Wyoming are pledged to their lenders under a mortgage and security agreements for real and personal property.

Employees

At December 31, 2012 , we had 1,925 full-time employees. Approximately 33 percent of our employees are represented by a collective bargaining agreement. We have not experienced any labor stoppages in recent years. At Dec. 31, 2012 , approximately 27 percent of our Utilities Group employees were eligible for regular or early retirement.

The following table sets forth the number of employees by business group:



	Number of Employees
Corporate	363
Utilities	1,415
Non-regulated Energy	147
Total	1,925

At Dec. 31, 2012 , certain of our Utilities Group employees were covered by the following collective bargaining agreements:



Utility	Number of Employees	Union Affiliation	Expiration Date of Collective Bargaining Agreement
Black Hills Power	148	IBEW Local 1250	March 31, 2017
Cheyenne Light	50	IBEW Local 111	June 30, 2016
Colorado Electric	129	IBEW Local 667	April 15, 2015
Iowa Gas	134	IBEW Local 204	July 31, 2015
Kansas Gas	20	Communications Workers of America, AFL-CIO Local 6407	Dec. 31, 2014
Nebraska Gas	147	IBEW Local 244	March 13, 2014
Total	628


ITEM 1A.	RISK FACTORS

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

OPERATING RISKS

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 development, expansion and acquisition activities. We can provide no assurance that we will be able to complete development projects or acquisitions 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 or the imposition of adverse conditions upon the approval of any acquisition;


•	Our inability to secure adequate rates through regulatory proceedings;


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


•	The possibility that one or more credit 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;


•	Reduced growth in the demand for utility services in the markets we serve;


•	Changes in federal, state, local or tribal laws and regulations, particularly those which would make it more difficult or costly to fully develop our coal reserves, our oil and gas reserves and our generation capacity;


•	Fuel prices or fuel supply constraints;


•	Pipeline capacity and transmission constraints; and


•	Competition within our industry and with producers of competing energy sources.

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

Operating electric generating facilities, oil and gas properties, the coal mine and electric and natural gas distribution systems involves risks, including:


•	Operational limitations imposed by environmental and other regulatory requirements;

•

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


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


•	Inability to recruit and retain skilled technical labor;


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


•	Operating hazards such as leaks, mechanical problems and accidents, including explosions, affecting our natural gas distribution system which could impact public safety, reliability and customer confidence;


•	Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;


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


•	Labor relations. Approximately 33 percent of our employees are represented by a total of six collective bargaining agreements.

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

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 along with the cost of complying with or satisfying conditions imposed upon such approvals;


•	Contractual restrictions upon the timing of scheduled outages;


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


•	The unavailability or increased cost of equipment;


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


•	Supply interruptions, work stoppages and labor disputes;


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


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


•	Weather interferences;


•	Availability and cost of fuel supplies;


•	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 operating and 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.

Operating results can be adversely affected by variations from normal weather conditions.

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. Because natural gas is primarily 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 than normal in the summer and warmer than normal in the winter. Unusually mild summers and winters therefore could have an adverse effect on our financial condition and results of operations.

Our coal mining operations are subject to operating risks that are beyond our control which could affect our profitability and production levels. Our surface mining operations could be disrupted or materially affected due to adverse weather or natural disasters such as heavy snow, rain or flooding. Additionally, weather patterns can also affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage, and therefore, increased generating requirements and the use of coal. Conversely, mild temperatures could result in lower electrical demand.

Weather conditions can also limit or temporarily halt our drilling and producing activities and other crude oil and natural gas operations. Primarily in the winter and spring, our operations can be curtailed because of cold, snow, and wet conditions. Severe weather could further curtail these operations, including drilling of new wells or production from existing wells. In addition, weather conditions and other events could temporarily impair our ability to transport our crude oil and natural gas production.

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

A portion of our net income is attributable to sales of contract and off-system wholesale electricity and natural gas. 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 crude oil and natural gas operations is affected by the prevailing market prices of crude oil and natural gas. Crude oil and natural gas prices and markets historically have also been, and are likely to continue to be, unpredictable. A decrease in crude 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. Crude oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for crude oil and natural gas, market uncertainty, and a variety of additional factors that are beyond our control.

The proliferation of domestic crude oil and natural gas shale plays in recent years has provided the market with an abundant new supply of crude oil and natural gas. Combined with lower demand from the economic downturn, this new and abundant supply source has created record volumes of natural gas in storage, and reduced domestic natural gas prices. In fact, the ratio of crude oil to natural gas prices is at an all-time high, far in excess of the six to one heating value equivalent ratio. This trend is likely to continue for the foreseeable future given the expected further development of domestic shale gas reserves.

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

Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered.

Our Utilities Group and Power Generation segment rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to ratepayers, to supply our natural gas-fired power plants 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.

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

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

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

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

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

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

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

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

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

Utilities

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

Our regulated electric and gas utility operations are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. 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 direct and allocated 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 are permitted to recover certain costs (such as increased fuel and purchased power costs) without having to file a rate case. To the extent we are able to 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 adversely affect our results of operations, financial position or cash flow.

If market or other conditions adversely affect operations or require us to make changes to our business strategy in any of our utility businesses, we may be forced to record a non-cash goodwill impairment charge. Any significant impairment of our goodwill related to these utilities would cause a decrease in our assets and a reduction in our net income and shareholders’ equity.

We had approximately $353.4 million of goodwill on our consolidated balance sheet as of December 31, 2012 . A substantial portion of the goodwill is related to the Aquila Transaction. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of our businesses, we may be forced to record a non-cash impairment charge, which would reduce our reported assets, net income and shareholders’ equity. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including future business operating performance, changes in economic and interest rates, regulatory, industry or market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of one or more business segments, which may result in an impairment charge.

Municipal governments may seek to limit or deny franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.

Municipal governments within our utility service territories possess the power of condemnation and could establish a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations, and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.

Coal Mining

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated.

Our mining consists of surface mining operations. The Surface Mining Control and Reclamation Act and similar state laws and regulation establish operations, reclamation and closure standards for all aspects of surface mining. We estimate our total reclamation liabilities based on permit requirements, engineering studies, and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers, and by government regulators. The estimated liability can change significantly if actual costs vary from our original assumptions or if government regulations change significantly. GAAP requires that asset retirement obligations be recorded as a liability based on fair value, which reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates. The resulting estimated reclamation obligations could change significantly if actual amounts or the timing of these expenses change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.

Estimates of the quality and quantity of our coal reserves may change materially due to numerous uncertainties inherent in three dimensional structural modeling. Significant inaccuracies in interpretation or modeling could materially affect the estimated quantity and quality of our reserve which could adversely affect our results of operations.

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, 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.

Oil and Gas

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. Significant inaccuracies in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves which could adversely affect our results of operations.

There are many uncertainties inherent in estimating quantities of proved reserves and their associated value. The process of estimating crude 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 crude oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable crude 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 crude oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions.

The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in restrictions which could increase costs and cause delays to the completion of certain oil and gas wells, and potentially preclude the economic drilling and completion of wells in certain reservoirs.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used extensively for decades to stimulate production of natural gas and/or oil from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques on our crude oil and natural gas properties. Hydraulic fracturing involves using mostly water, sand, and a small amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to enhance flow of hydrocarbons into the well-bore. The process is typically regulated by state crude oil and natural gas commissions; however, the EPA does assert federal regulatory authority over certain hydraulic fracturing activities when diesel comprises part of the fracturing fluid. In addition several agencies of the federal government including the EPA and the BLM are conducting studies of the fracturing stimulation process which may result in additional regulations. In 2012 the BLM has proposed regulations governing the use of hydraulic fracturing. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide the federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

Certain states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In the event federal, state, local or municipal legal restrictions are adopted in areas where we are conducting or in the future plan to conduct operations, we may incur additional costs to comply with such regulations that may be significant, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from utilizing fracture stimulation and effectively preclude the drilling of wells.

Exploratory and development drilling are speculative activities that may not result in commercially productive reserves. Lack of drilling success could result in uneconomical investments and could have an adverse effect on our financial condition and results of operations.

Drilling activities are subject to many risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. There can be no assurance that new wells drilled by us or in which we have an interest will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental rules and regulations and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays are caused by the high demand for rigs and other needed equipment by a large number of companies in active drilling basins. High activity in some basins may cause shortages of rigs and equipment in other basins. Our future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on our financial condition 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 cause a decrease in our assets and stockholders' equity and could adversely impact our results of operations.

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 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, SEC-defined commodity prices and recent costs are utilized. 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 crude oil reserve quantities and SEC-defined crude oil and gas prices, both of which impact the present value of estimated future net revenues. Revisions to estimates of natural gas and crude 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 a non-cash impairment charge in the second quarter of 2012 due to the full cost ceiling limitations. We may have to record additional non-cash impairment charges in the future if commodity prices drive the SEC-defined prices below levels that precipitated the 2012 impairment. See Note 12 to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

FINANCING RISKS

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 ( Positive outlook) by Moody’s; BBB- ( Positive outlook) by S&P; and BBB- ( Stable outlook) by Fitch. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt 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.

Derivatives regulations included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.

In July 2010, Dodd-Frank was passed by Congress and signed into law. Dodd-Frank contains significant derivatives regulations, including a requirement that certain transactions be cleared resulting in a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users such as utilities and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions.

We use crude oil and natural gas derivative instruments for our hedging activities for our oil and gas production activities and our gas utility operations. We also use interest rate derivative instruments to minimize the impact of interest rate fluctuations. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for certain swap transactions we enter into. In addition, many of the transactions which were previously classified as swaps have been converted to exchange-traded futures contracts, which are subject to futures margin posting requirements. Such a requirement could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price and interest rate uncertainty and to protect cash flows. Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or may require us to increase our level of debt. In addition, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.

Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results due to accounting requirements associated with such activities.

We use various financial 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 commodities or assets 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 potential adverse effects resulting from changes in commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though they are closely monitored by management, our hedging 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.

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

We have two defined benefit pension plans and three non-pension postretirement plans that cover certain eligible employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations.

We rely on cash distributions from our subsidiaries to make and maintain dividends and debt payments. Our subsidiaries may not be allowed or may be unable to make dividend payments or loan funds to us, which could adversely affect our ability to meet our financial obligations or pay dividends to our shareholders.

We are a holding company. Our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any applicable contractual or regulatory restrictions that may include requirements to maintain minimum levels of cash, working capital or debt service funds.

We expect to continue our policy of paying regular cash dividends. However, there is no assurance as to the amount of future dividends because they depend on our future earnings, capital requirements, and financial conditions, and are subject to declaration by the Board of Directors. Our operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to us. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K for further information regarding these restrictions and their impact on our liquidity.

We may be unable to obtain the financing needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy. Lack of credit at reasonable rates would have an adverse effect on our results of operations, financial position and liquidity.

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.

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 then-prevailing market conditions, prudent financial management and any applicable regulatory requirements.

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

The continued recessionary environment and any future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

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

Our ability to obtain insurance, as well as the cost of such insurance, could be affected by developments affecting insurance businesses, international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which the Company may be subject, including but not limited to environmental hazards, wildfire-related liability, risks associated with our oil and gas exploration and production activities, distribution property losses, cyber-security risks and dangers that exist in the gathering and transportation in pipelines.

Our operations are also subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual or unexpected geologic formations, pressures, down hole fires, mechanical failures, blowouts, explosions, uncontrollable flows of oil, gas or well fluids, pollution and other environmental risks. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We maintain insurance coverage for our operated wells and we participate in insurance coverage maintained by the operators of our wells, although there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us if any of the foregoing events occur.

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

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

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

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

We have deferred a substantial amount of income tax related to various tax planning strategies, including the deferral of a gain associated with the assets sold in the IPP Transaction. If the Internal Revenue Service successfully challenges these tax positions, our results of operations, financial position or liquidity could be adversely affected .

We have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes associated with the IPP Transaction and the Aquila Transaction.

The IRS has challenged our position with respect to the like-kind exchange. As currently stated in a Notice of Proposed Adjustment received from the IRS in January 2013, their position is to disallow a significant portion of the gain deferred as reported on our originally filed 2008 tax return. We disagree with such a position and will pursue all available IRS and/or legal channels to challenge the proposed adjustment. In the event we are unsuccessful in our challenge, the amount of deferred income tax on a worst case basis that could be accelerated into a current tax payable would be approximately $125 million. However, we would be entitled to a tax benefit associated with the additional tax depreciation that would result from increasing the depreciable cost for tax purposes in the assets acquired. This net current tax liability would accrue interest, which is estimated to be approximately $20 million before income tax effect.

In certain circumstances, the IRS may assess penalties when challenging our tax positions. If we were unsuccessful in defending against these penalties, it may have a material impact on our results of operations. No penalties have been assessed by the IRS in connection with the like-kind exchange transaction.

Our ability to successfully resolve the purchase price adjustments in question from the sale of Enserco.

On Feb. 29, 2012 , we sold the outstanding stock of Enserco, our Energy Marketing segment. Pursuant to the provisions of the Stock Purchase Agreement, disputes regarding post-closing purchase price adjustments are subject to arbitration before a nationally-recognized accounting firm and all other disputes are subject to the indemnification procedures in the agreement. The buyer originally demanded an amount totaling $7.2 million characterizing all claims in such demand as purchase price adjustments. We contested certain claims in the buyer's demand, including whether certain claims were properly characterized as purchase price adjustments, but reached a partial settlement and paid the buyer the sum of $1.4 million . The parties were unable to reach a negotiated agreement regarding the balance of the claims.

In December 2012, we agreed to arbitrate the claims that we believe are properly characterized as purchase price adjustments, but objected to the arbitration of the claims that we believe are not properly characterized as purchase price adjustments. After joint discussions of the parties with the arbitrator, in January 2013 the arbitrator advised the parties that it would not arbitrate the claims to which we objected. On Feb. 7, 2013, the buyer filed a petition in the United States District Court for the District of Colorado applying for an order compelling arbitration on all of the disputed claims. We will respond to this litigation, requesting the court to deny the buyer's application.

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

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

ENVIRONMENTAL RISKS

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

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

On May 20, 2011, with amendments on Dec. 21, 2012, the EPA’s Industrial and Commercial Boiler regulations became effective, which provide for hazardous air pollutant-related emission limits and monitoring requirements. The compliance deadline for this rule is March 21, 2014. Engineering evaluations have been completed and confirm the significant impact on our Neil Simpson I, Osage and Ben French facilities. We anticipate these units will be retired on or before March 21, 2014 compliance deadline.

On Dec. 16, 2011, with updates on Dec. 21, 2012, the EPA signed the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), which became effective on April 16, 2012. Affected units have three years from the rule effective date to be in compliance, with a pathway defined to apply for a one year extension due to certain circumstances. It is expected that all of our plants will be in compliance by the initial 2015 deadline, with the primary impacts to Neil Simpson II, Wygen I, Wygen II, Wygen III and the Wyodak Plant with the need to install mercury sorbent injection systems and the need to meet additional monitoring and testing.

The GHG Tailoring Rule, implementing regulations of GHG for permitting purposes, became effective in June 2010. This rule will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Existing permitted facilities will see monitoring reporting requirements incorporated into their operating permits upon renewal. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units is expected to be final in the first half of 2013 and as proposed, effectively prohibits new coal fired units until carbon capture and sequestration becomes technically and economically feasible. In 2013, we expect to see a proposed rule from the EPA, to regulate GHG emissions from existing steam electric generating units. This rule could have a significant impact on our coal generating fleet.

In 2010, the State of Colorado enacted House Bill 1365, the Colorado Clean Air, Clean Jobs Act, a coordinated utility plan to reduce air emissions from coal fired power plants and promoting the use of natural gas and other lower emitting resources. This act has a significant impact on our W.N. Clark facility and in October 2010, Colorado Electric filed testimony with the CPUC that recommended retirement of the W.N. Clark facility to comply with House Bill 1365. In December 2010, the CPUC issued an order approving the closure of the W.N. Clark generation facility by Dec. 31, 2013, and granted a presumption of need for replacement of the plant. On July 30, 2012, Colorado Electric filed its electric resource plan with the CPUC seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant. The CPUC dismissed the initial filing without prejudice. It directed Colorado Electric to refile the resource plan and address alternatives for not just the replacement capacity for its coal-fired W.N. Clark power plant, but also for the retirement of the aging natural gas-fired steam turbines at Pueblo Units 5 and 6 . On review, the CPUC confirmed Colorado Electric’s right to own the replacement capacity for the W.N. Clark power plant and extended the date to refile the resource plan to May 1, 2013.

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

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

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

Our business is subject to extensive energy, environmental and other laws and regulations of federal, state, tribal and local authorities. We generally must obtain and comply with a variety of regulations, 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 or cause us to reevaluate the feasibility of continued operations at certain sites, and have a detrimental effect on our business.

In connection with certain acquisitions, we assumed liabilities associated with the environmental condition of certain properties, regardless of when such liabilities arose, whether known or unknown, and in some cases agreed to indemnify the former owners of those properties for environmental liabilities. Future steps to bring our facilities into compliance or to address contamination from legacy operations, if necessary, could be expensive and could adversely affect our results of operation and financial condition. We expect our environmental compliance expenditures to be substantial in the future due to the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate.

The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization and the use of alternative energy sources for power generation as mandated by states could reduce coal consumption. As a result, coal users may switch to other fuels, which could affect the volume of our sales and the price of our products.

Coal contains impurities, including but not limited to sulfur, mercury, chlorine, carbon and other elements or compounds, many of which are released into the air when coal is burned. More stringent environmental regulations of emissions from coal-fueled power plants could increase the costs of using coal, thereby reducing demand for coal as a fuel source and the volume and price of our coal sales. Renewable energy requirements and changes to regulations could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter, or greenhouse gases may require the installation of costly emission control technology or the implementation of other measures. For example, in order to meet the federal Clean Air Act limits for SO ₂ emission from power plants, coal users may need to install scrubbers, use SO ₂ emission allowances (some of which they may purchase), blend high-sulfur coal with low-sulfur coal or switch to other fuels. Reductions in mercury emission required by certain states and the EPA will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury. Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our operations and financial results could be adversely impacted.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


ITEM 3.	LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 19 , “ Commitments and Contingencies ”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

ITEM 4. SPECIALIZED DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Annual Report.

PART II


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

Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of Dec. 31, 2012 , we had 4,517 common shareholders of record and approximately 29,000 beneficial owners, representing all 50 states, the District of Columbia and 8 foreign countries.

We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its Jan. 31, 2013 meeting, our Board of Directors declared a quarterly dividend of $0.38 per share, equivalent to an annual dividend of $1.52 per share, marking 2013 as the 43 ^rd consecutive annual dividend increase for the Company.

For additional discussion of our dividend policy and factors that may limit our ability to pay dividends, see “Liquidity and Capital Resources” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K.

Quarterly dividends paid and the high and low prices for our common stock, as reported in the New York Stock Exchange Composite Transactions, for the last two years were as follows:



Year ended Dec. 31, 2012	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Dividends paid per share	$	0.370	$	0.370	$	0.370	$	0.370
Common stock prices
High	$	35.82	$	34.31	$	36.28	$	37.00
Low	$	32.18	$	31.32	$	30.29	$	33.51



Year ended Dec. 31, 2011	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Dividends paid per share	$	0.365	$	0.365	$	0.365	$	0.365
Common stock prices
High	$	33.64	$	34.85	$	32.22	$	34.47
Low	$	29.76	$	28.12	$	25.83	$	29.10

UNREGISTERED SECURITIES ISSUED

There were no unregistered securities sold during 2012 .

ISSUER PURCHASES OF EQUITY SECURITIES

The following table contains information about our acquisitions of equity securities for the three months ended December 31, 2012 :



Period	Total Number of Shares Purchased ^*	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Oct. 1, 2012 –Oct. 31, 2012	—	N/A		—	—

Nov. 1, 2012 –Nov. 30, 2012	138	$	35.38	—	—

Dec. 1, 2012 –Dec. 31, 2012	—	N/A		—	—
Total	138	$	35.38	—	—

_________________________


*	Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of restricted stock and the exercise of stock options.


ITEM 6.	SELECTED FINANCIAL DATA



Years Ended Dec. 31,	2012			(1)	2011			(1)	2010			(1)	2009			(1)	2008			(1)
(dollars in thousands, except per share amounts)

Total Assets	$	3,729,471			$	4,127,083			$	3,711,509			$	3,317,698			$	3,379,889

Property, Plant and Equipment
Total property, plant and equipment	$	3,930,772			$	3,724,016			$	3,353,509			$	2,973,398			$	2,703,117
Accumulated depreciation and depletion	$	(1,188,023	)		$	(934,441	)		$	(861,775	)		$	(812,961	)		$	(681,387	)

Capital Expenditures	$	347,980			$	431,707			$	496,990			$	347,819			$	1,304,330		(2)

Capitalization
Current maturities of long-term debt	$	103,973			$	2,473			$	5,181			$	35,245			$	2,078
Notes payable	277,000				345,000				249,000				164,500				703,800
Long-term debt, net of current maturities	938,877				1,280,409				1,186,050				1,015,912				501,252
Common stock equity	1,232,509				1,209,336				1,100,270				1,084,837				1,050,536
Total capitalization	$	2,552,359			$	2,837,218			$	2,540,501			$	2,300,494			$	2,257,666

Capitalization Ratios
Short-term debt, including current maturities	14.9		%		12.2		%		10.0		%		8.7		%		31.3		%
Long-term debt, net of current maturities	36.8		%		45.1		%		46.7		%		44.2		%		22.2		%
Common stock equity	48.3		%		42.7		%		43.3		%		47.1		%		46.5		%
Total	100.0		%		100.0		%		100.0		%		100.0		%		100.0		%

Total Operating Revenues	$	1,173,884			$	1,272,188			$	1,219,691			$	1,198,712			$	946,480

Net Income Available for Common Stock
Utilities	$	79,588			$	81,860			$	74,563			$	57,071			$	43,904
Non-regulated Energy	24,725			(4)	866				10,189				1,581			(5)	(42,384		)	(6)
Corporate expenses and intersegment eliminations	(15,808		)	(3)	(42,361		)	(3)	(21,611		)	(3)	18,617			(3)	(76,668		)	(3)
Income (loss) from continuing operations	88,505				40,365				63,141				77,269				(75,148		)
Income (loss) from discontinued operations, net of tax ⁽⁷⁾	(6,977		)		9,365				5,544				4,286				180,358
Net loss attributable to non-controlling interest	—				—				—				—				(130		)
Net income available for common stock	$	81,528			$	49,730			$	68,685			$	81,555			$	105,080

SELECTED FINANCIAL DATA continued



Years Ended Dec. 31,	2012			(1)	2011		(1)	2010		(1)	2009		(1)	2008			(1)
(dollars in thousands, except per share amounts)

Dividends Paid on Common Stock	$	65,262			$	59,202		$	56,467		$	55,151		$	53,663

Common Stock Data ⁽⁸⁾ (in thousands)
Shares outstanding, average	43,820				39,864			38,916			38,614			38,193
Shares outstanding, average diluted	44,073				40,081			39,091			38,684			38,193
Shares outstanding, end of year	44,206				43,925			39,269			38,969			38,636

Earnings (Loss) Per Share of Common Stock (in dollars) ⁽⁸⁾
Basic earnings (loss) per average share -
Continuing operations	$	2.02			$	1.01		$	1.62		$	2.00		$	(1.97	)
Discontinued operations	(0.16		)		0.24			0.14			0.11			4.72
Total	$	1.86			$	1.25		$	1.76		$	2.11		$	2.75
Diluted earnings (loss) per average share -
Continuing operations	$	2.01			$	1.01		$	1.62		$	2.00		$	(1.95	)
Discontinued operations	(0.16		)		0.23			0.14			0.11			4.72
Total	$	1.85			$	1.24		$	1.76		$	2.11		$	2.77

Dividends Declared per Share	$	1.48			$	1.46		$	1.44		$	1.42		$	1.40



Book Value Per Share, End of Year	$	27.84		$	27.55		$	28.02		$	27.84		$	27.19

Return on Average Common Stock Equity (year-end)	6.7		%	4.3		%	6.3		%	7.6		%	10.4		%

SELECTED FINANCIAL DATA continued



Years ended Dec. 31,	2012	2011	2010	2009	2008
Operating Statistics:
Generating capacity (MW):
Electric Utilities (owned generation)	859	865	687	630	630
Electric Utilities (purchased capacity)	150	450	440	430	420
Power Generation (owned generation)	309	309	120	120	141
Total generating capacity	1,318	1,624	1,247	1,180	1,191

Electric Utilities:
Megawatt-hours sold: ⁽¹⁾
Retail electric	4,598,080	4,590,800	4,532,191	4,403,459	3,532,402
Contracted wholesale	340,036	349,520	468,782	645,297	665,795
Wholesale off-system	1,652,949	1,788,005	1,749,524	1,692,191	1,551,273
Total Megawatt-hours sold	6,591,065	6,728,325	6,750,497	6,740,947	5,749,470

Gas Utilities: ^{(1) (9)}
Gas sold (Dth)	47,358,505	55,764,154	55,265,630	56,671,438	23,053,599
Transport volumes (Dth)	60,480,822	59,216,132	59,879,450	55,104,284	26,805,075

Oil and gas production sold (MMcfe)	12,544	11,762	11,300	12,463	13,534
Oil and gas reserves (MMcfe) ⁽⁴⁾	80,683	133,242	131,096	119,304	185,542

Tons of coal sold (thousands of tons) ⁽¹⁰⁾	4,246	5,692	5,931	5,955	6,017
Coal reserves (thousands of tons)	232,265	256,170	261,860	268,000	274,000

____________________________________


(1)	All years have been reclassified to include our Energy Marketing segment in Discontinued Operations. 2008 includes electric and gas utilities acquired on July 14, 2008.


(2)	Includes $938.4 million for the Aquila acquisition.


(3)	2011, 2010 and 2008 include a $27.3 million , a $9.9 million and a $61.4 million , non-cash after-tax unrealized mark-to-market loss, respectively, related to certain interest rate swaps; while 2012 and 2009 include a $1.2 million and a $36.2 million non-cash after-tax unrealized mark-to-market gain, respectively, related to certain interest rate swaps.


(4)	2012 includes a non-cash after-tax ceiling test impairment loss of $17.3 million offset by an after-tax gain on sale of $18.9 million of our Williston Basin assets (see Notes 12 and 22 of the Notes to the Consolidated Financial Statements of this Annual Report on Form 10-K.)


(5)	Includes a $27.8 million non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties taken in 2009 and a $16.9 million after-tax gain on sale of 23.5 percent ownership interest in Wygen I.


(6)	Includes a $59.0 million non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties taken in 2008.


(7)	Discontinued operations include the operations of the Energy Marketing segment in 2012, 2011, 2010, 2009 and 2008, and the assets sold in the IPP Transaction for 2009 and 2008.


(8)	During November 2011, we issued 4.4 million shares of common stock which diluted our earnings per share in subsequent periods.


(9)	Excludes Cheyenne Light.


(10)	Tons of coal decreased in 2012 due to the expiration of an unprofitable train load-out contract.

For additional information on our business segments see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Note 17 to the Consolidated Financial Statements in this Annual Report on Form 10-K.


ITEMS 7 &	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS


and 7A.	OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET

RISK

We are an integrated energy company operating principally in the United States with two major business groups - Utilities and Non-regulated Energy. We report our business groups in the following financial segments:



Business Group	Financial Segment

Utilities	Electric Utilities
	Gas Utilities
Non-regulated Energy *	Power Generation
	Coal Mining
	Oil and Gas

__________________________


*	On Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations.

Our Utilities Group consists of our Electric and Gas utilities segments. Our Electric Utilities segment generates, transmits and distributes electricity to approximately 202,000 customers in South Dakota, Wyoming, Colorado and Montana and provides natural gas distribution services to approximately 35,000 customers of Cheyenne Light in Wyoming. Our Gas Utilities segment serves approximately 532,000 natural gas customers in Colorado, Iowa, Kansas and Nebraska. Our Non-regulated Energy Group engages in the production of natural gas, crude oil and coal, and the production of electric power through ownership of a portfolio of generating plants, the output energy and capacity of which is sold primarily under mid- and long-term wholesale contracts.

Industry Overview

Recovery from the 2008 global economic crisis remained unpredictable in 2012 because of ongoing sovereign debt problems, mostly centered in the European Union. Slow economic growth continued through 2012 reducing energy demand. Energy commodity prices, which were near historic highs in mid-2008, experienced dramatic declines in early 2009. While crude oil prices recovered notably from 2009 through 2011, natural gas prices have remained low. Domestic crude oil prices continued to be influenced by global factors, including foreign economic conditions (especially in China and Asia), the policies of OPEC and other large foreign oil producers, and political tensions and conflict in many regions.

The proliferation of domestic natural gas shale plays in recent years has provided the domestic market an abundant new supply of natural gas. Combined with lower demand from the economic downturn, this new and abundant supply source has created record volumes of natural gas in storage, and reduced domestic natural gas prices. In fact, the ratio of crude oil to natural gas prices is abnormally high, far in excess of the six to one heating value equivalent ratio. This trend is likely to continue for the foreseeable future given the expected further development of domestic shale gas reserves.

In the United States, electricity generated from coal is approximately 40 percent, down from approximately 50 percent a decade ago. According to the U.S. Energy Information Administration, coal consumption in the United States was estimated to decline approximately 10 percent in 2012 compared to 2011, offset by a growing demand for coal exports. Although coal prices for the Western market continued to experience volatility in 2012 with multiple micro and macro influences impacting prices, coal still remains the leading fuel and the cheapest source of energy for U.S. electricity generation. Powder River Basin (8,800 Btu per pound) spot prices started the year at $10.00/ton, then decreased to $8.25/ton in the summer, but ultimately settled back to $10.00/ton in late 2012.

Like other industries located in the United States, the energy industry is faced with numerous uncertainties, both short and long-term. Many utilities have large capital spending needs over the next few years to replace aging infrastructure, add new assets such as transmission lines and renewable energy resources, and upgrade or replace power generation facilities due to increasingly stringent state and federal emissions regulations. Utility companies generally are less impacted by economic downturns, but the severe recession and prolonged recovery affected demand for energy and the ability of customers to pay their utility bills, particularly in certain parts of the country. Although the recovery in the United States continues to be unpredictable, for credit-worthy companies, equity and debt financings were successfully undertaken over the past few years.

The state utility regulatory climate remained relatively constructive among government, industry and consumer representatives. In the seven-state region encompassing our utility operations, regulators were willing to establish rates based on multi-year considerations, including fuel and other reasonable cost adjustments, justifiable capital expenditures for maintenance and expansion of energy systems, and a response to environmental concerns through demand management and energy efficiency programs. Challenges remain, however, in obtaining satisfactory rate recovery for utility investments due to the general state of the economy and concern by regulators in various states that utility rate increases may cause further harm to local economies. In short, over the past year state regulatory commissions and staffs have become more stringent and conservative related to authorized returns and other regulatory mechanisms related to cost recovery.

Recent federal administrative and legislative actions have set the stage for an emphasis on increased regulation and government oversight of the energy industry. The energy marketplace and the Company continue to respond to the increased oversight and enforcement activity of FERC, and increased environmental and emissions reviews and mandates. The SEC was active issuing several disclosure requirements in 2012 relating to the Dodd-Frank Act which apply to the energy industry. The EPA passed rules in 2011 that will either require expensive upgrades or the closure of many older coal burning power plants. State legislatures also remained active on environmental issues, with a majority of states now having adopted some form of renewable energy standard, including some in which we operate. In addition, several states have passed greenhouse gas emissions legislation, which places limits on the emissions of CO ₂ and other GHGs. These known and potential future administrative and legislative actions could have significant macroeconomic consequences, which may impact us, as the associated cost increases may cause a dramatic increase in consumer costs for products and services, including rates for electricity and other energy in the mid- to long-term.

The November 2012 election increased the potential for a new wave of environmental regulations as the President has indicated that the administration would do more to reduce carbon emissions. The passage of the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, extended through 2012 lower tax rates introduced in 2001 and 2003, reduced the estate tax, extended unemployment benefits, reduced the Social Security portion of payroll taxes for employees, and extended bonus depreciation. A benefit to our investors, the bill extended through 2012 the lower capital gains tax rate introduced by the Jobs and Growth Tax Relief Reconciliation Act of 2003. Additionally, the bill extended the 100 percent bonus depreciation for business property acquired after Sept. 8, 2010 and placed into service prior to Jan. 1, 2012. This provision provided positive tax benefits for the Colorado Electric and Black Hills Colorado IPP generation projects completed in 2011. In early 2013, additional tax legislation was passed that further extended 50 percent bonus depreciation, which will benefit customers related to Cheyenne Prairie. The 2013 legislation also increased the tax rate on dividends and capital gains for many taxpayers and utility investors, but not to the extent industry proponents had feared.

Over the last decade, the corporate structure of many energy companies underwent evaluation and change, in large part due to efforts to create additional shareholder value. Since before the economic crisis, a number of companies contemplated or implemented a realignment of business lines, reflecting a shift in long-term strategies. Some divested certain energy properties to focus on core businesses, such as exiting non-regulated power production or energy marketing, in favor of more stable utility operations. Others engaged in mergers and acquisitions with a goal to improve economies of scale and returns to investors. Private equity investors continued to play a role in the changing composition of energy ownership.

Many industry analysts cite the need for expanded energy capacity and delivery systems. They continue to foresee an increase in capital investment across a wide spectrum of energy companies. Many electric and gas utilities must replace aging plant and equipment, and regulators appear willing to provide acceptable rate treatment for additional utility investment, although the current state of the economy makes rate recovery more challenging in the short run. If warranted based on commodity prices, oil and gas producers will continue to explore for new reserves, particularly natural gas, which will be the primary fuel of choice in light of concern regarding GHG emissions and the need to provide backup generation for renewable energy resources. The growing focus on environmental regulation made it increasingly more difficult to obtain drilling permits, particularly on federal and Native American lands. However, current low natural gas prices prompted some companies to curtail projects in order to conserve cash during a period of low cash flow and constrained capital markets.

Fossil fuel combustion continues to be a contentious domestic and international public policy issue, as many nations, including United States allies, advocate reductions in CO ₂ and other emissions. Many states now encourage the energy industry to invest in renewable energy resources, such as wind or solar power, or the use of bio-mass as a fuel. In many instances, renewable energy use is mandated by state regulators. Several years ago, the State of California mandated that future imports of power must come from power plants with emission levels no greater than combined-cycle natural gas-fired plants. Recently proposed EPA regulations on GHG emissions are very similar. Such restrictions may alter transmission flow of power in western states, as a large percentage of current power generation in the western grid comes from coal sources.

The power generation industry continues to make improvements in emissions control, both voluntarily and in response to regulatory mandates. Emissions from new coal-fired plants are now a small fraction of those produced by power plants built a generation ago. With similar technological progress, coal can and likely will remain an important, domestically available, and economical national energy resource that is vital to meet growing energy demand. In that regard, the DOE is beginning to take positive steps toward ensuring the future of coal through research funding for “clean coal” technologies and methods of carbon capture and sequestration.

Energy providers, government authorities and private interests continue to address issues concerning electric transmission, power generation capacity, the use of renewable and other diversified sources of energy, crude oil and natural gas pipelines and storage, and other infrastructure requirements. In the short-term, prevailing economic conditions will reduce industrial and retail energy consumption. Despite public and private efforts to promote conservation and efficiency, however, the demand for energy is expected to increase steadily over the long-term. To meet this demand growth, the industry will need to provide capital, resources and innovation to serve customers cost effectively, and to achieve suitable returns on investment.

We believe that we are well-positioned in this industry setting, and able to proceed with our key business objectives. Along with industry counterparts, we are preparing to address the challenges discussed in this overview, such as new environmental regulations and mandates, renewable portfolio standards, CO ₂ -related taxes or trading practices, credit market conditions, inflation, or other factors that may affect energy demand and supply. In particular, we are sensitive to additional costs that can negatively affect our customers or our profitability. To that end, we intend to work closely with regulators and industry leaders to assure that cost-conscious proposals and solutions are carefully explored in public policy proceedings.

Business Strategy

We are a customer-focused integrated energy company. Our business is comprised of electric and natural gas utilities, power generation assets, and fuel assets which produce coal, crude oil and natural gas. Our focus on customers - whether they are utility customers or non-regulated energy customers - provides opportunities to expand our businesses by constructing additional rate base assets to serve our utility customers and expanding our non-regulated energy holdings to provide additional products and services to our wholesale customers.

The diversity of our energy operations reduces reliance on any single business segment to achieve our strategic objectives. Our emphasis on our utility businesses with diverse geography and fuel mix, combined with a conservative approach to our non-regulated energy operations, mitigates our overall corporate risk and enhances our ability to earn stronger returns for shareholders over the long-term. Despite challenging conditions in the capital markets over the past few years, we have demonstrated our ability to access the debt and equity markets, resulting in sufficient liquidity and solid cash flows. Consequently, our financial foundation is sound and capable of supporting an expansion of operations in both the near and long-term.

Our long-term strategy focuses on growing both our utility and non-regulated energy businesses, primarily by increasing our customer base and providing superior service to both utility and non-regulated energy customers. In our natural gas and electric utilities, we intend to significantly grow our asset base to serve projected customer demand and to comply with environmental mandates in our existing utility service territories through expansion of infrastructure and construction of new rate-based power generation facilities. If the opportunity arises, we will pursue acquisitions of additional utility properties, primarily in the Great Plains and Rocky Mountain regions of the country. By maintaining our high customer service and reliability standards in a cost-efficient manner, our goal is to secure appropriate rate recovery to provide solid economic returns on our utility investments.

We will continue to prudently grow and develop our existing inventory of crude oil and natural gas reserves, while we strive to maintain strong relationships with mineral owners, landowners and regulatory authorities. We intend to focus our near-term efforts on proving up the substantial Mancos shale gas potential of our San Juan and Piceance Basin properties. Given increased regulatory emphasis on wind and solar power generation, and potential environmental regulations and legislation that may limit construction of new coal-fired power plants, we believe that natural gas will be the near-term fuel of choice for power generation. Additional gas-fired peaking resources will also be required to provide critical back-up supplies for renewable technologies.

Given the amount of electricity currently generated in the United States from coal-fired power plants, it will take decades and significant expense before this generation can be replaced with alternative technologies. As a result, coal-fired resources will remain a necessary component of the nation’s electric supply for the foreseeable future. The current regulatory climate, combined with the EPA's proposed and expected GHG regulations, will likely limit construction of new conventional coal-fired power plants, but technologies such as carbon capture and sequestration should provide for the long-term economic use of coal. We have and will continue to investigate the possible deployment of these technologies at our mine site in Wyoming and will continue efforts to develop additional markets for our coal production, including the possible development of additional power plants at our mine site.

We have expertise in permitting, constructing and operating power generation facilities. These skills, combined with our understanding of electric resource planning and regulatory procedures, provide a significant opportunity for us to add long-term shareholder value. We intend to grow our non-regulated power generation business by continuing to focus on long-term contractual relationships with other load-serving utilities.

Key Elements of our Business Strategy

Provide stable long-term rates for customers and increase earnings by efficiently planning, constructing and operating rate-base power generation facilities needed to serve our electric utilities. Our Company began as a vertically integrated electric utility, and this business model remains a core strength and strategy today, as we invest in and operate efficient power generation resources to cost effectively transmit and distribute electricity to our customers. We provide power at reasonable rates to our customers, and earn competitive returns for our investors.

We have a competitive power production strategy. Our access to coal and natural gas reserves allows us to be competitive as a power generator. Low production costs can result from a variety of factors, including low fuel costs, efficiency in converting fuel into energy, and low per unit operation and maintenance costs. We leverage the mine-mouth coal-fired generating capacity which strengthens our position as a low-cost producer by eliminating fuel transportation costs which often represent the largest component of the delivered cost of coal for many other utilities. In addition, we typically operate our plants with high levels of availability, as compared to industry benchmarks. We aggressively manage each of these factors with the goal of achieving low production costs.

Rate-base generation assets offer several advantages for consumers, regulators and investors. First, since the generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable than if the power was purchased from the open market through wholesale contracts that are renegotiated over time. Second, regulators participate in a planning process where long-term investments are designed to match long-term energy demand. Third, investors are assured that a long-term, reasonable, stable rate of return may be earned on their investment. A lower risk profile may also improve credit ratings which, in turn, can benefit both consumers and investors by lowering our cost of capital.

Examples of our progress include the January 2008 completion of Wygen II to serve the customers of Cheyenne Light, the April 2010 completion of Wygen III to serve the customers of Black Hills Power, and the January 2012 completion of a 180 megawatt gas-fired power plant to serve the customers of Colorado Electric. Due to existing legislation in Colorado, we plan to retire Colorado Electric’s W.N. Clark plant by Dec. 31, 2013 and EPA regulations covering hazardous air pollutants will necessitate the retirement of several of our other older coal-fired power plants, including Black Hills Power’s Osage, Ben French and Neil Simpson I plants in March 2014. We are replacing some of these facilities with Cheyenne Prairie’s rate-based natural gas-fired power plants.

For customers in states without renewable or CO ₂ mandates, such as South Dakota and Wyoming, we have constructed mine-mouth, state-of-the-art, cost-efficient, coal-fired facilities, such as Wygen II and Wygen III. Given the current environmental regulatory climate, it is unlikely we could secure a permit to construct additional coal-fired generation in the next several years, but we are monitoring developments associated with alternative coal-fired generation technologies, including IGCC and carbon capture and sequestration, though both appear cost prohibitive in the near term. These technologies may become cost effective in the future if regulatory or legislative actions place a sufficiently high price on CO ₂ emissions or further technological advancements reduce the costs of those technologies. The location of our coal mine and power plant complex in the Powder River Basin of Wyoming provides key strategic advantages for carbon capture and sequestration projects, such as readily available saline aquifers for the injection and sequestration of CO ₂ , as well as a potential CO ₂ market for use in enhanced oil recovery projects. Additionally, the Wyoming legislature has been proactive in passing legislation to address pore space ownership, injection regulations and other legal issues associated with the underground sequestration of CO ₂ .

Proactively integrate alternative and renewable energy into our utility energy supply while mitigating and remaining mindful of customer rate impacts. The energy and utility industries face tremendous uncertainty related to the potential impact of legislation and regulation intended to reduce GHG emissions and increase the use of renewable and other alternative energy sources. To date, many states have enacted and others are considering some form of mandatory renewable energy standard, requiring utilities to meet certain thresholds of renewable energy use. Additionally, many states have either enacted or are considering legislation setting GHG emissions reduction targets. Federal legislation for both renewable energy standards and GHG emission reductions is also under consideration.

Mandates for the use of renewable energy or the reduction of GHG emissions will likely produce substantial increases in the prices for electricity and natural gas. At the same time, however, as a regulated utility we are responsible for providing safe, reasonably priced, reliable sources of energy to our customers. As a result, we have developed a customer-centered strategy for complying with renewable energy standards and GHG emission reductions that balances our customers’ rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers. Examples of our balanced approach include:

•

In states such as South Dakota and Wyoming that currently have no legislative mandate on the use of renewable energy, we have proactively integrated cost-effective renewable energy into our generation supply based upon our expectation that there will be mandatory renewable energy standards in the future. For example, under two 20-year PPAs we purchase a total of 60 megawatts of wind energy from wind farms located near Cheyenne, Wyoming for use at Black Hills Power and Cheyenne Light;

•

Colorado and Montana have legislative mandates regarding the use of renewable energy. Therefore, we aggressively pursue cost-effective initiatives with the regulators that will allow us to meet our renewable energy requirements. To the extent practical, we intend to construct renewable generation resources as rate base assets, which will help mitigate the long-term customer rate impact of adding renewable energy supplies. For example, the CPUC approved a 29 megawatt wind turbine project, completed in the fourth quarter of 2012, in which we are permitted to rate base 50 percent ownership as part of our plan to meet Colorado’s Renewable Energy Standard. The Busch Ranch site also has significant expansion potential; and


•	In all states in which we conduct electric utility operations, we are exploring other potential biomass, solar and wind energy projects, particularly wind generation sites located near our utility service territories.

Expand utility operations through selective acquisitions of electric and gas utilities consistent with our regional focus and strategic advantages. For more than 130 years we have provided reliable utility services, delivering quality and value to our customers. Our tradition of accomplishment supports efforts to expand our utility operations into other markets, most likely in areas that permit us to take advantage of our intrinsic competitive advantages, such as baseload power generation, system reliability, superior customer service, community involvement and a relationship-based approach to regulatory matters. The 2005 acquisition of Cheyenne Light and the 2008 Aquila Transaction are examples of such expansion efforts. Utility operations also enhance other important business development opportunities, including gas transmission pipelines and storage infrastructure, which could promote other non-regulated energy operations. Utility operations can contribute substantially to the stability of our long-term cash flows, earnings and dividend policy.

We have and will continue to pursue the purchase of small private gas distribution systems, which can be easily integrated into our operations. We purchased several small systems in Kansas and Iowa in the past two years.

We have a platform of systems and processes which are scalable, which should simplify the integration of potential future utility acquisitions. Merger and acquisition activity in the utility industry has increased in the last year. We believe that impacts of the current recession may produce opportunities for healthy utility companies to acquire utility assets and operations of other companies on attractive terms and conditions. We expect to consider such opportunities if we believe they would further our long-term strategy and help maximize shareholder value.

Build and maintain strong relationships with wholesale power customers of both our utilities and non-regulated power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers and believe we will continue to be a primary provider of electricity to wholesale utility customers. We further believe that these entities will continue to need products, such as capacity, in order to reliably serve their customers. By providing these products under long-term contracts, we are able to help our customers meet their energy needs. Through this approach, we also believe we can earn more stable revenues and greater returns over the long term than we could by selling energy into more volatile spot markets. In addition, relationships that we’ve established with wholesale power customers have developed into other opportunities. MEAN and MDU, both wholesale power customers, are now also joint owners in two of our power plants, Wygen I and Wygen III, respectively.

Selectively grow our non-regulated power generation business in targeted regional markets by developing assets and selling most of the capacity and energy production through mid- and long-term contracts primarily to load-serving utilities. While much of our recent power plant development has been for our regulated utilities, we intend to continue to expand our non-regulated power generation business by developing and operating power plants in regional markets based on prevailing supply and demand fundamentals in a manner that complements our existing fuel assets and marketing capabilities. We intend to grow this business through a combination of the development of new power generation facilities and disciplined acquisitions primarily in the western region where we believe our detailed knowledge of market and electric transmission fundamentals provides us a competitive advantage and, consequently, increases our ability to earn attractive returns. We expect to prioritize small-scale facilities that serve incremental growth or provide critical back up to renewable resources, and are typically easier to permit and construct than large-scale generation projects.

Most of the energy and capacity from our non-regulated power facilities is sold under mid- and long-term contracts. When possible, we structure long-term contracts as tolling arrangements, whereby the contract counterparty assumes the fuel risk. Going forward, we will continue to focus on selling a majority of our non-regulated capacity and energy primarily to load-serving utilities under long-term agreements that have been reviewed or approved by state utility commissions. An example of this strategy is the 200 megawatts of combined-cycle gas-fired generation constructed by our non-regulated power generation subsidiary to serve our Colorado Electric utility subsidiary. The plant commenced operations on Jan. 1, 2012, under a 20-year tolling agreement.

With respect to our current power sale agreements, two of our long-term power contracts provide for the sale of capacity and energy to Cheyenne Light from our Gillette CT and Wygen I plants. The Gillette CT contract expires in 2014. The Wygen I contract expires in 2022, and provides an option for Cheyenne Light to purchase and rate base Black Hills Wyoming’s portion of Wygen I.

Increase the value of our oil and gas properties by prudently growing our reserves and increasing our production of natural gas and crude oil. Our strategy is to cost-effectively grow our reserves and increase our production of natural gas and crude oil through both organic growth and acquisitions. While consistent growth remains our objective, we realize the necessity of managing for value creation over managing for growth as follows:


•	Through detailed reservoir analysis, apply proven technologies to our existing assets to maximize value;


•	Participate in a limited number of selective and meaningful exploration prospects;

•

Primarily focus on the Rocky Mountain region, where we can more easily integrate new opportunities with our existing crude oil and natural gas operations as well as our power generation activities. Specifically, we intend to focus our near term efforts on fully developing the substantial shale gas potential of our San Juan and Piceance Basin properties and participating in select oil exploration prospects with substantial upside opportunities;


•	Support the future capital requirements of our drilling program by stabilizing cash flows with a hedging program that mitigates commodity price risk for a portion of our established production for up to two years in the future; and


•	Enhance our crude oil and natural gas production activities with the construction or acquisition of mid-stream gathering, compression and treating facilities in a manner that maximizes the economic value of our operations.

Diligently manage the credit, price and operational risks inherent in buying and selling energy commodities. All of our operations require effective management of counterparty credit risk. We mitigate this risk by conducting business with a diverse group of creditworthy counterparties. In certain cases where creditworthiness merits security, we require prepayment, secured letters of credit or other forms of financial collateral. We establish counterparty credit limits and employ continuous credit monitoring, with regular review of compliance under our credit policy by our Executive Credit Committee. Our oil and gas and power generation operations require effective management of price and operational risks related to adverse changes in commodity prices and the volatility and liquidity of the commodity markets. To mitigate these risks, we implemented risk management policies and procedures. Our oversight committees monitor compliance with these policies.

Maintain an investment grade credit rating and ready access to debt and equity capital markets. Access to capital has been and will continue to be critical to our success. We will require access to the capital markets to fund our planned capital investments or, when possible, to make strategic acquisitions that prudently grow our businesses. Our access to adequate and cost-effective financing depends upon our ability to maintain our investment-grade issuer credit rating.

We completed several key financings during 2012, including renewing our $500 million Revolving Credit Facility and extending a $150 million term loan.

Prospective Information

We expect to generate long-term growth through the expansion of integrated and diverse energy operations. We recognize that sustained growth requires continued capital deployment. Our diversified energy portfolio with an emphasis on regulated utilities provides growth opportunities, yet avoids concentrating business risk. We expect much of our growth in the next few years will come from major capital investments at our existing business segments. During 2012, we refinanced our Revolving Credit Facility and term loans on favorable terms. Although dependent on market conditions, we are confident in our ability to obtain additional financing to continue our growth plans. We remain focused on managing our operations cautiously and maintaining our overall liquidity to meet our operating, capital and financing needs, as well as executing our long-term strategic plan.

Utilities Group

Electric Utilities

Our Electric Utilities benefited from warm summer weather and an increase in rates resulting from rate cases approved for Colorado Electric and Cheyenne Light. The new rates for Colorado Electric were effective Jan. 1, 2012 upon commercial operation of a 180 megawatt gas-fired generation facility that now serves Colorado Electric customers. New rates for Cheyenne Light were effective on July 1, 2012. The addition of the new generation facility for Colorado Electric to our utility rate base and the successful approval of our rate case had a significant positive impact on our 2012 financial results.

Pursuant to prior approved resource plans, the Electric Utilities engaged in the following regulatory requests for construction activities during 2012:

•

The WPSC approved the CPCN for Cheyenne Light and Black Hills Power to construct a new jointly owned 132 megawatt generating facility in Cheyenne, Wyo. with an expected commercial operation date in the fourth quarter of 2014. Cheyenne Light and Black Hills Power also received approval from the WPSC to use a construction financing rider for Cheyenne Prairie in lieu of traditional AFUDC. This allows Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately a 60 percent share of the project costs related to serving Wyoming customers, while also lowering the overall cost of the project to customers. This rider was effective Nov. 1, 2012, resulting in an increase to gross margin of $0.2 million in 2012, and it will increase gross margin in 2013 and 2014 by approximately $5.5 million and $7.8 million, respectively. A request for a similar rider was made to the SDPUC. The SDPUC approved interim rates for that rider, effective April 1, 2013, which will increase gross margin by approximately $3.6 million and $5.6 million in 2013 and 2014, respectively. Interim rates are subject to refund until final approval is received;

•

Colorado Electric completed construction of a 29 megawatt wind project as part of our plan to meet Colorado’s Renewable Energy Standards. It was placed into commercial operation on Oct. 16, 2012 and Colorado Electric owns a 50 percent interest in this wind project. On Jan. 30, 2013, Colorado Electric received approval notification from the United States Treasury for an award letter grant of $8.4 million for our share of the Busch Ranch wind project; and

•

On July 30, 2012, Colorado Electric filed its Electric Resource Plan with the CPUC seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant, consistent with a prior CPUC order that had ordered the plant to be retired per the requirements of the Colorado Clean Air – Clean Jobs Act. The CPUC dismissed the initial filing without prejudice and directed Colorado Electric to refile the resource plan and address alternatives for not just the replacement capacity for its coal-fired W.N. Clark power plant, but also for the retirement of the aging natural gas-fired steam turbines, Pueblo Units #5 and #6. On review, the CPUC confirmed Colorado Electric’s right to own the replacement energy for the W.N. Clark power plant and extended the date to refile the resource plan to May 1, 2013.

Gas Utilities

Unseasonably warm winter weather adversely impacted 2012 results at our Gas Utilities. Our Gas Utilities are focused on the continued investment in our gas distribution network and related technology such as advanced metering infrastructure and mobile data terminals. We continually monitor our investments and costs of operations in all states to determine when additional rate cases or other rate filings will be necessary. As part of our growth strategy, we continue to look for opportunities to purchase municipal and rural gas infrastructure and the distribution systems. We acquired two small gas systems during 2012 with a total of 327 customers.

Non-regulated Energy Group

Power Generation

Our Power Generation segment was awarded the bid to provide 200 megawatts of power to our Colorado Electric subsidiary through a 20-year PPA. Construction for a 200 megawatt combined cycle natural gas-fired power generation facility in Colorado was completed in December 2011 and this facility commenced commercial operation on Jan. 1, 2012. We plan to continue evaluating opportunities to bid on the construction of generation resources, both new and existing, for other regional electric utilities for their energy and capacity needs.

Coal Mining

Production from the Coal Mining segment primarily serves mine-mouth generation plants and select regional customers with long-term fuel needs. Total annual production is estimated to be approximately 4.5 million tons for 2013, which is consistent with 2012. Annual production decreased in 2012 primarily due to the termination of the PacifiCorp Dave Johnston power plant contract which expired at the end of 2011. However, the termination of this contract had a positive impact on earnings since the pricing of this contract was such that we were not recovering our costs during the latter periods of the agreement. In the second quarter of 2012, the coal mine commenced operations under a revised mine plan. Mining operations moved to an area with lower overburden ratios, which should reduce mining costs for the next several years.

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. We have recently extended two smaller volume off-site sales contracts served by truck. There are some limitations in regards to transporting our lower-heat content coal; however, we continue to pursue new opportunities to market our coal.

Oil and Gas

During much of 2012, BHEP’s mission was to identify future investment opportunities while conserving capital and strictly controlling costs. In September 2012, we sold approximately 85 percent of our Bakken and Three Forks shale assets in the Williston Basin in North Dakota representing 73 gross wells and approximately 28,000 net leasehold acres for approximately $227.9 million. The sale reduced the full-cost pool by $198 million which will reduce our depreciation, depletion and amortization rate in the future. We will continue our efforts into 2013 to develop attractive oil and gas investment opportunities.

Corporate

On Feb. 1, 2012, we entered into a new five year $500 million Revolving Credit Facility at favorable terms, and on Oct. 31, 2012, we redeemed our $225 million senior unsecured 6.5 percent bonds early with the proceeds from the sale of the oil and gas assets. Repayment of this debt will significantly lower our interest expense in 2013.

As of Dec. 31, 2012 , we had interest rate swaps with a notional amount of $250 million , which do not currently qualify for “hedge accounting” treatment provided by accounting standards for derivatives and hedges. Accordingly, all mark-to-market adjustments on these swaps are recorded through the income statement. As of Dec. 31, 2012 , the mark-to-market value of these swaps was a liability of $88.1 million . In 2012, we recorded an unrealized mark-to-market after-tax gain of $1.2 million on these swaps. Fluctuations in interest rates create volatility in the fair value of these swaps which will likely have an impact on our 2013 earnings as we record the associated unrealized mark-to-market gains or losses within our income statement.

Results of Operations

Executive Summary and Overview



	For the Years Ended Dec. 31,
	2012			Variance			2011			Variance			2010
	(in thousands)
Revenue
Utilities	$	1,081,047		$	(87,868	)	$	1,168,915		$	48,194		$	1,120,721
Non-regulated Energy	216,239			37,867			178,372			16,017			162,355
Inter-company eliminations	(123,402		)	(48,303		)	(75,099		)	(11,714		)	(63,385		)
	$	1,173,884		$	(98,304	)	$	1,272,188		$	52,497		$	1,219,691

Income (loss) from continuing operations
Electric Utilities	$	51,598		$	3,907		$	47,691		$	239		$	47,452
Gas Utilities	27,990			(6,179		)	34,169			7,058			27,111
Utilities	79,588			(2,272		)	81,860			7,297			74,563

Power Generation	21,328			18,317			3,011			860			2,151
Coal Mining	5,626			6,050			(424		)	(8,105		)	7,681
Oil and Gas ^(a)	(2,229		)	(508		)	(1,721		)	(2,078		)	357
Non-regulated Energy	24,725			23,859			866			(9,323		)	10,189

Corporate and Eliminations ^(b)(c)	(15,808		)	26,553			(42,361		)	(20,750		)	(21,611		)

Income from continuing operations	88,505			48,140			40,365			(22,776		)	63,141

Income (loss) from discontinued operations, net of tax ^(d)	(6,977		)	(16,342		)	9,365			3,821			5,544
Net income (loss)	$	81,528		$	31,798		$	49,730		$	(18,955	)	$	68,685

______________


(a)	Income (loss) from continuing operations in 2012 includes a $17.3 million non-cash after-tax ceiling test impairment loss and an $18.9 million after-tax gain on sale of our Williston Basin assets. See Notes 12 and 22 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

(b)

Financial results of Enserco, our Energy Marketing segment, have been reclassified as discontinued operations in accordance with GAAP. When preparing this reclassification, certain indirect corporate costs and inter-segment interest expenses previously charged to our Energy Marketing segment could not be reclassified to discontinued operations and accordingly have been presented within Corporate of $0.6 million and $2.2 million for 2012 and 2011 , respectively. See Note 23 of the Consolidated Financial Statements in this Annual Report on Form 10-K.


(c)	Includes a $1.2 million non-cash after-tax mark-to-market gain on certain interest rate swaps in 2012 and a $27.3 million non-cash after-tax mark-to-market loss in 2011 on those same certain interest rate swaps.


(d)	Income (loss) from discontinued operations, net of tax includes the activities of Enserco, our Energy Marketing segment. See Note 23 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

On Feb. 29, 2012, we sold our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. Additionally, the following business group and segment information does not include inter-company eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.

2012 Compared to 2011

Income from continuing operations was $88.5 million , or $2.01 per share, in 2012 compared to $40.4 million , or $1.01 per share, in 2011 . The 2012 Income from continuing operations includes an $18.9 million after-tax gain on sale related to the Williston Basin asset sale, a $17.3 million non-cash after-tax ceiling test impairment, a $1.0 million non-cash after-tax write-off of deferred financing costs related to our previous Revolving Credit Facility and a $1.2 million non-cash after-tax mark-to-market gain on certain interest rate swaps. The 2011 Income from continuing operations includes a $27.3 million non-cash after-tax mark-to-market loss on certain interest rate swaps.

Net income was $81.5 million , or $1.85 per share, in 2012 compared to $49.7 million , or $1.24 per share, in 2011 .

Business Group highlights for 2012 include:

Utilities Group

Highlights of the Utilities Group include the following:


•	Our return on investments made in the Utilities Group was positively impacted by new and interim rates and tariffs implemented in three utility jurisdictions during 2012. Consequently, year-to-date revenues were positively impacted for rate increases in 2012 that were not in effect in the prior periods (dollars in millions).



Utility	State	Effective Date	Annual Revenue Increase
Colorado Electric	Colo.	1/2012	$	28.0
Cheyenne Light	Wyo.	7/2012		4.3
Colorado Gas	Colo.	12/2012		0.2
			$	32.5


•	Colorado Electric’s $230 million, 180 megawatt power plant near Pueblo, Colo. began commercial operations and started serving utility customers on Jan. 1, 2012. New rates and cost adjustments were effective Jan. 1, 2012, providing an additional $36 million in gross margins at Colorado Electric for the year ended Dec. 31, 2012.


•	On June 18, 2012, the WPSC approved a $2.7 million increase in annual electric revenue and a $1.6 million increase in annual natural gas revenue with a rate of return of 9.6 percent and a capital structure of 54 percent equity and 46 percent debt for Cheyenne Light. New rates were effective July 1, 2012.

•

On June 4, 2012, Colorado Gas filed a request with the CPUC for an increase in annual gas revenues to recover capital investments and increased operation and maintenance expenses. The filing was required by the CPUC as part of a 2008 rate case settlement. The CPUC approved a $0.2 million revenue increase with new rates effective Dec. 10, 2012. The settlement includes a return on equity of 9.6 percent and a capital structure of 50 percent equity and 50 percent debt.

•

2012 utility results were unfavorably impacted by warm weather, particularly at the Gas Utilities. Our service territories reported warmer winter weather, as measured by degree days, compared to the 30-year average and the prior year. Heating degree days year-to-date were 13 percent lower than weighted average norms for our Gas Utilities. When compared to colder than normal weather during the same period in 2011, heating degree days were 14 percent lower than the same period in 2011 for our Gas Utilities. For our Electric Utilities, although summer temperatures were above normal, weather-related demand was tempered by lower humidity in 2012 than 2011 in our service territories.

•

Cheyenne Light and Black Hills Power received final approvals and permits for Cheyenne Prairie. The WPSC approved the CPCN authorizing the construction, operation and maintenance for the new 132 megawatt natural gas-fired electric generation facility and related gas and electric transmission in Cheyenne, Wyo. The facility will include one simple-cycle, 37 megawatt combustion turbine that will be wholly owned by Cheyenne Light and one combined-cycle, 95 megawatt unit that will be jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Light will own 40 megawatts and Black Hills Power will own 55 megawatts of the combined-cycle unit. We have ordered all major equipment for the project and commencement of construction is expected in spring 2013. Commercial operation is expected in the fourth quarter of 2014. Project costs for plant construction and associated transmission are estimated at $222 million, with up to $15 million of construction financing, for a total of $237 million.

•

Cheyenne Light and Black Hills Power received approval from the WPSC to use a construction financing rider for Cheyenne Prairie in lieu of traditional AFUDC. This allows Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately a 60 percent share of the project costs related to serving Wyoming customers, while also lowering the overall cost of the project to customers. This rider was effective Nov. 1, 2012, resulting in an increase to gross margin of $0.2 million in 2012, and it will increase gross margin in 2013 and 2014 by approximately $5.5 million and $7.8 million, respectively. Black Hills Power filed for a similar construction financing rider in South Dakota. On Jan. 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013, subject to refund. We expect a final ruling by the SDPUC on the construction financing rider before the end of the third quarter.

•

Colorado Electric completed construction of the 29 megawatt Busch Ranch wind project as part of its plan to meet Colorado’s Renewable Energy Standard. Colorado Electric’s 50 percent share of this project cost approximately $25 million and began serving Colorado Electric customers on Oct. 16, 2012. Colorado Electric entered into a 25-year REPA to purchase the remaining 50 percent wind energy produced by the project. On Jan. 30, 2013, Colorado Electric received approval notification from the United States Treasury for an award letter grant of $8.4 million for our share of the wind project.

•

Black Hills Power and Colorado Electric announced plans to suspend plant operations at certain older coal-fired and natural gas-fired facilities. In addition, the companies identified retirement dates for the older coal-fired power plants because of state and federal environmental regulations and cost to retrofit. The affected plants are listed in the table below with their operations suspension date (if applicable) and their ultimate retirement date (if identified).



Plant	Company	Megawatts		Type of Plant	Date Suspended	Planned Retirement Date	Age of Plant (in years)
Osage	Black Hills Power		34.5	Coal	Oct. 1, 2010	March 21, 2014	64
Ben French	Black Hills Power		25.0	Coal	Aug. 31, 2012	March 21, 2014	52
Neil Simpson I	Black Hills Power		21.8	Coal	NA	March 21, 2014	43
W.N. Clark	Colorado Electric		42.0	Coal	Dec. 31, 2012	Dec. 31, 2013	57
Pueblo Unit #5	Colorado Electric		9.0	Gas	Dec. 31, 2012	to be determined	71
Pueblo Unit #6	Colorado Electric		20.0	Gas	Dec. 31, 2012	to be determined	63
	Total MW		152.3

•

On July 30, 2012, Colorado Electric filed its Electric Resource Plan with the CPUC seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant, which must be retired pursuant to the Colorado Clean Air – Clean Jobs Act. The CPUC dismissed the initial filing and directed Colorado Electric to refile its Electric Resource Plan by May 1, 2013 in order to address alternatives for the replacement capacity of W.N. Clark power plant, as well as the retirement of Pueblo #5 and Pueblo #6 and directed Colorado Electric to request a CPCN for any replacement capacity that Colorado Electric seeks to develop and own.

Non-regulated Energy Group

Highlights of the Non-regulated Energy Group include the following:

•

On Sept. 27, 2012 , our Oil and Gas segment sold approximately 85 percent of its Williston Basin assets, including approximately 73 gross wells and 28,000 net leasehold acres, for net cash proceeds of $227.9 million . We recognized a gain of $29.1 million on the sale. The portion of the sale amount not recognized as gain reduced the full-cost pool and should significantly decrease the future depreciation, depletion and amortization rate.


•	Coal Mining commenced operations under its revised mine plan. Mining operations moved in August 2012, to an area with lower overburden ratios, which should reduce mining costs for the next several years.


•	In the second quarter of 2012, our Oil and Gas segment recorded a $26.9 million non-cash ceiling test impairment loss as a result of continued low natural gas prices.


•	Construction of gas-fired generation at Black Hills Colorado IPP to serve a 20-year PPA with Colorado Electric was completed and the plant was placed into commercial operations on Jan. 1, 2012. The 200 megawatt project cost approximately $261 million .

Corporate

Activities at Corporate include the following:


•	On Feb. 1, 2012 , we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017 . The facility contains an accordion feature allowing us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million .


•	On June 24, 2012, we extended for one year our $150 million term loan at an interest rate of 1.1 percent over LIBOR.


•	On Oct. 31, 2012, we redeemed our $225 million senior unsecured, 6.5 percent notes scheduled to mature on May 15, 2013.


•	We recognized a non-cash unrealized mark-to-market gain related to certain interest rate swaps of $1.9 million in 2012 compared to a $42.0 million unrealized mark-to-market loss on these swaps in 2011 .

Discontinued Operations

On Feb. 29, 2012 , we sold the outstanding stock of Enserco, our Energy Marketing segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds at Dec. 31, 2012 from the transaction were approximately $165.0 million , subject to final post-closing adjustments.

2011 Compared to 2010

Income from continuing operations was $40.4 million , or $1.01 per share, in 2011 compared to $63.1 million , or $1.62 per share, in 2010 . The 2011 Income from continuing operations includes a $27.3 million after-tax non-cash mark-to-market loss on certain interest rate swaps. The 2010 Income from continuing operations includes a gain on sale of $5.8 million after-tax of a 23 percent ownership interest in the Wygen III plant and assets sold by Nebraska Gas after the annexation of a service area; and a $9.9 million after-tax non-cash mark-to-market loss on certain interest rate swaps.

Net income was $49.7 million , or $1.24 per share, in 2011 compared to $68.7 million , or $1.76 per share, in 2010 . Enserco, our Energy Marketing segment, has been reclassified and is included in Income from discontinued operations in 2011 and 2010 .

Highlights of our business groups are as follows:

Utilities Group

Our Electric Utilities were positively impacted by approved rate cases and an increase in off-system sales margins. Our Gas Utilities recorded increased margins due to the impact of rate increases. Additional highlights of the Utilities Group include the following:


•	Revenues in 2011 were positively impacted by a full year of rate increases that became effective at various dates in 2010 (dollars in millions).



Utility	State	Effective Date	Annual Revenue Increase
Black Hills Power	SD	4/2010	$	15.2
Black Hills Power	WY	6/2010		3.1
Colorado Electric	CO	8/2010		17.9
Nebraska Gas	NE	3/2010		8.3
Iowa Gas	IA	6/2010		3.4
			$	47.9


•	A 180 megawatt gas-fired generation plant constructed to serve Colorado Electric customers started providing energy on Jan. 1, 2012.


•	The Wygen III generating facility commenced commercial operations on April 1, 2010. In July 2010, Black Hills Power sold a 23 percent ownership interest in the Wygen III power generation facility to the City of Gillette for $62.0 million. A gain of $6.2 million was recognized on the sale.

•

On Oct. 1, 2010, Black Hills Power suspended the operations of its 62 year old, 34.5 megawatt coal-fired Osage Power Plant located in Osage, Wyo. We now have more economical power supply alternatives available to provide for present customer energy demands. The plant’s operating permits have been retained so that full operations can be restored if needed until its’ planned retirement in March 2014.


•	Our Electric Utilities reached agreement with the DOE for smart grid funding through matching grants totaling $20.7 million, made available through the American Recovery and Reinvestment Act of 2009. We have completed 100 percent of the installations related to these meters.


•	Due to the annexation of an outlying suburb by the City of Omaha, Neb., we sold assets serving approximately 3,000 customers to Metropolitan Utilities District on March 2, 2010. We received $6.1 million in cash and recognized a $2.7 million gain on the sale in 2010.


•	In December 2010, Colorado Electric received a final order from the CPUC regarding its plan to comply with the Colorado Clean Air, Clean Jobs Act. The order approved the retirement of the utility’s 40 megawatt W.N. Clark coal-fired generation facility and granted a presumption of need for replacement of the plant.

Non-Regulated Energy Group

Highlights of the Non-regulated Energy Group include the following:


•	A 200 megawatt gas-fired generation plant constructed for Black Hills Colorado IPP to serve a 20-year PPA with Colorado Electric started providing energy on Jan. 1, 2012.

Corporate

Activities of Corporate include the following:


•	We recognized a non-cash unrealized mark-to-market loss related to certain interest rate swaps of $42.0 million in 2011 compared to a $15.2 million unrealized loss on these swaps for the same period in 2010 .


•	In April 2010, we entered into a new three-year $500 million Revolving Credit Facility. The Revolving Credit Facility was used to fund working capital needs and other corporate purposes.


•	In July 2010, we completed a public offering of $200 million aggregate principal amount of senior unsecured notes due July 15, 2020. The notes were priced at par and carry an interest rate of 5.875 percent.


•	In November 2010, we entered into an equity forward offering for 4,000,000 shares. In December 2010, the underwriters exercised their over-allotment option and purchased 413,519 additional shares. We settled the equity forward instruments in November 2011.


•	In December 2010, we entered into a $100 million unsecured one-year term loan. The cost of borrowings under the loan is based on a spread of 1.375 percent over LIBOR.

•

In 2010, we recorded a $2.4 million reduction in tax expense reflecting a re-measurement of a tax position in accordance with accounting for uncertain tax positions. Approximately $2.0 million of this benefit was recorded in the Corporate segment. The re-measurement was prompted by a settlement agreement that was reached with the IRS Appeals Division primarily regarding tax depreciation method changes.

Operating Results

A discussion of operating results from our business segments follows.

Utilities Group

Electric Utilities

Operating results for the years ended Dec. 31 for the Electric Utilities were as follows (in thousands):



	2012			Variance			2011			Variance			2010
Revenue - electric	$	595,542		$	18,029		$	577,513		$	45,090		$	532,423
Revenue - Cheyenne Light gas	31,424			(5,394		)	36,818			(773		)	37,591
Total revenue	626,966			12,635			614,331			44,317			570,014

Fuel and purchased power - electric	257,042			(31,312		)	288,354			18,607			269,747
Purchased gas - Cheyenne Light	16,432			(5,566		)	21,998			(1,066		)	23,064
Total fuel and purchased power	273,474			(36,878		)	310,352			17,541			292,811

Gross margin - electric	338,500			49,341			289,159			26,483			262,676
Gross margin - Cheyenne Light gas	14,992			172			14,820			293			14,527
Total gross margin	353,492			49,513			303,979			26,776			277,203

Operations and maintenance	146,527			3,712			142,815			5,942			136,873
Gain on sale of operating asset	—			768			(768		)	5,470			(6,238		)
Depreciation and amortization	75,244			22,769			52,475			5,199			47,276
Total operating expenses	221,771			27,249			194,522			16,611			177,911

Operating income	131,721			22,264			109,457			10,165			99,292

Interest expense, net	(51,041		)	(12,065		)	(38,976		)	(1,933		)	(37,043		)
Other income, net	1,182			701			481			(2,734		)	3,215
Income tax expense	(30,264		)	(6,993		)	(23,271		)	(5,259		)	(18,012		)

Income (loss) from continuing operations	$	51,598		$	3,907		$	47,691		$	239		$	47,452



	2012	2011	2010
Regulated power plant fleet availability:
Coal-fired plants ^(a)	90.8%	91.3%	93.9%
Other plants	96.9%	96.4%	96.2%
Total availability	93.9%	93.1%	94.8%

____________________


(a)	2012 reflects a planned overhaul at Wygen II. 2011 reflects a major overhaul and an unplanned outage at the Neil Simpson II plant and the PacifiCorp-operated Wyodak plant.

2012 Compared to 2011

Gross margin increased primarily due to a $36 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric, a $3.5 million increase from the TCA, a $4.4 million increase from wholesale and transmission margins from increased pricing, a $2.1 million construction savings incentive related to the new 180 megawatt generating facility in Pueblo, Colo., a $1.6 million increase from an Environmental Improvement Cost Recovery Adjustment rider at Black Hills Power, partially offset by a decrease of $1.5 million from the expiration of a reserve capacity agreement with PacifiCorp.

Operations and maintenance increased primarily due to the costs associated with operating the new 180 megawatt generating facility in Pueblo, Colo. including increased corporate allocations, partially offset by a $2.1 million reduction of major maintenance accruals related to the power plants announced for retirement and cost reduction initiatives.

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party. The gain was eliminated in the consolidation.

Depreciation and amortization increased primarily due to a higher asset base associated with the new 180 megawatt generating facility in Pueblo, Colo., and the capital lease assets associated with the 200 megawatt generating facility providing capacity and energy from Colorado IPP.

Interest expense, net increased primarily due to debt associated with financing of the new 180 megawatt generating facility for which interest was capitalized during construction in 2011.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense) : The effective tax rate increased primarily due to a lower true up adjustment in 2012, while the prior year reflected an increased benefit for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit.

2011 Compared to 2010

Gross margin increased primarily due to a $17.1 million increase related to rate adjustments that include a return on significant capital investments, $1.3 million increase from the impact of a new Environmental Improvement Cost Recovery rider at Black Hills Power that went into effect on June 1, 2011, $3.1 million increase in retail megawatt-hours sold, $6.9 million increase for TCAs for retail and wholesale customers, and $0.3 million increase in off-system sales impacted by recognition of $0.7 million of deferred margins upon settlement of Colorado Electric’s power marketing sharing mechanism with the CPUC.

Operations and maintenance increased primarily due to higher allocation of corporate costs driven by an increased asset base in the Electric Utilities; additional costs associated with Wygen III, which commenced commercial operation on April 1, 2010, and approximately $1.1 million of deferred power marketing costs that were recognized in 2011 upon settlement of an off-system sales sharing mechanism with the CPUC, partially offset by suspension of the Osage plant.

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party. This gain was eliminated from the consolidated results of the Company. The gain on sale of operating assets in 2010 represents the sale of a 23 percent ownership interest in the Wygen III generating facility to the City of Gillette, Wyo.

Depreciation and amortization increased primarily due to a higher asset base including additional depreciation associated with Wygen III, which began commercial operation on April 1, 2010.

Interest expense, net increased due to higher borrowings related to recent capital projects, partially offset by increased AFUDC-borrowed and interest income. AFUDC-borrowed increased $5.1 million at Colorado Electric due to construction of the Pueblo Airport Generating Station, offset by a decrease in AFUDC-borrowed at Black Hills Power of $1.8 million due to the commencement of commercial operations of Wygen III.

Other income, net decreased primarily due to lower AFUDC-equity of $2.0 million, which decreased upon the placement of Wygen III into commercial operations on April 1, 2010.

Income tax expense : The effective tax rate increase in 2011 compared to 2010 reflects a $2.2 million benefit for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit resulting from a rate case settlement in 2010.

Gas Utilities

Operating results for the years ended Dec. 31 for the Gas Utilities were as follows (in thousands):



	2012			Variance			2011			Variance			2010
Natural gas - regulated	$	425,268		$	(101,704	)	$	526,972		$	6,281		$	520,691
Other - non-regulated	28,813			1,201			27,612			(2,404		)	30,016
Total revenue	454,081			(100,503		)	554,584			3,877			550,707

Natural gas - regulated	231,262			(85,995		)	317,257			711			316,546
Other - non-regulated	14,087			(617		)	14,704			(2,467		)	17,171
Total cost of sales	245,349			(86,612		)	331,961			(1,756		)	333,717

Natural gas - regulated	194,006			(15,709		)	209,715			5,570			204,145
Other non-regulated	14,726			1,818			12,908			63			12,845
Total gross margin	208,732			(13,891		)	222,623			5,633			216,990

Operations and maintenance	117,390			(4,590		)	121,980			(3,467		)	125,447
Gain on sale of operating assets	—			—			—			2,683			(2,683		)
Depreciation and amortization	25,163			856			24,307			(951		)	25,258
Total operating expenses	142,553			(3,734		)	146,287			(1,735		)	148,022

Operating income	66,179			(10,157		)	76,336			7,368			68,968

Interest expense, net	(23,981		)	1,995			(25,976		)	1,479			(27,455		)
Other expense (income), net	105			(112		)	217			170			47
Income tax expense	(14,313		)	2,095			(16,408		)	(1,959		)	(14,449		)

Income from continuing operations	$	27,990		$	(6,179	)	$	34,169		$	7,058		$	27,111

2012 Compared to 2011

Gross margin decreased primarily due to an $8.7 million impact from milder weather compared to the same period in the prior year. Heating degree days in 2012 were 14 percent lower than the prior year and 13 percent lower than normal. Also, $6.8 million of costs in 2012 were recorded as a reduction of gross margin, while these costs in 2011 had been recorded in operations and maintenance.

Operations and maintenance decreased primarily due to a reduction in bad debt expense, partially offset by increased compensation and benefits. Also, $6.8 million of costs that in 2011 had been recorded in operations and maintenance were recorded as a reduction of gross margin in 2012.

Depreciation and amortization was comparable to the prior year.

Interest expense, net decreased primarily due to lower interest rates and decrease in inter-company debt and associated expenses.

Other income (expense), net was comparable to the prior year.

Income tax benefit (expense) : The effective tax rate increased as a result of an unfavorable state tax true-up adjustment in 2012. Additionally, the 2011 period was favorably impacted as a result of federal research and development credits and a flow-through tax adjustment at Iowa Gas.

2011 Compared to 2010

Gross margin increased primarily due to an increase in rates from rate case settlements.

Operations and maintenance decreased primarily due to decreases in employee benefit costs, workers compensation insurance, lower corporate allocations and litigation-related expenses.

Gain on sale of operating assets was recognized in 2010 on assets sold to the City of Omaha, Neb. following annexation of a portion of our service territory by the city.

Depreciation and amortization decreased primarily due to certain assets that became fully depreciated during 2010, partially offset by capital expenditures during 2011.

Interest expense, net decreased primarily due to lower inter-company debt and allocation of debt service within the assigned capital structure.

Other expense (income), net was comparable to the same period in the prior year.

Income tax expense : The effective tax rate for 2011 decreased compared to the same period in the prior year primarily as a result of a true-up adjustment related to the 2010 tax filing and a flow-through tax adjustment at Iowa Gas.

Non-regulated Energy Group

Power Generation

Our Power Generation segment operating results for the years ended Dec. 31 were as follows (in thousands):



	2012			Variance			2011			Variance			2010

Revenue	$	79,389		$	47,717		$	31,672		$	1,323		$	30,349

Operations and maintenance	29,991			13,453			16,538			328			16,210
Depreciation and amortization	4,599			400			4,199			(267		)	4,466
Total operating expenses	34,590			13,853			20,737			61			20,676

Operating income	44,799			33,864			10,935			1,262			9,673

Interest expense, net	(14,757		)	(7,383		)	(7,374		)	736			(8,110		)
Other income (expense), net	7			(1,087		)	1,094			240			854
Income tax expense	(8,721		)	(7,077		)	(1,644		)	(1,378		)	(266		)

Income from continuing operations	$	21,328		$	18,317		$	3,011		$	860		$	2,151



	2012	2011	2010
Contracted fleet plant availability:
Gas-fired plants	99.4%	98.4%	99.9%
Coal-fired plants	99.6%	100.0%	98.5%
Total	99.4%	99.0%	99.1%

2012 Compared to 2011

Revenue increased due to the commencement of commercial operation of our new 200 megawatt generating facility in Pueblo, Colo., which began serving customers on Jan. 1, 2012.

Operations and maintenance increased primarily due to the costs to operate our new 200 megawatt generating facility in Pueblo, Colo., which began serving customers on Jan. 1, 2012.

Depreciation and amortization were comparable to the same period in the prior year. The new generating facility’s PPA to supply capacity and energy to Colorado Electric is accounted for as a capital lease under GAAP; as such, depreciation expense for the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net increased primarily due to interest expense associated with the financing of the Pueblo generating facility, which was capitalized during construction in 2011, partially offset by lower inter-company debt.

Other income (expense), net included a gain on sale of ownership interest in the partnership that held the Idaho generating facilities in 2011.

Income tax expense : The effective tax rate in 2012 was favorably impacted by a state tax true-up that included certain research and development tax credits.

2011 Compared to 2010

Revenue increased primarily due to higher sales from Wygen I, which incurred a forced outage and major overhaul in the prior year.

Operations and maintenance increased primarily due to higher costs associated with the Black Hills Colorado IPP as employees prepared for operations of the facilities. This was partially offset by lower operating costs associated with Wygen I which incurred a forced outage and major overhaul in the prior year.

Depreciation and amortization were comparable to the same period in the prior year.

Interest expense, net decreased primarily due to capitalized interest related to the generation construction at Black Hills Colorado IPP and increased inter-company interest income at Black Hills Wyoming.

Other (income) expenses, net was comparable to other income to same period in the prior year.

Income tax expense : The effective tax rate for 2011 increased compared to the same period in the prior year primarily due to a true-up for research and development credits in 2010.

Coal Mining

Coal Mining operating results for the years ended Dec. 31 were as follows (in thousands):



	2012			Variance			2011			Variance			2010

Revenue	$	57,778		$	(9,114	)	$	66,892		$	9,050		$	57,842

Operations and maintenance	42,553			(14,064		)	56,617			22,589			34,028
Depreciation, depletion and amortization	13,060			(5,610		)	18,670			(413		)	19,083
Total operating expenses	55,613			(19,674		)	75,287			22,176			53,111

Operating income (loss)	2,165			10,560			(8,395		)	(13,126		)	4,731

Interest income, net	930			(2,958		)	3,888			708			3,180
Other income, net	2,616			424			2,192			43			2,149
Income tax benefit (expense)	(85		)	(1,976		)	1,891			4,270			(2,379		)
Income (loss) from continuing operations	$	5,626		$	6,050		$	(424	)	$	(8,105	)	$	7,681

The following table provides certain operating statistics for the Coal Mining segment (in thousands):



	2012		2011	2010
Tons of coal sold	4,246	^(a)	5,692	5,931

Cubic yards of overburden moved	8,329		14,735	15,679

Coal reserves at year-end	232,265		256,170	261,860

____________


(a)	Decrease in tons of coal sold is due to the Dec.31, 2011 expiration of an agreement with PacifiCorp.

2012 Compared to 2011

Revenue decreased primarily due to a 25 percent decrease in tons sold as a result of the expiration of an unprofitable train load-out contract on Dec. 31, 2011, partially offset by increased tons sold to the Wyodak plant that experienced an outage in 2011. Approximately 50 percent of our current coal production is sold under contracts that include price adjustments based on actual mining cost increases.

Operations and maintenance decreased due to reduced overburden moved associated with lower sales volumes related to the expiration of an unprofitable train load-out contract on Dec. 31, 2011. Additionally, a revised mine plan resulted in fuel cost and headcount reductions.

Depreciation, depletion and amortization decreased primarily due to lower equipment usage and lower depreciation of mine reclamation asset retirement costs.

Interest income, net decreased primarily due to a decrease in inter-company notes receivable upon payment of a dividend to the parent.

Other income, net was comparable to the same period in the prior year.

Income tax benefit (expense) The low effective tax rate in 2012 was primarily due to the impact of percentage depletion and a tax return true-up, while 2011 was impacted by a favorable research and development credit.

2011 Compared to 2010

Revenue increased primarily due to a 21 percent increase in average price per ton partially offset by a 4 percent decrease in volumes sold as a result of overhauls and unplanned outages at the PacifiCorp operated Wyodak plant. The higher average sales price reflects the impact of price escalators and adjustments in certain of our sales contracts. In 2011, approximately 40 percent of our coal production was sold under contracts that include price adjustments based on actual mining costs. Most of our remaining production is sold under contracts where the sales price may escalate based on published indices. These escalators have not kept up with actual mining cost increases, reducing coal mine operating income and negatively impacting 2011 results. One of these contracts, representing 29 percent of the tons sold during 2011, was terminated at Dec. 31, 2011.

Operations and maintenance increased reflecting longer haul distances and higher overburden stripping costs in the current phase of our mining. Additionally, we experienced higher costs associated with drilling and blasting, equipment maintenance, clay parting removal, fuel, staffing levels for our train load-out facility and weather conditions. As noted above, a portion of our production is sold under contracts that have price escalators based on published indices. These escalators have not kept up with actual mining cost increases, reducing coal mine operating income and negatively impacting 2011 results. One of these contracts, representing 29 percent of the tons sold during 2011, was terminated at Dec. 31, 2011. Previous periods also include the capitalization of certain costs associated with mine infrastructure, including our in-pit conveyor system used to transport coal to mine-mouth generation facilities.

Depreciation, depletion and amortization was comparable to the same period in the prior year.

Interest income, net increased primarily due to increased lending to affiliates.

Other income, net was comparable to the same period in the prior year.

Income taxes : The effective tax rate decreased primarily due to an increased tax benefit from percentage depletion and a research and development credit.

Oil and Gas

Oil and Gas operating results for the years ended Dec. 31 were as follows (in thousands):



	2012			Variance			2011			Variance			2010

Revenue	$	79,072		$	(736	)	$	79,808		$	5,644		$	74,164

Operations and maintenance	43,267			1,887			41,380			2,081			39,299
Gain on sale of assets	(29,129		)	(29,129		)	—			—			—
Depreciation, depletion and amortization	38,494			2,804			35,690			5,407			30,283
Impairment of long-lived assets	26,868			26,868			—			—			—
Total operating expenses	79,500			2,430			77,070			7,488			69,582

Operating income (loss)	(428		)	(3,166		)	2,738			(1,844		)	4,582

Interest expense, net	(3,935		)	1,959			(5,894		)	(522		)	(5,372		)
Other income (expense), net	207			423			(216		)	(938		)	722
Income tax benefit (expense)	1,927			276			1,651			1,226			425

Income (loss) from continuing operations	$	(2,229	)	$	(508	)	$	(1,721	)	$	(2,078	)	$	357

The following tables provide certain operating statistics for the Oil and Gas segment:



Crude Oil and Natural Gas Production	2012	2011	2010
Bbls of oil sold	559,971	451,823	375,646
Mcf of natural gas sold	8,686,191	8,526,420	8,483,981
Gallons of NGL sold	3,485,514	3,674,814	3,937,584
Mcf equivalent sales	12,543,948	11,762,331	11,300,369



Average Price Received ^(a)	2012		2011		2010
Gas/Mcf	$	3.33	$	4.29	$	4.85
Oil/Bbl	$	83.27	$	79.74	$	75.59
NGL/gallon	$	0.77	$	0.96	$	0.74

__________________________


(a)	Net of hedge settlement gains/losses



	2012		2011		2010
Depletion expense/Mcfe*	$	2.87	$	2.76	$	2.36

___________

The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. The increased depletion rate in 2012 is primarily driven by the high cost of wells associated with our drilling activities in the Bakken shale formation. The depletion rate for the nine months prior to the Williston Basin sale was $3.07 per Mcfe and $1.44 per Mcfe for the remaining three months of 2012 subsequent to the sale. The reduction in the full cost pool due to the sale of our Williston Basin assets should significantly decrease the depletion per Mcfe rate in 2013. See Note 22 of Notes to the Consolidated Financial Statements included in this Annual Report filed on Form 10-K.

The following is a summary of certain annual average operating expenses per Mcfe at Dec. 31:



	2012
	LOE		Gathering Compression and Processing		Production Taxes		Total
San Juan	$	1.22	$	0.31	$	0.35	$	1.88
Piceance	0.30		0.46		0.17		0.93
Powder River	1.57		—		1.18		2.75
Williston	0.35		—		1.35		1.70
All other properties	1.91		—		0.34		2.25
Total	$	1.05	$	0.19	$	0.64	$	1.88



	2011
	LOE		Gathering Compression and Processing		Production Taxes		Total
San Juan	$	1.09	$	0.35	$	0.49	$	1.93
Piceance	0.79		0.76		0.11		1.66
Powder River	1.37		—		1.29		2.66
Williston	0.79		—		1.55		2.34
All other properties	1.06		—		0.27		1.33
Total	$	1.07	$	0.23	$	0.70	$	2.00



	2010
	LOE		Gathering Compression and Processing		Production Taxes			Total
San Juan	$	1.30	$	0.34	$	0.54		$	2.18
Piceance	0.68		0.64		(0.09		)	1.23
Powder River	1.20		—		1.02			2.22
Williston	0.92		—		1.03			1.95
All other properties	0.92		—		0.25			1.17
Total	$	1.13	$	0.22	$	0.55		$	1.90

At the East Blanco Field in the San Juan Basin in New Mexico and our Piceance Basin assets in Colorado, we own and operate gas gathering systems, including associated compression and treating facilities.

The following is a summary of our proved oil and gas reserves at Dec. 31:



	2012	2011	2010
Bbls of oil (in thousands)	4,116	6,223	5,940
MMcf of natural gas	55,985	95,904	95,456
Total MMcfe	80,683	133,242	131,096

Reserves are based on reports prepared by an independent consulting and engineering firm. The reports were prepared by CG&A. Reserves were determined using SEC-defined product prices. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The current estimate takes into account 2012 production of approximately 12.0 Bcfe, additions from extensions, discoveries and acquisitions of 5.6 Bcfe and negative revisions to previous estimates of 4.0 Bcfe, primarily due to reserve aging.

Reserves reflect SEC-defined pricing held constant for the life of the reserves, as follows:



	2012				2011				2010
	Oil		Gas		Oil		Gas		Oil		Gas
NYMEX prices	$	94.71	$	2.76	$	96.19	$	4.12	$	79.43	$	4.38
Well-head reserve prices	$	85.31	$	2.24	$	88.49	$	3.59	$	70.82	$	3.45

2012 Compared to 2011

Revenue was comparable to prior year. Crude oil volumes sold increased 24 percent along with a 4 percent increase in the average price received for crude oil sales, partially offset by a 5 percent decrease in natural gas and NGL volumes sold and a 22 percent decrease in average price received for natural gas. Crude oil production increases reflect volumes from new wells in the Bakken shale formation prior to the sale of a majority of those assets on Sept. 27, 2012.

Operations and maintenance increased primarily due to higher costs from non-operated wells and higher compensation and benefit costs.

Depreciation, depletion and amortization increased primarily due to the year-to-date impact from adjusting our expected 2012 reserves. This was caused by commodity price reserve revisions, as well as higher cost reserves associated with our remaining Bakken activities and a higher depletion rate per Mcfe on higher volumes prior to the sale of most of our Williston Basin assets.

Gain on sale of operating assets represents the gain on the sale of our Williston Basin assets . We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for gain on sale recognition unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The remainder of the sale amount not recognized as gain reduced the full-cost pool and should significantly decrease the future depreciation, depletion and amortization rate.

Impairment of long-lived assets represents a write-down in the value of our natural gas and crude oil properties driven by low natural gas prices in the second quarter of 2012. The write-down reflected a 12-month average NYMEX price of $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead, for natural gas, and $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead, for crude oil.

Interest expense, net decreased primarily due to decreased debt as a result of the sale of the Williston Basin assets along with lower interest rates.

Other income, net was comparable to the prior period.

Income tax (benefit) expense : The effective tax rate for 2011 was positively impacted by a research and development credit and the benefit generated by percentage depletion had a lesser impact on the effective tax rate in 2012.

2011 Compared to 2010

Revenue increased primarily due to a 5 percent increase in the annual average hedged price received for crude oil and a 20 percent increase in crude oil production, partially offset by a 12 percent decrease in the annual average hedged price received for natural gas. The increase in crude oil production is primarily due to production from new wells in our ongoing Bakken drilling program. Natural gas production increased slightly as production from new wells has more than offset natural production declines in existing producing properties, which followed reduced capital deployment during 2010 and 2009.

Operations and maintenance increased primarily as a result of increased production taxes from higher revenue.

Depreciation, depletion and amortization increased primarily due to a higher depletion rate per Mcfe. The increasing depletion rate is primarily driven by the high cost of wells associated with our oil drilling activities in the Bakken shale formation.

Interest expense, net increased primarily due to increased debt used to finance additional capital expenditures and higher interest rates.

Other income, net decreased primarily due to lower earnings from our equity investments.

Income tax (benefit) expense : The effective tax rate in both 2011 and 2010 includes a tax benefit related to percentage depletion. The effect of such benefit on the effective tax rate was more pronounced in 2010. Additionally, 2010 includes a $0.4 million re-measurement of a previously recorded uncertain tax position prompted by a settlement agreement with the IRS Appeals Division.

Corporate

Corporate results represent unallocated costs for administrative activities that support the business segments. Corporate also includes business development activities that do not fall under the two business groups as well as allocated costs associated with discontinued operations that could not be included in discontinued operations.

2012 Compared to 2011

Corporate results for 2012 included costs related to early retirement of debt and refinancing of debt in the amount of $7.1 million and an unrealized, non-cash mark-to-market gain on certain interest rate swaps of approximately $1.9 million compared to an unrealized, non-cash mark-to-market loss of $42.0 million on these interest rate swaps for the year ended Dec. 31, 2011 .

Costs of $0.9 million previously allocated to our Energy Marketing segment were reclassified to the Corporate segment consistent with accounting for discontinued operations for the year ended Dec. 31, 2012 compared to $3.4 million in 2011 .

2011 Compared to 2010

Corporate results for 2011 included a $42.0 million unrealized mark-to-market loss in 2011 related to certain interest rate swaps compared to a $15.2 million unrealized mark-to-market loss in 2010 on those same interest rate swaps. Additionally, Corporate results included $3.4 million of costs originally allocated to our Energy Marketing segment in 2011 which consistent with accounting for discontinued operations could not be included in discontinued operations compared to $3.5 million in 2010 .

Discontinued Operations

On Feb. 29, 2012 , we sold the outstanding stock of Enserco, our Energy Marketing segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds on Dec. 31, 2012 were approximately $165.0 million , subject to final post-closing adjustments. The proceeds represent $107.5 million received from the buyer and $57.5 million cash retained from Enserco before closing.

Income (loss) from discontinued operations was $(7.0) million and $9.4 million for the twelve months ended Dec. 31, 2012 and 2011 , respectively. Results for 2012 include an after-tax loss on sale of $2.5 million including transaction related costs, net of tax benefit of $2.5 million .

Pursuant to the provisions of the Stock Purchase Agreement, disputes regarding post-closing purchase price adjustments are subject to arbitration before a nationally-recognized accounting firm and all other disputes are subject to the indemnification procedures in the agreement. The buyer originally demanded an amount totaling $7.2 million , characterizing all claims in such demand as purchase price adjustments. We contested certain claims in the buyer's demand, including whether certain claims were properly characterized as purchase price adjustments, but reached a partial settlement and paid the buyer the sum of $1.4 million . The parties were unable to reach a negotiated agreement regarding the balance of the claims.

Critical Accounting Estimates

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

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

Goodwill

We perform our annual goodwill impairment test as of November 30 each year or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Accounting standards for testing goodwill for impairment require a two-step process be performed to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. Our reporting units have been determined to be at the operating segment level. The first step of this test, used to identify potential impairment, compares the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds fair value under the first step, then the second step of the impairment test is performed to measure the amount of any impairment loss.

Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industries. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans with long range cash flows estimated using a terminal value calculation and adjusted as appropriate for our view of market participant assumptions, 2) estimates of long-term growth rates for our businesses, 3) the determination of an appropriate weighted-average cost of capital or discount rate, and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries.

We have $353.4 million in goodwill as of Dec. 31, 2012. The results of our Nov. 30, 2012 annual impairment test indicated that our goodwill was not impaired, as the estimated fair value of all reporting units exceeded their carrying value.

Although an impairment did not exist as of Nov. 30, 2012, we determined that one reporting unit, Colorado Electric with goodwill of $245.6 million, had an estimated fair value that exceeded its carrying value by only 15 percent, which we do not consider a substantial excess. The result of our valuation analysis estimates Colorado Electric's fair value at $825.6 million, compared to a carrying value of $717.9 million as of Nov. 30, 2012. The result of the income approach was sensitive to the 2.0 percent long-term cash flow growth rate applicable to periods beyond our internal five-year business plan financial forecast and the 5.66 percent weighted-average cost of capital assumptions. As an illustration of this sensitivity, an increase of 0.25 percent in the cost of capital combined with a growth rate reduction of 0.25 percent would result in an estimated fair value in excess of carrying value of $33 million or 5 percent as of Nov. 30, 2012.

Full Cost Method of Accounting for Oil and Gas Activities

Accounting for oil and gas activities is subject to special, unique rules. Two generally accepted methods of accounting for oil and gas activities are available - successful efforts and full cost. We account for our oil and gas activities under the full cost method whereby all productive and nonproductive costs related to acquisition, exploration, development, abandonment and reclamation activities are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized. Net capitalized costs are subject to a ceiling test that limits such costs to the aggregate of the present value of future net revenues of proved reserves and the lower of cost or fair value of unproved properties. This method values the reserves based upon SEC-defined prices for oil and gas as of the end of each reporting period adjusted for contracted price changes. The prices, as well as costs and development capital, are assumed to remain constant for the remaining life of the properties. If the net capitalized costs exceed the full-cost ceiling, then a permanent non-cash write-down is required to be charged to earnings in that reporting period. Under these SEC-defined product prices, our net capitalized costs were more than the full cost ceiling at June 30, 2012, which required a write-down of $17.3 million after-tax. Under the SEC-defined product prices at Dec. 31, 2012 , no additional write-down was required. Reserves in 2012 and 2011 were determined consistent with SEC requirements using a 12-month average price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Because of the fluctuations in natural gas and oil prices, we can provide no assurance that future write-downs will not occur.

As noted, we utilize the full-cost method of accounting for our oil and gas activities in accordance with SEC Rule 4-10 of Regulation S-X (Rule 4-10). Under the full-cost method, sales of oil and gas properties generally are recorded as an adjustment to capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between the capitalized costs and proved oil and gas reserves. The Company’s sale of oil and gas properties in the Williston Basin of North Dakota was significant as defined by Rule 4-10 and, accordingly, an $18.9 million after-tax gain on sale was recorded. Total net cash proceeds from the sale were approximately $227.9 million.

Under the guidance of Rule 4-10, if a gain or loss is recognized on such a sale, total capitalized costs shall be allocated between the reserves sold and the reserves retained on the same basis used to compute amortization, unless there are substantial economic differences between the properties sold and those retained, in which case capitalized costs shall be allocated on the basis of the relative fair value of the properties in the cost center. Because of the substantial differences between the crude oil properties we sold and those properties retained, which were predominantly natural gas, we allocated based on relative fair values.

If a different method of allocating the capitalized costs was chosen, the gain recorded on our transaction could vary substantially. For example, if the allocation was made on the same basis used to compute amortization as noted within Rule 4-10 and we utilized the ratio of proven reserve quantities from the properties sold compared to total proven reserve quantities in our cost center, we would have recorded a gain on sale of approximately $160 million. Because of the value associated with the undeveloped acreage sold, we did not believe this was an appropriate methodology for allocation.

Any change in the gain recorded would impact the amount of adjustment to our capitalized costs therefore impacting future depletion expense recorded within our financial statements.

Oil and Natural Gas Reserve Estimates

Estimates of our proved oil and natural gas reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. An independent petroleum engineering company prepares reports that estimate our proved oil and natural gas reserves annually. The accuracy of any oil and natural gas reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and work over costs, all of which may in fact vary considerably from actual results. In addition, as oil and gas prices and cost levels change from year to year, the estimate of proved reserves may also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.

Despite the inherent imprecision in estimating our oil and natural gas reserves, the estimates are used throughout our financial statements. For example, since we use the unit-of-production method of calculating depletion expense, the amortization rate of our capitalized oil and gas properties incorporates the estimated unit-of-production attributable to the estimates of proved reserves. The net book value of our oil and gas properties is also subject to a “ceiling” limitation based in large part on the value of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

Risk Management Activities

In addition to the information provided below, see Note 3 , “ Risk Management Activities ” and Note 4 , “ Fair Value Measurement ,” of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Derivatives

Accounting standards for derivatives require the recognition of all derivative instruments as either assets or liabilities on the balance sheet and their measurement at fair value. Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or fair values. The effective portion of changes in fair values of derivatives designated as cash flow hedges is recorded as a component of other comprehensive income (loss) until it is reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of derivatives designated as cash flow hedges is recorded in current earnings. Changes in fair value of derivatives designated as fair value hedges are recognized in current earnings along with fair value changes of the underlying hedged item.

We currently use derivative instruments, including options, swaps, futures, forwards and other contractual commitments for non-trading (hedging) purposes. Our typical hedging transactions relate to contracts we enter into to fix the price received for anticipated future production at our Oil and Gas segment, or to fulfill the natural gas hedging plans for gas and electric utilities (see below), and for interest rate swaps we enter into to convert a portion of our variable rate debt, or associated variable rate interest payments, to a fixed rate.

Fair values of derivative instruments contracts are based on actively quoted market prices or other external source pricing information, where possible. If external market prices are not available, fair value is determined based on other relevant factors and pricing models that consider current market and contractual prices for the underlying financial instruments or commodities, as well as time value and yield curve or volatility factors underlying the positions.

Pricing models and their underlying assumptions impact the amount and timing of unrealized gains and losses recorded, and the use of different pricing models or assumptions could produce different financial results.

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations. We have interest rate swaps with a notional amount of $250 million that are not designated as hedge instruments. Accordingly, mark-to-market changes in value on the swaps are recorded within the income statement. A one basis point move in the interest rate curves over the term of the swaps would have a pre-tax impact of approximately $0.4 million . These swaps have remaining terms of 6 and 16 years and have early termination dates ranging from Dec. 15, 2013 to Dec. 31, 2013 , respectively.

Counterparty Credit Risk and Allowance for Doubtful Accounts

As of Dec. 31, 2012 , our credit exposure included a $7.6 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and by imposing collateral requirements under certain circumstances, including the use of master netting agreements.

We continuously monitor collections and payments from our customers and establish an allowance for doubtful accounts based upon our historical experience and any specific customer collection issue that we have identified. The allowances provided are estimated and may be impacted by economic, market and regulatory conditions, which could have an effect on future allowance requirements and significantly impact future results of operations. While most credit losses have historically been within our expectations and established provisions, we can provide no assurance that our actual credit losses will be consistent with our estimates.

Pension and Other Postretirement Benefits

As described in Note 18 to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have two defined benefit pension plans, three defined post-retirement healthcare plans and several non-qualified retirement plans. Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; rate of future increases in compensation levels; and healthcare cost projections. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

The pension benefit cost for 2013 for our non-contributory funded pension plan is expected to be $15.4 million compared to $13.9 million in 2012. The estimated discount rate used to determine annual benefit cost accruals will be 4.30 percent in 2013; the discount rate used in 2012 was 4.65 percent. In selecting the discount rate, we consider cash flow durations for each plan’s liabilities and returns on high credit quality fixed income yield curves for comparable durations.

We do not pre-fund our non-qualified pension plans. One of the three postretirement benefit plans is partially funded. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our three Retiree Healthcare Plans (in thousands):



Change in Assumed Trend Rate	Impact on December 31, 2012 Accumulated Postretirement Benefit Obligation			Impact on 2012 Service and Interest Cost
Increase 1%	$	2,082		$	127
Decrease 1%	$	(1,771	)	$	(107	)

Contingencies

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

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each tax paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

We use the liability method of accounting for income taxes. Under this method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities.

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. With respect to changes in tax law, we do not expect that the recently enacted American Taxpayer Relief Act of 2012 will have a material impact on the amounts provided for income taxes including our ability to realize deferred tax assets. Since the date of enactment was Jan. 2, 2013, the ATRA could not be considered when determining deferred tax liabilities and assets as of Dec. 31, 2012, which resulted in the reclassification of a sizable amount of Federal and state deferred tax assets related to net operating loss carryforwards from non-current to current. However, certain provisions of the ATRA, primarily the extension of 50 percent bonus depreciation, are currently expected to result in minimal utilization of such carryforwards in 2013. See Note 14 in our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

Liquidity and Capital Resources

OVERVIEW

BHC and its subsidiaries require cash to support and grow our business. Our predominant source of cash is supplied by our operations and supplemented with corporate borrowings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate.

The most significant items impacting cash are our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, as well as the payment of dividends to our shareholders. We could experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices.

We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.

The following table provides an informational summary of our financial position as of Dec. 31 (dollars in thousands):



Financial Position Summary	2012			2011
Cash and cash equivalents	$	15,462		$	21,628
Restricted cash and equivalents	$	7,916		$	9,254
Short-term debt, including current maturities of long-term debt	$	380,973		$	347,473
Long-term debt	$	938,877		$	1,280,409
Stockholders’ equity	$	1,232,509		$	1,209,336

Ratios
Long-term debt ratio	43.2		%	51.4		%
Total debt ratio	51.7		%	57.4		%

The proceeds from the sale of Enserco and the sale of a majority of our Williston Basin assets were used to pay down debt, improving our credit profile.

Significant Factors Affecting Liquidity

Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including seasonality, commodity prices, significant capital projects, requirements imposed by state and federal agencies, and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow; however, the potential for unforeseen events affecting cash needs will continue to exist.

Weather Seasonality, Commodity Pricing and Associated Hedging Strategies

We manage liquidity needs through hedging activities, primarily in connection with seasonal needs of our utility operations (including seasonal peaks in fuel requirements), interest rate movements, and commodity price movements.

Utility Factors

Our cash flows and in turn liquidity needs in many of our regulated jurisdictions can be subject to fluctuations in weather and commodity prices. Since weather conditions are uncontrollable, we have implemented commission-approved natural gas hedging programs in many of our regulated jurisdictions to mitigate significant changes in natural gas commodity pricing. We target hedging approximately 50 to 70 percent of our natural gas supply using options, futures and basis swaps.

Oil and Gas Factors

Our cash flows in our Oil and Gas segment can be subject to fluctuations in commodity prices. Significant changes in crude oil or natural gas commodity prices can have a significant impact on liquidity needs. Since commodity prices are uncontrollable, we have implemented a hedging program to mitigate the effects of significant changes in crude oil and natural gas commodity pricing on existing production. New production is subject to market prices until the production can be quantified and hedged. We target to hedge approximately 70 percent to 100 percent of our existing natural gas and crude oil production using options, futures and basis swaps for the next two years. See Market Risk Disclosures for hedge details.

Interest Rates

Several of our debt instruments have a variable interest rate component which can change dramatically depending on the economic climate. We deploy hedging strategies that include floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations. At Dec. 31, 2012 , 96.5 percent of our interest rate exposure has been mitigated through either fixed or hedged interest rates.

We have interest rate swaps with a notional amount of $250 million that are not designated as hedge instruments. Accordingly, mark-to-market changes in value on these swaps are recorded within the income statements. We recorded a $1.9 million non-cash pre-tax unrealized mark-to-market gain and $42.0 million non-cash pre-tax unrealized mark-to-market loss on these swaps for the years ended Dec. 31, 2012 and Dec. 31, 2011 , respectively. The mark-to-market value on these swaps was a liability of $88.1 million , net of cash collateral, at Dec. 31, 2012 . Subsequent mark-to-market adjustments could have a significant impact on our results of operations. A one basis point move in the interest rate curve over the term of the swaps would have a pre-tax impact of approximately $0.3 million. These swaps are for terms of 6 and 16 years and have early termination dates ranging from Dec. 15, 2013 to Dec. 31, 2013 , respectively. We anticipate extending these agreements upon their early termination dates and have continued to maintain these swaps in anticipation of our upcoming financing needs. Alternatively, we may choose to cash settle these swaps at fair value prior to the early termination dates, or unless these dates are extended, we will cash settle these swaps for an amount equal to their fair value on the termination dates.

In addition, we have $150 million notional amount floating-to-fixed interest rate swaps with a maximum remaining term of 4 years. These swaps have been designated as cash flow hedges, and accordingly their mark-to-market adjustments are recorded in accumulated other comprehensive income (loss) on the accompanying Consolidated Balance Sheets. The mark-to-market value of these swaps was a liability of $24 million at Dec. 31, 2012 .

Federal and State Regulations

Federal

We are structured as a utility holding company which owns several regulated utilities. Within this structure, we are subject to various regulations by our commissions that can influence our liquidity. As an example, the issuance of debt by our regulated subsidiaries and the use of our utility assets as collateral generally require the prior approval of the state regulators in the state in which the utility assets are located. Furthermore, as a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

Income Tax

The Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of 2010, enacted into law on Dec. 17, 2010, included provisions allowing for the acceleration of depreciation of certain property for tax purposes. These provisions resulted in approximately $320 million of tax benefits for BHC as indicated in the table below. The tax benefits contributed to the generation of a tax loss carryforward that we believe will defer payment of cash taxes until approximately 2016.



(in millions)	2012		2011		2010
Tax benefit	$	56	$	218	$	46

The ATRA, enacted into law on Jan. 2, 2013, extended 50 percent bonus depreciation generally to qualifying property placed in service during 2013. It is anticipated that the extension of bonus depreciation by the ATRA will result in approximately $65 million of additional tax benefits to BHC. The additional depreciation deductions will serve to reduce taxable income and extend the tax loss carryforwards as indicated above from being fully utilized in 2016 to being fully utilized in 2017 based on current projections. The cash generated by bonus depreciation is an acceleration of tax benefits that we would have otherwise received over 15 to 20 years. Additionally, from a regulatory perspective, while the capital additions at the Company's regulated businesses generally increase future revenue requirements, the bonus depreciation associated with these capital additions will partially mitigate future rate increases related to capital additions.

See additional information in Note 14 of Notes to the Consolidated Financial Statements filed in this Annual Report on Form 10-K.

CASH GENERATION AND CASH REQUIRMENTS

Cash Generation

Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring Feb. 1, 2017 and our ability to access the public and private capital markets through debt and securities offerings when necessary.

Restricted Cash

Although we have the ability to access cash when necessary, some of our subsidiaries have contractual agreements with covenants that restrict the use of cash. As provisions under these agreements are met, cash is no longer restricted and becomes available for its intended purposes. Our restricted cash positions as of Dec. 31, 2012 totaled $7.9 million .

Cash Collateral

Under contractual agreements and exchange requirements, BHC or its subsidiaries have collateral requirements, which if triggered, require us to post cash collateral positions with the counterparty to meet these obligations.

We have posted the following amounts of cash collateral with counterparties at Dec. 31 (in thousands):



Purpose of Cash Collateral	2012		2011
Natural Gas Futures and Basis Swaps Pursuant to Utility Commission Approved Hedging Programs	$	12,930	$	19,416
Oil and Gas Derivatives	3,193		—
Interest Rate Swaps Derivatives Not Designated as Hedges	5,960		—
Total Cash Collateral Positions	$	22,083	$	19,416

CASH FLOW ACTIVITIES

The following table summarizes our cash flows (in thousands):



	2012			2011			2010
Cash provided by (used in)
Operating activities	$	316,971		$	223,704		$	147,752
Investing activities	$	11,169		$	(447,007	)	$	(389,168	)
Financing activities	$	(371,446	)	$	249,633		$	160,953

2012 Compared to 2011

Operating Activities:

Net cash provided by operating activities was $93.3 million higher than in 2011 primarily attributable to:


•	Cash earnings (income from continuing operations plus non-cash adjustments) were $46.8 million higher than prior year;


•	Net inflows from operating assets and liabilities of continuing operations of $42.2 million higher than prior year. The increase primarily related to decreased gas volumes in inventory, the decrease in accounts payable of approximately $9.0 million due to the expiration of Colorado Electric’s contract with PSCo at Dec. 31, 2011, and other normal working capital changes;


•	A $25.4 million contribution in 2012 to our defined benefit plans compared to $11.1 million in 2011 ; and


•	A 14.2 million increase in net cash inflows from discontinued operations in 2012 compared to 2011.

Investing Activities:

Net cash provided by investing activities was $11.2 million in 2012 compared to net cash used in investing activities of $447.0 million in 2011 for a net inflow of $458.2 million . The change was driven by:


•	Cash proceeds from assets sold during 2012, including $227.9 million from the sale of approximately 85 percent of our Williston Basin assets by our Oil and Gas segment, $25 million from the sale of a 50 percent ownership interest in the Busch Ranch Wind project, and $107.5 million from the sale of Enserco; and


•	In 2012, we had lower capital expenditures of $91.6 million primarily due to the completion of construction of our

Pueblo generation facility.

Financing Activities:

Cash used in financing activities was $371.4 million in 2012 , which was an increase in outflow of $621.1 million from 2011 primarily attributable to:

•

During 2012 , approximately $110 million of the proceeds from the sale of Enserco were used to pay down short-term borrowings on the Revolving Credit Facility. Additional borrowings on the Revolving Credit Facility were primarily used for our working capital needs, while in 2011 we increased short-term borrowings by approximately $196.0 million primarily due to our continued construction in Colorado;


•	In 2012 , we repaid our $225.0 million senior unsecured 6.5 percent bonds with proceeds from the sale of Williston Basin assets and Black Hills Power repaid its $6.5 million Pollution Control Revenue Bonds;


•	Cash dividends on common stock of $65.3 million were paid in 2012 compared to $59.2 million paid in 2011 ; and


•	In 2011 we issued common stock for proceeds of $123.0 million primarily from an equity forward transaction.

2011 Compared to 2010

Operating Activities:

Cash provided by operating activities was $223.7 million , $76.0 million more than in 2010 . In addition to normal working capital changes, our operating cash flow increase was primarily attributable to:


•	Cash earnings (income from continuing operations plus non-cash adjustments) were $31.2 million higher than prior year;


•	An $11.1 million contribution in 2011 to our defined benefit plans compared to $30.0 million in 2010 ;


•	Increased inflows from operating assets and liabilities of continuing operations of $20.1 million primarily as a result of:


•	Increased cash outflows for materials, supplies and fuel primarily including purchases of natural gas at our Gas Utilities and purchases of additional supplies for generation built to support Colorado Electric customers;


•	Increased cash inflows primarily due to adjustments to our GCA at our Gas Utilities in regulatory assets and regulatory liabilities combined with inflows from energy efficiency rebates; and


•	Cash inflows from accounts receivable and other current assets primarily the result of a settlement reached with the IRS.


•	A 15.8 million increase in net cash inflows from discontinued operations in 2011 compared to 2010.

Investing Activities:

Cash used in investing activities was $447.0 million in 2011 , which was $57.8 million more than in 2010 . Capital additions were $440.7 million in 2011 compared to $472.3 million in 2010 . The cash outflows for property, plant and equipment additions reflect significant additions during 2011 and 2010 for completion of construction of 180 megawatts of natural gas-fired electric generation at Colorado Electric and of 200 megawatts of natural gas-fired electric generation at Black Hills Colorado IPP, new transmission at the Electric Utilities and oil and gas property maintenance capital and development drilling. The 2010 outflows were partially offset by cash proceeds of $62.0 million for the sale of a portion of Wygen III to the City of Gillette and $6.1 million for the sale of operating assets in Nebraska to the City of Omaha.

Financing Activities:

Cash provided by financing activities was $249.6 million in 2011 , which was an increase of $88.7 million from 2010 . During 2011 , we issued additional common stock for $123.0 million primarily from an equity forward transaction, paid $59.2 million in cash dividends on common stock, increased short-term borrowings by approximately $196.0 million primarily due to our continued construction in Colorado and repaid $8.4 million primarily for Black Hills Wyoming project financing debt. In 2010, we issued $200 million unsecured notes, increased short-term borrowings by approximately $84.5 million and repaid $59.9 million primarily for Black Hills Power bonds and Black Hills Wyoming project debt.

CAPITAL EXPENDITURES

Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next three years.

Historically, a significant portion of our capital expenditures relate primarily to assets that may be included in utility rate base, and if considered prudent by regulators, can be recovered from our utility customers. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate and are subject to rate agreements. Our Electric Utilities’ capital expenditures consist of building Cheyenne Prairie, improvements to generating stations, transmission and distribution lines. Capital expenditures associated with our Gas Utilities are primarily to improve the existing gas distribution network. In addition to our utility capital expenditures, we allocate a portion of our capital budget to Non-regulated operations with specific focus on our oil and gas drilling program. We believe that cash generated from operations and borrowing on our existing Revolving Credit Facility will be adequate to fund ongoing capital expenditures, including approximately $222 million to build Cheyenne Prairie. We would ultimately expect to finance this new generation with long-term bonds.

Historical Capital Requirements

Our primary capital requirements for the three years ended Dec. 31 were as follows (in thousands):



	2012		2011		2010
Property additions ^(a) :
Utilities -
Electric Utilities ^(b)	$	167,263	$	173,078	$	232,466
Gas Utilities	45,711		43,954		51,363
Non-regulated Energy -
Power Generation ^(c)	5,547		98,927		148,191
Coal Mining	13,420		10,438		17,053
Oil and Gas ^(d)	107,839		89,672		40,345
Corporate	7,376		13,279		7,182
Capital expenditures for continuing operations	347,156		429,348		496,600
Discontinued operations investing activities	824		2,359		390
Total expenditures for property, plant and equipment	347,980		431,707		496,990
Common stock dividends	65,262		59,202		56,467
Maturities/redemptions of long-term debt	240,077		8,382		59,926
Discontinued operations financing activities	—		158		2,037
	$	653,319	$	499,449	$	615,420

____________________________


(a)	Includes accruals for property, plant and equipment.

(b)

Includes (1) $25.4 million in 2012 for orders placed relating to Cheyenne Prairie which will commence construction in the spring of 2013 and $25.0 million for construction of our 50 percent ownership in the Busch Ranch Wind Project; (2) $65.8 million and $116.3 million in 2011 and 2010, respectively for construction of the 180 megawatt natural gas-fired generation facility at Colorado Electric, excluding transmission; (3) $31.9 million, $23.1 million and $28.0 million in new transmission projects in 2012, 2011 and 2010, respectively; and (4) $13.1 million for Wygen III construction in 2010. During 2010, we received reimbursement of $59.1 million from the joint owners of the Wygen III facility. We retained ownership of 52 percent of the Wygen III coal-fired plant that went into service in 2010.


(c)	Includes $98.2 million and $146.2 million in 2011 and 2010, respectively, for construction of the 200 megawatt natural gas-fired power generation facility at Black Hills Colorado IPP.


(d)	Approximately $37.9 million and $26.2 of the capital expenditures in 2012 and 2011, respectively, were for our drilling program in the Bakken shale formation. A majority of those assets were sold Sept. 27, 2012.

Forecasted Capital Requirements

Our primary capital requirements for the three years ended Dec. 31 are expected to be as follows (in thousands):



	2013		2014		2015
Utilities:
Electric Utilities ⁽¹⁾	$	284,200	$	230,500	$	127,600
Gas Utilities	59,800		58,000		43,000
Non-regulated Energy:
Power Generation	3,200		4,800		2,400
Coal Mining	7,100		6,000		5,100
Oil and Gas	98,300		84,300		109,100
Corporate	7,500		6,500		5,700
	$	460,100	$	390,100	$	292,900

_____________________


(1)	Capital expenditures for our Electric Utilities include expenditures associated with building Cheyenne Prairie of $139.3 million and $57.7 million in 2013 and 2014, respectively.

We continue to evaluate potential future acquisitions and other growth opportunities which are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimates identified above.

DEBT

Operating Activities

Our principal sources to meet day-to-day operating cash requirements are cash from operations and our corporate Revolving Credit Facility.

Revolving Credit Facility

We have a $500 million revolving corporate credit facility which matures on Feb. 1, 2017 that has an accordion feature which allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million . Borrowings are available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings under the agreement are determined based upon our credit ratings. At our current credit rating of BBB- , the margins for base rate borrowings, Eurodollar borrowings and letters of credit are 0.5 percent , 1.5 percent and 1.5 percent , respectively. A commitment fee is charged on the unused amount of the Revolving Credit Facility which is 0.25 percent based on current credit ratings.

Our Revolving Credit Facility at Dec. 31, 2012 had the following borrowings, outstanding letters of credit and available capacity (in millions):



		Current		Borrowings at		Letters of Credit at		Available Capacity at
Credit Facility	Expiration	Capacity		Dec. 31, 2012		Dec. 31, 2012		Dec. 31, 2012
Revolving Credit Facility	February 1, 2017	$	500.0	$	127.0	$	36.3	$	336.6

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions, and maintaining a recourse leverage ratio not to exceed 0.65 to 1.00. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. Under the Revolving Credit Facility, our recourse leverage ratio is the ratio of our recourse debt, letters of credit and guarantees issued over our total capital which includes the balance in the numerator plus our net worth. We were in compliance with these covenants as of Dec. 31, 2012 .

The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.

Utility Money Pool

As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utility subsidiaries and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates ( 1.7 percent at Dec. 31, 2012 ). While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.

At Dec. 31, money pool balances included (in thousands):



	Borrowings From (Loans To) Money Pool Outstanding
Subsidiary	2012			2011
Black Hills Utility Holdings	$	27,852		$	273,063
Black Hills Power	(31,645		)	(50,477		)
Cheyenne Light	5,277			(15,208		)
Total Money Pool borrowings from Parent	$	1,484		$	207,378

Capital Resources

Our principal sources for our long-term capital needs have been issuances of long-term debt securities by the Company and its subsidiaries along with proceeds obtained from public and private offerings of equity.

Black Hills Power Pollution Control Bonds

In May 2012, Black Hills Power’s 4.8 percent Pollution Control Revenue Bonds were paid in full for $6.5 million principal and interest.

Corporate Term Loans

In June 2012, we extended a one-year $150 million unsecured, single draw, term loan (the “Term Loan”) with CoBank, the Bank of Nova Scotia and U.S. Bank to mature on June 24, 2013 . The cost of borrowing under the Term Loan is based on a spread of 1.10 percent , over LIBOR ( 1.35 percent at Dec. 31, 2012 ). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional minimum net worth requirement. We were in compliance with these covenants as of Dec. 31, 2012 .

We have a $100 million two-year term loan (the “Loan”) with J.P Morgan and Union Bank that matures on Sept. 30, 2013 . The cost of the borrowings under the Loan is based on a spread of 1.375 percent over LIBOR ( 1.63 percent at Dec. 31, 2012 ). Borrowings under the Loan may be prepaid without penalty. The proceeds were used to reduce borrowings on the Revolving Credit Facility. The covenants are substantially the same as under the Revolving Credit Facility. We were in compliance with these covenants as of December 31, 2012 .

$225 Million Senior Unsecured Bonds

On Oct 31, 2012 , we redeemed our $225 million senior unsecured 6.50 percent notes, which were originally scheduled to mature on May 15, 2013 . The total payment was $238.8 million , including accrued interest and a make-whole provision payment of $7.1 million pre-tax.

$250 Million Senior Unsecured Bonds

On May 15, 2014 , our 9 percent , $250 million of senior unsecured bonds mature.

100

Future Financing Plans

During the next three years, BHC plans to consider completing the following financing activities to take advantage of the low interest rate environment:


•	Extend the $150 million and $100 million term loans;


•	Analyze the early refinancing of our $250 million, 9 percent senior unsecured bonds that mature in May 2014; and/or


•	Review long-term financing options for the estimated $222 million Cheyenne Prairie capital project.

Cross-Default Provisions

Our Revolving Credit Facility and two corporate term loans contain cross-default provisions that would result in a default if BHC or its subsidiaries failed to make timely payments of debt obligations or triggered other default provisions under any debt agreement totaling in the aggregate principal amount of $35 million or more that permits the acceleration of debt maturities or mandatory debt prepayment.

The Revolving Credit Facility prohibits us from paying cash dividends if we are in a default or if paying dividends would cause us to be in default.

Equity

Our current three-year outlook does not anticipate the need to access the equity markets unless future acquisitions are announced.

Shelf Registration

We have an effective automatic shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of Dec. 31, 2012 , we had approximately 44 million shares of common stock outstanding and no shares of preferred stock outstanding.

Common Stock Dividends

Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors which will be evaluated and approved by our Board of Directors.

In January 2013, our Board of Directors declared a quarterly dividend of $0.38 per share or an annualized equivalent dividend rate of $1.52 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share.



	2012	2011	2010
Dividend Payout Ratio	80%	118%	82%
Dividends Per Share	$1.48	$1.46	$1.44

Our three-year annualized dividend growth rate was 1.4 percent , and all dividends were paid out of available operating cash flows.

101

Dividend Restrictions

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. For example, the issuance of debt by our utility subsidiaries (including the ability of Black Hills Utility Holdings to issue debt) and the use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. As a result of our holding company structure, our right as a common shareholder, to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization, is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders.

Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not meet certain financial covenants. The most restrictive financial covenants of our Revolving Credit Facility include the following: a recourse leverage ratio not to exceed .65 to 1.00 and a minimum consolidated net worth of $625 million plus 50 percent of aggregate consolidated net income since January 1, 2005. As of Dec. 31, 2012 , we were in compliance with these covenants.

Covenants within Cheyenne Light's financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than .60 to 1.00. Our utilities in Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which they 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 percent of their total capitalization; and 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. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As of December 31, 2012 , the restricted net assets at our Electric and Gas Utilities were approximately $263.1 million .

As required by a covenant of the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings, the parent of Black Hills Electric Generation which is the parent of Black Hills Wyoming, has restricted shareholders’ equity of at least $100 million . In addition, Black Hills Wyoming holds $7.9 million of restricted cash associated with the project financing requirements.

CREDIT RATINGS AND COUNTERPARTIES

Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short and long-term financing. The inability to raise capital on favorable terms could negatively affect the Company's ability to maintain or expand its businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the company's credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

The following table represents the credit ratings, outlook and risk profile of Black Hills Corporation's Senior Unsecured Debt at Dec. 31, 2012 :



Rating Agency	Rating	Outlook		Risk Profile
S&P	BBB-	Positive	^(a)	Excellent	^(b)
Moody's	Baa3	Positive	^(a)	Excellent
Fitch	BBB-	Stable		Strong

____________________________


(a)	In October 2012, both Moody's and S&P upgraded our outlook from Stable to Positive.


(b)	In July 2012, S&P published its updated credit review, leaving our senior unsecured credit rating of BBB- and upgraded our risk profile from strong to excellent.

102

Our fees and interest payments under various corporate debt agreements are based on the lowest credit rating of S&P or Moody's. If either S&P or Moody's downgraded our senior unsecured debt, we would be required to pay additional fees and incur higher interest rates under current bank credit agreements.

We have an interest rate swap with a notional amount of $50 million , which has collateral requirements based upon our corporate credit ratings. At our current credit ratings, we are required to post collateral for any amount by which the swap's negative mark-to-market fair value exceeds $20 million . If our senior unsecured credit rating drops to BB+ or below by S&P or Ba1 or below by Moody's, we would be required to post collateral for the entire amount of the swap's negative mark-to-market fair value. We had $6.0 million cash collateral posted at Dec. 31, 2012 .

The following table represents the credit ratings of Black Hills Power's First Mortgage Bonds at Dec. 31, 2012 :



Rating Agency	Rating
S&P	BBB+
Moody's	A3
Fitch	A-

We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings or other trigger events. If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.

103

CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS

Contractual Obligations

In addition to our capital expenditure programs, we have contractual obligations and other commitments that will need to be funded in the future. The following information summarizes our cash obligations and commercial commitments at December 31, 2012 . Actual future costs of estimated obligations may differ materially from these amounts (in thousands).



	Payments Due by Period
Contractual Obligations	Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
Long-term debt ^(a)(b)	$	1,042,961	$	103,973	$	262,986	$	78,947	$	597,055
Unconditional purchase obligations ^(c)	811,570		187,301		315,703		149,518		159,048
Operating lease obligations ^(d)	12,756		2,690		5,986		2,505		1,575
Other long-term obligations ^(e)	50,548		—		—		—		50,548
Employee benefit plans ^(f)	235,415		26,256		59,458		45,301		104,400
Liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions ^(g)	40,683		—		13,717		3,278		23,688
Notes payable	277,000		277,000		—		—		—
Total contractual cash obligations ^(h)	$	2,470,933	$	597,220	$	657,850	$	279,549	$	936,314


(a)	Long-term debt amounts do not include discounts or premiums on debt.

(b)

The following amounts are estimated for interest payments on long-term debt over the next five years based on a mid-year retirement date for those debt tranches expiring during the identified period: $62.9 million in 2013, $50.7 million in 2014, $39.2 million in 2015, $37.7 million in 2016, and $36.3 million in 2017. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2012 .

(c)

Unconditional purchase obligations include the energy and capacity costs associated with our PPAs, capacity and certain transmission, gas purchases, gas transportation and storage agreements, and gathering commitments for our Oil and Gas segment. The energy charge under the PPAs and the commodity price under the gas purchase contracts are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2012 and price assumptions using existing prices at December 31, 2012 . Our transmission obligations are based on filed tariffs as of December 31, 2012 . A portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure are carried out for 60 days. The gathering commitments for our Oil and Gas segment are described in Part I, Delivery Commitments, of this Annual Report filed on Form 10-K.


(d)	Includes operating leases associated with several office buildings, warehouses and call centers, equipment and vehicles.


(e)	Includes estimated asset retirement obligations associated with our Electric Utilities, Gas Utilities, Coal Mining and Oil and Gas segments as discussed in Note 10 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.


(f)	Represents estimated employer contributions to employee benefit plans through the year 2022.


(g)	Years 1-3 include an estimated reversal of approximately $8.2 million associated with the gain deferred from the tax treatment related to the IPP Transaction and the Aquila Transaction.

(h)

Amounts in the table exclude: (1) any obligation that may arise from our derivatives, including interest rate swaps and commodity related contracts that have a negative fair value at December 31, 2012 . These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments. (2) A portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table. (3) The obligations presented above do not include inter-company transactions and obligations negotiated for the construction of Cheyenne Prairie. This 132 megawatt generating facilities is expected to cost $222 million for which we have secured approximately 14 percent of the procurement contracts as of December 31, 2012 .

Off-Balance Sheet Commitments

Guarantees

We have entered into various off-balance sheet commitments in the form of guarantees and letters of credit. We provide various guarantees supporting certain of our subsidiaries under specified agreements or transactions. At December 31, 2012 , we had outstanding guarantees as indicated in the table below. Of the $175.3 million , $120.8 million was related to performance obligations under subsidiary contracts and $54.5 million was related to indemnification for reclamation and surety bonds of subsidiaries. For more information on these guarantees, see Note 20 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

104

We had the following guarantees in place (in thousands):



	Outstanding at		Year
Nature of Guarantee	December 31, 2012		Expiring
Guarantees for payment of obligations arising from commodity-related physical and financial transactions by Black Hills Utility Holdings	$	70,000	Ongoing
Guarantee for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric	33,264		2013
Indemnification for subsidiary reclamation/surety bonds	54,509		Ongoing
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Colorado Gas	10,000		2013
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply	7,500		2013
	$	175,273

Letters of Credit

Letters of credit reduce the borrowing capacity available on our corporate Revolving Credit Facility. We had $36.3 million in letters of credit issued under our Revolving Credit Facility in place at December 31, 2012 .

Market Risk Disclosures

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures.

Market risk is the potential loss that may occur as a result of an adverse change in market price or rate. We are exposed to the following market risks, including, but not limited to:


•	Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Electric Utilities and Gas Utilities segments resulting from commodity price changes; and


•	Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our other long-term debt instruments as described in Notes 8 and 9 of our Notes to Consolidated Financial Statements.

Our exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates, and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.

The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee and reviewed by the Audit Committee of our Board of Directors. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities, and employee conduct. The Executive Risk Committee, which includes senior level executives, meets on a regular basis to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.

105

Utilities Group

We produce, purchase and distribute power in four states, and purchase and distribute natural gas in five states. All of our utilities have GCA provisions that allow them to pass the prudently-incurred cost of gas through to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to “true-up” billed amounts to match the actual natural gas cost we incurred. In South Dakota, Colorado, Wyoming and Montana, we have a mechanism for our regulated electric utilities that serves a purpose similar to the GCAs for our regulated gas utilities. To the extent that our fuel and purchased power costs are higher or lower than the energy cost built into our tariffs, the difference (or a portion thereof) is passed through to the customer. These adjustments are subject to periodic prudence reviews by the state utility commissions.

Our utility customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers' underlying exposure to these fluctuations. These transactions are considered derivatives and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. Unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with state commission guidelines. Accordingly, the hedging activity is recognized in the Consolidated Statements of Income or the Consolidated Statements of Comprehensive Income (Loss) when the related costs are recovered through our rates.

The fair value of our Utilities Group derivative contracts at Dec. 31 is summarized below (in thousands):



	2012			2011
Net derivative liabilities	$	(8,533	)	$	(16,676	)
Cash collateral	12,930			19,416
	$	4,397		$	2,740

Oil and Gas

Oil and Gas Exploration and Production

We produce natural gas and crude oil through our exploration and production activities. Our natural "long" positions, or unhedged open positions, introduce commodity price risk and variability in our cash flows. We employ risk management methods to mitigate this commodity price risk and preserve cash flows, and we have adopted guidelines covering hedging for our natural gas and crude oil production. These guidelines have been approved by our Executive Risk Committee and the Board of Directors, and are routinely reviewed by the Audit Committee of our Board of Directors.

To mitigate commodity price risk and preserve cash flows, we primarily use over-the-counter swaps, exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. Our hedging policy allows up to 100 percent of our natural gas and crude oil production from proven producing reserves to be hedged for a period up to three years in the future.

106

We have entered into agreements to hedge a portion of our estimated 2013 and 2014 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place as of Dec. 31, 2012 are as follows:

Natural Gas



	For the Three Months Ended
	March 31,		June 30,		Sept. 30,		Dec. 31,		Total Year
2013
Swaps - MMBtu	1,220,000		1,233,000		1,246,000		1,154,000		4,853,000
Weighted Average Price per MMBtu	$	4.01	$	3.55	$	3.33	$	3.50	$	3.60

2014
Swaps - MMBtu	950,000		952,500		730,000		730,000		3,362,500
Weighted Average Price per MMBtu	$	3.71	$	3.65	$	3.98	$	3.98	$	3.81

Crude Oil



	For the Three Months Ended
	March 31,		June 30,		Sept. 30,		Dec. 31,		Total Year
2013
Swaps - Bbls	30,000		21,000		15,000		15,000		81,000
Weighted Average Price per Bbl	$	101.62	$	108.96	$	110.20	$	101.75	$	105.13

Puts - Bbls	30,000		36,000		39,000		36,000		141,000
Weighted Average Price per Bbl	$	76.75	$	78.96	$	79.81	$	80.63	$	79.15

Calls - Bbls	30,000		36,000		39,000		36,000		141,000
Weighted Average Price per Bbl	$	96.50	$	97.17	$	97.08	$	97.25	$	97.02

2014
Swaps - Bbls	45,000		60,000		30,000		30,000		165,000
Weighted Average Price per Bbl	$	94.38	$	90.65	$	89.70	$	89.70	$	91.32

Our hedge agreements had a fair value, net of cash collateral, of approximately $0.6 million as of Dec. 31, 2012 .

Wholesale Power

A potential risk related to power sales is the price risk arising from the sale of wholesale power that exceeds our generating capacity. These short positions can arise from unplanned plant outages or from unanticipated load demands. To control such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin.

Financing Activities

We engage in activities to manage risks associated with changes in interest rates. We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. At Dec. 31, 2012 , we had $150.0 million of notional amount floating-to-fixed interest rate swaps, with a maximum term of 4 years. These swaps have been designated as hedges in accordance with accounting standards for derivatives and hedges and accordingly their mark-to-market adjustments are recorded in Accumulated other comprehensive loss on the Consolidated Balance Sheets.

107

We also have interest rate swaps with a notional amount of $250.0 million , which were entered into for the purpose of hedging interest rate movements that would impact long-term financings that were originally expected to occur in 2008. Based on credit market conditions that transpired during the fourth quarter of 2008, we determined it was probable that the forecasted long-term debt financings would not occur in the time period originally specified and, as a result, the swaps were no longer effective hedges and the hedge relationships were de-designated. Mark-to-market adjustments on the swaps are now recorded within the income statements and for the years ended Dec. 31, 2012 , 2011 and 2010 we recorded a pre-tax unrealized mark-to-market gain (loss) of $1.9 million , $(42.0) million and $(15.2) million , respectively. These swaps are 6 and 16 year swaps which have early termination dates ranging from Dec. 15, 2013 to Dec. 31, 2013 , respectively.

We have continued to maintain these swaps in anticipation of our upcoming financing needs, particularly our upcoming holding company debt maturities. Alternatively, we may choose to cash settle these swaps at their fair value prior to their early termination dates, or unless these dates are extended, we will cash settle these swaps for an amount equal to their fair value on the stated termination dates.

Further details of the swap agreements are set forth in Note 3 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

On Dec. 31, 2012 and Dec. 31, 2011 , our interest rate swaps and related balances were as follows (dollars in thousands):



	Notional		Weighted Average Fixed Interest Rate		Maximum Terms in Years	Current Assets		Non- current Assets		Current Liabilities, net of Cash Collateral		Non- current Liabilities		Pre-tax Accumulated Other Comprehensive Income (Loss)			Pre-tax Income (Loss)
Dec. 31, 2012
Interest rate swaps	$	150,000	5.04	%	4	$	—	$	—	$	7,039	$	16,941	$	(23,980	)	$	—
Interest rate swaps - De-designated	250,000		5.67	%	1	—		—		88,148		—		—			1,882
	$	400,000				$	—	$	—	$	95,187	$	16,941	$	(23,980	)	$	1,882

Dec. 31, 2011
Interest rate swaps	$	150,000	5.04	%	5	$	—	$	—	$	6,513	$	20,363	$	(26,876	)	$	—
Interest rate swaps - De-designated	250,000		5.67	%	2	—		—		75,295		20,696		—			(42,010		)
	$	400,000				$	—	$	—	$	81,808	$	41,059	$	(26,876	)	$	(42,010	)

Based on Dec. 31, 2012 market interest rates and balances, a loss of approximately $7.0 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will likely change during the next twelve months as market interest rates change.

The table below presents principal amounts and related weighted average interest rates by year of maturity for our long-term debt obligations, including current maturities (dollars in thousands):



	2013			2014			2015			2016			2017			Thereafter			Total
Long-term debt
Fixed rate ^(a)	$	—		$	250,000		$	—		$	—		$	—		$	577,200		$	827,200
Average interest rate ^(b)	—		%	9		%	—		%	—		%	—		%	6.27		%	7.09		%

Variable rate	$	103,973		$	6,023		$	6,963		$	78,947		$	—		$	19,855		$	215,761
Average interest rate ^(b)	1.7		%	3.59		%	3.59		%	3.59		%	—		%	0.37		%	2.38		%

Total long-term debt	$	103,973		$	256,023		$	6,963		$	78,947		$	—		$	597,055		$	1,042,961
Average interest rate ^(b)	1.7		%	8.87		%	3.59		%	3.59		%	—		%	6.07		%	6.12		%

_________________________


(a)	Excludes unamortized premium or discount.


(b)	The average interest rates do not include the effect of interest rate swaps.

108

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. We have adopted the Black Hills Corporation Credit Policy that establishes guidelines, controls, and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. In addition, our Executive Risk Committee, which includes senior executives, meets on a regular basis to review our credit activities and to monitor compliance with the adopted policies.

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 parental guarantees, prepayments, letters of credit, and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by our review of their current credit information. We maintain a provision for estimated credit losses based upon our historical experience and any specific customer collection issue that we have identified. While most credit losses have historically been within our expectations and provisions established, we cannot provide assurance that we will continue to experience the same credit loss rates that we have in the past, or that an investment grade counterparty will not default sometime in the future.

At Dec. 31, 2012 , our credit exposure included a $7.6 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among investment grade companies, municipal cooperatives and federal agencies.

New Accounting Pronouncements

See Note 2 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2012 or pending adoption.

109


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS




Report of Independent Registered Public Accounting Firm	111

Consolidated Statements of Income for the three years ended Dec. 31, 2012	112

Consolidated Statements of Comprehensive Income (Loss) for the three years ended Dec. 31, 2012	113

Consolidated Balance Sheets as of Dec. 31, 2012 and 2011	114

Consolidated Statements of Cash Flows for the three years ended Dec. 31, 2012	116

Consolidated Statements of Common Stockholders’ Equity for the three years ended Dec. 31, 2012	117

Notes to Consolidated Financial Statements	118

110

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Black Hills Corporation

Rapid City, South Dakota

We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income (loss), cash flows, and common stockholders’ equity for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Black Hills Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 25, 2013

111

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME



Years ended	Dec. 31, 2012			Dec. 31, 2011			Dec. 31, 2010
	(in thousands, except per share amounts)
Revenue:
Utilities	$	1,064,813		$	1,155,519		$	1,109,761
Non-regulated energy	109,071			116,669			109,930
Total revenue	1,173,884			1,272,188			1,219,691

Operating expenses:
Utilities -
Fuel, purchased power and cost of gas sold	407,066			574,989			566,967
Operations and maintenance	242,367			247,496			251,375
Non-regulated energy operations and maintenance	85,830			93,453			71,672
Gain on sale of operating assets	(29,129		)	—			(8,921		)
Depreciation, depletion and amortization	154,632			135,591			126,606
Impairment of long-lived assets	26,868			—			—
Taxes - property, production and severance	40,487			33,710			27,592
Other operating expenses	2,052			710			980
Total operating expenses	930,173			1,085,949			1,036,271

Operating income	243,711			186,239			183,420

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)	(117,754		)	(116,684		)	(105,676		)
Allowance for funds used during construction - borrowed	3,462			14,041			10,689
Capitalized interest	682			11,260			4,381
Unrealized gain (loss) on interest rate swaps, net	1,882			(42,010		)	(15,193		)
Interest income	1,957			2,017			541
Allowance for funds used during construction - equity	540			932			2,996
Other expense	(71		)	(817		)	(140		)
Other income	2,486			2,490			2,733
Total other income (expense)	(106,816		)	(128,771		)	(99,669		)
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes	136,895			57,468			83,751
Equity in earnings (loss) of unconsolidated subsidiaries	10			1,121			1,559
Income tax benefit (expense)	(48,400		)	(18,224		)	(22,169		)
Income (loss) from continuing operations	88,505			40,365			63,141
Income (loss) from discontinued operations, net of tax	(6,977		)	9,365			5,544
Net income available for common stock	$	81,528		$	49,730		$	68,685

Earnings (loss) per share of common stock:
Earnings (loss) per share, Basic -
Income (loss) from continuing operations, per share	$	2.02		$	1.01		$	1.62
Income (loss) from discontinued operations, per share	(0.16		)	0.24			0.14
Total income (loss) per share, Basic	$	1.86		$	1.25		$	1.76
Earnings (loss) per share, Diluted -
Income (loss) from continuing operations, per share	$	2.01		$	1.01		$	1.62
Income (loss) from discontinued operations, per share	(0.16		)	0.23			0.14
Total income (loss) per share, Diluted	$	1.85		$	1.24		$	1.76
Weighted average common shares outstanding:
Basic	43,820			39,864			38,916
Diluted	44,073			40,081			39,091

The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

112

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



Years ended (in thousands)	Dec. 31, 2012			Dec. 31, 2011			Dec. 31, 2010

Net income available for common stock	$	81,528		$	49,730		$	68,685

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $296, $4,135 and $674, respectively)	(542		)	(7,609		)	(1,307		)
Benefit plan liability adjustments - prior service (costs) (net of tax of $86, $176 and $111, respectively)	(157		)	(325		)	(214		)
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $887, $1,708 and $(636), respectively)	(1,268		)	(2,831		)	1,336
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $534, $(709) and $2,498, respectively)	(643		)	1,468			(4,232		)
Other comprehensive income (loss), net of tax	(2,610		)	(9,297		)	(4,417		)

Comprehensive income (loss)	$	78,918		$	40,433		$	64,268

See Note 15 for additional disclosures related to Comprehensive Income.

The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

113

BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS



	As of
	Dec. 31, 2012			Dec. 31, 2011
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	15,462		$	21,628
Restricted cash and equivalents	7,916			9,254
Accounts receivable, net	163,698			156,774
Materials, supplies and fuel	77,643			84,064
Derivative assets, current	3,236			18,583
Income tax receivable, net	—			9,344
Deferred income tax assets, net, current	77,231			37,202
Regulatory assets, current	31,125			59,955
Other current assets	28,795			21,266
Assets of discontinued operations	—			340,851
Total current assets	405,106			758,921

Investments	16,402			17,261

Property, plant and equipment	3,930,772			3,724,016
Less accumulated depreciation and depletion	(1,188,023		)	(934,441		)
Total property, plant and equipment, net	2,742,749			2,789,575

Other assets:
Goodwill	353,396			353,396
Intangible assets, net	3,620			3,843
Derivative assets, non-current	510			1,971
Regulatory assets, non-current	188,268			182,175
Other assets, non-current	19,420			19,941
Total other assets, non-current	565,214			561,326
TOTAL ASSETS	$	3,729,471		$	4,127,083

The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

114

BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

(Continued)



	As of
	Dec. 31, 2012			Dec. 31, 2011
	(in thousands, except share amounts)

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	84,422		$	104,748
Accrued liabilities	154,389			151,319
Derivative liabilities, current	96,541			84,367
Accrued income tax, net	4,936			—
Regulatory liabilities, current	13,628			16,231
Notes payable	277,000			345,000
Current maturities of long-term debt	103,973			2,473
Liabilities of discontinued operations	—			173,929
Total current liabilities	734,889			878,067

Long-term debt, net of current maturities	938,877			1,280,409

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	385,908			300,988
Derivative liabilities, non-current	16,941			49,033
Regulatory liabilities, non-current	127,656			108,217
Benefit plan liabilities	167,397			177,480
Other deferred credits and other liabilities	125,294			123,553
Total deferred credits and other liabilities	823,196			759,271

Commitments and contingencies (See Notes 3, 8, 9, 10, 13, 18, 19 and 20)

Stockholders’ equity:
Common stock equity-
Common stock $1 par value; 100,000,000 shares authorized; issued: 44,278,189 and 43,957,502 shares, respectively	44,278			43,958
Additional paid-in capital	733,095			722,623
Retained earnings	492,869			476,603
Treasury stock at cost - 71,782 and 32,766 shares, respectively	(2,245		)	(970		)
Accumulated other comprehensive income (loss)	(35,488		)	(32,878		)
Total stockholders’ equity	1,232,509			1,209,336
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,729,471		$	4,127,083

The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

115

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



Year ended	Dec. 31, 2012			Dec. 31, 2011			Dec. 31, 2010
	(in thousands)
Operating activities:
Net income available for common stock	$	81,528		$	49,730		$	68,685
(Income) loss from discontinued operations, net of tax	6,977			(9,365		)	(5,544		)
Income (loss) from continuing operations	88,505			40,365			63,141
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	154,632			135,591			126,606
Deferred financing cost amortization	5,555			5,655			5,859
Impairment of long-lived assets	26,868			—			—
Derivative fair value adjustments	2,728			(8,693		)	13,546
Gain on sale of operating assets	(29,129		)	—			(8,921		)
Stock compensation	8,271			5,643			5,637
Unrealized mark-to-market loss (gain) on interest rate swaps	(1,882		)	42,010			15,193
Deferred income taxes	39,716			33,600			17,354
Equity in (earnings) loss of unconsolidated subsidiaries	(10		)	(1,121		)	(1,559		)
Allowance for funds used during construction - equity	(540		)	(932		)	(2,996		)
Employee benefit plans	20,973			14,586			16,342
Other adjustments, net	2,751			4,947			(9,710		)
Change in certain operating assets and liabilities:
Materials, supplies and fuel	6,343			(21,385		)	(338		)
Accounts receivable, unbilled revenues and other current assets	(2,257		)	(4,202		)	(18,480		)
Accounts payable and other current liabilities	(10,713		)	(31,091		)	(12,848		)
Regulatory assets	12,864			12,691			(21,283		)
Regulatory liabilities	3,194			11,198			50
Contributions to defined benefit pension plans	(25,350		)	(11,050		)	(30,015		)
Other operating activities, net	(6,732		)	(11,118		)	(1,013		)
Net cash provided by operating activities of continuing operations	295,787			216,694			156,565
Net cash provided by (used in) operating activities of discontinued operations	21,184			7,010			(8,813		)
Net cash provided by operating activities	316,971			223,704			147,752

Investing activities:
Property, plant and equipment additions	(349,129		)	(440,698		)	(472,292		)
Payment for acquisition of net assets, net of cash acquired	—			—			(2,250		)
Proceeds from sale of assets	253,791			583			70,357
Other investing activities	(180		)	(4,533		)	15,407
Net cash provided by (used in) investing activities of continuing operations	(95,518		)	(444,648		)	(388,778		)
Proceeds from sale of business operations	107,511			—			—
Net cash provided by (used in) investing activities of discontinued operations	(824		)	(2,359		)	(390		)
Net cash provided by (used in) investing activities	11,169			(447,007		)	(389,168		)

Financing activities:
Dividends paid on common stock	(65,262		)	(59,202		)	(56,467		)
Common stock issued	4,726			123,041			3,246
Short-term borrowings - issuances	203,753			1,017,300			854,500
Short-term borrowings - repayments	(271,753		)	(821,300		)	(770,000		)
Long-term debt - issuance	—			—			200,000
Long-term debt - repayments	(240,077		)	(8,382		)	(59,926		)
Other financing activities	(2,833		)	(1,666		)	(8,363		)
Net cash provided by (used in) financing activities of continuing operations	(371,446		)	249,791			162,990
Net cash provided by (used in) financing activities of discontinued operations	—			(158		)	(2,037		)
Net cash provided by (used in) financing activities	(371,446		)	249,633			160,953

Net change in cash and cash equivalents	(43,306		)	26,330			(80,463		)

Cash and cash equivalents beginning of year *	58,768			32,438			112,901
Cash and cash equivalents end of year *	$	15,462		$	58,768		$	32,438

____________________


*	Cash and cash equivalents include cash of discontinued operations of $37.1 million , $16.0 million and $97.5 million at Dec. 31, 2011 , 2010 and 2009 , respectively.

See Note 16 for supplemental disclosure of cash flow information.

The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

116

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY



	Common Stock			Treasury Stock
(in thousands except share and per share amounts)	Shares	Value		Shares	Value			Additional Paid in Capital			Retained Earnings			AOCI			Total
Balance at Dec. 31, 2009	38,977,526	$	38,978	8,834	$	(224	)	$	591,390		$	473,857		$	(19,164	)	$	1,084,837
Net income (loss) available for common stock	—	—		—	—			—			68,685			—			68,685
Other comprehensive income (loss), net of tax	—	—		—	—			—			—			(4,417		)	(4,417		)
Dividends on common stock	—	—		—	—			—			(56,467		)	—			(56,467		)
Share-based compensation	195,915	196		2,128	(85		)	4,706			—			—			4,817
Tax effect of share-based compensation	—	—		—	—			(33		)	—			—			(33		)
Equity Forward	—	—		—	—			(288		)	—			—			(288		)
Dividend reinvestment and stock purchase plan	106,231	106		—	—			3,035			—			—			3,141
Other stock transactions	376	—		—	—			(5		)	—			—			(5		)
Balance at Dec. 31, 2010	39,280,048	$	39,280	10,962	$	(309	)	$	598,805		$	486,075		$	(23,581	)	$	1,100,270
Net income (loss) available for common stock	—	—		—	—			—			49,730			—			49,730
Other comprehensive income (loss), net of tax	—	—		—	—			—			—			(9,297		)	(9,297		)
Dividends on common stock	—	—		—	—			—			(59,202		)	—			(59,202		)
Share-based compensation	161,424	161		21,804	(661		)	5,576			—			—			5,076
Tax effect of share-based compensation	—	—		—	—			(28		)	—			—			(28		)
Issuance of common stock	4,413,519	4,414		—	—			115,216			—			—			119,630
Dividend reinvestment and stock purchase plan	102,511	103		—	—			3,099			—			—			3,202
Other stock transactions	—	—		—	—			(45		)	—			—			(45		)
Balance at Dec. 31, 2011	43,957,502	$	43,958	32,766	$	(970	)	$	722,623		$	476,603		$	(32,878	)	$	1,209,336
Net income (loss) available for common stock	—	—		—	—			—			81,528			—			81,528
Other comprehensive income (loss), net of tax	—	—		—	—			—			—			(2,610		)	(2,610		)
Dividends on common stock	—	—		—	—			—			(65,262		)	—			(65,262		)
Share-based compensation	219,946	220		39,016	(1,275		)	7,095			—			—			6,040
Tax effect of share-based compensation	—	—		—	—			117			—			—			117
Dividend reinvestment and stock purchase plan	100,741	100		—	—			3,282			—			—			3,382
Other stock transactions	—	—		—	—			(22		)	—			—			(22		)
Balance at Dec. 31, 2012	44,278,189	$	44,278	71,782	$	(2,245	)	$	733,095		$	492,869		$	(35,488	)	$	1,232,509

Dividends per share paid were $1.48 , $1.46 and $1.44 for the years ended Dec. 31, 2012 , 2011 and 2010 , respectively.

The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

117

BLACK HILLS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012 , 2011 and 2010


( 1 )	BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Corporation is a diversified energy company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, operates in two primary business groups: Utilities and Non-regulated Energy.

The Utilities Group includes our Electric Utilities and Gas Utilities segments. Electric Utilities include the operating results of the regulated electric utility operations of Black Hills Power and Colorado Electric, and the electric and natural gas utility operations of Cheyenne Light, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility services to Cheyenne, Wyo. and vicinity. Gas Utilities consist of the operating results of the regulated natural gas utility operations of Colorado Gas, Nebraska Gas, Iowa Gas, and Kansas Gas.

The Non-regulated Energy Group includes our Power Generation, Coal Mining and Oil and Gas segments. Power Generation, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Coal Mining, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyo. Oil and Gas, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities located in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. These businesses are aggregated for reporting purposes as Non-regulated Energy.

On Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. See Note 23 for additional information.

For further descriptions of our reportable business segments, see Note 17 .

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company revenues, see Note 17 .

Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 7 for additional information.

As a result of the sale of our Energy Marketing segment, amounts associated with this segment have been reclassified as discontinued operations on the accompanying Consolidated Financial Statements. See Note 23 for additional information.

118

Cash and Cash Equivalents

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

Restricted Cash and Equivalents

The Black Hills Wyoming project financing requires that we maintain cash accounts for various specified purposes. We do not readily have access to these accounts and can only withdraw funds upon meeting certain requirements. Therefore, we have classified these amounts as restricted cash.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable for our Utilities Group primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Non-regulated Energy Group consists of amounts due from sales of coal, crude oil and natural gas, electric energy and capacity.

We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.

Following is a summary of accounts receivable as of Dec. 31 (in thousands):



2012	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	54,482	$	23,843	$	(527	)	$	77,798
Gas Utilities	31,495		39,962		(222		)	71,235
Power Generation	16		—		—			16
Coal Mining	2,247		—		—			2,247
Oil and Gas	11,622		—		(19		)	11,603
Corporate	799		—		—			799
Total	$	100,661	$	63,805	$	(768	)	$	163,698

119



2011	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	42,773	$	21,151	$	(545	)	$	63,379
Gas Utilities	39,353		38,992		(1,011		)	77,334
Power Generation	282		—		—			282
Coal Mining	4,056		—		—			4,056
Oil and Gas	11,282		—		(105		)	11,177
Corporate	546		—		—			546
Total	$	98,292	$	60,143	$	(1,661	)	$	156,774

Revenue Recognition

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

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

For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement.

Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment.

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of (in thousands):



	Dec. 31, 2012		Dec. 31, 2011
Materials and supplies	$	43,397	$	40,838
Fuel - Electric Utilities	8,589		8,201
Natural gas in storage held for distribution	25,657		35,025
Total materials, supplies and fuel	$	77,643	$	84,064

Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represent oil, gas, and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are valued using weighted-average cost. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.

120

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus cost of removal, is charged to accumulated depreciation. Removal costs associated with non-legal obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various class of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, a unit-of-production methodology based on plant hours run is used.

Oil and Gas Operations

We account for our oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized. However, we recognized a gain on the sale of a majority of our Williston Basin assets in 2012. See Note 22 for further discussion.

Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement which varies in length.

Under the full cost method, net capitalized costs are subject to a ceiling test which limits these costs to the present value of future net cash flows discounted at an SEC required rate, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the net capitalized costs. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. As a result of lower natural gas prices, we recorded a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment in 2012. No ceiling test write-down was recorded in 2011 or 2010. See Note 12 for additional information.

The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We elected to include PUDs of only one location away from a producing well in our volume reserve estimate. See information on our oil and gas drilling activities in Note 21 .

Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report on these additional reserve categories.

121

Goodwill and Intangible Assets

Goodwill and intangible assets with indefinite lives are not amortized but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform this annual review of goodwill and indefinite lived intangible assets as of Nov. 30 each year (or more frequently if impairment indicators arise).

We performed our annual goodwill impairment tests as of Nov. 30, 2012 . We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method, and an analysis of comparable transactions. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, and long-term earnings and merger multiples for comparable companies.

Goodwill primarily arose from the acquisition of one regulated electric and four regulated gas utilities in the Aquila Transaction. This goodwill from the Aquila Transaction was allocated approximately 72 percent to Colorado Electric and 28 percent to the Gas Utilities. We believe that the goodwill amount reflects the value of the relatively stable, long-lived cash flows of the regulated gas utility business, considering the regulatory environment and market growth potential and the long-lived cash flow and rate base growth opportunities at our electric utility in Colorado. Goodwill balances were as follows (in thousands):



	Electric Utilities		Gas Utilities		Power Generation		Total
Ending balance at Dec. 31, 2010	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2011	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2012	$	250,487	$	94,144	$	8,765	$	353,396

Our intangible assets represent easements, rights-of-way and trademarks and are amortized using a straight-line method based on estimated useful lives. The finite lived intangible assets are currently being amortized over 20 years . Changes to intangible assets for the years ended Dec. 31, were as follows (in thousands):



	2012			2011			2010
Intangible assets, net, beginning balance	$	3,843		$	4,069		$	4,309
Additions (adjustments)	—			—			—
Amortization expense *	(223		)	(226		)	(240		)
Intangible assets, net, ending balance	$	3,620		$	3,843		$	4,069

_________________


*	Amortization expense for existing intangible assets is expected to be $0.2 million for each year of 2013 , 2014 , 2015 , 2016 , and 2017 .

Asset Retirement Obligations

Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset.

We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations, other than Oil and Gas. For the Oil and Gas segment, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and depleted pursuant to our use of the full cost method. Additional information is included in Note 10 .

122

Fair Value Measurements

Derivative Financial Instruments

Assets and liabilities are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

Oil and Gas Segment:


•	The commodity option contracts for the Oil and Gas segment are valued under the market approach and include calls and puts. Fair value was derived using quoted prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure.


•	The commodity basis swaps for the Oil and Gas segment are valued under the market approach using the instrument’s current forward price strip hedged for the same quantity and date and discounted based on the three-month LIBOR. We utilize observable inputs which support Level 2 disclosure.

Utilities Segment:

•

The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) and OTC basis swaps (Level 3) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third party market participant since these instruments are not traded on an exchange.

123

Corporate Segment:

•

The interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

Additional information is included in Note 4 .

Derivatives and Hedging Activities

The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value, and that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly. Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists.

Accounting standards for derivatives and hedging require that the unrealized gains or losses on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting unrealized loss or gain on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument must be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Deferred Financing Costs

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

Development Costs

According to accounting standards for business combinations, we expense, when incurred, development and acquisition costs associated with corporate development activities prior to acquiring or beginning construction of a project. Expensed development costs are included in Other operating expenses on the accompanying Consolidated Statements of Income.

Legal Costs

Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been incurred, and the amount can be reasonably estimated. Legal costs related to ongoing litigation are expensed as incurred.

124

Regulatory Accounting

Our Utilities Group follows accounting standards for regulated operations and reflects the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which would require these net assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but are not allowed a return. In the event we determine that our regulated net assets no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.

We had the following regulatory assets and liabilities (in thousands):



	Maximum Recovery
	or Settlement Period	As of		As of
	(in years)	Dec. 31, 2012		Dec. 31, 2011
Regulatory assets
Deferred energy and fuel costs adjustments - current ^(a)	1	$	16,005	$	33,526
Deferred gas cost adjustments and gas price derivatives ^(a)	7	20,741		26,208
AFUDC ^(b)	45	12,416		12,482
Employee benefit plans ^(c)	13	115,521		120,708
Environmental ^(a)	subject to approval	1,792		1,770
Asset retirement obligations ^(a)	44	3,247		3,097
Bond issue cost ^(a)	25	3,561		3,704
Renewable energy standard adjustment ^(a)	5	19,484		20,095
Flow through accounting ^(d)	35	16,620		12,191
Other regulatory assets ^(a)	15	10,006		8,349
		$	219,393	$	242,130

Regulatory liabilities
Deferred energy and gas costs ^(a)	1	$	21,091	$	16,961
Employee benefit plans ^(e)	13	59,362		59,455
Cost of removal ^(a)	44	53,526		42,257
Other regulatory liabilities ^(f)	25	7,305		5,775
		$	141,284	$	124,448

__________


(a)	Recovery of costs, but not allowed a rate of return.


(b)	In addition to recovery of costs, we are allowed a rate of return.


(c)	In addition to recovery of costs, we are allowed a return on approximately $24.6 million .


(d)	In addition to recovery of costs, we are allowed a return on approximately $5.4 million .


(e)	Approximately $13.2 million is included in our rate base calculations as a reduction to rate base.


(f)	Approximately $2.6 million is included in our rate base calculations as a reduction to rate base.

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

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

125

Deferred Gas Cost Adjustment and Gas Price Derivatives - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. In addition, as allowed by state utility commissions, we have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Cheyenne Light files monthly with the WPSC a GCA to be included in tariff rates. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions.

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

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plans and post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income, including costs being amortized from the Aquila Transaction.

Environmental - Environmental is associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown.

Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 10 for additional details.

Bond Issue Costs - Bond issue costs are recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.

Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills.

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

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

Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery in purchased power, transmission and natural gas costs.

Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement aspect of a rate regulated environment.

Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.

126

Income Taxes

We use the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax asset will not be realized.

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

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income.

We account for uncertainty in income taxes recognized in the financial statements in accordance with accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets. See Note 14 for additional information.

Earnings per Share of Common Stock

Basic earnings per share from continuing and discontinued operations is computed by dividing Income (loss) from continuing or discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings (loss) per share is computed by including all dilutive common shares outstanding during each year.

A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):



	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Income (loss) from continuing operations	$	88,505	$	40,365	$	63,141

Weighted average shares - basic *	43,820		39,864		38,916
Dilutive effect of:
Stock options	13		19		14
Restricted stock	173		153		107
Equity forward instrument	—		—		29
Other dilutive effects	67		45		25
Weighted average shares - diluted	44,073		40,081		39,091

_______________


*	In November 2011, we issued shares in conjunction with the settlement of an equity forward agreement. See Note 11 for further information.

127

The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):



	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock options	95	105	158
Restricted stock	53	17	1
Other stock	15	19	1
Anti-dilutive shares excluded from computation of earnings (loss) per share	163	141	160

Discontinued Operations

Assets of discontinued operations are recorded at the lower of their carrying amount or fair value less cost to sell. Additionally, in accordance with GAAP, indirect corporate costs previously allocated to a disposal group cannot be reclassified to discontinued operations. Assets of discontinued operations and Liabilities of discontinued operations on the accompanying Consolidated Balance Sheets included the assets and liabilities of Enserco Energy Inc. See Note 23 for additional information.

( 2 ) RECENTLY ISSUED AND ADOPTED ACCOUNTING PRONOUNCEMENTS AND LEGISLATION

Recently Adopted Accounting Standards

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and Deferral of the Effective Date for Amendments to the Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending accounting standards for comprehensive income to improve the comparability, consistency and transparency of reporting. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after Dec. 15, 2011, with early adoption permitted. In Dec. 2011, FASB issued ASU 2011-12. ASU 2011-12 indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments on the face of the financial statements for items reclassified from other comprehensive income to net income. Ultimately FASB chose not to reinstate the reclassification adjustment requirements in ASU 2011-05 but instead issued ASU 2013-02 in February 2013.

At Dec. 31, 2011, we elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain financial statements and provided additional details in notes to the financial statements, but did not have any other impact on our consolidated financial statements. See additional Comprehensive Income Statement and additional disclosures in Note 15 .

Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04

In May 2011, FASB issued an accounting standards update amending ASC 820, Fair Value Measurements and Disclosures, to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a non-financial asset that is different from the asset’s highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after Dec. 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our consolidated financial statements. The additional disclosures are included in Note 4 .

128

Extractive Activities — Oil and Gas Reserves, ASU 2010-03 (SEC Release #33-8995)

The FASB issued an accounting standards update which aligns the oil and gas reserve estimation and disclosure requirements with the SEC released Final Rule, “Modernization of Oil and Gas Reporting,” which amended the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technology advances. Key revisions include the ability to include non-traditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the oil and gas prices used to determine reserves from the period-end price to a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months before the end of the reporting period. The amendment was effective for reporting periods ending on or after Dec. 31, 2009. The implementation of this SEC requirement resulted in additional depletion expense of $1.3 million in the fourth quarter of 2010.

Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 33-9286, 33-9338, and 34-67717

In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for certain swap transactions we enter into. In addition, many of the transactions which were previously classified as swaps have been converted to exchange-traded futures contracts, which are subject to futures margin posting requirements. The adoption of this rule did not have an impact on our financial position, results of operations or cash flows.

In August 2012, the SEC approved a final rule implementing Section 1504 of Dodd-Frank. The rule requires issuers engaged in the commercial development of oil, natural gas or minerals to disclose cash payments made to a foreign government or the Federal government of the United States. We are in the process of evaluating our reporting requirements with the first filing due in 2013. The adoption of this rule will not have an impact on our financial position, results of operations or cash flows.

In December 2011, the SEC issued Final Rule 33-9286 providing requirements for Section 1503 of Dodd-Frank. This release requires issuers that are operators of a coal mine to disclose information concerning mine safety violations or other regulatory matters. The required information for our WRDC coal mine is included in Exhibit 95 of this Form 10-K.

Significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required in order to implement the restrictions, limitations, and requirements contemplated by Dodd-Frank. We will continue to evaluate the impact of additional rules as they become available.

Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08

In September 2011, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing on goodwill is necessary. Specifically, an entity has the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step test. If an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. This standard is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after Dec. 15, 2011. The adoption of this standard did not have a material impact on our consolidated financial statements.

Intangible - Goodwill and Other: Testing Indefinite Lived Intangible Assets for Impairment, ASU 2012-02

In July 2012, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing of indefinite lived intangible assets is necessary. This ASU aligns the impairment testing for intangible assets with that of goodwill as amended by ASU 2011-08. This guidance is effective for interim and annual periods beginning after Sept. 15, 2012, with early adoption permitted. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.

129

Recently Issued Accounting Pronouncements and Legislation

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, ASU 2013-02

In February 2013, the FASB issued new disclosure requirements for items reclassified out of AOCI to expand the disclosure requirements in ASC 220, Comprehensive Income, for presentation of changes in AOCI. ASU 2013-02 requires disclosure of (1) changes in components of other comprehensive income, (2) for items reclassified out of AOCI and into net income in their entirety, the effect of the reclassification on each affected net income line item and (3) cross references to other disclosures that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net income. Disclosures are required either on the face of the statements of income or as a separate disclosure in the notes to the financial statements. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2012. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11

In December 2011, the FASB issued revised accounting guidance to amend ASC 210, Balance Sheet, related to the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company’s netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning Jan. 1, 2013. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.

( 3 ) RISK MANAGEMENT ACTIVITIES

Market Risk

Market risk is the potential loss that may occur as a result of an adverse change in market price or rate. We are exposed to the following market risks, including, but not limited to:


•	Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Electric Utilities and Gas Utilities segments resulting from commodity price changes; and


•	Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our other long-term debt instruments .

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

130

As of Dec. 31, 2012 , our credit exposure included a $7.6 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 4 .

Oil and Gas Exploration and Production

To mitigate commodity price risk and preserve cash flows, we primarily use over-the-counter swaps, exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in Accumulated other comprehensive income (loss) on the accompanying Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue on the accompanying Consolidated Statements of Income.

We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:



	Dec. 31, 2012				Dec. 31, 2011
	Crude oil futures, swaps and options		Natural gas futures, swaps and options		Crude oil futures, swaps and options			Natural gas futures, swaps and options
Notional ^(a)	528,000		8,215,500		528,000			5,406,250
Maximum terms in years ^(b)	1		0.75		1.25			1.75
Derivative assets, current	$	1,405	$	1,831	$	729		$	8,010
Derivative assets, non-current	$	297	$	170	$	771		$	1,148
Derivative liabilities, current	$	847	$	507	$	2,559		$	—
Derivative liabilities, non-current	$	—	$	—	$	811		$	7
Pre-tax accumulated other comprehensive income (loss)	$	206	$	873	$	(1,928	)	$	9,152
Cash collateral included in Derivative liabilities	$	786	$	620	$	—		$	—
Cash collateral included in Other current assets	$	1,078	$	709	$	—		$	—
Expense included in Revenue ^(c)	$	429	$	88	$	(58	)	$	—

________________________


(a)	Crude in Bbls, gas in MMBtu.


(b)	Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.


(c)	Represents the amortization of put premiums.

Based on Dec. 31, 2012 market prices, a $2.1 million gain would be reclassified from AOCI during 2013 . Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

131

Utilities

The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Gas Utilities were as follows, as of:



	Dec. 31, 2012		Dec. 31, 2011
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	15,350,000	83	14,310,000	84
Natural gas options purchased	2,430,000	2	1,720,000	3
Natural gas basis swaps purchased	12,020,000	72	7,160,000	60

We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:



	Dec. 31, 2012		Dec. 31, 2011
Derivative assets, current	$	—	$	9,844
Derivative assets, non-current	$	43	$	52
Derivative liabilities, non-current	$	—	$	7,156
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	9,596	$	17,556

Cash collateral receivable (payable) included in derivatives	$	8,576	$	19,416
Cash collateral included in Other assets, current	$	4,354	$	—
Option premiums and commissions included in derivatives	$	1,063	$	880

132

Financing Activities

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. Our interest rate swaps and related balances were as follows (dollars in thousands) as of:



	Dec. 31, 2012						Dec. 31, 2011
	Interest Rate Swaps ^(a)			De-designated Interest Rate Swaps ^(b)			Interest Rate Swaps ^(a)			De-designated Interest Rate Swaps ^(b)
Notional	$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.0			1.0			5.0			2.0
Derivative liabilities, current	$	7,039		$	88,148		$	6,513		$	75,295
Derivative liabilities, non-current	$	16,941		$	—		$	20,363		$	20,696
Pre-tax accumulated other comprehensive income (loss)	$	(23,980	)	$	—		$	(26,876	)	$	—
Pre-tax gain (loss)	$	—		$	1,882		$	—		$	(42,010	)
Cash collateral receivable (payable) included in derivatives	$	—		$	5,960		$	—		$	—

___________________


(a)	These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming, both of which are priced using three-month LIBOR, matching the floating portion of the related swaps.


(b)	The maximum term in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value at the termination date. If extended, swaps totaling $100.0 million terminate in 6 years and swaps totaling $150.0 million terminate in 16 years .

Collateral requirements based on our corporate credit rating apply to $50.0 million of our de-designated swaps. At our current credit ratings, we are required to post collateral for any amount by which the swap’s negative mark-to-market fair value exceeds $20.0 million . If our senior unsecured credit rating drops to BB+ or below by S&P, or Ba1 or below by Moody’s, we would be required to post collateral for the entire amount of the swap’s negative mark-to-market fair value. We had $6.0 million cash collateral posted at Dec. 31, 2012 .

Based on Dec. 31, 2012 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $7.0 million would be reclassified from AOCI during the next 12 months. Estimated and realized gains or losses will change during future periods as market interest rates change.

( 4 ) FAIR VALUE MEASUREMENTS

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the placement within the fair value hierarchy levels.

133

There have been no significant transfers between Level 1 and Level 2 derivative balances during 2012 or 2011 . The following tables set forth, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):



	As of Dec. 31, 2012
	Level 1 ^(a)		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	378	$	—	$	—		$	378
Basis Swaps -- Oil	—		1,325		—		—			1,325
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		2,000		—		—			2,000
Commodity derivatives - Utilities	—		—		43		—			43
Cash equivalents	15,462		—		—		—			15,462
Total	$	15,462	$	3,703	$	43	$	—		$	19,208

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	1,131	$	—	$	(336	)	$	795
Basis Swaps -- Oil	—		502		—		(450		)	52
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		1,127		—		(620		)	507
Commodity derivatives - Utilities	—		8,576		—		(8,576		)	—
Interest rate swaps	—		118,088		—		(5,960		)	112,128
Total	$	—	$	129,424	$	—	$	(15,942	)	$	113,482

______________


(a)	Level 1 assets and liabilities are described in Note 5 .

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



	Fair Value at		Valuation	Unobservable	Range (Weighted)
	Dec. 31, 2012		Technique	Input	Average
Assets:
Commodity derivatives - Utilities ^(a)	$	43	Independent price quotes	Long-term natural gas prices - Basis Differential	$	(0.13	)

_____________

(a)

The significant unobservable inputs used in the fair value measurement of the long-term OTC contracts are based on the average of price quotes from an independent third party market participant and the OTC contract broker. The unobservable inputs are long-term natural gas prices. Significant changes to these inputs along with the contract term would impact the derivative asset/liability and regulatory asset/liability, but will not impact the results of operations until the contract is settled under the original terms of the contract. The contracts will be classified as Level 2 once settlement is within 60 months of maturity and quoted market prices from a market exchange are available.

134



	As of Dec. 31, 2011
	Level 1 ^(a)		Level 2			Level 3		Cash Collateral and Counterparty Netting		Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—		$	768	$	5	$	773
Basis Swaps -- Oil	—		727			—		—		727
Options -- Gas	—		—			—		—		—
Basis Swaps -- Gas	—		9,158			—		—		9,158
Commodity derivatives - Utilities	—		(9,520		)	—		19,416		9,896
Cash equivalents	6,005		—			—		—		6,005
Total	$	6,005	$	365		$	768	$	19,421	$	26,559

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—		$	1,165	$	5	$	1,170
Basis Swaps -- Oil	—		2,200			—		—		2,200
Options -- Gas	—		—			—		—		—
Basis Swaps -- Gas	—		7			—		—		7
Commodity derivatives - Utilities	—		7,156			—		—		7,156
Interest rate swaps	—		122,867			—		—		122,867
Total	$	—	$	132,230		$	1,165	$	5	$	133,400

_________


(a)	Level 1 assets and liabilities are described in Note 5 .

The following tables present the changes in level 3 recurring fair value (in thousands):



	As of Dec. 31, 2012									As of Dec. 31, 2011
Assets:	Commodity Derivatives -- Oil			Commodity Derivatives -- Utilities			Total			Commodity Derivatives -- Oil
Balances as of beginning of period	$	768		$	—		$	768		$	266
Total gain (loss) included in revenue	—			—			—			—
Total gain (loss) included in AOCI	(360		)	(54		)	(414		)	598
Purchases	—			192			192			—
Issuances	—			—			—			—
Settlements	(4		)	—			(4		)	(96		)
Transfers into level 3 ^(a)	—			—			—			—
Transfers out of level 3 ^(b)(c)	(404		)	(95		)	(499		)	—
Balances at end of period	$	—		$	43		$	43		$	768

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	(54	)	$	(54	)	$	(101	)

135



	As of Dec. 31, 2012								As of Dec. 31, 2011
Liabilities:	Commodity Derivatives -- Oil			Commodity Derivatives -- Utilities		Total			Commodity Derivatives -- Oil
Balances as of beginning of period	$	1,165		$	—	$	1,165		$	—
Total gain (loss) included in revenue	—			—		—			—
Total gain (loss) included in AOCI	182			—		182			1,165
Purchases	—					—			—
Issuances	—			—		—			—
Settlements	—			—		—			—
Transfers into level 3 ^(a)	—			—		—			—
Transfers out of level 3 ^(b)(c)	(1,347		)	—		(1,347		)	—
Balances at end of period	$	—		$	—	$	—		$	1,165

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	—		$	—

__________


(a)	Transfers into Level 3 would occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs.


(b)	Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.


(c)	Previously, we utilized pricing methodologies developed by our Energy Marketing segment to value our Oil and Gas derivatives. Oil and Gas now obtains available observable inputs including quoted prices traded on active exchanges from multiple sources to value our options. Therefore, options in the Oil and Gas segment have been reclassified from Level 3 to Level 2.

Fair Value Measures

As required by accounting standards for derivatives and hedging, fair values within the following tables are presented on a gross basis and do not reflect the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements. Further, the amounts do not include net cash collateral on deposit in margin accounts at Dec. 31, 2012 and 2011 , to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 3 .

136

The following tables present the fair value and balance sheet classification of our derivative instruments as of Dec. 31. exclusive of cash collateral (in thousands):



		2012				2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives		Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets - current	$	2,874	$	—	$	8,739	$	—
Commodity derivatives	Derivative assets - non-current	510		—		1,919		—
Commodity derivatives	Derivative liabilities - current	—		1,993		—		2,559
Commodity derivatives	Derivative liabilities - non-current	—		821		—		818
Interest rate swaps	Derivative liabilities - current	—		7,038		—		6,513
Interest rate swaps	Derivative liabilities - non-current	—		16,941		—		20,363
Total derivatives designated as hedges		$	3,384	$	26,793	$	10,658	$	30,253

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	362	$	—	$	—	$	9,572
Commodity derivatives	Derivative assets - non-current	—		—		—		(52		)
Commodity derivatives	Derivative liabilities - current	1,180		4,957		—		—
Commodity derivatives	Derivative liabilities - non-current	406		5,153		—		7,156
Interest rate swaps	Derivative liabilities - current	—		94,108		—		75,295
Interest rate swaps	Derivative liabilities - non-current	—		—		—		20,696
Total derivatives not designated as hedges		$	1,948	$	104,218	$	—	$	112,667

A description of our derivative activities is discussed in Note 3 . The following tables present the impact that derivatives had on our Consolidated Statements of Income.

Cash Flow Hedges

The impact of cash flow hedges on our Consolidated Statements of Income and Balance Sheets for the years ended are presented as follows (in thousands):



	Dec. 31, 2012
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(4,794	)	Interest expense	$	(7,607	)		$	—
Commodity derivatives	2,639			Revenue	8,784				—
Total	$	(2,155	)		$	1,177			$	—

137



	Dec. 31, 2011
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(12,280	)	Interest expense	$	(7,664	)		$	—
Commodity derivatives	7,741			Revenue	5,487				—
Total	$	(4,539	)		$	(2,177	)		$	—



	Dec. 31, 2010
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(13,527	)	Interest expense	$	(7,609	)		$	—
Commodity derivatives	15,456			Revenue	14,339				—
Total	$	1,929			$	6,730			$	—

Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments that have not been designated as hedging instruments on our Consolidated Statements of Income for the years ended Dec. 31 was as follows (in thousands):



		2012			2011			2010
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income

Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swap, net	$	1,882		$	(42,010	)	$	(15,193	)
Interest rate swaps - realized	Interest expense	(12,959		)	(13,373		)	(13,312		)
		$	(11,077	)	$	(55,383	)	$	(28,505	)

138

( 5 ) FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at Dec. 31 were as follows (in thousands):



	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	15,462	$	15,462	$	21,628	$	21,628
Restricted cash and equivalents ^(a)	$	7,916	$	7,916	$	9,254	$	9,254
Notes payable ^(a)	$	277,000	$	277,000	$	345,000	$	345,000
Long-term debt, including current maturities ^(b)	$	1,042,850	$	1,231,559	$	1,282,882	$	1,464,289

_______________


(a)	Fair value approximates carrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

(b)

Long-term debt is valued using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.

Cash and Cash Equivalents

Included in cash and cash equivalents is cash, overnight repurchase agreement accounts, money market funds and term deposits. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.

Restricted Cash and Equivalents

Restricted cash and cash equivalents represent restricted cash and uninsured term deposits.

Notes Payable

Notes Payable represent our short-term corporate term loan and borrowings under our Revolving Credit Facility.

Long-Term Debt

For additional information on our long-term debt, see Note 8 .

139

( 6 ) PROPERTY, PLANT AND EQUIPMENT

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



Utilities Group	2012			2011			Lives ( in years)
Electric Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Electric plant:
Production	$	959,636	45	$	707,498	49	25	80
Electric transmission	234,279		50	170,146		49	40	65
Electric distribution	631,654		44	580,699		45	15	65
Plant acquisition adjustment	4,870		32	4,870		32	32	32
General	137,584		22	136,304		22	3	60
Capital lease - plant in service ^(a)	260,874		19	260,874		20	19	19
Construction work in progress	48,008			288,760
Total electric plant	2,276,905			2,149,151
Less accumulated depreciation and amortization	439,772			385,840
Electric plant net of accumulated depreciation and amortization	$	1,837,133		$	1,763,311

_____________


(a)	Capital lease - plant in service represents the assets accounted for as a capital lease under the 20-year PPA between Colorado Electric and Black Hills Colorado IPP.



	2012			2011			Lives (in years)
Gas Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Gas plant:
Production	$	13	37	$	35	37	37	37
Gas transmission	18,071		54	15,543		53	53	57
Gas distribution	474,998		46	442,114		46	41	56
General	68,856		19	56,869		19	16	22
Construction work in progress	6,305			8,813
Total gas plant	568,243			523,374
Less accumulated depreciation and amortization	68,530			52,249
Gas plant net of accumulated depreciation and amortization	$	499,713		$	471,125

140



2012									Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	139,396	$	1,323	$	38,541	$	102,178	35	2	40
Coal Mining	148,045		7,023		80,210		74,858		14	2	59
Oil and Gas	785,594		—		562,926		222,668		24	3	25
	$	1,073,035	$	8,346	$	681,677	$	399,704



2011									Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	135,051	$	930	$	35,074	$	100,907	36	2	40
Coal Mining	140,683		4,341		73,777		71,247		20	2	39
Oil and Gas	763,645		—		386,377		377,268		25	3	26
	$	1,039,379	$	5,271	$	495,228	$	549,422



2012										Lives ( in years)
	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	368	$	3,875	$	(1,956	)	$	6,199	6	2	30

___________

(a) Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.



2011									Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	2,136	$	4,705	$	1,124	$	5,717	6	2	30

141

( 7 ) JOINTLY OWNED FACILITIES

Oil and Gas

BHEP owns a 44.7 percent non-operating interest in a natural gas processing facility (the Newcastle Gas Plant). The Newcastle Gas Plant gathers and processes gas, primarily from the Finn-Shurley Field in Wyoming. We receive our proportionate share of the Newcastle Gas Plant’s net revenues and are committed to pay our proportionate share of additions, replacements and operating and maintenance expenses. Each of the respective owners is responsible for providing its own financing. As of Dec. 31, 2012 , our investment in the Newcastle Gas Plant included $4.4 million in plant and equipment which is included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. This asset is included in the asset pool being depleted and therefore accumulated depreciation is not separated by asset. Our share of direct expenses is included in the corresponding categories of revenue and expenses in the accompanying Consolidated Statements of Income.

Utility Plant

•

Black Hills Power owns a 20 percent interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. Black Hills Power receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying Black Hills Power with coal for its share of the Wyodak Plant, our Coal Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.

•

Black Hills Power also owns a 35 percent interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the tie is 400 megawatts - 200 megawatts West to East and 200 megawatts from East to West. Black Hills Power is committed to pay its proportionate share of the additions and replacements to and operating and maintenance expenses of the transmission tie.

•

Black Hills Power owns 52 percent of the Wygen III coal-fired generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations. Our Coal Mining subsidiary supplies coal to Wygen III for the life of the plant.


•	Colorado Electric owns 50 percent of the Busch Ranch Wind Project while AltaGas owns the remaining undivided ownership interest. We retain responsibility for operations of the wind farm.

Non-Regulated Plants


•	Black Hills Wyoming owns 76.5 percent of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for their share of the costs associated with administrative services, plant operations and coal supply provided by our Coal Mining subsidiary during the life of the facility. We retain responsibility for plant operations.

Our share of direct expenses for the jointly-owned utility and non-regulated facilities is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income. Each of the respective owners is responsible for providing its own financing.

142

At Dec. 31, 2012 , our interests in jointly-owned generating facilities and transmission systems were (in thousands):



	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	109,465	$	451	$	47,776
Transmission Tie	$	19,648	$	—	$	4,414
Wygen I	$	105,020	$	343	$	25,162
Wygen III	$	130,267	$	565	$	8,376
Busch Ranch Wind Project	$	17,984	$	—	$	150

( 8 ) LONG-TERM DEBT

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



	Due Date	Interest Rate	Dec. 31, 2012			Dec. 31, 2011
Corporate
Senior unsecured notes due 2013 ^{(a) (c)}	May 15, 2013	6.50%	$	—		$	225,000
Unamortized discount on notes due 2013			—			(41		)
Senior unsecured notes due 2014 ^(c)	May 15, 2014	9.00%	250,000			250,000
Senior unsecured notes due 2020 ^(c)	July 15, 2020	5.88%	200,000			200,000
Corporate term loan, variable rate ^(b)	Sept. 30, 2013	1.63%	100,000			100,000
Total Corporate Debt			550,000			774,959

Electric Utilities
First Mortgage Bonds due 2032	Aug. 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	Nov. 1, 2039	6.13%	180,000			180,000
Unamortized discount on First Mortgage Bonds due 2039			(111		)	(115		)
Pollution control revenue bonds due 2014 ^(d)	Oct. 1, 2014	4.80%	—			6,450
Pollution control revenue bonds due 2024	Oct. 1, 2024	5.35%	12,200			12,200
First Mortgage Bonds due 2037	Nov. 20, 2037	6.67%	110,000			110,000
Industrial development revenue bonds due 2021, variable rate ^(b)	Sept. 1, 2021	0.20%	7,000			7,000
Industrial development revenue bonds due 2027, variable rate ^(b)	March 1, 2027	0.20%	10,000			10,000
Series 94A Debt, variable rate ^(b)	June 1, 2024	1.35%	2,855			2,855
Other long-term debt	May 25, 2012	13.66%	—			72
Total Electric Utilities			396,944			403,462

Power Generation
Black Hills Wyoming project financing, variable rate ^(b)	Dec. 9, 2016	3.59%	95,906			104,461

Total long-term debt			1,042,850			1,282,882
Less current maturities			103,973			2,473
Net long-term debt			$	938,877		$	1,280,409

_______________


(a)	On Oct. 31, 2012, we redeemed these senior unsecured notes. See discussion below.


(b)	Variable interest rates; rates presented are as of Dec. 31, 2012 .


(c)	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.


(d)	On May 15, 2012, Black Hills Power repaid these Pollution Control Refund Revenue Bonds. See discussion below.

143

Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):



2013	$	103,973
2014	$	256,023
2015	$	6,963
2016	$	78,947
2017	$	—
Thereafter	$	597,055

Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at Dec. 31, 2012 .

Substantially all of the tangible utility property of Black Hills Power and Cheyenne Light is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of Black Hills Power and Cheyenne Light may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. The first mortgage bonds issued by Black Hills Power and Cheyenne Light are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds.

Early Redemption of Long-term Debt

On Oct. 31, 2012, we redeemed $225.0 million of senior unsecured 6.5 percent notes, which were originally scheduled to mature on May 15, 2013 for $238.8 million . The payment included accrued interest and a make-whole provision of $7.1 million included in Interest expense on the accompanying Consolidated Statements of Income.

On May 15, 2012 , Black Hills Power repaid its 4.8 percent Pollution Control Revenue Bonds in full for $6.5 million principal and interest. These bonds were originally due to mature on Oct. 1, 2014 .

Loan Extensions

Our $100.0 million term loan (the “Loan”) with J.P. Morgan and Union Bank was extended through Sept. 30, 2013 . The cost of borrowings under the Loan was based on a spread of 1.375 percent over LIBOR ( 1.63 percent at Dec. 31, 2012 ). The covenants are substantially the same as the Revolving Credit Facility.

Amortization Expense

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):



	Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheet at		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2012		2012		2011		2010
Senior unsecured notes due 2014	$	634	$	462	$	462	$	462
Senior unsecured notes due 2020	$	1,260	$	167	$	167	$	77
First mortgage bonds due 2032	$	651	$	33	$	33	$	33
First mortgage bonds due 2039	$	2,037	$	76	$	76	$	76
First mortgage bonds due 2037	$	766	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016	$	3,177	$	1,037	$	1,012	$	1,036
Other	$	721	$	57	$	70	$	74

( 9 ) NOTES PAYABLE

Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of Dec. 31, 2012 , we were in compliance with all of these covenants.

144

We had the following short-term debt outstanding at the Consolidated Balance Sheet dates (in thousands):



	Dec. 31, 2012				Dec. 31, 2011
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	127,000	$	36,300	$	195,000	$	43,700
Term Loan due June 2013 ^(a)	150,000		—		150,000		—
Total	$	277,000	$	36,300	$	345,000	$	43,700

__________


(a)	In June 2012, this short-term loan was extended for one year. See discussion below.

Revolving Credit Facility

On Feb. 1, 2012 , we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017 . The facility contains an accordion feature allowing us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million . The Revolving Credit Facility can be used for the issuance of letters of credit, to fund working capital needs and for other corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.50 percent , 1.50 percent and 1.50 percent , respectively, at Dec. 31, 2012 . The facility contains a commitment fee that is charged on the unused amount of the Revolving Credit Facility. Based upon current credit ratings, the fee is 0.25 percent .

Deferred financing costs on the new facility of $2.8 million are being amortized over the estimated useful life of the Revolving Credit Facility and included in Interest expense on the accompanying Consolidated Statements of Income. Upon entering into the Revolving Credit Facility, $1.5 million of deferred financing costs relating to the previous credit facility were written off through Interest expense. The deferred financing costs on the new facility are being amortized as follows (in thousands):



	Deferred Financing Costs Remaining on Balance Sheet as of		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2012		2012		2011		2010
Revolving Credit Facility	$	2,068	$	2,187	$	1,891	$	1,340

Corporate Term Loans

In June 2012, we extended our one-year $150.0 million unsecured, single draw term loan until June 24, 2013 . The cost of borrowing under the extended loan is based on a spread of 1.10 percent over LIBOR ( 1.35 percent at Dec. 31, 2012 ). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional requirement to maintain a minimum consolidated net worth. We were in compliance with these covenants as of Dec. 31, 2012 .

Debt Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):



	At Dec. 31, 2012			Covenant Requirement
Consolidated net worth	$	1,232,509		Greater than	$	924,895
Recourse leverage ratio	53.8		%	Less than	65.0		%

145

( 10 ) ASSET RETIREMENT OBLIGATIONS

We have identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in the Oil and Gas segment, reclamation of coal mining sites at the Coal Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines at the regulated Electric Utilities segment and asbestos at our regulated Gas Utilities segment. We periodically review and update estimated costs related to these asset retirement obligations. The actual cost may vary from estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials and equipment.

The following tables present the details of ARO which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):



	Dec. 31, 2011		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates ^(a)		Dec. 31, 2012
Electric Utilities	$	3,064	$	3,626	$	—		$	291	$	—	$	6,981
Gas Utilities	270		—		(22		)	11		—		259
Coal Mining	17,158		1,627		—			921		580		20,286
Oil and Gas	22,422		158		(1,059		)	1,345		156		23,022
Total	$	42,914	$	5,411	$	(1,081	)	$	2,568	$	736	$	50,548



	Dec. 31, 2010		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates ^(a)			Dec. 31, 2011
Electric Utilities	$	3,039	$	—	$	—		$	25	$	—		$	3,064
Gas Utilities	255		—		—			15		—			270
Coal Mining	17,560		—		—			1,123		(1,525		)	17,158
Oil and Gas	21,663		43		(627		)	1,343		—			22,422
Total	$	42,517	$	43	$	(627	)	$	2,506	$	(1,525	)	$	42,914

_____________________


(a)	The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium.

We also have legally required AROs related to certain assets within our electric and gas utility transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a value for the cost of these obligations cannot be measured at this time.

( 11 ) COMMON STOCK

Equity Issuance

On Nov. 10, 2010 , we entered into an Equity Forward Agreement with J.P. Morgan in connection with a public offering of 4,000,000 shares of Black Hills Corporation common stock. Subsequently, the underwriters exercised the over-allotment option to purchase 413,519 additional shares under the same terms as the original Forward Equity Agreement. We settled the equity forward instrument on Nov. 1, 2011 by physically delivering 4,413,519 shares of common stock in return for proceeds of $119.6 million .

Equity Compensation Plans

Our 2005 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 863,929 shares available to grant at Dec. 31, 2012 .

146

Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of Dec. 31, 2012 , total unrecognized compensation expense related to non-vested stock awards was $7.8 million and is expected to be recognized over a weighted-average period of 1.9 years . Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follow (in thousands):



	2012		2011		2010
Stock-based compensation expense	$	8,271	$	5,643	$	5,637

Stock Options

We have granted options with an option exercise price equal to the fair market value of the stock on the day of the grant. The options granted vest proportionately over 3 years and expire 10 years after the grant date.

A summary of the status of the stock options at Dec. 31, 2012 was as follows:



	Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)				(in years)	(in thousands)
Balance at beginning of period	264		$	30.50
Granted	—		—
Forfeited/canceled	(16	)	32.04
Expired	(26	)	34.97
Exercised	(101	)	28.21
Balance at end of period	121		$	31.23	5.7	$	619

Exercisable at end of period	71		$	30.65	3.8	$	404

The table below provides details of our option plans at Dec. 31 (in thousands):



	2012		2011		2010
Summary of Stock Options
Unrecognized compensation expense	$	218	$	479	$	—
Intrinsic value of options exercised ^(a)	$	623	$	94	$	234
Net cash received from exercise of options	$	2,839	$	1,009	$	1,034
Tax benefit realized from exercise of shares ^(b)	$	218	$	33	$	82

_____________________


(a)	The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.


(b)	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.

As of December 31, 2012 , the unrecognized compensation expense related to non-vested stock options is expected to be recognized over a weighted-average period of 1.4 years .

Restricted Stock and Restricted Stock Units

The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant.

The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years , contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.

147

A summary of the status of the restricted stock and non-vested restricted stock units at Dec. 31, 2012 was as follows:



	Restricted Stock and Stock Units		Weighted-Average Grant Date Fair Value
	(in thousands)
Restricted Stock and Restricted Stock Units balance at beginning of period	278		$	28.82
Granted	151		34.99
Vested	(108	)	27.94
Forfeited	(34	)	30.22
Restricted Stock and Restricted Stock Units balance at end of period	287		$	32.23

The weighted-average grant-date fair value of restricted stock and restricted stock units granted and the total fair value of shares vested during the years ended Dec. 31 was as follows:



	Weighted-Average Grant Date Fair Value		Total Fair Value of Shares Vested
			(in thousands)
2012	$	34.99	$	3,781
2011	$	30.33	$	3,211
2010	$	27.30	$	2,212

As of Dec. 31, 2012 , there was $5.2 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.0 years .

Performance Share Plan

Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria.

The performance awards are paid 50 percent in cash and 50 percent in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100 percent in cash. If it is determined that a change-in-control is probable, the equity portion of $1.7 million at Dec. 31, 2012 would be reclassified as a liability.

Outstanding performance periods at Dec. 31 were as follows (shares in thousands):



			Possible Payout Range of Target
Grant Date	Performance Period	Target Grant of Shares	Minimum	Maximum
Jan. 1, 2010	Jan. 1, 2010 - Dec. 31, 2012	66	0%	175%
Jan. 1, 2011	Jan. 1, 2011 - Dec. 31, 2013	62	0%	175%
Jan. 1, 2012	Jan. 1, 2012 - Dec. 31, 2014	65	0%	200%

148

A summary of the status of the Performance Share Plan at Dec. 31 was as follows:



	Equity Portion				Liability Portion
	Shares		Weighted-Average Grant Date Fair Value		Shares		Weighted-Average Dec. 31, 2012 Fair Value
	(in thousands)				(in thousands)
Performance Shares balance at beginning of period	106		$	26.47	106
Granted	33		32.26		33
Forfeited	(7	)	26.19		(7	)
Vested	(36	)	29.20		(36	)
Performance Shares balance at end of period	96		$	27.49	96		$	26.04

The grant date fair values for the performance shares granted in 2012 , 2011 and 2010 were determined by Monte Carlo simulation using a blended volatility of 21 percent , 30 percent and 31 percent , respectively, comprised of 50 percent historical volatility and 50 percent implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.

The weighted-average grant-date fair value of performance share awards granted in the years ended was as follows:



	Weighted Average Grant Date Fair Value
Dec. 31, 2012	$	32.26
Dec. 31, 2011	$	25.92
Dec. 31, 2010	$	24.26

Performance plan payouts have been as follows (dollars and shares in thousands):



Performance Period	Year of Payment	Stock Issued	Cash Paid		Total Intrinsic Value
Jan. 1, 2009 to Dec. 31, 2011	2012	—	$	—	$	—
Jan. 1, 2008 to Dec. 31, 2010	2011	—	$	—	$	—
Jan. 1, 2007 to Dec. 31, 2009	2010	—	$	—	$	—

On Jan. 30, 2013, the Compensation Committee of our Board of Directors determined that the company’s total shareholder return for the Jan. 1, 2010 through Dec. 31, 2012 performance period was at the 78 ^th percentile of its peer group and confirmed a payout equal to 170.75 percent of target shares, valued at $4.5 million . The payout was fully accrued at Dec. 31, 2012 .

As of Dec. 31, 2012 , there was $2.4 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.7 years .

Dividend Reinvestment and Stock Purchase Plan

We have a DRIP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100 percent of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We are currently issuing new shares.

149

A summary of the Dividend Reinvestment and Stock Purchase Plan for the years ended and at Dec. 31, is as follows (shares in thousands):



	2012		2011
Shares Issued	101		103

Weighted Average Price	$	33.58	$	31.23

Unissued Shares Available	353		453

Dividend Restrictions

Our credit facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of Dec. 31, 2012 , we were in compliance with these covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at Dec. 31, 2012 :


•	Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of Dec. 31, 2012 , the restricted net assets at our Utilities Group were approximately $263.1 million .


•	As required by the covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted shareholders’ equity of at least $100.0 million .

( 12 ) IMPAIRMENT OF LONG-LIVED ASSETS

Under the full cost method of accounting used by our Oil and Gas segment to account for exploration, development, and acquisition of crude oil and natural gas reserves, all costs attributable to these activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge.

As a result of continued low commodity prices in the second quarter of 2012, we recorded a $26.9 million non-cash impairment of oil and gas assets included in the Oil and Gas segment. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead; for crude oil, the average NYMEX price was $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead.

( 13 ) OPERATING LEASES

We have entered into lease agreements for vehicles, equipment and office facilities. Rental expense incurred under these operating leases, including month to month leases, for the years ended Dec. 31 was as follows (in thousands):



	2012		2011		2010
Rent expense	$	6,839	$	6,125	$	4,219

150

The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):



2013	$	2,690
2014	$	2,377
2015	$	2,144
2016	$	1,465
2017	$	1,269
Thereafter	$	2,811

( 14 ) INCOME TAXES

Income tax expense (benefit) from continuing operations for the years ended Dec. 31 was (in thousands):



	2012			2011			2010
Current:
Current federal income tax expense (benefit)	$	4,972		$	(14,539	)	$	678
Current state income tax expense (benefit)	3,712			(837		)	4,137
	8,684			(15,376		)	4,815
Deferred:
Deferred federal income tax expense (benefit)	39,876			30,876			20,186
Deferred state income tax expense (benefit)	68			2,970			(2,495		)
Tax credit amortization expense (benefit)	(228		)	(246		)	(337		)
	39,716			33,600			17,354

Total income tax expense (benefit)	$	48,400		$	18,224		$	22,169

151

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



	2012			2011
Deferred tax assets:
Asset valuation reserves	$	3,101		$	2,605
Regulatory liabilities	57,471			40,642
Employee benefits	23,767			22,488
Items of other comprehensive income (loss)	20,038			36,398
Derivative fair value adjustments	35,947			39,099
State net operating loss	8,300			12,311
Federal net operating loss	147,153			195,834
Asset impairment	55,971			47,033
State tax credits	15,546			—
Other deferred tax assets	25,101			17,683
Less: Valuation allowance	(6,192		)	(773		)
Total deferred tax assets	386,203			413,320

Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(571,262		)	(508,261		)
Regulatory assets	(23,537		)	(23,498		)
Mining development and oil exploration	(48,411		)	(94,334		)
Deferred costs	(17,723		)	(15,663		)
State deferred tax liability	(19,986		)	(14,611		)
Other deferred tax liabilities	(13,961		)	(20,739		)
Total deferred tax liabilities	(694,880		)	(677,106		)

Net deferred tax liability	$	(308,677	)	$	(263,786	)

152

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



	2012		2011		2010
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax (net of federal tax effect)	2.0		1.8		1.1
Amortization of excess deferred and investment tax credits	(0.2	)	(0.5	)	(0.4	)
Percentage depletion in excess of cost	(1.3	)	(2.5	)	(1.7	)
Equity AFUDC	—		(0.5	)	(1.0	)
Tax credits	—		—		(3.2	)
Accounting for uncertain tax positions adjustment	0.8		2.8		1.2
Flow-through adjustments ^(a)	(1.3	)	(4.5	)	(4.6	)
Other tax differences	0.4		(0.5	)	(0.4	)
	35.4	%	31.1	%	26.0	%

_________________________

(a)

The flow-through adjustments relate primarily to an accounting method change for tax purposes that was filed with the 2008 tax return and for which consent was received from the IRS in September 2009. The effect of the change allows us to take a current tax deduction for repair costs that were previously capitalized for tax purposes. These costs will continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. Due to this regulatory treatment, we recorded an income tax benefit in 2010 that was attributable to the 2008 through 2010 tax years. We continue to record a tax benefit consistent with the flow through method in accordance with such regulatory treatment.

At Dec. 31, 2012 , we had federal and state NOL carryforwards of $425.8 million and $475.6 million , respectively, which will expire at various dates as follows (in thousands):



Expiration Years	Federal Net Operating Loss Carry forward		State Net Operating Loss Carry forward
2014-2019	$	2,217	$	146,854
2020-2025	$	16,461	$	119,459
2026-2031	$	407,086	$	209,319

As of Dec. 31, 2012 , we had a $2.2 million valuation allowance against the state NOL carryforwards. The re-evaluation of our ability to utilize such NOLs resulted in an increase of the valuation allowance of approximately $1.4 million and an increase to tax expense. The valuation allowance adjustment was primarily attributable to an increase in the NOL generated, as trued up with the filing of the 2011 tax return, in certain states whose carryforward period is much shorter than what is allowed for federal income tax purposes. Ultimate usage of these NOLs depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.

153

The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):



	Changes in Uncertain Tax Positions
Beginning balance at Jan. 1, 2010	$	107,088
Additions for prior year tax positions	19,592
Reductions for prior year tax positions	(76,545		)
Additions for current year tax positions	—
Settlements	—
Ending balance at Dec. 31, 2010	50,135
Additions for prior year tax positions	2,725
Reductions for prior year tax positions	(3,533		)
Additions for current year tax positions	—
Settlements	—
Ending balance at Dec. 31, 2011	49,327
Additions for prior year tax positions	111
Reductions for prior year tax positions	(8,906		)
Additions for current year tax positions	151
Settlements	—
Ending balance at Dec. 31, 2012	$	40,683

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $1.5 million .

We recognized the following interest expense for the years ended Dec. 31 as follows (in thousands):



	2012		2011		2010
Interest expense included in income tax expense	$	1,400	$	1,400	$	2,300

We had approximately $8.3 million pre-tax and $6.9 million pre-tax of accrued interest associated with income taxes at December 31, 2012 and 2011 , respectively.

We file income tax returns with the IRS, various state jurisdictions and Canada. We are currently under examination by the IRS for the 2007 , 2008 and 2009 tax years and by the state of Colorado for tax years 2001 through 2009 . We remain subject to examination by Canadian income tax authorities for tax years as early as 1999 .

We have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125.0 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS has challenged our position with respect to the like-kind exchange and it is reasonably possible that the total unrecognized tax benefits attributable to such transaction could change significantly due to a settlement with the IRS prior to Dec. 31, 2013. However, based on the information currently available, it is difficult to determine any reasonable estimate of the financial statement impact including the impact on the effective tax rate.

154

Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At Dec. 31, 2012 , we had remaining foreign tax credit carryforwards of approximately $2.3 million , which break down as follows (in thousands):



Foreign Tax Credit Carryforward, Gross		Expiration Year
$	263	2012
$	6	2013
$	376	2014
$	693	2015
$	5	2016
$	41	2017
$	961	2018

As of Dec. 31, 2012 , we had a $0.5 million valuation allowance against the foreign tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in the establishment of a valuation allowance and an increase to tax expense. Utilization of the foreign tax credit carryforward balance is expected to be included as computational adjustments upon finalization of our current IRS examination covering tax years 2007 to 2009 . Due to the expectation that the IRS examination will come to a conclusion within the next twelve months, the balance was reclassified to current tax assets and netted against current tax liability. In addition, approximately $1.8 million of foreign tax credit carryforward is reflected as an offset to liabilities for unrecognized tax benefits in recognition of the estimated impact the resolution of material uncertain tax positions could have with respect to utilization of such carryforward.

State tax credits have been generated and are available to offset future state income taxes. At Dec. 31, 2012 , we had the following state tax credit carryforwards (in thousands):



State Tax Credit Carryforwards			Expiration Year
Investment tax credit	$	14,711	2023
Research and development	$	835	No expiration

As of Dec. 31, 2012 , we had a $3.4 million valuation allowance against the state tax credit carryforwards. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense.

( 15 ) ACCUMULATED OTHER COMPREHENSIVE INCOME

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



	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
As of Dec. 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)
Other comprehensive income (loss)	(1,911		)	(699		)	(2,610		)
As of Dec. 31, 2012	$	(15,713	)	$	(19,775	)	$	(35,488	)


	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
As of Dec. 31, 2010 *	$	(12,439	)	$	(11,142	)	$	(23,581	)
Other comprehensive income (loss)	(1,363		)	(7,934		)	(9,297		)
As of Dec. 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)

____________

* Includes cash flow hedges of equity method investee related to the Idaho Cogeneration Facilities.

155

( 16 ) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Years ended Dec. 31,	2012			2011			2010
	(in thousands)
Non-cash investing activities and financing from continuing operations -
Property, plant and equipment acquired with accrued liabilities	$	35,556		$	37,529		$	48,879
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	5,743		$	(1,525	)	$	(1,858	)

Cash (paid) refunded during the period for continuing operations-
Interest (net of amount capitalized)	$	(116,593	)	$	(103,110	)	$	(101,947	)
Income taxes, net	$	(3,027	)	$	9,854		$	9,384

( 17 ) BUSINESS SEGMENTS INFORMATION

Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. All of our operations and assets are located within the United States.

On Feb. 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being reclassified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment as discontinued operations. Indirect corporate costs and inter-segment interest expense related to Enserco that have not been classified as discontinued operations have been reclassified to our Corporate segment. For further information see Note 23 .

Segment information was as follows (in thousands):



Total Assets (net of inter-company eliminations) as of Dec. 31,	2012		2011
Utilities:
Electric ^(a)	$	2,387,458	$	2,254,914
Gas	765,165		746,444
Non-regulated Energy:
Power Generation ^(a)	119,170		129,121
Coal Mining	83,810		88,704
Oil and Gas	258,460		425,970
Corporate ^(b)	115,408		141,079
Discontinued Operations ^(c)	—		340,851
Total assets	$	3,729,471	$	4,127,083

__________________


(a)	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.


(b)	Deferred taxes that were not classified as discontinued operations are now included in the Corporate segment in 2011.


(c)	See Note 23 for further information relating to discontinued operations.

156



Capital Expenditures and Asset Acquisitions ^(a) for the years ended Dec. 31,	2012		2011
Utilities:
Electric Utilities	$	167,263	$	173,078
Gas Utilities	45,711		43,954
Non-regulated Energy:
Power Generation	5,547		98,927
Coal Mining	13,420		10,438
Oil and Gas	107,839		89,672
Corporate	7,376		13,279
Total capital expenditures and asset acquisitions of continuing operations	347,156		429,348
Total capital expenditures of discontinued operations	824		2,359
Total capital expenditures and asset acquisitions	$	347,980	$	431,707

_________________


(a)	Includes accruals for property, plant and equipment.



Property, Plant and Equipment as of Dec. 31,	2012		2011
Utilities:
Electric Utilities ^(a)	$	2,276,905	$	2,149,151
Gas Utilities	568,243		523,374
Non-regulated Energy:
Power Generation ^(a)	140,719		135,981
Coal Mining	155,068		145,024
Oil and Gas	785,594		763,645
Corporate	4,243		6,841
Total property, plant and equipment	$	3,930,772	$	3,724,016

_______________


(a)	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.

157



	Consolidating Income Statement
Year ended Dec. 31, 2012	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	610,732		$	454,081		$	4,189		$	25,810		$	79,072		$	—		$	—		$	1,173,884
Inter-company revenue	16,234			—			75,200			31,968			—			196,453			(319,855		)	—
Fuel, purchased power and cost of gas sold	273,474			245,349			—			—			—			—			(111,757		)	407,066
Gross margin	353,492			208,732			79,389			57,778			79,072			196,453			(208,098		)	766,818

Operations and maintenance	146,527			117,390			29,991			42,553			43,267			179,059			(188,051		)	370,736
Gain on sale of operating assets ^(a)	—			—			—			—			(29,129		)	—			—			(29,129		)
Depreciation, depletion and amortization	75,244			25,163			4,599			13,060			38,494			10,936			(12,864		)	154,632
Impairment of long-lived assets ^(b)	—			—			—			—			26,868			—			—			26,868
Operating income (loss)	131,721			66,179			44,799			2,165			(428		)	6,458			(7,183		)	243,711

Interest expense ^(c)	(59,194		)	(26,746		)	(15,452		)	(238		)	(4,539		)	(92,650		)	85,209			(113,610		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			1,882			—			1,882
Interest income	8,153			2,765			695			1,168			604			64,695			(76,123		)	1,957
Other income (expense), net	1,182			105			7			2,616			207			48,769			(49,921		)	2,965
Income tax benefit (expense)	(30,264		)	(14,313		)	(8,721		)	(85		)	1,927			3,187			(131		)	(48,400		)
Income (loss) from continuing operations	$	51,598		$	27,990		$	21,328		$	5,626		$	(2,229	)	$	32,341		$	(48,149	)	$	88,505

________________


(a)	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 22 ).


(b)	Oil and Gas includes a ceiling test impairment (see Note 12 ).


(c)	Corporate includes a make-whole provision from early repayment of long-term debt (see Note 8 ).

158



	Consolidating Income Statement
Year ended Dec. 31, 2011	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	600,935		$	554,584		$	4,059		$	32,802		$	79,808		$	—		$	—		$	1,272,188
Inter-company revenue	13,396			—			27,613			34,090			—			192,250			(267,349		)	—
Fuel, purchased power and cost of gas sold	310,352			331,961			—			—			—			97			(67,421		)	574,989
Gross margin	303,979			222,623			31,672			66,892			79,808			192,153			(199,928		)	697,199

Operations and maintenance	142,815			121,980			16,538			56,617			41,380			170,947			(174,908		)	375,369
Gain on sale of operating assets ^(a)	(768		)	—			—			—			—			1			767			—
Depreciation, depletion and amortization	52,475			24,307			4,199			18,670			35,690			11,205			(10,955		)	135,591
Operating income (loss)	109,457			76,336			10,935			(8,395		)	2,738			10,000			(14,832		)	186,239

Interest expense	(53,770		)	(31,621		)	(8,903		)	(9		)	(5,896		)	(93,314		)	102,130			(91,383		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			(42,010		)	—			(42,010		)
Interest income	14,794			5,645			1,529			3,897			2			64,299			(88,149		)	2,017
Other income (expense), net	481			217			1,094			2,192			(216		)	46,510			(46,552		)	3,726
Income tax benefit (expense)	(23,271		)	(16,408		)	(1,644		)	1,891			1,651			19,289			268			(18,224		)
Income (loss) from continuing operations	$	47,691		$	34,169		$	3,011		$	(424	)	$	(1,721	)	$	4,774		$	(47,135	)	$	40,365

_________________


(a)	Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.

159



	Consolidating Income Statement
Year ended Dec. 31, 2010	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	554,617		$	550,707		$	4,297		$	31,285		$	74,164		$	—		$	—		$	1,215,070
Inter-company revenue	15,397			—			26,052			26,557			—			140,756			(204,141		)	4,621
Fuel, purchased power and cost of gas sold	292,811			333,717			—			—			—			150			(59,711		)	566,967
Gross margin	277,203			216,990			30,349			57,842			74,164			140,606			(144,430		)	652,724

Operations and maintenance	136,873			125,447			16,210			34,028			39,299			129,641			(129,879		)	351,619
Gain on sale of operating assets ^(a)	(6,238		)	(2,683		)	—			—			—			—			—			(8,921		)
Depreciation, depletion and amortization	47,276			25,258			4,466			19,083			30,283			9,469			(9,229		)	126,606
Operating income (loss)	99,292			68,968			9,673			4,731			4,582			1,496			(5,322		)	183,420

Interest expense	(43,855		)	(28,927		)	(9,303		)	(177		)	(5,380		)	(75,406		)	72,442			(90,606		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			(15,193		)	—			(15,193		)
Interest income	6,812			1,472			1,193			3,357			8			54,472			(66,773		)	541
Other income (expense), net	3,215			47			854			2,149			722			28,768			(28,607		)	7,148
Income tax benefit (expense)	(18,012		)	(14,449		)	(266		)	(2,379		)	425			12,512			—			(22,169		)
Income (loss) from continuing operations	$	47,452		$	27,111		$	2,151		$	7,681		$	357		$	6,649		$	(28,260	)	$	63,141

______________________


(a)	Electric Utilities includes gain on sale to the City of Gillette of an ownership interest in the Wygen III power generation facility. Gas Utilities includes a gain on the sale of operating assets at Nebraska Gas (see Note 22 ).

( 18 ) EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50 percent of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides a Company Matching Contribution for all eligible participants and for certain eligible participants a Company Retirement Contribution based on the participant’s age and years of service. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20 percent per year with 100 percent vesting when the participant has 5 years of service with the Company.

Funded Status of Benefit Plans

The funded status of postretirement benefit plans is required to be recognized in the statement of financial position. The funded status for pension plans is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. Except for our regulated utilities, the unrecognized net periodic benefit cost is recorded within Accumulated other comprehensive income (loss), net of tax. For our regulated utilities, these costs are recoverable in our rates, and accordingly, the unrecognized net periodic benefit cost was alternatively recorded as a regulatory asset or regulatory liability, net of tax (see Note 1 ). The measurement date for all plans is Dec. 31 . As of Dec. 31, 2012 , the funded status of our Defined Benefit Pension Plans was $(94.4) million ; the funded status of our Supplemental Non-qualified Defined Benefit Plans was $(34.4) million ; and the funded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $(42.3) million .

160

Defined Benefit Pension Plans (Pension Plans)

Our BHC Pension Plan covers certain eligible employees of Black Hills Service Company, Black Hills Power, WRDC, BHEP and Cheyenne Light. The Black Hills Utility Holdings, Inc. Pension Plan covers certain eligible employees of Black Hills Energy. The benefits for the Pension Plans are based on year of service and calculations of average earnings during a specific time period prior to retirement. As of Jan. 1, 2012, both Pension Plans have been frozen to new employees and certain employees who did not meet age and service based criteria at the time the Pension Plans were frozen.

In 2011, the Cheyenne Light Pension Plan was amended to freeze the benefits of certain bargaining unit employees. This amendment was effective as of Jan. 1, 2012 . Additionally, effective Oct. 1, 2012 , the Cheyenne Light Pension Plan was merged into the BHC Pension Plan. The Pension Plan benefits are based on years of service and compensation levels.

On Oct. 29, 2012, our Board of Directors approved a new Investment Policy. The objective of the Investment Policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plans’ beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a structured portfolio strategy that will provide liquidity to meet the Plans’ benefit payment obligations. The Pension Plans’ assets are held in trust and consist primarily of equity and fixed income investments. The expected long-term rate of return for investments was 7.25 percent and 8.75 percent for the 2012 and 2011 plan years, respectively. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements.

Plan Assets

The percentages of total plan asset fair value by investment category for our Pension Plans at Dec. 31 were as follows:



	2012		2011
Equity	47	%	64	%
Real estate	8		3
Fixed income	44		32
Cash	1		1
Total	100	%	100	%

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company.

Plan Assets

We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor three retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Healthcare Plans periodically. A portion of the Healthcare Plans is pre-funded via VEBAs. We have determined that the post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

Plan Assets

We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Energy Plan provides for partial pre-funding via VEBAs. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees of Black Hills Energy located in the states of Kansas and Iowa. We do not pre-fund the Postretirement Healthcare Plans for those employees outside Kansas and Iowa.

161

Plan Contributions

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



	2012		2011
Defined Contribution Plan
Company Retirement Contribution	$	2,639	$	2,440
Matching contributions - Defined Contribution Plans	$	8,981	$	8,916



	2012		2011
Defined Benefit Plans
Defined Benefit Pension Plans	$	25,350	$	11,050
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	5,191	$	4,963
Supplemental Non-Qualified Defined Benefit Plans	$	1,270	$	956

While we do not have required contributions, we expect to make approximately $8.8 million in contributions to our Pension Plans in 2013.

Fair Value Measurements

As required by accounting standards for Compensation - Retirement Benefits, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels.

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):



Defined Benefit Pension Plans	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	1,486	$	—	$	—	$	1,486
Common Collective Trust - Money Market	—		1,118		—		1,118
Common Collective Trust - Equity	—		126,105		—		126,105
Common Collective Trust - Fixed Income	—		114,440		—		114,440
Common Collective Trust - Real Estate	—		13,361		7,770		21,131
Structured Products	—		4,536		—		4,536
Insurance Contracts	—		—		—		—
Total investments measured at fair value	$	1,486	$	259,560	$	7,770	$	268,816

162



Defined Benefit Pension Plans	Dec. 31, 2011
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	70	$	—	$	—	$	70
Registered Investment Companies - Equity	23,498		—		—		23,498
Registered Investment Companies - Fixed Income	23,422		—		—		23,422
103-12 Investment Entities - Equity	—		10,329		—		10,329
Common Collective Trust - Money Market	—		25		—		25
Common Collective Trust - Equity	—		103,004		—		103,004
Common Collective Trust - Fixed Income	—		48,024		—		48,024
Common Collective Trust - Real Estate	—		—		7,042		7,042
Structured Products	—		3,884		—		3,884
Insurance Contracts	—		2,424		—		2,424
Total investments measured at fair value	$	46,990	$	167,690	$	7,042	$	221,722



Non-pension Defined Benefit Postretirement Plans	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Common Collective Trust - Money Market	$	—	$	4,351	$	—	$	4,351
Total investments measured at fair value	$	—	$	4,351	$	—	$	4,351



Non-pension Defined Benefit Postretirement Plan	Dec. 31, 2011
	Level 1		Level 2		Level 3		Total
Common Collective Trust - Money Market	$	—	$	4,319	$	—	$	4,319
Total investments measured at fair value	$	—	$	4,319	$	—	$	4,319

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



	2012		2011
Balance, beginning of period	$	7,043	$	6,126
Unrealized gain (loss)	727		917
Balance, end of period	$	7,770	$	7,043

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



	Fair Value at		Valuation	Unobservable	Range (Weighted)
	Dec. 31, 2012		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate ^(a)	$	7,770	Market Approach	Redemption Restriction	N/A

_____________

(a)

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

163

Additional information about assets of the Pension Plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:

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

103-12 Investment Entities: The trustee determines the value of the pooled trust fund and the units thereof in U.S. Dollars as of (i) each daily valuation date, and (ii) each other day designated by mutual agreement between the trustee and the investment manager. As of each valuation date, the trustee shall determine the total value of the assets of the pooled trust fund, including the value of any interest accrued or dividends payable with respect thereto, shall be determined and securities valued as of the close of business in the applicable trading market coinciding with or next preceding the close of business on the New York Stock Exchange.

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

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

Structured Products: Investments are created through the process of financial engineering, (that is, by combining underlying securities like equity, bonds, or indices with derivatives). The value of derivative securities, such as options, forwards and swaps is determined by (respectively, derives from) the prices of the underlying securities.

Other Plan Information

The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the statement of financial position, components of the net periodic expense and elements of accumulated other comprehensive income (in thousands):

Benefit Obligations



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2012			2011			2012			2011			2012			2011
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	325,944		$	280,623		$	30,223		$	24,725		$	50,141		$	46,304
Service cost	5,720			5,421			889			1,028			1,610			1,498
Interest cost	14,747			14,929			1,410			1,298			2,093			2,168
Actuarial (gain) loss	28,639			36,543			3,140			4,128			(4,430		)	3,017
Amendments	—			—			—			—			—			(160		)
Benefits paid	(11,815		)	(11,178		)	(1,269		)	(956		)	(5,190		)	(4,963		)
Plan curtailment liability reduction	—			(394		)	—			—			—			—
Medicare Part D accrued	—			—			—			—			289			188
Plan participants’ contributions	—			—			—			—			2,168			2,089
Projected benefit obligation at end of year	$	363,235		$	325,944		$	34,393		$	30,223		$	46,681		$	50,141

164

A reconciliation of the fair value of Plan assets was as follows (in thousands):



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans ^(a)
	2012			2011			2012		2011		2012			2011
Beginning market value of plan assets	$	221,722		$	220,164		$	—	$	—	$	4,319		$	4,564
Investment income (loss)	33,559			1,686			—		—		(3		)	1
Employer contributions	25,350			11,050			—		—		2,172			2,087
Retiree contributions	—			—			—		—		1,458			1,366
Benefits paid	(11,815		)	(11,178		)	—		—		(3,595		)	(3,713		)
Plan administrative expenses	—			—			—		—		—			14
Ending market value of plan assets	$	268,816		$	221,722		$	—	$	—	$	4,351		$	4,319

____________________


(a)	Asset of VEBA

Amounts recognized in the Consolidated Balance Sheets at Dec. 31 consist of (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2012		2011		2012		2011		2012		2011
Regulatory assets	$	94,199	$	93,423	$	—	$	—	$	6,438	$	9,161
Current liabilities	$	—	$	—	$	1,286	$	1,116	$	2,573	$	3,522
Non-current liabilities	$	94,410	$	104,214	$	33,180	$	30,953	$	39,807	$	42,313
Regulatory liabilities	$	—	$	—	$	—	$	—	$	2,174	$	590

Accumulated Benefit Obligation



(in thousands)	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2012		2011		2012		2011		2012		2011
Accumulated benefit obligation - Black Hills Corporation	$	124,143	$	106,800	$	28,056	$	23,023	$	12,309	$	14,313
Accumulated benefit obligation - Black Hills Energy	202,897		184,345		453		446		25,868		25,842
Accumulated benefit obligation - Cheyenne Light	—		5,731		—		—		8,504		9,986
Total Accumulated Benefit Obligation	$	327,040	$	296,876	$	28,509	$	23,469	$	46,681	$	50,141

165

Components of Net Periodic Expense



(in thousands)	Defined Benefit Pension Plans									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2012			2011			2010			2012		2011		2010		2012			2011			2010
Service cost	$	5,720		$	5,421		$	6,131		$	889	$	1,028	$	685	$	1,610		$	1,498		$	1,509
Interest cost	14,747			14,929			15,091			1,410		1,298		1,284		2,093			2,168			2,446
Expected return on assets	(16,334		)	(16,955		)	(14,493		)	—		—		—		(78		)	(164		)	(208		)
Amortization of prior service cost	89			99			99			3		3		3		(500		)	(479		)	(309		)
Recognized net actuarial loss (gain)	9,630			4,540			3,126			807		510		285		887			677			636
Curtailment expense	—			13			57			—		—		—		—			—			—
Net periodic expense	$	13,852		$	8,047		$	10,011		$	3,109	$	2,839	$	2,257	$	4,012		$	3,700		$	4,074

Accumulated Other Comprehensive Income

In accordance with accounting standards for defined benefit plans, amounts included in Accumulated other comprehensive income (loss), after-tax, that have not yet been recognized as components of net periodic benefit cost at Dec. 31 were as follows (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2012		2011		2012		2011		2012			2011
Net (gain) loss	$	12,090	$	11,472	$	7,283	$	6,894	$	2,097		$	2,556
Prior service cost (gain)	78		98		11		12		(1,784		)	(1,956		)
Total accumulated other comprehensive (income) loss	$	12,168	$	11,570	$	7,294	$	6,906	$	313		$	600

The amounts in Accumulated other comprehensive income (loss), Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2013 are as follows (in thousands):



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss	$	8,005	$	515	$	313
Prior service cost (credit)	41		2		(325		)
Total net periodic benefit cost expected to be recognized during calendar year 2013	$	8,046	$	517	$	(12	)

Assumptions



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine benefit obligations:	2012		2011		2010		2012		2011		2010		2012		2011		2010

Discount rate	4.30	%	4.65	%	5.48	%	3.44	%	4.30	%	4.95	%	3.85	%	4.42	%	5.03	%
Rate of increase in compensation levels	3.84	%	3.77	%	3.79	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A

166



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine net periodic benefit cost for plan year:	2012		2011		2010		2012		2011		2010		2012		2011		2010

Discount rate:
Black Hills Corporation	4.68	%	5.50	%	6.05	%	4.70	%	5.00	%	6.10	%	4.35	%	5.00	%	5.90	%
Black Hills Energy	4.60	%	5.40	%	6.00	%	3.90	%	4.40	%	5.05	%	4.35	%	4.60	%	5.15	%
Cheyenne Light	N/A		5.55	%	6.05	%	N/A		N/A		N/A		4.65	%	5.50	%	6.00	%

Expected long-term rate of return on assets ^(a)	7.25	%	7.75	%	8.00	%	N/A		N/A		N/A		2.00	%	4.00	%	5.00	%
Rate of increase in compensation levels	3.75	%	3.79	%	4.20	%	5.00	%	5.00	%	5.00	%	NA		NA		N/A

_____________________________


(a)	The expected rate of return on plan assets is 7.25 percent for the calculation of the 2013 net periodic pension cost.

The healthcare benefit obligation was determined at Dec. 31 as follows:



	Black Hills Corporation		Black Hills Energy		Cheyenne Light
2012
Healthcare trend rate pre-65
Trend for next year	7.75	%	7.75	%	7.75	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027

Healthcare trend rate post-65
Trend for next year	6.50	%	6.50	%	6.50	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2026		2026		2026

2011
Healthcare trend rate pre-65
Trend for next year	9.01	%	9.01	%	9.01	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027

Healthcare trend rate post-65
Trend for next year	9.01	%	9.01	%	9.01	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027

167

We do not pre-fund our non-qualified pension plans or two of the three postretirement benefit plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Retiree Healthcare Plans (in thousands):



Change in Assumed Trend Rate	Impact on Dec. 31, 2012 Accumulated Postretirement Benefit Obligation			Impact on 2012 Service and Interest Cost
Increase 1%	$	2,082		$	127
Decrease 1%	$	(1,771	)	$	(107	)

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



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plan		Non-Pension Defined Benefit Postretirement Healthcare Plans
2013	$	13,034	$	1,286	$	3,136
2014	$	13,953	$	1,463	$	3,350
2015	$	14,890	$	1,462	$	3,399
2016	$	15,982	$	1,540	$	3,419
2017	$	17,013	$	1,586	$	3,456
2018-2022	$	102,883	$	7,949	$	16,814

( 19 ) COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties:


•	Black Hills Power’s PPA with PacifiCorp, expiring Dec. 31, 2023 , for the purchase of 50 megawatts of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.


•	Black Hills Power has a firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023 . The agreement provides 50 megawatts of capacity and energy to be transmitted annually by PacifiCorp.


•	Cheyenne Light’s PPA with Duke Energy’s Happy Jack wind site, expiring Sept. 3, 2028 , provides up to 30 megawatts of wind energy from Happy Jack to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50 percent of the facility output to Black Hills Power.


•	Cheyenne Light’s PPA with Duke Energy’s Silver Sage wind site, expiring Sept. 30, 2029 , provides up to 30 megawatts of wind energy. Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 megawatts of energy from Silver Sage to Black Hills Power.


•	Colorado Electric’s PPA with Cargill expiring Dec. 31, 2013 , whereby Colorado Electric purchases 50 megawatts of economy energy.


•	Colorado Electric’s REPA with AltaGas expiring Oct. 16, 2037 , provides up to 14.5 megawatts of wind energy from the Busch Ranch Wind Project in which Colorado Electric owns a 50 percent undivided ownership interest.


•	Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through March 13, 2013 . The agreement became effective March 14, 2011.

168

Costs under these power purchase contracts for the years ended Dec. 31 were as follows (in thousands):



	2012		2011		2010
PPA with PacifiCorp	$	13,224	$	12,515	$	12,936
PPA with PSCo ^(a)	$	—	$	97,988	$	110,575
Transmission services agreement with PacifiCorp	$	1,215	$	1,215	$	1,215
PPA with Happy Jack	$	1,988	$	1,955	$	2,815
PPA with Silver Sage	$	3,269	$	3,281	$	1,723
Busch Ranch Wind Project	$	502	$	—	$	—

_______________________


(a)	This PPA with PSCo expired on Dec. 31, 2011 and was replaced with the facilities constructed by Colorado Electric and Black Hills Colorado IPP at our Pueblo Airport Generation site. The facilities constructed by Black Hills Colorado IPP were to support an inter-company PPA with Colorado Electric. This inter-company PPA is being accounted for as a capital lease.

Other Supply Agreements

Our Gas Utilities also purchase natural gas, including transportation capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2017 .

Construction Obligations

We have purchase obligations related to Cheyenne Prairie construction. Our total obligations under these contracts were approximately $31 million , as of Dec. 31, 2012 which are expected to be paid in 2013 and 2014.

Future Minimum Payments

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



2013	$	187,301
2014	$	109,707
2015	$	108,024
2016	$	97,972
2017	$	86,564
Thereafter	$	222,002

Related Party Purchase Option

Cheyenne Light’s PPA for 60 megawatts of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on Dec. 31, 2022 , includes an option for Cheyenne Light to purchase Black Hills Wyoming’s ownership in the Wygen I facility. The purchase price related to the option is $2.6 million per megawatt which is the equivalent per megawatt of the estimated price of new construction of the Wygen III plant. This option purchase price is reduced annually by an amount equal to annual depreciation.

Power Sales Agreements

Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:


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

•

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

169


•	Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light provides 40 megawatts of capacity and energy through March 31, 2013 .


•	Black Hills Power has a PPA with MEAN expiring April 1, 2015 . Under this contract, MEAN purchases 5 megawatts of unit-contingent capacity from Neil Simpson II and 5 megawatts of unit-contingent capacity from Wygen III.


•	Black Hills Power has a PPA with MEAN expiring May 31, 2023 . This contract is unit-contingent on up to 10 megawatts from Neil Simpson II and up to 10 megawatts from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.

Related Party Lease

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on Dec. 31, 2031 , provides 200 megawatts of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations.

Environmental Matters

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

Air

Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT II, Lange CT, Wygen II, Wygen III and Wyodak plants. Title IV of the Clean Air Act created an SO ₂ allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2042.

The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which impose emission limits, fuel requirements and monitoring requirements. The rule has a compliance deadline of March 21, 2014. In anticipation of this rule we suspended operations at the Osage plant in October 2010 and as a result of this rule, we suspended operations at the Ben French facility on Aug. 31, 2012 with plans to retire Ben French, Osage and Neil Simpson I on or before March 21, 2014. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than Dec. 31, 2013. This facility suspended operations Dec. 31, 2012. While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.

Solid Waste Disposal

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

Our W.N. Clark plant, at which operations have been suspended, 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.

170

Reclamation Liability

For our Pueblo Airport Generation site, we have posted a bond of $3.9 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

Under its land lease for Busch Ranch, Colorado Electric is required to reclaim all land where it has placed wind turbines. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

Under its mining permit, WRDC is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

See Note 10 for additional information.

Manufactured Gas Processing

As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.1 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operator of the Nebraska MGPs. Under this agreement, Nebraska Gas agreed to remediate the Blair and Plattsmouth sites in Nebraska. Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth in Nebraska's Voluntary Cleanup Program. Site remediation was completed in September 2012, however there is a potential for additional minimal remediation work at Plattsmouth. If required, it is expected to be completed by mid-2013. Both Nebraska sites will be required to monitor groundwater quality for a minimum two year period.

As of Dec. 31, 2012, our estimated liabilities for all of the MGP sites currently range from approximately $2.9 million to $6.3 million for which we had $3.1 million accrued for remediation of sites as of Dec. 31, 2012 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets.

Prior to Black Hills Corporation's ownership, Aquila received rate orders that enabled recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of these current and future costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted.

Legal Proceedings

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

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

171

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills. It is alleged that the fire occurred when a high voltage electrical transmission line maintained by our electric utility subsidiary fell to the ground, and that electrical arcing from the downed line ignited dry grass or brush. The fire burned approximately 60,000 acres of land owned by private landowners, and by the United States Bureau of Land Management and the State of Wyoming. Our utility subsidiary received written claims from the State of Wyoming and a landowner seeking recovery of damages for alleged injury to timber, grass, fencing, fire suppression and rehabilitation costs. The total amount of damages currently claimed by the State of Wyoming and a landowner is approximately $8.0 million . We have been notified that additional private landowner claims are forthcoming. Our investigation into the cause and origin of the fire is still pending. Based upon information developed in our investigation to this date, we expect to deny and will vigorously defend all claims arising out of the fire. Given the uncertainty of litigation, however, a loss relating to the fire and the litigation is reasonably possible. We cannot reasonably estimate the amount of a potential loss because our investigation is ongoing, and because we expect further claims to be presented by other parties. Although we cannot predict the outcome of our investigation or the viability of potential claims, based on information currently available, management believes that any such claims, if determined adversely to us, will not have a material effect on our financial statements.

( 20 ) GUARANTEES

We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include guarantees of debt obligations, contractual performance obligations and indemnification for reclamation and surety bonds.

We had the following guarantees in place as of (in thousands):



	Maximum Exposure at
Nature of Guarantee	Dec. 31, 2012		Expiration
Guarantees of payment obligations arising from commodity-related physical and financial transactions of Black Hills Utility Holdings ⁽¹⁾	$	70,000	Ongoing
Guarantee for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric ⁽²⁾	33,264		March 29, 2013
Indemnification for subsidiary reclamation/surety bonds ⁽³⁾	54,509		Ongoing
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Colorado Gas ⁽⁴⁾	10,000		July 31, 2013
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply ⁽⁵⁾	7,500		June 30, 2013
	$	175,273

_______________________

(1)

We have guaranteed some of the obligations of Black Hills Utility Holdings for payment obligations arising from commodity-related physical and financial transactions with BP Energy Company and/or BP Canada Energy Marketing Corp, Northern Natural Gas Company and PSCo. These commodity transactions secure natural gas supply for our regulated gas utilities. The guarantee is a continuing guarantee that may be terminated upon 30 days written notice to the counterparty.


(2)	We have issued a guarantee to Vestas-American Wind Technology, Inc. for the performance and payment obligations of Colorado Electric relating to the purchase of wind turbines for the Colorado Electric wind power generation project. This guarantee will remain in effect until 91 days after satisfaction of Colorado Electric’s contractual obligations.


(3)	We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.


(4)	We issued a guarantee to Colorado Interstate Gas Company for payment obligations of Black Hills Utility Holdings related to natural gas transportation, storage and services agreement.


(5)	We issued a guarantee to Cross Timbers Energy Services for the performance and payment obligation of Black Hills Utility Holdings for natural gas supply purchase.

172

( 21 ) OIL AND GAS RESERVES (Unaudited)

BHEP has operating and non-operating interests in 1,200 gross developed oil and gas wells in 9 states and holds leases on approximately 268,636 net acres.

Costs Incurred

Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended Dec. 31 (in thousands):



	2012		2011		2010
Acquisition of properties:
Proved	$	2,437	$	673	$	—
Unproved	33,052		8,317		3,846
Exploration costs	115		44,384		8,159
Development costs	73,877		38,638		25,264
Asset retirement obligations incurred	158		43		1,228
Total costs incurred	$	109,639	$	92,055	$	38,497

Reserves

The following table summarizes BHEP’s quantities of proved developed and undeveloped oil and natural gas reserves, estimated using SEC-defined product prices, as of December 31, 2012 , 2011 and 2010 , and a reconciliation of the changes between these dates. These estimates are based on reserve reports by CG&A. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

173

Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.



	2012						2011						2010
	Oil			Gas			Oil			Gas			Oil			Gas
	(in Mbbls of oil and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year	6,223			95,904			5,940			95,456			5,274			87,660
Production ^(a)	(560		)	(8,686		)	(452		)	(8,526		)	(376		)	(8,484		)
Additions - acquisitions (sales) ^(b)	(2,025		)	(3,070		)	(84		)	—			(13		)	(377		)
Additions - extensions and discoveries	449			2,898			927			29,664			1,145			1,710
Revisions to previous estimates ^(c)	29			(31,061		)	(108		)	(20,690		)	(90		)	14,947
Balance at end of year	4,116			55,985			6,223			95,904			5,940			95,456

Proved developed reserves at end of year included above	3,851			54,086			4,830			71,867			4,434			67,656

Proved undeveloped reserves at the end of year included in above	265			1,901			1,393			24,037			1,506			27,800

NYMEX prices	$	94.71		$	2.76		$	96.19		$	4.12		$	79.43		$	4.38

Well-head reserve prices	$	85.31		$	2.24		$	88.49		$	3.59		$	70.82		$	3.45

________________________


(a)	Production for reserve calculations does not include volumes for natural gas liquids (NGLs).


(b)	Reflects the sale of the majority of the Williston Basin assets during 2012.


(c)	Included in total revisions are (27,051) MMcfe due to lower commodity prices and (2,422) MMcfe for dropped PUD locations due to five year aging of reserves with negative performance revisions of (1,565) MMcfe in various basins.

Reserve additions totaled 5.6 Bcfe, replacing 46 percent of production. Additions resulted from drilling in the Williston Basin, San Juan, Piceance and Powder River Basins. Drilling in Williston Basin (Bakken Shale) accounted for 3.1 Bcfe, Piceance Basin (Mancos Shale) 1.9 Bcfe, Powder River Basin 0.3 Bcfe and recompletions in the San Juan Basin 3.0 Bcfe. Capital spending in 2012 was increased to accommodate the Williston Bakken drilling and to continue evaluating the development potential of the Mancos Shale under our leasehold in the San Juan and Piceance Basins. Additionally, exploratory investments were made to develop future opportunities. Future capital spending rates are anticipated to be dependent on product prices.

SEC regulations require that proved undeveloped locations meet the test of being developed within five years of being categorized as proved. Approximately 2.4 Bcfe was removed from previous estimates due to five year reserve aging of the PUD locations in the Bear Paw Uplift, the Piceance Basin and the Wind River Basin. Negative revisions to previous estimates were mostly due to lower natural gas prices received at the well head. Approximately 27.1 Bcfe of the negative revision was due to low commodity prices. Most of the negative revisions were located in the San Juan Basin 11.5 Bcfe; Piceance Basin 13.9 Bcfe; Wind River Basin 0.8 Bcfe; Oklahoma Basins 0.5 Bcfe; and Bear Paw Uplift and other basins 0.4 Bcfe. Additionally, a 0.5 Bcfe behind pipe reserve in the Piceance Basin was dropped. Overall, approximately 1.6 Bcfe was dropped in various basins for small performance downgrades which were offset by performance upgrades in some basins.

Companies are required to include a narrative disclosure of the total quantity of PUD locations at year end, any material changes in PUD locations during the year, and investment and progress made in converting the PUD locations during the year.


•	In 2012 , we sold 29 year-end 2011 PUD locations as part of an asset sale in the Williston Basin that represented $41.7 million in investment and 9.5 Bcfe reserves.


•	The San Juan Basin has three PUD locations (approximately 8.1 Bcfe and $15.1 million investment) and three PUD locations in the Piceance Basin ( 12.1 Bcfe and $24.7 million investment) were dropped due to low commodity pricing.

174


•	Approximately 34 PUD locations were dropped for reserve aging. Of those, 32 PUD locations were in the Bear Paw Uplift ( 1.0 Bcfe) and two PUD locations were in the Piceance Basin ( 1.4 Bcfe).


•	We invested $5.7 million to develop three Williston Basin PUD locations in our remaining Williston Basin assets. PUD locations, proved reserves and future development costs associated with the Williston Basin during 2012 and at Dec. 31, 2012 were:



	As of Dec. 31, 2012
Williston Basin	Proved Reserves (in Bcfe)	Gross PUD Locations	Future Development Costs (in millions)
Existed	0.9	3	$	4.9
Added	0.5	8	$	2.1
Williston Basin	1.4	11	$	7.0


•	None of our PUD locations have been reflected in our reserves for five or more years. Consistent with the SEC guidance, these PUD locations will be monitored and reported each year until they are drilled or revised.

Capitalized Costs

Following is information concerning capitalized costs for the years ended Dec. 31 (in thousands):



	2012			2011			2010
Unproved oil and gas properties	$	59,526		$	28,656		$	28,160
Proved oil and gas properties	662,444			674,494			592,978
Gross capitalized costs	721,970			703,150			621,138

Accumulated depreciation, depletion and amortization and valuation allowances ^(a)	(534,777		)	(361,173		)	(334,955		)
Net capitalized costs	$	187,193		$	341,977		$	286,183

__________________


(a)	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.

Results of Operations

Following is a summary of results of operations for producing activities for the years ended Dec. 31 (in thousands):



	2012			2011			2010
Revenue	$	79,072		$	79,808		$	74,164

Production costs	23,483			23,820			21,922
Gain on sale of assets	(29,129		)	—			—
Depreciation, depletion and amortization and valuation provisions	37,323			34,415			29,013
Impairment of long-lived assets	26,868			—			—
Total costs	58,545			58,235			50,935
Results of operations from producing activities before tax	20,527			21,573			23,229

Income tax benefit (expense)	(7,082		)	(7,442		)	(8,014		)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	13,445		$	14,131		$	15,215

175

Unproved properties not subject to amortization at Dec. 31, 2012 , 2011 and 2010 consisted mainly of exploration cost on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.7 million , $0.9 million and $0.8 million of interest during 2012 , 2011 and 2010 , respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined. We expect the exploration cost listed below to be added to the cost pool in the next year.

The table below sets forth the cost of unproved properties excluded from the amortization base as of Dec. 31, 2012 and notes the year in which the associated costs were incurred (in thousands):



	2012		2011		2010			Prior		Total
Leasehold acquisition cost	$	35,539	$	638	$	2,138		$	16,709	$	55,024
Exploration cost	328		—		—			—		328
Capitalized interest	683		60		(36		)	3,467		4,174
Total	$	36,550	$	698	$	2,102		$	20,176	$	59,526

Standardized Measure of Discounted Future Net Cash Flows

Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended Dec. 31 (in thousands):



	2012			2011			2010
Future cash inflows	$	502,769		$	931,637		$	764,585
Future production costs	(186,695		)	(280,910		)	(256,455		)
Future development costs	(8,462		)	(92,233		)	(73,805		)
Future income tax expense	(69,877		)	(157,922		)	(111,666		)
Future net cash flows	237,735			400,572			322,659
10 percent annual discount for estimated timing of cash flows	(101,632		)	(197,215		)	(154,551		)
Standardized measure of discounted future net cash flows	$	136,103		$	203,357		$	168,108

The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended Dec. 31 (in thousands):



	2012			2011			2010
Standardized measure - beginning of year	$	203,357		$	168,108		$	129,108
Sales and transfers of oil and gas produced, net of production costs	(48,905		)	(52,914		)	(40,282		)
Net changes in prices and production costs	(42,639		)	57,087			57,380
Extensions, discoveries and improved recovery, less related costs	19,870			31,179			17,076
Changes in future development costs	43,854			43,809			(17,125		)
Development costs incurred during the period	21,931			18,940			4,975
Revisions of previous quantity estimates	(86,277		)	(58,211		)	27,513
Accretion of discount	25,509			19,655			13,434
Net change in income taxes	36,578			(23,283		)	(23,233		)
Purchases of reserves	—			—			—
Sales of reserves ^(a)	(37,175		)	(1,013		)	(738		)
Standardized measure - end of year	$	136,103		$	203,357		$	168,108

________


(a)	Reflects sale of Williston Basin assets

176

Changes in the standardized measure from “revisions of previous quantity estimates” are driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications are generally made at the well level each year through the reserve review process. These production profile modifications are based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments are reviewed each year and are often modified in response to current market conditions for items such as permitting, and service availability.

( 22 ) SALE OF ASSETS

Partial Sale of Electric Utilities Assets

On Sept. 18, 2012 , Colorado Electric completed the sale of an undivided 50 percent ownership interest in the Busch Ranch Wind Farm to AltaGas for $25.0 million . Colorado Electric retains the remaining undivided interest and will be the operator of this jointly owned facility. Commercial operation of the newly constructed wind farm commenced on Oct. 16, 2012 . Colorado Electric will purchase AltaGas’s interest, or approximately 14.5 megawatts, in the energy produced by the wind farm through a REPA expiring on Oct. 16, 2037 .

On July 14, 2010 , Black Hills Power sold a 23 percent ownership interest in Wygen III to the City of Gillette for $62.0 million . The Participation Agreement provides that the City of Gillette will pay Black Hills Power for administrative services and share in the costs of operating the plant for the life of the facility. The amount of net fixed assets sold totaled $55.8 million . Black Hills Power recognized a gain on the sale of $6.2 million .

Partial Sale of Oil and Gas Assets

On Sept. 27, 2012 , our Oil and Gas segment sold a majority of its Bakken and Three Forks shale assets in the Williston Basin in North Dakota. The sale included approximately 73 gross wells, 28,000 net leasehold acres and had an effective date of July 1, 2012 .

Our Oil and Gas segment follows the full-cost method of accounting for oil and gas activities. Typically this methodology does not allow for gain or loss on sale and proceeds from sale are credited against the full cost pool. Gain or loss recognition is allowed when such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Sept. 27, 2012 sale of the majority of the Williston Basin assets significantly alters the relationship and accordingly we have recorded a gain of $29.1 million with the remainder of the proceeds recorded as a reduction in the full cost pool. This reduction in the full cost pool significantly decreased the depreciation, depletion and amortization rate for the remainder of 2012.

Net cash proceeds were as follows (in thousands):



Cash proceeds received on date of sale	$	243,314
Less:
Post close adjustments	2,793
Transaction adviser fees	(1,400		)
Estimated payment for contractual obligation related to “back-in” fee *	(16,847		)
Net cash proceeds	$	227,860

_____________


*	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

Partial Sale of Gas Utilities Assets

On March 1, 2010 , Nebraska Gas sold certain assets to Metropolitan Utilities District as a result of annexation proceedings by the City of Omaha, Nebraska. Nebraska Gas received $6.1 million in cash and recognized a $2.7 million pre-tax gain on the sale.

177

( 23 ) DISCONTINUED OPERATIONS

Results of operations for discontinued operations have been classified as Income from discontinued operations, net of income taxes in the accompanying Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been classified and reflected on the accompanying Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassification on a consistent basis.

Energy Marketing Segment

On Feb. 29, 2012 , we sold the outstanding stock of our Energy Marketing segment, Enserco Energy Inc. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds on Dec. 31, 2012 were approximately $165.0 million , subject to final post-closing adjustments. The proceeds represent $107.5 million received from the buyer and $57.5 million cash retained from Enserco before closing.

Operating results of the Energy Marketing segment included in Income (loss) from discontinued operations, net of tax on the accompanying Consolidated Statements of Income were as follows (in thousands):



For the Years Ended Dec. 31,	2012			2011			2010

Revenue	$	(604	)	$	41,101		$	27,999

Pre-tax income (loss) from discontinued operations	(6,061		)	14,838			8,673
Pre-tax gain (loss) on sale	(4,184		)	—			—
Income tax (expense) benefit	3,268			(5,473		)	(3,129		)
Income (loss) from discontinued operations, net of tax ^(a)	$	(6,977	)	$	9,365		$	5,544

________


(a)	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended Dec. 31, 2012 .

178

Total indirect corporate costs and inter-segment interest expenses previously allocated to Enserco were not reclassified to discontinued operations in accordance with GAAP and instead have been reclassified to our Corporate segment.

Net assets of the Energy Marketing segment included in Assets/Liabilities of discontinued operations in the Consolidated Balance Sheets were as follows (in thousands) as of:



	Dec. 31, 2011
Other current assets	$	280,221
Derivative assets, current and non-current	52,859
Property, plant and equipment, net	5,828
Goodwill	1,435
Other non-current assets	508
Other current liabilities	(132,951		)
Derivative liabilities, current and non-current	(26,084		)
Other non-current liabilities	(14,894		)
Net assets	$	166,922

179

( 24 ) QUARTERLY HISTORICAL DATA (Unaudited)

The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2012 and 2011 .



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2012
Revenue	$	365,851		$	242,363		$	246,808		$	318,862
Operating income ^(a)	$	70,048		$	20,591		$	77,810		$	75,262
Income (loss) from continuing operations ^{(b) (c)}	$	35,271		$	(12,323	)	$	34,623		$	30,934
Income (loss) from discontinued operations	$	(5,484	)	$	(1,160	)	$	(166	)	$	(167	)
Net income (loss) available for common stock ^{(b) (c)}	$	29,787		$	(13,483	)	$	34,457		$	30,767

Income (loss) per share for continuing operations - basic	$	0.81		$	(0.28	)	$	0.79		$	0.70
Income (loss) per share for discontinued operations - basic	(0.13		)	(0.03		)	—			—
Income (loss) per share - basic	$	0.68		$	(0.31	)	$	0.79		$	0.70

Income (loss) per share for continuing operations - diluted	$	0.80		$	(0.28	)	$	0.78		$	0.70
Income (loss) per share for discontinued operations - diluted	(0.12		)	(0.03		)	—			—
Income (loss) per share - diluted	$	0.68		$	(0.31	)	$	0.78		$	0.70

Dividends paid per share	$	0.370		$	0.370		$	0.370		$	0.370

Common stock prices - High	$	35.82		$	34.31		$	36.28		$	37.00
Common stock prices - Low	$	32.18		$	31.32		$	30.29		$	33.51

__________________________


(a)	Second quarter includes a pre-tax ceiling test impairment loss of $26.9 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27.3 million and $1.8 million , respectively.


(b)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million , $(10.1) million , $0.4 million , and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.


(c)	Second quarter includes an after-tax ceiling test impairment loss of $17.3 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $17.7 million and $1.2 million , respectively.

180



	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2011
Revenue	$	400,835		$	260,649	$	249,523		$	361,181
Operating income	$	58,367		$	36,160	$	39,572		$	52,140
Income (loss) from continuing operations ^(a)	$	29,068		$	3,706	$	(11,163	)	$	18,754
Income (loss) from discontinued operations	$	(2,158	)	$	4,046	$	638		$	6,839
Net income (loss) available for common stock ^(a)	$	26,910		$	7,752	$	(10,525	)	$	25,593

Earnings (loss) per share for continuing operations - basic	$	0.74		$	0.09	$	(0.29	)	$	0.45
Earnings (loss) per share for discontinued operations - basic	(0.05		)	0.11		0.02			0.16
Earnings (loss) per share - basic	$	0.69		$	0.20	$	(0.27	)	$	0.61

Earnings (loss) per share for continuing operations - diluted	$	0.73		$	0.09	$	(0.29	)	$	0.44
Earnings (loss) per share for discontinued operations - diluted	(0.05		)	0.10		0.02			0.16
Earnings (loss) per share - diluted	$	0.68		$	0.19	$	(0.27	)	$	0.60

Dividends paid per share	$	0.365		$	0.365	$	0.365		$	0.365

Common stock prices - High	$	33.64		$	34.85	$	32.22		$	34.47
Common stock prices - Low	$	29.76		$	28.12	$	25.83		$	29.10

__________________________


(a)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $3.6 million , $(5.1) million , $(24.9) million and $(0.9) million after-tax in the first, second, third and fourth quarters, respectively.

181


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

None.


ITEM 9A.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of Dec. 31, 2012 . Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2012, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting, except that we completed execution of our remediation plan to address a material weakness in internal controls surrounding accounting for income taxes, previously reported in our 2011 Annual Report on Form 10-K and 2012 Quarterly Reports on Form 10-Q.

In response to the identified material weakness, management conducted an investigation and review of the processes and controls surrounding the material weakness. Management, with oversight from our Audit Committee, developed a plan of remediation in the first quarter of 2012 that included changes to processes to prevent or detect similar future occurrences. As a result of this plan, the following control remediation steps were taken during 2012:


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


•	Enhanced processes and controls related to income tax accounting and reporting.


•	Utilized a quarterly “Executive Tax Dashboard” to ensure a comprehensive assessment of each quarter's tax status.


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

Management’s Report on Internal Control over Financial Reporting

Management of Black Hills Corporation is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of Dec. 31, 2012 , based on the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of Dec. 31, 2012 .

Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial reporting as of Dec. 31, 2012. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.

Black Hills Corporation

182

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Black Hills Corporation

Rapid City, South Dakota

We have audited the internal controls over financial reporting of Black Hills Corporation’s and subsidiaries’ (the “Company’s”) as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting . Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2012 of the Company and our report dated February 25, 2013 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 25, 2013


ITEM 9B.	OTHER INFORMATION

None

183

PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3), 407(d)(4) and 407(d)(5) of Regulation S-K, is set forth in the Proxy Statement for our 2013 Annual Meeting of Shareholders, which is incorporated herein by reference.

Executive Officers

David R. Emery, age 50, was elected Chairman in April 2005 and has been President and Chief Executive Officer and a member of the Board of Directors since January 2004. Prior to that, he was our President and Chief Operating Officer — Retail Business Segment from April 2003 to January 2004 and Vice President — Fuel Resources from January 1997 to April 2003. Mr. Emery has 23 years of experience with the Company.

Scott A. Buchholz, age 51, has been our Senior Vice President — Chief Information Officer since the closing of the Aquila Transaction in July 2008. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from June 2005 until July 2008, Six Sigma Deployment Leader/Black Belt from January 2004 until June 2005, and General Manager, Corporate Information Technology from February 2002 until January 2004. He was employed with Aquila for 28 years.

Anthony S. Cleberg , age 60, has been Executive Vice President and Chief Financial Officer since July 2008. He was an independent investor, developer and consultant with companies in Colorado and Wyoming from 2002 until joining the Company in 2008. Prior to his consulting role, he was the Executive Vice President and Chief Financial Officer of two publicly-traded companies: Washington Group, International, Inc., a large engineering and construction company involved in power plant construction and mining operations, and Champion Enterprises, a builder of factory-built housing. Before his CFO roles, he spent 15 years in various senior financial positions with Honeywell International, Inc., and eight years in public accounting at Deloitte & Touche, LLP.

Linden R. Evans, age 50, has been President and Chief Operating Officer — Utilities since October 2004. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary from December 2003 to October 2004, and served as our Associate Counsel from May 2001 to December 2003. Mr. Evans has 11 years of experience with the Company.

Steven J. Helmers, age 56, has been our Senior Vice President, General Counsel and Chief Compliance Officer since January 2008. He served as our Senior Vice President, General Counsel since January 2004 and our Senior Vice President, General Counsel and Corporate Secretary from 2001 to 2004. Mr. Helmers has 12 years of experience with the Company.

Robert A. Myers, age 55, has been our Senior Vice President — Chief Human Resource Officer since January 2009 and served as our Interim Human Resources Executive since June 2008. He was a partner with Strategic Talent Solutions, a human resources consulting firm, from October 2006 until December 2008, Senior Vice President — Chief Human Resource Officer for Devon Energy from March 2006 until September 2006, and Senior Vice President and Chief Human Resource Officer at Reebok International, Ltd from November 2003 until January 2006. He has over 32 years of service in key human resources leadership roles.

184


ITEM 11.	EXECUTIVE COMPENSATION

Information required under this item is set forth in the Proxy Statement for our 2013 Annual Meeting of Shareholders, which is incorporated herein by reference.


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

Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for our 2013 Annual Meeting of Shareholders, which is incorporated herein by reference.

EQUITY COMPENSATION PLAN INFORMATION

The following table includes information as of December 31, 2012 with respect to our equity compensation plans. These plans include the 1999 Stock Option Plan, 2001 Omnibus Incentive Plan and 2005 Omnibus Incentive Plan.



Equity Compensation Plan Information
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights				Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)				(c)
Equity compensation plans approved by security holders	340,786	⁽¹⁾		$	31.23	⁽¹⁾	863,929	⁽²⁾
Equity compensation plans not approved by security holders	—			$	—		—
Total	340,786			$	31.23		863,929

_________________________

⁽¹⁾

Includes 220,013 full value awards outstanding as of December 31, 2012 , comprised of restricted stock units, performance shares and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares or common stock units. In addition, 287,422 shares of unvested restricted stock were outstanding as of December 31, 2012 , which are not included in the above table because they have already been issued.


⁽²⁾	Shares available for issuance are from the 2005 Omnibus Incentive Plan. The 2005 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards.


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

Information regarding certain relationships and related transactions and director independence is set forth in the Proxy Statement for our 2013 Annual Meeting of Shareholders, which is incorporated herein by reference.


ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

Information regarding principal accounting fees and services is set forth in the Proxy Statement for our 2013 Annual Meeting to Shareholders, which is incorporated herein by reference.

185

PART IV


ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(a)	1.	Consolidated Financial Statements

		Financial statements required under this item are included in Item 8 of Part II

	2.	Schedules

		Schedule I — Condensed Financial Information of the Registrant

		Schedule II — Consolidated Valuation and Qualifying Accounts for the years ended Dec. 31, 2012, 2011 and 2010

		All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included in our consolidated financial statements and notes thereto.

	3.	Exhibits

186

SCHEDULE I

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED STATEMENTS OF INCOME



	2012			2011			2010
	(in thousands)

Revenue	$	—		$	—		$	—
Operating expenses	831			772			735
Operating income (loss)	(831		)	(772		)	(735		)

Other income (expense):
Equity income (loss) in earnings of subsidiaries	93,479			87,150			88,627
Interest expense	(19,665		)	(15,229		)	(14,985		)
Unrealized (loss) gain on interest rate swaps, net	1,882			(42,010		)	(15,193		)
Interest income	32			3			22
Other income (expense), net	49			(42		)	34
Total other income (expense)	75,777			29,872			58,505
Income (loss) before income taxes	74,946			29,100			57,770
Income tax benefit (expense)	6,582			20,630			10,915
Net income (loss) available for common stock	$	81,528		$	49,730		$	68,685

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

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



Years ended (in thousands)	Dec. 31, 2012			Dec. 31, 2011			Dec. 31, 2010

Net income available for common stock	$	81,528		$	49,730		$	68,685

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $296, $4,135 and $674, respectively)	(542		)	(7,609		)	(1,307		)
Benefit plan liability adjustments - prior service (costs) (net of tax of $86, $176 and $111, respectively)	(157		)	(325		)	(214		)
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $887, $1,708 and $(636), respectively)	(1,268		)	(2,831		)	1,336
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $534, $(709) and $2,498, respectively)	(643		)	1,468			(4,232		)
Other comprehensive income (loss), net of tax, including earnings (loss) of consolidated subsidiaries	(2,610		)	(9,297		)	(4,417		)

Comprehensive income (loss)	$	78,918		$	40,433		$	64,268

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

187

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED BALANCE SHEETS



At Dec. 31,	2012		2011
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,266	$	3,114
Accounts receivable — affiliates, current	2,194		1,445
Notes receivable — affiliates, current	637,586		453,216
Income tax receivable, net	5,843		8,653
Deferred income tax assets, net, current	29,779		36,951
Other current assets	4,887		7,178
Total current assets	681,555		510,557

Property and Equipment	1,135		1,135

Investments in subsidiaries	1,194,501		1,339,024

Notes receivable — affiliate, non-current	250,000		575,000
Deferred income tax assets, net, non-current	41,494		29,454
Other long-term assets	4,014		4,834
Total other assets, non-current	295,508		609,288

TOTAL ASSETS	$	2,172,699	$	2,460,004

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable -- affiliate, current	$	565	$	5,202
Derivative liabilities, current	91,617		78,502
Notes payable	277,000		345,000
Notes payable — affiliate, current	1,032		1,754
Current maturities of long-term debt	100,000		—
Other current liabilities	9,943		12,070
Total current liabilities	480,157		442,528

Derivative liabilities, non-current	9,252		31,368

Long-term debt	450,000		774,959
Note payable — affiliate, non-current	781		1,813
Total long-term debt	450,781		776,772

Total stockholders’ equity	1,232,509		1,209,336

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,172,699	$	2,460,004

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

188

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED STATEMENTS OF CASH FLOWS



Years ended Dec. 31,	2012			2011			2010
	(in thousands)
Operating activities:
Net income (loss) available for common stock	$	81,528		$	49,730		$	68,685
Loss from discontinued operations, net of tax	—			—			—
Income from continuing operations	81,528			49,730			68,685
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities —
Equity in earnings of subsidiaries	(93,479		)	(87,150		)	(88,627		)
Dividend from subsidiaries	—			14,500			6,298
Stock compensation	8,271			5,643			5,637
Unrealized mark-to-market (gain) loss on certain interest rate swaps	(1,882		)	42,010			15,193
Derivative fair value adjustments	(4,339		)	2,291			(6,384		)
Deferred income taxes	(8,116		)	2,599			(34,452		)
Other adjustments, net	3,909			4,376			2,508
Change in operating assets and liabilities —
Accounts receivable and other current assets	6,541			(5,141		)	2,198
Accounts payable and other current liabilities	(6,764		)	3,550			4,846
Other operating activities	(3,477		)	550			(2,514		)
Net cash provided by (used in) operating activities	(17,808		)	32,958			(26,612		)

Investing activities:
Property, plant and equipment additions	—			(1,135		)	—
Decrease (Increase) in advances to affiliates	96,073			(258,117		)	(216,337		)
Other investing activities	450			—			—
Net cash provided by (used in) investing activities	96,523			(259,252		)	(216,337		)

Financing activities:
Dividends paid on common stock	(65,262		)	(59,202		)	(56,467		)
Common stock issued	4,726			123,041			3,246
Short-term borrowings -- repayments	(271,753		)	(821,300		)	(770,000		)
Short-term borrowings -- issuances	203,753			1,017,300			854,500
Increase (Decrease) in Notes payable to affiliates	275,806			(25,302		)	14,995
Long-term debt — issuance	—			—			200,000
Long-term debt — repayment	(225,000		)	—			—
Other financing activities	(2,833		)	(5,348		)	(5,379		)
Net cash provided by financing activities	(80,563		)	229,189			240,895
Net change in cash and cash equivalents	(1,848		)	2,895			(2,054		)

Cash and cash equivalents beginning of year	3,114			219			2,273
Cash and cash equivalents end of year	$	1,266		$	3,114		$	219

189



Supplemental Cash Flow Information
Years ended	2012			2011			2010
	(in thousands)
Non-cash investing and financing activities-
Non-cash adjustment to notes receivable from affiliates	$	40,039		$	—		$	62,019
Non-cash adjustment to notes payable to affiliates	$	(277,560	)	$	—		$	13,874
Non-cash dividend, net of non-cash contributions, from affiliates	$	237,521		$	—		$	—

Cash (paid) refunded during the period for-
Interest	$	(18,550	)	$	(14,667	)	$	(56,464	)
Income taxes	$	3,911		$	23,830		$	(504	)

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

NOTES TO BLACK HILLS CORPORATION (PARENT COMPANY) CONDENSED FINANCIAL STATEMENTS

( 1 ) BASIS OF PRESENTATION

Pursuant to rules and regulations of the SEC, the unconsolidated condensed financial statements of Black Hills Corporation do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in this Annual Report on Form 10-K.

Dividends paid and distributed to Black Hills Corporation (the Parent) from its subsidiaries were as follows (in thousands):



	2012		2011		2010
Cash dividends paid to Parent by subsidiaries	$	—	$	14,500	$	6,298
Non-Cash dividends, net of non-cash contributions, distributed to Parent by subsidiaries	$	237,521	$	—	$	—

( 2 ) NOTES RECEIVABLE AND NOTES PAYABLE

Black Hills Corporation has notes receivable and notes payable with affiliates under Utility Money Pool Agreements and Non-Utility Money Pool Agreements. Borrowings under these agreements bear interest at the weighted average daily cost of external funds as defined under the agreements.

Additionally, Black Hills Corporation has a Revolving Credit Facility and corporate term loans with various banks. Our credit facility and debt securities contain certain restrictive financial covenants. At December 31, 2012 , we were in compliance with all of these covenants. See Note 9 to Notes to Consolidated Financial Statements on this Annual Report on Form 10-K.

190

( 3 ) LONG-TERM DEBT

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



	Due Date	Interest Rate	2012		2011
Senior unsecured notes due 2013 ^(a)	May 15, 2013	6.50%	$	—	$	225,000
Unamortized discount on notes due 2013 ^(a)			—		(41		)
Senior unsecured notes due 2014 ^{(b) (e)}	May 15, 2014	9.00%	250,000		250,000
Senior unsecured notes due 2020 ^{(c) (e)}	July 15, 2020	5.88%	200,000		200,000
Long-term term loan ^(d)	Sept. 30, 2013	1.63%	100,000		100,000
Total long-term debt			550,000		774,959
Less current maturities			100,000		—
Net long-term debt			$	450,000	$	774,959

_______________


(a)	This note was repaid on Oct. 31, 2012 . This senior unsecured note had been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2011.


(b)	This senior unsecured note has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012.


(c)	This senior unsecured note has been recorded by Colorado Electric and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012. In 2011 $100 million of this senior unsecured note had been recorded by Black Hills Colorado IPP and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.


(d)	This term loan has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, current on the Parent’s Condensed Balance Sheets for 2012.


(e)	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.

Certain debt instruments of the Company contain restrictions and covenants, all of which we were in compliance with at December 31, 2012 .

Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):



2013	$	100,000
2014	$	250,000
2015	$	—
2016	$	—
2017	$	—
Thereafter	$	200,000

( 4 ) GUARANTEES

( 5 ) RISK MANAGEMENT ACTIVITIES

191

On Dec. 31 our interest rate swaps and related balances were as follows (dollars in thousands):



	2012						2011
	Interest Rate Swaps			De-designated Interest Rate Swaps			Interest Rate Swaps			De-designated Interest Rate Swaps
Notional ^(a)	$	75,000		$	250,000		$	75,000		$	250,000
Weighted average fixed interest rate	4.97		%	5.67		%	4.97		%	5.67		%
Maximum terms in years	4.0			1.0			5.0			2.0
Current derivative liabilities	$	3,469		$	88,148		$	3,207		$	75,295
Non-current derivative liabilities	$	9,252		$	—		$	10,672		$	20,696
Pre-tax accumulated other comprehensive (loss)	$	(12,721	)	$	—		$	(13,879	)	$	—
Pre-tax gain (loss)	$	—		$	1,882		$	—		$	(42,010	)
Cash collateral receivable (payable) included in derivatives	$	—		$	5,960		$	—		$	—

________________________

(a)

Under the terms of the Black Hills Wyoming project financing, Black Hills Wyoming was required to become a party to hedging agreements fixing the interest rate on a portion of the principal amount of the debt. To accomplish this, two existing swap agreements totaling $75.0 million were amended and transferred to Black Hills Wyoming so that the Parent and Black Hills Wyoming are now both jointly and severally liable for the full amount of the obligations under the swap agreements. The balance in AOCI of the Parent was frozen at that point in time and is being amortized over the remaining life of the swaps through the quarterly settlement process.

Based on December 31, 2012 market interest rates and balances, a loss of approximately $3.5 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will change during the future periods as market interest rates fluctuate.

( 6 ) FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at Dec. 31 were as follows (in thousands):



	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	1,266	$	1,266	$	3,114	$	3,114
Notes payable ^(a)	$	277,000	$	277,000	$	345,000	$	345,000
Long-term debt ^(b)	$	550,000	$	615,239	$	774,959	$	851,241

______________


(a)	Fair value approximates carrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

(b)

Cash and Cash Equivalents

Notes Payable

Notes Payable represent our short-term corporate term loan and borrowings under our Revolving Credit Facility.

192

Long-Term Debt

For additional information see Note 3 of these Black Hills Corporation (the Parent) Condensed Financial Statements.

( 7 ) COMMON STOCK

Forward Equity Issuance

In November 2011, we settled the equity forward agreement. For additional information see Note 11 of Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

( 8 ) COMMITMENTS AND CONTINGENCIES

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

SCHEDULE II



BLACK HILLS CORPORATION CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31, 2012, 2011, AND 2010

Description	Balance at Beginning of Year		Adjustments		Additions Charged to Costs and Expenses		Recoveries and Other Additions		Write-offs and Other Deductions			Balance at End of Year
	(in thousands)
Allowance for doubtful accounts:
2012	$	1,661	$	—	$	1,913	$	3,822	$	(6,628	)	$	768
2011	$	2,295	$	—	$	3,042	$	5,369	$	(9,045	)	$	1,661
2010	$	3,683	$	—	$	1,898	$	2,196	$	(5,482	)	$	2,295

193


3.	Exhibits



Exhibit Number	Description

2.1*	Stock Purchase Agreement by and between Twin Eagle Resource Management, LLC and Black Hills Non-Regulated Holdings LLC for the purchase of capital stock of Enserco Energy Inc., dated January 18, 2012 (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2012).

2.2*	Purchase and Sale Agreement, dated as of August 23, 2012, by and among Black Hills Exploration and Production, Inc. and other sellers and QEP Energy Company, as Purchaser (excluding exhibits and certain schedules, which the Registrant agrees to furnish supplementally to the Securities and Exchange Commission upon request) (filed as Exhibit 2 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2012).

3.1*	Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 10-K for 2004).

3.2*	Amended and Restated Bylaws of the Registrant dated January 28, 2010 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010).

4.1*	Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010).

4.2*	Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).

4.3*	Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).

10.1*†	Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001). First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002). Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.2 to the Registrant’s Form 10-K for 2008).

10.2*†	2005 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.3 to the Registrant’s Form 10-K for 2008).

10.3*†	Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2008). First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011).

10.4*†	Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.4 to the Registrant’s Form 10-K for 2010).

194



10.5*†	Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005). First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008). Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26, 2010).

10.6*†	Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.13 to the Registrant’s Form 10-K for 2008).

10.7*†	Form of Restricted Stock Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2008).

10.8*†	Form of Restricted Stock Unit Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.17 to the Registrant’s Form 10-K for 2008).

10.9*†	Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2010 (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2009). Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2012 (filed as Exhibit 10.10 to Registrant’s Form 10-K for 2011).

10.10*†	Form of Short-term Incentive for Omnibus Plan effective for awards granted on or after January 1, 2010. (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2010).

10.11*†	Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, 2004).

10.12*†	Change in Control Agreement dated September 7, 2010 between Black Hills Corporation and David R. Emery (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on September 10, 2010).

10.13*†	Form of Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on September 10, 2010).

10.14*†	Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed as Exhibit 10.23 to the Registrant’s Form 10-K for 2008). First Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2011 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2010).

10.15†	Second Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2013.

10.16*†	Independent Contractor Agreement dated May 3, 2010, between Black Hills Corporation and Lone Mountain Investment, Inc. (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2010). First Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated July 27, 2011 (filed as Exhibit 10.3 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011). Second Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated December 12, 2011 (filed as Exhibit 10.17 to Registrant’s Form 10-K for 2011).

10.17*†	Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees (filed as Exhibit 10.19 to Registrant’s Form 10-K for 2011).

10.18*	Credit Agreement dated December 15, 2010 among Black Hills Corporation as Borrower, the financial institutions party thereto, as Banks, J.P. Morgan Chase Bank N.A., as Administrative Agent, and J.P. Morgan Securities LLC and Union Bank of California N.A., as Co-Lead Arrangers and Joint Book Runner (filed as Exhibit 10 to the Registrant’s Form 8-K filed on December 16, 2010). First Amendment to the Credit Agreement (filed as Exhibit 10 to the Registrant’s Form 8-K filed on October 3, 2011).

10.19*	Credit Agreement, dated February 1, 2012, among Black Hills Corporation, as Borrower, U.S. Bank, National Association, in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other banks party thereto (filed as Exhibit 10 to the Registrant’s Form 8-K filed on February 3, 2012).

195



10.20*	Credit Agreement, dated as June 24, 2011, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, The Bank of Nova Scotia, as Administrative Agent, Co-Lead Arranger and Joint Book Runner, and U.S. Bank N.A. and CoBank, ACB, as Co-Lead Arrangers and Joint Book Runners (filed as Exhibit 10 to the Registrant’s Form 8-K filed on June 29, 2011). First Amendment to the Credit Agreement, dated June 22, 2012 (filed as Exhibit 10 to the Registrant’s Form 8-K filed on June 26, 2012).



10.21*	Coal Leases between WRDC and the Federal Government -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10‑K for 1989) -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10‑K for 1989) -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10‑K for 1989).

10.22*	Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997).

21	List of Subsidiaries of Black Hills Corporation.

23.1	Independent Auditors’ Consent.

23.2	Consent of Petroleum Engineer and Geologist.

31.1	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

31.2	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

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



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

95	Mine Safety and Health Administration Safety Data

99	Report of Cawley, Gillespie & Associates, Inc.

101	Financial Statements in XBRL Format

________________________


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


†	Indicates a board of director or management compensatory plan.


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


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

196

SIGNATURES

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



		BLACK HILLS CORPORATION

		By:	/S/ DAVID R. EMERY
		David R. Emery, Chairman, President
		and Chief Executive Officer
Dated:	February 25, 2013

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



/S/ DAVID R. EMERY	Director and	February 25, 2013
David R. Emery, Chairman, President	Principal Executive Officer
and Chief Executive Officer

/S/ ANTHONY S. CLEBERG	Principal Financial and	February 25, 2013
Anthony S. Cleberg, Executive Vice President	Accounting Officer
and Chief Financial Officer

/S/ JACK W. EUGSTER	Director	February 25, 2013
Jack W. Eugster

/S/ MICHAEL H. MADISON	Director	February 25, 2013
Michael H. Madison

/S/ STEVEN R. MILLS	Director	February 25, 2013
Steven R. Mills

/S/ STEPHEN D. NEWLIN	Director	February 25, 2013
Stephen D. Newlin

/S/ GARY L. PECHOTA	Director	February 25, 2013
Gary L. Pechota

/S/ REBECCA B. ROBERTS	Director	February 25, 2013
Rebecca B. Roberts

/S/ WARREN L. ROBINSON	Director	February 25, 2013
Warren L. Robinson

/S/ JOHN B. VERING	Director	February 25, 2013
John B. Vering

/S/ THOMAS J. ZELLER	Director	February 25, 2013
Thomas J. Zeller

197

INDEX TO EXHIBITS



Exhibit Number	Description
2.1*	Stock Purchase Agreement by and between Twin Eagle Resource Management, LLC and Black Hills Non-Regulated Holdings LLC for the purchase of capital stock of Enserco Energy Inc., dated January 18, 2012 (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2012).

2.2*	Purchase and Sale Agreement, dated as of August 23, 2012, by and among Black Hills Exploration and Production, Inc. and other sellers and QEP Energy Company, as Purchaser (excluding exhibits and certain schedules, which the Registrant agrees to furnish supplementally to the Securities and Exchange Commission upon request) (filed as Exhibit 2 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2012).

3.1*	Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 10-K for 2004).

3.2*	Amended and Restated Bylaws of the Registrant dated January 28, 2010 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010).

4.1*	Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on July 15, 2010).

4.2*	Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).

4.3*	Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).

10.1*†	Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001). First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002). Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.2 to the Registrant’s Form 10-K for 2008).

10.2*†	2005 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.3 to the Registrant’s Form 10-K for 2008).

10.3*†	Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2008). First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011).

10.4*†	Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.4 to the Registrant’s Form 10-K for 2010).

198



10.5*†	Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005). First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008). Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26, 2010).

10.6*†	Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.13 to the Registrant’s Form 10-K for 2008).

10.7*†	Form of Restricted Stock Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2008).

10.8*†	Form of Restricted Stock Unit Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.17 to the Registrant’s Form 10-K for 2008).

10.9*†	Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2010 (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2009). Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2012 (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2011).

10.10*†	Form of Short-Term Incentive for Omnibus Plan effective for awards granted on or after January 1, 2010. (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2010).

10.11*†	Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, 2004).

10.12*†	Change in Control Agreement dated September 7, 2010 between Black Hills Corporation and David R. Emery (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on September 10, 2010).

199




10.13*†	Form of Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on September 10, 2010).

10.14*†	Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed as Exhibit 10.23 to the Registrant’s Form 10-K for 2008). First Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2011 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2010).

10.15†	Second Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2013.

10.16*†	Independent Contractor Agreement dated May 3, 2010, between Black Hills Corporation and Lone Mountain Investment, Inc. (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2010). First Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated July 27, 2011 (filed as Exhibit 10.3 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011). Second Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated December 12, 2011 (filed as Exhibit 10.17 to the Registrant’s Form 10-K for 2011).

10.17*†	Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees (filed as Exhibit 10.19 to the Registrant’s Form 10-K for 2011).

10.18*	Credit Agreement dated December 15, 2010 among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, J.P. Morgan Chase Bank N.A., as Administrative Agent, and J.P. Morgan Securities LLC and Union Bank of California, N.A., as Co-Lead Arrangers and Joint Book Runners (filed as Exhibit 10 to the Registrant’s Form 8-K filed on December 16, 2010). First Amendment to the Credit Agreement (filed as Exhibit 10 to the Registrant’s Form 8-K filed on October 3, 2011).

10.19*	Credit Agreement, dated February 1, 2012, among Black Hills Corporation, as Borrower, U.S. Bank, National Association, in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other banks party thereto (filed as Exhibit 10 to the Registrant’s Form 8-K filed on February 3, 2012).

10.20*	Credit Agreement, dated as June 24, 2011, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, The Bank of Nova Scotia, as Administrative Agent, Co-Lead Arranger and Joint Book Runner, and U.S. Bank N.A. and CoBank, ACB, as Co-Lead Arrangers and Joint Book Runners (filed as Exhibit 10 to the Registrant’s Form 8-K filed on June 29, 2011). First Amendment to the Credit Agreement, dated June 22, 2012 (filed as Exhibit 10 to the Registrant’s Form 8-K filed on June 26, 2012).

200



10.21*	Coal Leases between WRDC and the Federal Government -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10‑K for 1989) -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10‑K for 1989) -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10‑K for 1989).

10.22*	Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997).

21	List of Subsidiaries of Black Hills Corporation.

23.1	Independent Auditors’ Consent.

23.2	Consent of Petroleum Engineer and Geologist.

31.1	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

31.2	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

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

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

95	Mine Safety and Health Administration Safety Data

99	Report of Cawley, Gillespie & Associates, Inc.

101	Financial Statements in XBRL Format

__________________________


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


†	Indicates a board of director or management compensatory plan.

201

TABLE OF CONTENTS

Part I Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 3. Legal Proceedings Item 4. Specialized Disclosures Part II Item 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities Item 6. Selected Financial Data Item 8. Financial Statements and Supplementary Data Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information Part III Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Item 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accounting Fees and Services Part IV Item 15. Exhibits, Financial Statement Schedules

BKH 10-K Fiscal year ended Dec. 31, 2012