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BKH 093012 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2012
OR
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	IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701

Registrant's telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report
NONE

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 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 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

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



Class	Outstanding at October 31, 2012

Common stock, $1.00 par value	44,180,030 shares



TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations	3

PART I.	FINANCIAL INFORMATION	5

Item 1.	Financial Statements	5

	Condensed Consolidated Statements of Income - unaudited
	Three and Nine Months Ended Sept. 30, 2012 and 2011	5

	Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
	Three and Nine Months Ended Sept. 30, 2012 and 2011	6

	Condensed Consolidated Balance Sheets - unaudited
	Sept. 30, 2012, Dec. 31, 2011 and Sept. 30, 2011	7

	Condensed Consolidated Statements of Cash Flows - unaudited
	Nine Months Ended Sept. 30, 2012 and 2011	9

	Notes to Condensed Consolidated Financial Statements - unaudited	10

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	65

Item 4.	Controls and Procedures	69

PART II.	OTHER INFORMATION	70

Item 1.	Legal Proceedings	70

Item 1A.	Risk Factors	70

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	70

Item 4.	Mine Safety Disclosures	70

Item 5.	Other Information	70

Item 6.	Exhibits	71

	Signatures	72

	Exhibit Index	73

GLOSSARY OF TERMS AND ABBREVIATIONS

AND ACCOUNTING STANDARDS

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
AOCI	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BHC	Black Hills Corporation, the "Company"
BHEP	Black Hills Exploration and Production, Inc., representing our Oil and Gas segment, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Electric Generation	Black Hills Electric Generation, LLC, representing our Power Generation segment, a direct wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business activities of Black Hills Utility Holdings
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of the Company
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Service Company	Black Hills Service Company, a direct wholly-owned subsidiary of the Company
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu	British thermal unit
CFTC	Commodity Futures Trading Commission
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the Company
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
Colorado IPP	Black Hills Colorado IPP, a direct wholly-owned subsidiary of Black Hills Electric Generation
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CT	Combustion Turbine
CVA	Credit Valuation Adjustment
CWIP	Construction Work-In-Progress
De-designated interest rate swaps	The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but were subsequently de-designated.
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
ECA	Energy Cost Adjustment



Enserco	Enserco Energy Inc., representing our Energy Marketing segment, sold Feb. 29, 2012
Equity Forward Instrument	Equity Forward Agreement with J.P. Morgan connected to a public offering of 4,413,519 shares of Black Hills Corporation common stock
FASB	Financial Accounting Standards Board
FDIC	Federal Deposit Insurance Corporation
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles of the United States
Global Settlement	Settlement with the utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
IFRS	International Financial Reporting Standards
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
IRS	Internal Revenue Service
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
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	One thousand standard cubic feet
Mcfe	One thousand standard cubic feet equivalent. Natural gas liquid is converted by dividing gallons by 7. Crude oil is converted by multiplying barrels by 6.
MMBtu	One million British thermal units
MSHA	Mine Safety and Health Administration
MW	Megawatt
MWh	Megawatt-hour
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
NGL	Natural Gas Liquids
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
OTC	Over-the-counter
PGA	Purchase Gas Adjustment
PPA	Power Purchase Agreement
REPA	Renewable Energy Purchase Agreement
Revolving Credit Facility	Our $500 million five-year revolving credit facility which commenced on Feb. 1, 2012 and expires on Feb. 1, 2017
S&P	Standard and Poor's
SEC	United States Securities and Exchange Commission
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, representing our Coal Mining segment

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(unaudited)



	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
	(in thousands, except per share amounts)
Revenue:
Utilities	$	214,716		$	223,714		$	766,317		$	834,463
Non-regulated energy	32,092			25,809			88,705			76,544
Total revenue	246,808			249,523			855,022			911,007

Operating expenses:
Utilities -
Fuel, purchased power and cost of gas sold	62,582			86,127			283,217			400,465
Operations and maintenance	59,398			58,313			183,721			184,411
Non-regulated energy operations and maintenance	22,466			22,813			65,774			69,438
Gain on sale of operating assets	(27,285		)	—			(27,285		)	—
Depreciation, depletion and amortization	41,408			33,278			121,398			97,434
Taxes - property, production and severance	10,213			9,161			31,201			24,598
Impairment of long-lived assets	—			—			26,868			—
Other operating expenses	216			259			1,679			562
Total operating expenses	168,998			209,951			686,573			776,908

Operating income	77,810			39,572			168,449			134,099

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums, discounts and realized settlements on interest rate swaps)	(27,475		)	(29,303		)	(85,151		)	(87,099		)
Allowance for funds used during construction - borrowed	1,127			3,520			2,608			9,874
Capitalized interest	175			2,981			467			8,198
Unrealized gain (loss) on interest rate swaps, net	605			(38,246		)	(2,902		)	(40,608		)
Interest income	364			536			1,428			1,547
Allowance for funds used during construction - equity	196			189			668			676
Other income (expense), net	(287		)	528			2,073			1,763
Total other income (expense)	(25,295		)	(59,795		)	(80,809		)	(105,649		)

Income (loss) before equity in earnings (loss) of unconsolidated subsidiaries and income taxes	52,515			(20,223		)	87,640			28,450
Equity in earnings (loss) of unconsolidated subsidiaries	22			43			(12		)	1,076
Income tax benefit (expense)	(17,914		)	9,017			(30,057		)	(7,915		)
Income (loss) from continuing operations	34,623			(11,163		)	57,571			21,611
Income (loss) from discontinued operations, net of tax	(166		)	638			(6,810		)	2,526
Net income (loss) available for common stock	$	34,457		$	(10,525	)	$	50,761		$	24,137

Income (loss) per share, Basic -
Income (loss) from continuing operations, per share	$	0.79		$	(0.29	)	$	1.31		$	0.55
Income (loss) from discontinued operations, per share	—			0.02			(0.16		)	0.07
Total income (loss) per share, Basic	$	0.79		$	(0.27	)	$	1.15		$	0.62
Income (loss) per share, Diluted -
Income (loss) from continuing operations, per share	$	0.78		$	(0.29	)	$	1.31		$	0.54
Income (loss) from discontinued operations, per share	—			0.02			(0.16		)	0.07
Total income (loss) per share, Diluted	$	0.78		$	(0.27	)	$	1.15		$	0.61
Weighted average common shares outstanding:
Basic	43,847			39,145			43,792			39,105
Diluted	44,108			39,145			44,026			39,792

Dividends paid per share of common stock	$	0.370		$	0.365		$	1.110		$	1.095

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)



	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
	(in thousands)

Net income (loss) available for common stock	$	34,457		$	(10,525	)	$	50,761		$	24,137

Other comprehensive income (loss), net of tax:
Fair value adjustment of derivatives designated as cash flow hedges (net of tax of $1,204 and $(1,215) for the three months ended 2012 and 2011 and $1,092 and $653 for the nine months ended 2012 and 2011, respectively)	(3,591		)	1,922			(3,004		)	(991		)
Reclassification adjustments of cash flow hedges settled and included in net income (loss) (net of tax of $13 and $(129) for the three months ended 2012 and 2011 and $890 and $(985) for the nine months ended 2012 and 2011, respectively)	28			285			(1,333		)	1,907
Other comprehensive income (loss), net of tax	(3,563		)	2,207			(4,337		)	916

Comprehensive income (loss)	$	30,894		$	(8,318	)	$	46,424		$	25,053

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)



	Sept. 30, 2012			Dec. 31, 2011			Sept. 30, 2011
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	247,192		$	21,628		$	30,198
Restricted cash and equivalents	7,302			9,254			4,080
Accounts receivable, net	104,482			156,774			102,673
Materials, supplies and fuel	80,900			84,064			84,607
Derivative assets, current	16,063			18,583			12,177
Income tax receivable, net	11,869			9,344			4,728
Deferred income tax assets, net, current	33,681			37,202			37,931
Regulatory assets, current	24,606			59,955			45,713
Other current assets	44,823			21,266			25,269
Assets of discontinued operations	—			340,851			332,503
Total current assets	570,918			758,921			679,879

Investments	16,273			17,261			17,338

Property, plant and equipment	3,950,222			3,724,016			3,656,762
Less accumulated depreciation and depletion	(1,253,808		)	(934,441		)	(931,299		)
Total property, plant and equipment, net	2,696,414			2,789,575			2,725,463

Other assets:
Goodwill	353,396			353,396			353,396
Intangible assets, net	3,675			3,843			3,899
Derivative assets, non-current	1,167			1,971			3,246
Regulatory assets, non-current	191,935			182,175			142,267
Other assets, non-current	19,850			19,941			20,081
Total other assets	570,023			561,326			522,889

TOTAL ASSETS	$	3,853,628		$	4,127,083		$	3,945,569

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)

(unaudited)



	Sept. 30, 2012			December 31, 2011			Sept. 30, 2011
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	69,138		$	104,748		$	91,628
Accrued liabilities	179,284			151,319			161,650
Derivative liabilities, current	86,509			84,367			101,312
Regulatory liabilities, current	10,705			16,231			10,568
Notes payable	225,000			345,000			359,000
Current maturities of long-term debt	328,310			2,473			2,893
Liabilities of discontinued operations	—			173,929			171,685
Total current liabilities	898,946			878,067			898,736

Long-term debt, net of current maturities	942,950			1,280,409			1,282,194

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	338,194			300,988			317,864
Derivative liabilities, non-current	41,410			49,033			22,475
Regulatory liabilities, non-current	120,491			108,217			85,074
Benefit plan liabilities	167,690			177,480			124,214
Other deferred credits and other liabilities	129,630			123,553			127,007
Total deferred credits and other liabilities	797,415			759,271			676,634

Commitments and contingencies (See Notes 6, 7, 9, 11, 12 and 14)

Stockholders' equity:
Common stock —
Common stock $1 par value: 100,000,000 shares authorized: issued 44,250,588; 43,957,502 and 39,491,616 shares, respectively	44,251			43,958			39,492
Additional paid-in capital	731,176			722,623			604,945
Retained earnings	478,459			476,603			467,043
Treasury stock at cost – 75,420; 32,766 and 28,041 shares, respectively	(2,354		)	(970		)	(810		)
Accumulated other comprehensive income (loss)	(37,215		)	(32,878		)	(22,665		)
Total stockholders' equity	1,214,317			1,209,336			1,088,005

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,853,628		$	4,127,083		$	3,945,569

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended Sept. 30,
	2012			2011
Operating activities:	(unaudited, in thousands)
Net income (loss) available to common stock	$	50,761		$	24,137
(Income) loss from discontinued operations, net of tax	6,810			(2,526		)
Income (loss) from continuing operations	57,571			21,611
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	121,398			97,434
Deferred financing cost amortization	5,301			5,040
Impairment of long-lived assets	26,868			—
Derivative fair value adjustments	(3,522		)	(2,305		)
Gain on sale of operating assets	(27,285		)	—
Stock compensation	5,974			4,840
Unrealized mark-to-market (gain) loss on interest rate swaps	2,902			40,608
Deferred income taxes	28,718			20,854
Allowance for funds used during construction - equity	(668		)	(676		)
Employee benefit plans	15,737			10,930
Other adjustments, net	3,505			3,177
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	3,085			(21,692		)
Accounts receivable, unbilled revenues and other current assets	43,447			50,649
Accounts payable and other current liabilities	(22,042		)	(51,846		)
Regulatory assets	15,544			22,357
Regulatory liabilities	(1,983		)	5,041
Contributions to defined benefit pension plans	(25,000		)	(11,050		)
Other operating activities, net	(1,067		)	(1,755		)
Net cash provided by operating activities of continuing operations	248,483			193,217
Net cash provided by (used in) operating activities of discontinued operations	21,184			13,309
Net cash provided by operating activities	269,667			206,526

Investing activities:
Property, plant and equipment additions	(261,414		)	(326,543		)
Proceeds from sale of assets	268,482			583
Investment in notes receivable	(21,832		)	—
Other investing activities	5,057			1,051
Net cash provided by (used in) investing activities of continuing operations	(9,707		)	(324,909		)
Proceeds from sale of discontinued business operations	108,837			—
Net cash provided by (used in) investing activities of discontinued operations	(824		)	(1,953		)
Net cash provided by (used in) investing activities	98,306			(326,862		)

Financing activities:
Dividends paid on common stock	(48,904		)	(43,169		)
Common stock issued	3,835			2,199
Short-term borrowings - issuances	62,453			770,000
Short-term borrowings - repayments	(182,453		)	(560,000		)
Long-term debt - repayments	(11,647		)	(6,169		)
Other financing activities	(2,833		)	(28		)
Net cash provided by (used in) financing activities of continuing operations	(179,549		)	162,833
Net cash provided by (used in) financing activities of discontinued operations	—			(157		)
Net cash provided by (used in) financing activities	(179,549		)	162,676
Net change in cash and cash equivalents	188,424			42,340
Cash and cash equivalents, beginning of period*	58,768			32,438
Cash and cash equivalents, end of period*	$	247,192		$	74,778

_______________________


*	Includes cash of discontinued operations of $37.1 million, $44.6 million and $16.0 million at Dec. 31, 2011, Sept. 30, 2011 and Dec. 31, 2010, respectively.

See Note 3 for supplemental disclosure of cash flow information.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company's 2011 Annual Report on Form 10-K)

(1) MANAGEMENT'S STATEMENT

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the "Company," "us," "we," or "our"), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2011 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the Sept. 30, 2012, December 31, 2011 and Sept. 30, 2011 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for gas utilities is November through March and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended Sept. 30, 2012 and Sept. 30, 2011, and our financial condition as of Sept. 30, 2012, December 31, 2011, and Sept. 30, 2011 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

On Feb. 29, 2012, we sold 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 classification of this segment as discontinued operations. For further information see Note 17.

Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation. Specifically, the Company has reclassified deferred financing cost amortization into a separate line on the Condensed Consolidated Statements of Cash Flows. This reclassification had no effect on total assets, net income, cash flows or earnings per share.

(2) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION

Recently Adopted Accounting Standards and Legislation

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending accounting guidance for Comprehensive Income to improve the comparability, consistency and transparency of reporting of comprehensive income. The update 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 is effective for the fiscal years, and interim periods within those years beginning after Dec. 15, 2011. In December 2011, FASB issued ASU 2011-12, which 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.

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, but did not have any other impact on our financial statements.

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 accounting guidance for 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 financial statements. Additional disclosures are included in Notes 12 and 13.

Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08

In September 2011, the FASB issued an amendment to accounting guidance to Intangibles - Goodwill and Other to provide an option to perform a qualitative assessment to determine whether further impairment testing of 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 testing performed for fiscal years beginning after Dec. 15, 2011. We perform our annual impairment testing in November of each year. The adoption of this standard will not have an impact on our financial statements.

Recently Issued Accounting Standards and Legislation

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11

In December 2011, the FASB issued revised accounting guidance to amend accounting guidance for 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.

Intangible - Goodwill and Other: Testing Indefinite Lived Intangible Assets for Impairment, ASU 2012-02

In July 2012, the FASB issued an amendment to accounting guidance for 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 statements.

Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 34-67717 and No. 33-9338

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 United States government. We are in the process of evaluating our reporting requirements. The adoption of this rule will not have an impact on our financial statements.

Additionally, in July 2012, the CFTC and SEC published final rules that define “swap,” “security-based swap” and other key terms and concepts that are critical to the implementation of the derivatives reforms required by Dodd-Frank. We are in the process of evaluating our reporting requirements. The adoption of this rule will not have an impact on our financial position, results of operations or cash flows.

(3) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



	Nine Months Ended
	Sept. 30, 2012			Sept. 30, 2011
	(in thousands)
Non-cash investing activities from continuing operations—
Property, plant and equipment acquired with accounts payable and accrued liabilities	$	39,303		$	49,566
Capitalized assets associated with retirement obligations	$	3,806		$	—
Cash (paid) refunded during the period for continuing operations—
Interest (net of amounts capitalized)	$	(69,901	)	$	(60,934	)
Income taxes, net	$	425		$	11,939

(4) MATERIALS, SUPPLIES AND FUEL

The amounts of materials, supplies and fuel included in the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands) as of:



	Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
Materials and supplies	$	43,847	$	40,838	$	37,327
Fuel - Electric Utilities	8,289		8,201		8,639
Natural gas in storage held for distribution	28,764		35,025		38,641
Total materials, supplies and fuel	$	80,900	$	84,064	$	84,607

(5) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable consists primarily of customer trade accounts. The Gas Utilities' accounts receivable balance fluctuates primarily due to seasonality. We maintain an allowance for doubtful accounts that reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect our ability to collect.

Following is a summary of receivables (in thousands) as of:



	Accounts		Unbilled		Less Allowance for			Accounts
Sept. 30, 2012	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	46,802	$	18,441	$	(603	)	$	64,640
Gas Utilities	18,198		9,480		(204		)	27,474
Oil and Gas	10,272		—		(105		)	10,167
Coal Mining	1,540		—		—			1,540
Power Generation	4		—		—			4
Corporate	657		—		—			657
Total	$	77,473	$	27,921	$	(912	)	$	104,482



	Accounts		Unbilled		Less Allowance for			Accounts
Dec. 31, 2011	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	42,773	$	21,151	$	(545	)	$	63,379
Gas Utilities	39,353		38,992		(1,011		)	77,334
Oil and Gas	11,282		—		(105		)	11,177
Coal Mining	4,056		—		—			4,056
Power Generation	282		—		—			282
Corporate	546		—		—			546
Total	$	98,292	$	60,143	$	(1,661	)	$	156,774



	Accounts		Unbilled		Less Allowance for			Accounts
Sept. 30, 2011	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	41,889	$	16,401	$	(590	)	$	57,700
Gas Utilities	21,168		12,518		(789		)	32,897
Oil and Gas	8,820		—		(161		)	8,659
Coal Mining	1,845		—		—			1,845
Power Generation	119		—		—			119
Corporate	1,453		—		—			1,453
Total	$	75,294	$	28,919	$	(1,540	)	$	102,673

(6) NOTES PAYABLE

Our credit facility and debt securities contain certain restrictive financial covenants. We were in compliance with all of these covenants at Sept. 30, 2012.

We had the following short-term debt outstanding at the Condensed Consolidated Balance Sheet dates (in thousands) as of:



	Sept. 30, 2012				Dec. 31, 2011				Sept. 30, 2011
	Notes Payable		Letters of Credit		Notes Payable		Letters of Credit		Notes Payable		Letters of Credit
Revolving Credit Facility	$	75,000	$	36,300	$	195,000	$	43,700	$	209,000	$	42,355
Term Loan due June 2013 ^(a)	150,000		—		150,000		—		150,000		—
Total	$	225,000	$	36,300	$	345,000	$	43,700	$	359,000	$	42,355

______________

(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 Sept. 30, 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 Revolving Credit Facility of $2.8 million are being amortized over the estimated useful life of the Revolving Credit Facility and are included in Interest expense on the accompanying Condensed 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.

Term Loans

On June 24, 2012, we extended the term of the $150 million term loan to June 24, 2013. The cost of borrowing is based on 1.10 percent over LIBOR.

Debt Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):



	As of
	Sept. 30, 2012			Covenant Requirement
Consolidated Net Worth	$	1,214,317		Greater than	$	909,511
Recourse Leverage Ratio	56.3		%	Less than	65.0		%

(7) LONG TERM DEBT

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.

(8) EARNINGS PER SHARE

Basic Income (loss) per share from continuing operations is computed by dividing Income (loss) from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted Income (loss) per share is computed by including all dilutive common shares potentially outstanding during a period.

A reconciliation of share amounts used to compute Income (loss) per share is as follows (in thousands):



	Three Months Ended Sept. 30,					Nine Months Ended Sept. 30,
	2012		2011			2012		2011

Income (loss) from continuing operations	$	34,623	$	(11,163	)	$	57,571	$	21,611

Weighted average shares - basic	43,847		39,145			43,792		39,105
Dilutive effect of:
Restricted stock	175		—			159		147
Stock options	12		—			14		16
Equity forward instruments	—		—			—		473
Other dilutive effects	74		—			61		51
Weighted average shares - diluted	44,108		39,145			44,026		39,792

Below is a discussion of our potentially dilutive shares that were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive.

Due to our net loss for the quarter ended Sept. 30, 2011, potentially dilutive securities, consisting of outstanding stock options, restricted common stock, restricted stock units, non-vested performance-based share awards and warrants, were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, 11,880 options to purchase shares of common stock, 159,873 vested and non-vested restricted stock shares, 31,408 warrants and other performance shares and 424,715 forward equity instruments were excluded from the computations for the three months ended Sept. 30, 2011.

In addition to these potentially dilutive shares excluded due to our net loss for third quarter of 2011, the following outstanding securities also were excluded in the computation of diluted Income (loss) per share from continuing operations as their inclusion would have been anti-dilutive (in thousands):



	Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
	2012	2011	2012	2011
Stock options	77	176	101	119
Restricted stock	61	20	53	17
Other stock	—	27	19	19
Anti-dilutive shares	138	223	173	155

(9) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans (Pension Plans). One covers certain eligible employees of Black Hills Service Company, Black Hills Power, WRDC and BHEP, one covers certain eligible employees of Cheyenne Light, and one covers certain eligible employees of Black Hills Energy. As of Jan. 1, 2012, all Pension Plans have been frozen to new employees and certain eligible employees who did not meet age and service based criteria at the time the Pension Plans were frozen. Additionally, effective Oct. 1, 2012, the Cheyenne Light Pension Plan was merged into the Black Hills Corporation Pension Plan. The Pension Plan benefits are based on years of service and compensation levels.

The components of net periodic benefit cost for the Pension Plans were as follows (in thousands):



	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
Service cost	$	1,431		$	1,355		$	4,291		$	4,066
Interest cost	3,688			3,732			11,062			11,196
Expected return on plan assets	(4,084		)	(4,239		)	(12,252		)	(12,717		)
Prior service cost	22			25			66			75
Net loss (gain)	2,408			1,135			7,224			3,405
Net periodic benefit cost	$	3,465		$	2,008		$	10,391		$	6,025

Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor the following retiree healthcare plans (Healthcare Plans): the Black Hills Corporation Postretirement Healthcare Plan, the Healthcare Plan for Retirees of Cheyenne Light, and the Black Hills Energy Postretirement Healthcare Plan. Employees who participate in the Healthcare Plans and who retire on or after meeting certain eligibility requirements are entitled to postretirement healthcare benefits.

The components of net periodic benefit cost for the Healthcare Plans were as follows (in thousands):



	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
Service cost	$	402		$	375		$	1,206		$	1,125
Interest cost	523			542			1,569			1,626
Expected return on plan assets	(19		)	(41		)	(57		)	(123		)
Prior service cost (benefit)	(125		)	(120		)	(375		)	(360		)
Net loss (gain)	222			169			666			507
Net periodic benefit cost	$	1,003		$	925		$	3,009		$	2,775

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives (Supplemental Plans). The Supplemental Plans are non-qualified defined benefit plans.

The components of net periodic benefit cost for the Supplemental Plans were as follows (in thousands):



	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011
Service cost	$	243	$	257	$	735	$	771
Interest cost	331		324		993		973
Prior service cost	1		1		3		3
Net loss (gain)	202		128		606		383
Net periodic benefit cost	$	777	$	710	$	2,337	$	2,130

Contributions

We anticipate that we will make contributions to the benefit plans during 2012 and 2013. Contributions to the Pension Plans will be made in cash, and contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):



	Contributions Made		Contributions Made		Additional
	Three Months Ended Sept. 30, 2012		Nine Months Ended Sept. 30, 2012		Contributions Anticipated for 2012		Contributions Anticipated for 2013
Defined Benefit Pension Plans	$	—	$	25,000	$	—	$	4,500
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,063	$	3,189	$	1,063	$	4,380
Supplemental Non-qualified Defined Benefit Plans	$	278	$	834	$	278	$	1,090

(10) BUSINESS SEGMENT 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 classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification 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 17.

We conduct our operations through the following five reportable segments:

Utilities Group —


•	Electric Utilities, which supplies electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility service to Cheyenne, Wyo. and vicinity; and


•	Gas Utilities, which supplies natural gas utility service to areas in Colorado, Iowa, Kansas and Nebraska.

Non-regulated Energy Group —


•	Oil and Gas, which acquires, explores for, develops and produces crude oil and natural gas interests located in the Rocky Mountain region and other states;


•	Power Generation, which produces and sells power and capacity to wholesale customers from power plants located in Wyoming and Colorado; and


•	Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, Wyo.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Segment information included in the accompanying Condensed Consolidated Statements of Income and Condensed Consolidated Balance Sheets was as follows (in thousands):



Three Months Ended Sept. 30, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	151,281	$	3,736		$	14,573
Gas	63,435		—			3
Non-regulated Energy:
Oil and Gas ^(a)	24,728		—			17,389
Power Generation	1,256		19,695			5,128
Coal Mining	6,108		8,567			1,690
Corporate ^(b)	—		—			(4,160		)
Intercompany eliminations	—		(31,998		)	—
Total	$	246,808	$	—		$	34,623



Three Months Ended Sept. 30, 2011	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	151,063	$	2,653		$	15,790
Gas	72,651		—			572
Non-regulated Energy:
Oil and Gas	19,163		—			241
Power Generation	1,011		7,089			337
Coal Mining	9,184		8,651			555
Corporate ^(b)(c)	—		—			(28,307		)
Intercompany eliminations	—		(21,942		)	(351		)
Total	$	253,072	$	(3,549	)	$	(11,163	)



Nine Months Ended Sept. 30, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	451,974	$	11,946		$	37,478
Gas	314,343		—			16,369
Non-regulated Energy:
Oil and Gas ^(a)(d)	66,994		—			(2,219		)
Power Generation	3,193		56,119			15,968
Coal Mining	18,518		24,273			3,924
Corporate ^(b)	—		—			(13,949		)
Intercompany eliminations	—		(92,338		)	—
Total	$	855,022	$	—		$	57,571



Nine Months Ended Sept. 30, 2011	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	431,624	$	9,902		$	34,653
Gas	402,839		—			24,275
Non-regulated Energy:
Oil and Gas	55,907		—			(553		)
Power Generation	2,589		20,911			2,071
Coal Mining	23,064		25,806			(1,124		)
Corporate ^(b)(c)	—		—			(37,299		)
Intercompany eliminations	—		(61,635		)	(412		)
Total	$	916,023	$	(5,016	)	$	21,611

____________

Income Statement Notes:


(a)	Income (loss) from continuing operations includes a $17.7 million after-tax gain on the sale of the Williston Basin assets. See Note 15.

(b)

Income (loss) from continuing operations includes $0.4 million net after-tax non-cash mark-to-market gain and $1.9 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2012, respectively, and a $24.9 million and $26.4 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2011, respectively.


(c)	Certain indirect corporate costs and inter-segment interest expenses after-tax totaling $0.5 million for the three months ended Sept. 30, 2011 and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011 were included in the Corporate segment in continuing operations and were not reclassified as discontinued operations. See Note 17 for further information.


(d)	Income (loss) from continuing operations includes a $17.3 million non-cash after-tax ceiling test impairment expense. See Note 16 for further information.



Total Assets (net of inter-company eliminations) as of:	Sept. 30, 2012		Dec. 31, 2011			Sept. 30, 2011
Utilities:
Electric^(a)	$	2,302,951	$	2,254,914		$	1,917,184
Gas	710,099		746,444			683,163
Non-regulated Energy:
Oil and Gas ^(b)	263,088		425,970			405,513
Power Generation^(a)	119,489		129,121			372,313
Coal Mining	90,444		88,704			94,908
Corporate	367,557		141,079		^(c)	139,985		^(c)
Discontinued operations	—		340,851		^(d)	332,503		^(d)
Total assets	$	3,853,628	$	4,127,083		$	3,945,569

____________


(a)	Upon commercial operation on Dec. 31, 2011 of the new generating facility constructed by Colorado IPP at our Pueblo Airport Generation site, the PPA under which energy and capacity is sold to Colorado Electric 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 as a capital lease.


(b)	2012 includes a ceiling test impairment and the sale of the Williston Basin assets by our Oil and Gas segment. See Notes 15 and 16.


(c)	Assets of the Corporate segment were reclassified due to deferred taxes that were not classified as discontinued operations.


(d)	See Note 17 for further information relating to discontinued operations.

(11) RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation 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 as discussed in our 2011 Annual Report on Form 10-K.

Market Risk

Market risk is the potential loss that might 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 and non-regulated segments; and


•	Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our derivative instruments.

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.

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 investment grade rated companies, 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.

As of Sept. 30, 2012, our credit exposure (exclusive of retail customers of the regulated utilities) was concentrated primarily among investment grade rated companies, cooperative utilities and federal agencies.

We actively manage our exposure to certain market and credit risks as described in Note 3 of the Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are detailed below and in Note 12.

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, result in commodity price risk and variability to our cash flows.

We hold a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on those OTC swaps and options. 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 are marked to fair value and are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed 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) and the ineffective portion, if any, is reported in Revenue.

We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:



	Sept. 30, 2012					Dec. 31, 2011					Sept. 30, 2011
	Crude Oil Swaps/ Options		Natural Gas Swaps			Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options		Natural Gas Swaps
Notional ^(a)	537,000		7,455,250			528,000			5,406,250		414,000		4,957,250
Maximum terms in years ^(b)	1.00		1.00			1.25			1.75		1.00		0.25
Derivative assets, current	$	1,651	$	2,032		$	729		$	8,010	$	1,885	$	6,937
Derivative assets, non-current	$	494	$	39		$	771		$	1,148	$	2,529	$	717
Derivative liabilities, current	$	527	$	1,040		$	2,559		$	—	$	—	$	—
Derivative liabilities, non-current	$	414	$	141		$	811		$	7	$	—	$	7
Pre-tax accumulated other comprehensive income (loss)	$	428	$	(344	)	$	(1,928	)	$	9,152	$	4,257	$	7,647
Cash collateral included in Derivative liabilities	$	—	$	—		$	—		$	—	$	—	$	—
Cash collateral included in Other current assets	$	1,126	$	1,288		$	—		$	—	$	—	$	—
Expense included in Revenue ^(c)	$	350	$	54		$	58		$	—	$	157	$	—

____________


(a)	Crude oil in Bbls, gas in MMBtus.


(b)	Refers to the term of the derivative instrument. Assets and liabilities are classified as current or non-current based on the term of the hedged transaction and the corresponding settlement of the derivative instruments.


(c)	Represents the amortization of put premiums.

Based on Sept. 30, 2012 market prices, a $1.2 million gain would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

Utilities

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 certain 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 Condensed Consolidated Balance Sheets. Gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with accounting standards for regulated utility operations. Accordingly, the hedging activity is recognized in the Condensed Consolidated Statements of Income when the related costs are recovered through our rates or adjustment mechanisms.

The contract notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows as of:



	Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	14,690,000	75	14,310,000	84	9,890,000	18
Natural gas options purchased	5,560,000	6	1,720,000	3	3,880,000	6
Natural gas basis swaps purchased	8,800,000	75	7,160,000	60	—	—

We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:



	Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
Derivative assets, current	$	12,380	$	9,844	$	3,355
Derivative assets, non-current	$	634	$	52	$	—
Derivative liabilities, non-current	$	4,527	$	7,156	$	1,360
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	9,318	$	17,556	$	11,813
Included in Derivatives:
Cash collateral receivable (payable)	$	15,740	$	19,416	$	12,058
Option premiums and commissions	$	2,065	$	880	$	1,750

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:



	Sept. 30, 2012						Dec. 31, 2011						Sept. 30, 2011
	Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*
Notional	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.25			1.25			5.00			2.00			5.25			0.25
Derivative liabilities, current	$	7,028		$	77,914		$	6,513		$	75,295		$	6,724		$	94,588
Derivative liabilities, non-current	$	18,660		$	17,668		$	20,363		$	20,696		$	21,108		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(25,688	)	$	—		$	(26,876	)	$	—		$	(27,832	)	$	—
Year-to Date pre-tax gain (loss)	$	—		$	(2,902	)	$	—		$	(42,010	)	$	—		$	(40,608	)
Cash collateral receivable (payable) included in derivative	$	—		$	3,310		$	—		$	—		$	—		$	—

_____________


*	Maximum terms 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 on the termination date. If extended, de-designated swaps totaling $100 million notional terminate in 6.25 years and de-designated swaps totaling $150 million notional terminate in 16.25 years.

Collateral requirements based on our corporate credit rating apply to $50 million of our de-designated swaps. At our current credit ratings, we are required to post collateral for any amount by which the swaps' negative mark-to-market fair value exceeds $20 million. If our senior unsecured credit rating drops to BB+ or below by S&P, or to Ba1 or below by Moody's, we would be required to post collateral for the entire amount of the swaps' negative mark-to-market fair value.

Based on Sept. 30, 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 actual realized gains or losses will change during future periods as market interest rates change.

(12) FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The ASC on Fair Value Measurements and Disclosure Requirements establishes a hierarchy for grouping assets and liabilities, based on significance of inputs. For additional information see Notes 3 and 4 included in our 2011 Annual Report on Form 10-K filed with the SEC. 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

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 multiple 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.

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.

Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. 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 Sept. 30, 2012
	Level 1		Level 2			Level 3			Counterparty Netting		Cash Collateral			Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	619		$	—		$	—	$	—		$	619
Basis Swaps -- Oil	—		1,526			—			—		—			1,526
Options -- Gas	—		—			—			—		—			—
Basis Swaps -- Gas	—		2,071			—			—		—			2,071
Commodity derivatives — Utilities	—		(2,760		)	34		^(b)	—		15,740			13,014
Cash and cash equivalents ^(a)	247,192		—			—			—		—			247,192
Total	$	247,192	$	1,456		$	34		$	—	$	15,740		$	264,422

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	885		$	—		$	—	$	—		$	885
Basis Swaps -- Oil	—		56			—			—		—			56
Options -- Gas	—		—			—			—		—			—
Basis Swaps -- Gas	—		1,181			—			—		—			1,181
Commodity derivatives — Utilities	—		4,527			—			—		—			4,527
Interest rate swaps	—		124,580			—			—		(3,310		)	121,270
Total	$	—	$	131,229		$	—		$	—	$	(3,310	)	$	127,919

______________


(a)	Level 1 assets and liabilities are described in Note 13.

(b)

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.



	As of Dec. 31, 2011
	Level 1		Level 2			Level 3			Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—		$	768	^(a)	$	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
Money market funds	6,005		—			—			—		—		6,005
Total	$	6,005	$	365		$	768	^(a)	$	5	$	19,416	$	26,559

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—		$	1,165	^(a)	$	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	^(a)	$	5	$	—	$	133,400

_________


(a)	Of the net balance included as Level 3, transfers out of Level 3 included settlement of losses of approximately $0.5 million within AOCI and approximately $0.9 million transferred to level 2 as inputs becoming more observable.



	As of Sept. 30, 2011
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—		$	328	$	—	$	—	$	328
Basis Swaps -- Oil	—		4,086			—		—		—		4,086
Options -- Gas	—		—			—		—		—		—
Basis Swaps -- Gas	—		7,654			—		—		—		7,654
Commodity derivatives — Utilities	—		(8,703		)	—		—		12,058		3,355
Money market funds	9,006		—			—		—		—		9,006
Total	$	9,006	$	3,037		$	328	$	—	$	12,058	$	24,429

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—		$	—	$	—	$	—	$	—
Basis Swaps -- Oil	—		—			—		—		—		—
Options -- Gas	—		—			—		—		—		—
Basis Swaps -- Gas	—		7			—		—		—		7
Commodity derivatives — Utilities	—		1,360			—		—		—		1,360
Interest rate swaps	—		122,420			—		—		—		122,420
Total	$	—	$	123,787		$	—	$	—	$	—	$	123,787

Fair Value Measures

As required by accounting standards for derivatives and hedges, 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 Sept. 30, 2012, Dec. 31, 2011, and Sept. 30, 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 Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 11.

The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):



As of Sept. 30, 2012
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	3,263	$	—
Commodity derivatives	Derivative assets — non-current	533		—
Commodity derivatives	Derivative liabilities — current	—		1,534
Commodity derivatives	Derivative liabilities — non-current	—		555
Interest rate swaps	Derivative liabilities — current	—		7,029
Interest rate swaps	Derivative liabilities — non-current	—		18,661
Total derivatives designated as hedges		$	3,796	$	27,779

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	421	$	3,361
Commodity derivatives	Derivative assets — non-current	—		(634		)
Commodity derivatives	Derivative liabilities — current	—		33
Commodity derivatives	Derivative liabilities — non-current	—		4,527
Interest rate swaps	Derivative liabilities — current	—		77,913
Interest rate swaps	Derivative liabilities — non-current	—		20,977
Total derivatives not designated as hedges		$	421	$	106,177



As of Dec. 31, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	8,739	$	—
Commodity derivatives	Derivative assets — non-current	1,919		—
Commodity derivatives	Derivative liabilities — current	—		2,559
Commodity derivatives	Derivative liabilities — non-current	—		818
Interest rate swaps	Derivative liabilities — current	—		6,513
Interest rate swaps	Derivative liabilities — non-current	—		20,363
Total derivatives designated as hedges		$	10,658	$	30,253

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	9,572
Commodity derivatives	Derivative assets — non-current	—		(52		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		7,156
Interest rate swaps	Derivative liabilities — current	—		75,295
Interest rate swaps	Derivative liabilities — non-current	—		20,696
Total derivatives not designated as hedges		$	—	$	112,667



As of Sept. 30, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives			Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	8,822		$	—
Commodity derivatives	Derivative assets — non-current	3,246			—
Commodity derivatives	Derivative liabilities — current	—			—
Commodity derivatives	Derivative liabilities — non-current	—			7
Interest rate swaps	Derivative liabilities — current	—			6,724
Interest rate swaps	Derivative liabilities — non-current	—			21,108
Total derivatives designated as hedges		$	12,068		$	27,839

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—		$	8,703
Commodity derivatives	Derivative assets — non-current	—			—
Commodity derivatives	Derivative liabilities — current	(2		)	(1,360		)
Commodity derivatives	Derivative liabilities — non-current	—			—
Interest rate swaps	Derivative liabilities — current	—			94,588
Interest rate swaps	Derivative liabilities — non-current	—			—
Total derivatives not designated as hedges		$	(2	)	$	101,931

A description of our derivative activities is included in Note 11. The following tables present the impact that derivatives had on our Condensed Consolidated Statements of Income.

Cash Flow Hedges

The impact of cash flow hedges on our Condensed Consolidated Statements of Income was as follows (in thousands):



Three Months Ended Sept. 30, 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 Reclassified Gain/(Loss) 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	$	(1,684	)	Interest expense	$	(1,853	)		$	—
Commodity derivatives	(3,111		)	Revenue	1,838				—
Total	$	(4,795	)		$	(15	)		$	—



Three Months Ended Sept. 30, 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 Reclassified Gain/(Loss) 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	$	(6,958	)	Interest expense	$	(1,930	)		$	—
Commodity derivatives	10,095			Revenue	1,516				—
Total	$	3,137			$	(414	)		$	—



Nine Months Ended Sept. 30, 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 Reclassified Gain/(Loss) 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	$	(4,697	)	Interest expense	$	(5,518	)		$	—
Commodity derivatives	601			Revenue	7,741				—
Total	$	(4,096	)		$	2,223			$	—



Nine Months Ended Sept. 30, 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 Reclassified Gain/(Loss) 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	$	(11,428	)	Interest expense	$	(5,741	)		$	—
Commodity derivatives	9,784			Revenue	2,849				—
Total	$	(1,644	)		$	(2,892	)		$	—

Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments that have not been designated as hedging instruments on our Condensed Consolidated Statements of Income was as follows (in thousands):



		Three Months Ended			Nine Months Ended
		Sept. 30, 2012			Sept. 30, 2012
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
Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swaps, net	$	605		$	(2,902	)
Interest rate swaps - realized	Interest expense	(3,250		)	(9,697		)
Commodity derivatives	Revenue	(14		)	(14		)
		$	(2,659	)	$	(12,613	)



		Three Months Ended			Nine Months Ended
		Sept. 30, 2011			Sept. 30, 2011
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
Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swaps, net	$	(38,246	)	$	(40,608	)
Interest rate swaps - realized	Interest expense	(3,373		)	(10,077		)
		$	(41,619	)	$	(50,685	)

(13) FAIR VALUE OF FINANCIAL INSTRUMENTS

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



	Sept. 30, 2012				Dec. 31, 2011				Sept. 30, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	247,192	$	247,192	$	21,628	$	21,628	$	30,198	$	30,198
Restricted cash and equivalents ^(a)	$	7,302	$	7,302	$	9,254	$	9,254	$	4,080	$	4,080
Notes receivable ^(a)	$	21,832	$	21,832	$	—	$	—	$	—	$	—
Notes payable ^(b)	$	225,000	$	225,000	$	345,000	$	345,000	$	359,000	$	359,000
Long-term debt, including current maturities ^(c)	$	1,271,260	$	1,471,932	$	1,282,882	$	1,464,289	$	1,285,087	$	1,430,271

____________


(a)	Fair value approximates carrying value due to either the 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)	The carrying amounts of our notes payable approximate fair value due to their variable interest rates with short reset periods.


(c)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

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

Cash and Cash Equivalents

Included in cash and cash equivalents are 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 equivalents represent restricted cash and uninsured term deposits.

Notes Receivable

Notes receivable, included in Other current assets on the accompanying Condensed Consolidated Balance Sheet, represents cash held by a third party related to tax planning strategies for effecting like-kind exchange structuring for the purchase of additional oil and gas leases.

Notes Payable

Notes Payable represent our short-term corporate term loan and borrowings under our Revolving Credit Facility.

Long-term Debt

Our debt instruments are marked to fair value using the market valuation approach. The fair value for our fixed rate debt instruments is estimated based on quoted market prices and yields for debt instruments having similar maturities and debt ratings. The carrying amounts of our variable rate debt approximate fair value due to the variable interest rates with short reset periods.

(14) COMMITMENTS AND CONTINGENCIES

Commitments and Contingencies

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of Sept. 30, 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 stockholders 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 Sept. 30, 2012:


•	Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of Sept. 30, 2012, the restricted net assets at our Utilities Group were approximately $227.2 million.


•	As required by the covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted equity of at least $100.0 million.

(15) SALE OF ASSETS

Oil and Gas

On Sept. 27, 2012, our Oil and Gas segment sold a majority of its Bakken and Three Forks shale assets in the Williston Basin of North Dakota. The sale included approximately 73 gross wells, 28,000 net lease 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 significantly alters the relationship and accordingly we have recorded a gain of $27.3 million with the remainder of the proceeds recorded as a reduction in the full cost pool. This reduction in the full cost pool will decrease in the depreciation, depletion and amortization rate.

Net cash proceeds were as follows (in thousands):



Cash proceeds received on date of sale	$	243,314

Adjustments to proceeds:
Post close adjustments	1,490
Transaction adviser fees	(1,400		)
Estimated payment for contractual obligation related to "back-in" fee *	(16,847		)

Net cash proceeds	$	226,557

_____________

* Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

Electric Utilities

On Sept. 18, 2012, Colorado Electric completed the sale of an undivided 50 percent ownership interest in the 29 megawatt Busch Ranch Wind project 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 was achieved on Oct. 16, 2012. Colorado Electric will purchase AltaGas's interest in the energy produced by the wind farm through a REPA expiring on Oct. 16, 2037.

(16) 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, we recorded a $26.9 million non-cash impairment of oil and gas assets included in our Oil and Gas segment in the second quarter of 2012. 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.

(17) DISCONTINUED OPERATIONS

Pursuant to the provisions of the stock purchase agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $1.4 million, which is accrued for in the accompanying financial statements as of Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, resolution will occur through the dispute resolution provision of the stock purchase agreement.

The accompanying Condensed Consolidated Financial Statements have been classified to reflect Enserco as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification.

Operating results of the Energy Marketing segment included in Income (loss) from discontinued operations, net of tax on the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):



	For the Three Months Ended						For the Nine Months Ended
	Sept. 30, 2012			Sept. 30, 2011			Sept. 30, 2012			Sept. 30, 2011

Revenue	$	—		$	6,937		$	(604	)	$	21,878

Pre-tax income (loss) from discontinued operations	$	(311	)	$	1,495		$	(6,622	)	$	4,404
Pre-tax gain (loss) on sale	—			—			(3,787		)	—
Income tax (expense) benefit	145			(857		)	3,599			(1,878		)

Income (loss) from discontinued operations, net of tax ^(a)	$	(166	)	$	638		$	(6,810	)	$	2,526

_____________


(a)	Includes transaction related costs, net of tax, of $0.2 million and $2.5 million for three and nine months ended Sept. 30, 2012, respectively.

Indirect corporate costs and inter-segment interest expense after-tax totaling $0.5 million for the three months ended Sept. 30, 2011, and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011, respectively, were reclassified from the Energy Marketing segment to the Corporate segment in continuing operations on the accompanying Condensed Consolidated Statements of Income.

Net assets of the Energy Marketing segment included in Assets/Liabilities of discontinued operations in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands) as of:



	Dec. 31, 2011			Sept. 30, 2011

Other current assets	$	280,221		$	282,361
Derivative assets, current and non-current	52,859			50,519
Property, plant and equipment, net	5,828			5,391
Goodwill	1,435			1,435
Other non-current assets	508			(7,204		)
Other current liabilities	(132,951		)	(134,747		)
Derivative liabilities, current and non-current	(26,084		)	(31,978		)
Other non-current liabilities	(14,894		)	(4,959		)
Net assets	$	166,922		$	160,818

(18) SUBSEQUENT EVENTS

Long-term Debt

On Oct. 31, 2012, we redeemed our $225.0 million of senior unsecured 6.5 percent notes, which were originally scheduled to mature on May 15, 2013. The total payment was $238.8 million, including accrued interest expense and a make-whole provision payment of $7.1 million.


ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 the stock of Enserco, our Energy Marketing segment, to a third party buyer and therefore we now classify the segment 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 201,500 customers in South Dakota, Wyoming, Colorado and Montana; and also distributes natural gas to approximately 34,800 Cheyenne Light customers in Wyoming. Our Gas Utilities serve approximately 528,800 natural gas customers in Colorado, Iowa, Kansas and Nebraska. Our Non-regulated Energy Group consists of our Power Generation, Coal Mining and Oil and Gas segments. Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy principally to our utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, Wyo. and sells the coal primarily to on-site, mine-mouth power generation facilities. Our Oil and Gas segment principally engages in exploration, development and production of crude oil and natural gas, primarily in the Rocky Mountain region.

Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August with sensitivity from the degree of humidity while the normal peak usage season for gas utilities is November through March, and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended Sept. 30, 2012 and 2011, and our financial condition as of Sept. 30, 2012, Dec. 31, 2011, and Sept. 30, 2011 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 64.

The following business group and segment information does not include intercompany eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated. Information has been revised to remove information related to the operations of our Energy Marketing segment, now classified as discontinued operations, as a result of the sale of Enserco on Feb. 29, 2012.

Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011. Income from continuing operations for the three months ended Sept. 30, 2012 was $34.6 million, or $0.78 per share, compared to Loss from continuing operations of $11.2 million, or $0.29 per share, reported for the same period in 2011. The 2012 Income from continuing operations included an after-tax gain on sale of $17.7 million relating to the sale of the Williston Basin assets of our Oil and Gas segment, an incentive accrual of $2.2 million after-tax relating to the Williston Basin asset sale and a $0.4 million non-cash after-tax unrealized mark-to-market gain on certain interest rate swaps. The 2011 Loss from continuing operations included a $24.9 million after-tax non-cash unrealized mark-to-market loss on the same interest rate swaps.

Net income for the three months ended Sept. 30, 2012 was $34.5 million, or $0.78 per share, compared to Net loss of $10.5 million, or $0.27 per share, for the same period in 2011. Net income for the three months ended Sept. 30, 2012 and 2011 include the same significant items discussed above.

Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011. Income from continuing operations for the nine months ended Sept. 30, 2012 was $57.6 million, or $1.31 per share, compared to Income from continuing operations of $21.6 million, or $0.54 per share, reported for the same period in 2011. The 2012 Income from continuing operations included an after-tax gain of $17.7 million relating to the sale of the Williston Basin assets of our Oil and Gas segment, an incentive accrual of $2.2 million after-tax relating to the Williston Basin asset sale, a non-cash after-tax ceiling test impairment of $17.3 million, a $1.9 million non-cash after-tax unrealized mark-to-market loss on certain interest rate swaps, and an after-tax write-off of $1.0 million of deferred financing costs related to our previous revolving credit facility. The 2011 Income from continuing operations included a $26.4 million after-tax unrealized non-cash mark-to-market loss on the same interest rate swaps.

Net income for the nine months ended Sept. 30, 2012 was $50.8 million, or $1.15 per share, compared to $24.1 million, or $0.61 per share, for the same period in 2011. Net income for the nine months ended Sept. 30, 2012 and 2011 include the same significant items discussed above.



	Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance
	(in thousands)
Revenue
Utilities	$	218,452		$	226,367		$	(7,915	)	$	778,263		$	844,365		$	(66,102	)
Non-regulated Energy	60,354			45,098			15,256			169,097			128,277			40,820
Intercompany eliminations	(31,998		)	(21,942		)	(10,056		)	(92,338		)	(61,635		)	(30,703		)
	$	246,808		$	249,523		$	(2,715	)	$	855,022		$	911,007		$	(55,985	)

Net income (loss)
Electric Utilities	$	14,573		$	15,790		$	(1,217	)	$	37,478		$	34,653		$	2,825
Gas Utilities	3			572			(569		)	16,369			24,275			(7,906		)
Utilities	14,576			16,362			(1,786		)	53,847			58,928			(5,081		)

Power Generation	5,128			337			4,791			15,968			2,071			13,897
Coal Mining	1,690			555			1,135			3,924			(1,124		)	5,048
Oil and Gas ^(a)	17,389			241			17,148			(2,219		)	(553		)	(1,666		)
Non-regulated Energy	24,207			1,133			23,074			17,673			394			17,279

Corporate and eliminations ^(b)(c)	(4,160		)	(28,658		)	24,498			(13,949		)	(37,711		)	23,762

Income (loss) from continuing operations	34,623			(11,163		)	45,786			57,571			21,611			35,960

Income (loss) from discontinued operations, net of tax	(166		)	638			(804		)	(6,810		)	2,526			(9,336		)
Net income (loss)	$	34,457		$	(10,525	)	$	44,982		$	50,761		$	24,137		$	26,624

______________


(a)	Net income (loss) for three and nine months ended Sept. 30, 2012 includes a $17.7 million after-tax gain on the sale of the Williston Basin assets and Net income (loss) for the nine months ended Sept. 30, 2012 also includes a $17.3 million non-cash after-tax ceiling test impairment. See Notes 15 and 16 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

(b)

Financial results of our Energy Marketing segment have been classified as discontinued operations. Certain indirect corporate costs and inter-segment interest expenses totaling $0.5 million after-tax for the three months ended Sept. 30, 2011 and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011, respectively were not reclassified as discontinued operations and are included in the Corporate segment in continuing operations. See Note 17 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

(c)

Business Group highlights for 2012 include:

Utilities Group


•	On Sept. 18, 2012, Colorado Electric completed the sale of a 50 percent ownership interest in the 29 megawatt Busch Ranch Wind project for $25.0 million. The wind turbine project commenced commercial operation on Oct. 16, 2012.


•	On June 18, 2012, the WPSC approved a stipulation and agreement for Cheyenne Light resulting in an annual revenue increase of $2.7 million for electric customers and $1.6 million for gas customers effective July 1, 2012. The settlement also included a return on equity of 9.6 percent with a capital structure of 54 percent equity and 46 percent debt.

•

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 CPUC required this rate case filing as part of a previous settlement agreement when we purchased Colorado Gas. All parties reached a rate case settlement and the settlement hearing was held on Oct. 12, 2012. A decision is expected in the first quarter of 2013. The settlement, if approved, includes a $0.2 million revenue increase, a return on equity of 9.6 percent and a capital structure of 50 percent equity and 50 percent debt.

•

Weather was a contributing factor for our utilities for the quarter and the year. Year-to-date utility results were unfavorably impacted by warm weather, particularly at the Gas Utilities. Our service territories reported warmer weather, as measured by degree days, compared to the 30-year average and last year. Heating degree days year-to-date were 21 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 40 percent lower than the same period in 2011 for our Gas Utilities. For our Electric Utilities, although temperatures were above normal, weather-related demand was tempered by significantly lower humidity in 2012 than 2011 in our service territories.


•	Colorado Electric’s new $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 $30.0 million in gross margins at Colorado Electric for the nine months ended Sept. 30, 2012.

•

Cheyenne Light and Black Hills Power received final approvals and permits for the Cheyenne Prairie Generating Station. The WPSC approved the CPCN on July 31, 2012 authorizing the construction, operation and maintenance of a new $237 million, 132 megawatt natural gas-fired electric generating facility in Cheyenne, Wyo. The state of Wyoming issued the air permit for the project on Aug. 31, 2012 and the U.S. Environmental Protection Agency issued the greenhouse gas air permit on Sept. 27, 2012. Upon receipt of the final permit, the major equipment for the project was ordered. Commencement of construction for the new plant is expected in spring 2013. Project costs for plant construction and associated transmission are estimated at $222 million, with up to $15 million of construction financing costs, for a total of $237 million.

•

On Oct. 30, 2012 Cheyenne Light and Black Hills Power received approval from the WPSC to use a construction financing rider during construction of the Cheyenne Prairie Generating Station in lieu of traditional AFUDC. The rider allows Cheyenne Light and Black Hills Power to earn a rate of return during the construction period on the approximately 60 percent of the project cost related to serving Wyoming customers. We are evaluating filing for a similar rider in South Dakota.

•

On Aug. 6, 2012 Black Hills Power and Colorado Electric announced plans to suspend plant operations at some of our older coal-fired and natural gas-fired facilities. In addition, we also identified retirement dates for the older coal-fired power plants because of federal and state environmental regulations. 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	Suspend Date	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	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	40	Coal	Dec. 31, 2012	Dec. 31, 2013	57
Pueblo Unit #5	Colorado Electric	9	Gas	Dec. 31, 2012	to be determined	71
Pueblo Unit #6	Colorado Electric	20	Gas	Dec. 31, 2012	to be determined	63

•

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 re-file an Energy Resource Plan by Jan. 18, 2013 in order to address alternatives for the replacement capacity of W.N. Clark power plant, as well as the retirement of Pueblo No. 5 and No. 6. The CPUC also directed Colorado Electric to request a CPCN for any replacement capacity that Colorado Electric seeks to develop and own.

Non-regulated Energy Group


•	On Sept. 27, 2012, our Oil and Gas segment sold 85 percent of its Williston Basin assets, including approximately 73 gross wells and 28,000 net lease acres, for net cash proceeds of $226.6 million. We recognized a gain of $27.3 million on the sale. The portion of the sale amount not recognized as gain reduced the full-cost pool and will decrease our depreciation, depletion and amortization rate.


•	Our Coal Mining segment received all necessary permits and approval for a revised mine plan relocating mining operations to an area in the mine with lower overburden, reducing overall mining costs for the next several years. The new mine plan went into effect during the second quarter of 2012.


•	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.


•	Colorado IPP’s new $261 million, 200 megawatt power plant near Pueblo, Colo. began serving customers on Jan. 1, 2012. Output from the plant is sold under a 20-year power purchase agreement to Colorado Electric.

Corporate


•	On Oct. 31, 2012, we redeemed our $225.0 million of senior unsecured 6.5 percent notes, which originally were scheduled to mature on May 15, 2013.


•	On June 24, 2012, we extended for one year our $150 million term loan at an interest rate of 1.10 percent over LIBOR.


•	On Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017. Deferred financing costs of $1.5 million relating to the previous credit facility were written off during the first quarter of 2012.


•	We recognized a non-cash unrealized mark-to-market loss related to certain interest rate swaps of $2.9 million for the nine months ended Sept. 30, 2012 compared to a $40.6 million non-cash unrealized mark-to-market loss on these swaps for the same period 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 from the transaction were approximately $166.3 million, subject to final post-closing adjustments. Pursuant to the provisions of the stock purchase agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $1.4 million, which is accrued in the accompanying financial statements as of Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, resolution will occur through the dispute resolution provision of the stock purchase agreement.

Utilities Group

We report two segments within the Utilities Group: Electric Utilities and Gas Utilities. The Electric Utilities segment includes the electric operations of Black Hills Power, Colorado Electric and the electric and natural gas operations of Cheyenne Light. The Gas Utilities segment includes the regulated natural gas utility operations of Black Hills Energy in Colorado, Iowa, Kansas and Nebraska.

Electric Utilities



	Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance
	(in thousands)
Revenue — electric	$	151,465		$	149,664		$	1,801		$	442,731		$	417,512		$	25,219
Revenue — gas	3,552			4,052			(500		)	21,189			24,014			(2,825		)
Total revenue	155,017			153,716			1,301			463,920			441,526			22,394

Fuel, purchased power and cost of gas — electric	65,992			71,387			(5,395		)	191,113			203,319			(12,206		)
Purchased gas — gas	1,046			1,703			(657		)	11,087			13,583			(2,496		)
Total fuel, purchased power and cost of gas	67,038			73,090			(6,052		)	202,200			216,902			(14,702		)

Gross margin — electric	85,473			78,277			7,196			251,618			214,193			37,425
Gross margin — gas	2,506			2,349			157			10,102			10,431			(329		)
Total gross margin	87,979			80,626			7,353			261,720			224,624			37,096

Operations and maintenance	34,080			34,837			(757		)	110,176			106,107			4,069
Gain on sale of operating assets	—			(768		)	768			—			(768		)	768
Depreciation and amortization	18,821			13,221			5,600			56,448			39,051			17,397
Total operating expenses	52,901			47,290			5,611			166,624			144,390			22,234

Operating income	35,078			33,336			1,742			95,096			80,234			14,862

Interest expense, net	(12,527		)	(9,729		)	(2,798		)	(38,069		)	(29,780		)	(8,289		)
Other income (expense), net	198			200			(2		)	1,207			556			651
Income tax benefit (expense)	(8,176		)	(8,017		)	(159		)	(20,756		)	(16,357		)	(4,399		)
Income (loss) from continuing operations	$	14,573		$	15,790		$	(1,217	)	$	37,478		$	34,653		$	2,825

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



	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
Revenue - Electric (in thousands)	2012		2011		2012		2011
Residential:
Black Hills Power	$	15,794	$	15,034	$	43,903	$	44,977
Cheyenne Light	8,324		7,826		23,816		22,923
Colorado Electric	26,390		24,462		70,048		64,053
Total Residential	50,508		47,322		137,767		131,953

Commercial:
Black Hills Power	20,336		19,889		55,948		54,962
Cheyenne Light	13,003		14,802		42,346		40,840
Colorado Electric	20,898		19,784		61,595		54,742
Total Commercial	54,237		54,475		159,889		150,544

Industrial:
Black Hills Power	5,846		6,716		18,929		18,944
Cheyenne Light	4,551		3,017		10,863		8,573
Colorado Electric	8,476		8,086		27,689		24,520
Total Industrial	18,873		17,819		57,481		52,037

Municipal:
Black Hills Power	930		908		2,515		2,425
Cheyenne Light	454		475		1,352		1,321
Colorado Electric	3,419		3,442		10,031		9,564
Total Municipal	4,803		4,825		13,898		13,310

Total Retail Revenue - Electric	128,421		124,441		369,035		347,844

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	5,627		4,519		14,902		13,509

Off-system Wholesale:
Black Hills Power	5,599		9,158		23,331		23,553
Cheyenne Light	1,532		1,535		6,012		7,002
Colorado Electric ^(a)	1,663		—		2,073		—
Total Off-system Wholesale ^(a)	8,794		10,693		31,416		30,555

Other Revenue:
Black Hills Power	7,002		8,716		22,248		21,862
Cheyenne Light	624		649		1,663		1,905
Colorado Electric	997		646		3,467		1,837
Total Other Revenue	8,623		10,011		27,378		25,604

Total Revenue - Electric	$	151,465	$	149,664	$	442,731	$	417,512

____________


(a)	Off-system sales revenue during 2010 and 2011 was deferred until a sharing mechanism was approved by the CPUC in December 2011, and recognition of 25 percent of the revenue commenced Jan. 2, 2012. As a result, Colorado Electric deferred $2.0 million and $8.4 million in off-system revenue during the three and nine months ended Sept. 30, 2011.



	Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
Quantities Generated and Purchased (in MWh)	2012	2011	2012	2011
Generated —
Coal-fired:
Black Hills Power	475,752	463,032	1,344,593	1,286,876
Cheyenne Light	155,099	170,643	436,576	511,209
Colorado Electric	61,820	74,470	177,712	202,381
Total Coal-fired	692,671	708,145	1,958,881	2,000,466

Gas and Oil-fired:
Black Hills Power	21,543	11,424	28,122	13,595
Cheyenne Light	—	—	—	—
Colorado Electric	50,691	2,748	72,271	2,778
Total Gas and Oil-fired	72,234	14,172	100,393	16,373

Total Generated:
Black Hills Power	497,295	474,456	1,372,715	1,300,471
Cheyenne Light	155,099	170,643	436,576	511,209
Colorado Electric	112,511	77,218	249,983	205,159
Total Generated	764,905	722,317	2,059,274	2,016,839

Purchased —
Black Hills Power	280,815	409,174	1,228,072	1,186,004
Cheyenne Light	191,884	172,520	604,911	548,768
Colorado Electric	488,321	527,975	1,298,690	1,496,812
Total Purchased	961,020	1,109,669	3,131,673	3,231,584

Total Generated and Purchased:
Black Hills Power	778,110	883,630	2,600,787	2,486,475
Cheyenne Light	346,983	343,163	1,041,487	1,059,977
Colorado Electric	600,832	605,193	1,548,673	1,701,971
Total Generated and Purchased	1,725,925	1,831,986	5,190,947	5,248,423



	Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
Quantity Sold (in MWh)	2012	2011	2012	2011
Residential:
Black Hills Power	139,282	132,571	396,267	414,654
Cheyenne Light	68,816	65,643	197,093	197,053
Colorado Electric	185,696	185,775	476,425	481,774
Total Residential	393,794	383,989	1,069,785	1,093,481

Commercial:
Black Hills Power	202,418	198,774	553,792	544,660
Cheyenne Light	141,433	157,138	449,718	446,382
Colorado Electric	198,839	201,266	548,964	547,168
Total Commercial	542,690	557,178	1,552,474	1,538,210

Industrial:
Black Hills Power	93,147	106,658	303,906	301,268
Cheyenne Light	62,397	44,857	151,326	128,327
Colorado Electric	89,305	90,895	267,739	265,992
Total Industrial	244,849	242,410	722,971	695,587

Municipal:
Black Hills Power	11,154	9,917	27,565	25,958
Cheyenne Light	2,318	2,528	7,028	7,122
Colorado Electric	35,461	36,657	95,649	96,483
Total Municipal	48,933	49,102	130,242	129,563

Total Retail Quantity Sold	1,230,266	1,232,679	3,475,472	3,456,841

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	88,334	84,346	249,388	256,558

Off-system Wholesale:
Black Hills Power	190,143	299,511	943,522	819,753
Cheyenne Light	46,157	47,615	166,777	211,541
Colorado Electric	52,228	48,643	60,899	222,091
Total Off-system Wholesale	288,528	395,769	1,171,198	1,253,385

Total Quantity Sold:
Black Hills Power	724,478	831,777	2,474,440	2,362,851
Cheyenne Light	321,121	317,781	971,942	990,425
Colorado Electric	561,529	563,236	1,449,676	1,613,508
Total Quantity Sold	1,607,128	1,712,794	4,896,058	4,966,784

Losses and Company Use:
Black Hills Power	53,632	51,853	126,347	123,624
Cheyenne Light	25,863	25,382	69,545	69,552
Colorado Electric	39,302	41,957	98,997	88,463
Total Losses and Company Use	118,797	119,192	294,889	281,639

Total Quantity Sold	1,725,925	1,831,986	5,190,947	5,248,423



	Three Months Ended Sept. 30,
Degree Days	2012			2011
Heating Degree Days:	Actual	Variance from 30-Year Average		Actual	Variance from 30-Year Average

Black Hills Power	99	(56	)%	153	(33	)%
Cheyenne Light	170	(40	)%	197	(40	)%
Colorado Electric	54	(45	)%	46	(50	)%

Cooling Degree Days:

Black Hills Power	731	37	%	620	26	%
Cheyenne Light	430	44	%	399	73	%
Colorado Electric	898	31	%	958	36	%



	Nine Months Ended Sept. 30,
Degree Days	2012			2011
	Actual	Variance from 30-Year Average		Actual	Variance from 30-Year Average
Heating Degree Days:
Black Hills Power	3,558	(50	)%	5,050	(30	)%
Cheyenne Light	3,772	(47	)%	4,674	(37	)%
Colorado Electric	2,753	(51	)%	3,465	(38	)%

Cooling Degree Days:
Black Hills Power	937	47	%	676	13	%
Cheyenne Light	568	63	%	429	57	%
Colorado Electric	1,321	47	%	1,252	36	%



Electric Utilities Power Plant Availability	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012			2011
Coal-fired plants	95.4	%	95.1	%	89.1	%	^(a)	91.6	%	^(b)
Other plants	98.5	%	98.6	%	96.6	%		95.7	%
Total availability	97.0	%	96.4	%	93.0	%		93.1	%

_________________________


(a)	Reflects an unplanned outage due to a transformer failure and a planned outage at Neil Simpson II, and a planned and extended overhaul at Wygen II.


(b)	Reflects a major overhaul and an unplanned outage at the PacifiCorp-operated Wyodak plant.

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 these natural gas distribution operations:



	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011
Revenue - Gas (in thousands):
Residential	$	2,362	$	2,561	$	12,947	$	14,592
Commercial	770		946		5,789		6,492
Industrial	248		370		1,882		2,226
Other Sales Revenue	172		175		571		704
Total Revenue - Gas	$	3,552	$	4,052	$	21,189	$	24,014

Gross Margin (in thousands):
Residential	$	1,864	$	1,739	$	7,092	$	7,459
Commercial	417		387		2,141		2,293
Industrial	53		63		302		338
Other Gross Margin	172		160		567		341
Total Gross Margin	$	2,506	$	2,349	$	10,102	$	10,431

Volumes Sold (Dth):
Residential	168,229		179,602		1,453,478		1,745,313
Commercial	119,344		122,138		918,131		1,048,404
Industrial	64,721		66,962		411,664		463,618
Total Volumes Sold	352,294		368,702		2,783,273		3,257,335

Results of Operations for the Electric Utilities for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Electric Utilities was $14.6 million for the three months ended Sept. 30, 2012 compared to $15.8 million for the three months ended Sept. 30, 2011 as a result of:

Gross margin increased primarily due to a $9.6 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric, partially offset by a $0.7 million decrease in wholesale and transmission margins as a result of decreased pricing, a decrease of $0.3 million in off-system sales and a decrease of $0.6 million from expiration of a reserve capacity agreement with PacifiCorp.

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

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party and 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 constructed 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 interest associated with the financing of the Pueblo generating facility completed in December 2011. Interest costs were capitalized during construction in the prior year.

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

Income tax benefit (expense): The effective tax rate in 2012 was impacted by a unfavorable true-up adjustment while 2011 was impacted by a favorable true-up adjustment.

Results of Operations for the Electric Utilities for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Income from continuing operations for the Electric Utilities was $37.5 million for the nine months ended Sept. 30, 2012 compared to $34.7 million for the nine months ended Sept. 30, 2011 as a result of:

Gross margin increased primarily due to a $30.0 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric, a $1.5 million increase from wholesale and transmission margins from increased pricing, a $0.4 million increase in off-system sales mainly from higher quantities sold, a $1.2 million increase from an Environmental Improvement Cost Recovery Adjustment rider at Black Hills Power and increased retail margins as a result of higher quantities sold driven by warmer weather partially offset by a decrease of $0.6 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 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 containment efforts.

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party and 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 interest associated with financing of the Pueblo generating facility completed in December 2011. Interest costs were capitalized during construction in the prior year.

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

Income tax benefit (expense): The effective tax rate increased due to a favorable benefit in the prior year for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit.

Gas Utilities



	Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance
	(in thousands)
Natural gas — regulated	$	56,845		$	65,887		$	(9,042	)	$	293,047		$	382,517		$	(89,470	)
Other — non-regulated services	6,590			6,764			(174		)	21,296			20,322			974
Total revenue	63,435			72,651			(9,216		)	314,343			402,839			(88,496		)

Natural gas — regulated	20,802			29,693			(8,891		)	154,342			229,152			(74,810		)
Other — non-regulated services	3,383			3,480			(97		)	10,272			10,260			12
Total cost of sales	24,185			33,173			(8,988		)	164,614			239,412			(74,798		)

Gross margin	39,250			39,478			(228		)	149,729			163,427			(13,698		)

Operations and maintenance	28,339			28,317			22			88,121			91,126			(3,005		)
Depreciation and amortization	6,338			6,064			274			18,748			18,032			716
Total operating expenses	34,677			34,381			296			106,869			109,158			(2,289		)

Operating income (loss)	4,573			5,097			(524		)	42,860			54,269			(11,409		)

Interest expense, net	(5,370		)	(6,329		)	959			(17,659		)	(19,640		)	1,981
Other income (expense), net	(2		)	27			(29		)	82			176			(94		)
Income tax benefit (expense)	802			1,777			(975		)	(8,914		)	(10,530		)	1,616
Income (loss) from continuing operations	$	3		$	572		$	(569	)	$	16,369		$	24,275		$	(7,906	)

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



Revenue (in thousands)	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011
Residential:
Colorado	$	4,498	$	5,493	$	33,837	$	39,228
Nebraska	11,370		12,736		65,832		91,798
Iowa	9,776		11,235		56,216		77,259
Kansas	7,354		7,928		36,537		46,449
Total Residential	32,998		37,392		192,422		254,734

Commercial:
Colorado	898		1,352		6,525		8,167
Nebraska	2,742		3,520		20,760		29,823
Iowa	3,988		4,397		24,495		33,082
Kansas	1,973		2,076		10,702		14,316
Total Commercial	9,601		11,345		62,482		85,388

Industrial:
Colorado	1,110		1,174		1,756		1,872
Nebraska	306		194		735		530
Iowa	357		334		1,551		1,478
Kansas	7,078		10,437		12,314		18,406
Total Industrial	8,851		12,139		16,356		22,286

Transportation:
Colorado	113		84		616		591
Nebraska	1,866		1,626		7,337		8,057
Iowa	816		687		3,044		2,839
Kansas	1,338		1,311		4,367		4,503
Total Transportation	4,133		3,708		15,364		15,990

Other Sales Revenue:
Colorado	15		22		65		78
Nebraska	469		432		1,561		1,551
Iowa	86		122		350		441
Kansas	692		727		4,447		2,049
Total Other Sales Revenue	1,262		1,303		6,423		4,119

Total Regulated Revenue	56,845		65,887		293,047		382,517

Non-regulated Services	6,590		6,764		21,296		20,322

Total Revenue	$	63,435	$	72,651	$	314,343	$	402,839



Gross Margin (in thousands)	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011
Residential:
Colorado	$	2,548	$	2,695	$	11,375	$	12,575
Nebraska	8,334		8,480		32,922		37,861
Iowa	7,850		8,291		28,373		34,885
Kansas	5,622		5,465		20,537		21,663
Total Residential	24,354		24,931		93,207		106,984

Commercial:
Colorado	399		460		1,818		2,105
Nebraska	1,404		1,486		7,027		8,462
Iowa	1,890		1,862		7,723		8,458
Kansas	1,087		1,006		4,365		4,731
Total Commercial	4,780		4,814		20,933		23,756

Industrial:
Colorado	307		239		509		402
Nebraska	99		48		204		139
Iowa	56		38		172		176
Kansas	1,096		1,144		2,090		2,136
Total Industrial	1,558		1,469		2,975		2,853

Transportation:
Colorado	113		84		617		590
Nebraska	1,866		1,626		7,337		8,057
Iowa	816		687		3,044		2,839
Kansas	1,338		1,311		4,367		4,503
Total Transportation	4,133		3,708		15,365		15,989

Other Sales Margins:
Colorado	15		22		65		78
Nebraska	469		433		1,562		1,552
Iowa	86		122		351		441
Kansas	648		695		4,248		1,712
Total Other Sales Margins	1,218		1,272		6,226		3,783

Total Regulated Gross Margin	36,043		36,194		138,706		153,365

Non-regulated Services	3,207		3,284		11,023		10,062

Total Gross Margin	$	39,250	$	39,478	$	149,729	$	163,427



Volumes Sold (in Dth)	Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
	2012	2011	2012	2011
Residential:
Colorado	372,722	450,778	3,773,819	4,298,162
Nebraska	681,361	764,676	6,032,705	8,607,301
Iowa	479,912	564,426	5,486,267	7,485,204
Kansas	422,708	461,169	3,581,184	4,710,725
Total Residential	1,956,703	2,241,049	18,873,975	25,101,392

Commercial:
Colorado	98,453	145,413	804,701	980,931
Nebraska	315,832	373,386	2,606,223	3,465,363
Iowa	527,923	486,758	3,424,736	4,375,492
Kansas	219,870	203,109	1,439,351	1,830,720
Total Commercial	1,162,078	1,208,666	8,275,011	10,652,506

Industrial:
Colorado	265,451	202,956	416,020	318,278
Nebraska	69,229	30,816	134,931	67,010
Iowa	74,535	56,401	297,494	234,864
Kansas	1,912,296	2,010,001	3,381,657	3,518,599
Total Industrial	2,321,511	2,300,174	4,230,102	4,138,751

Total Volumes Sold	5,440,292	5,749,889	31,379,088	39,892,649

Transportation:
Colorado	98,893	75,828	607,469	604,493
Nebraska	6,453,607	5,910,136	20,042,972	18,546,617
Iowa	4,038,804	4,068,243	13,718,759	13,647,342
Kansas	3,993,675	4,331,612	11,640,182	11,712,421
Total Transportation	14,584,979	14,385,819	46,009,382	44,510,873

Other Volumes:
Colorado	—	—	—	—
Nebraska	—	—	—	—
Iowa	—	—	—	—
Kansas ^(a)	8,427	4,086	40,380	66,152
Total Other Volumes	8,427	4,086	40,380	66,152

Total Volumes and Transportation Sold	20,033,698	20,139,794	77,428,850	84,469,674

___________

(a) Other volumes represent wholesale customers.



	Three Months Ended Sept. 30, 2012		Nine Months Ended Sept. 30, 2012
Heating Degree Days:	Actual	Variance From Normal	Actual	Variance From Normal
Colorado	116	(39)%	3,018	(23)%
Nebraska	110	12%	2,880	(22)%
Iowa	216	21%	3,629	(19)%
Kansas ^(a)	42	(35)%	2,373	(21)%
Combined ^(b)	150	5%	3,176	(21)%



	Three Months Ended Sept. 30, 2011			Nine Months Ended Sept. 30, 2011
Heating Degree Days:	Actual	Variance From Normal		Actual	Variance From Normal
Colorado	116	(38	)%	3,717	(7	)%
Nebraska	157	49	%	4,023	4	%
Iowa	235	38	%	4,780	3	%
Kansas ^(a)	54	74	%	3,085	1	%
Combined ^(b)	178	36	%	4,247	2	%

_______________


(a)	Our gross margin in Kansas utilizes normal degree days from an approved weather normalization mechanism.


(b)	The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas which has an approved weather normalization mechanism.

Our Gas Utilities are highly seasonal, and sales volumes vary considerably with weather and seasonal heating and industrial loads. Over 70 percent of our Gas Utilities' revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for and certain expenses of these operations fluctuate significantly among quarters. Depending upon the state in which our Gas Utilities operate, the winter heating season begins around Nov. 1 and ends around March 31.

Results of Operations for the Gas Utilities for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Gas Utilities was $0.0 million for the three months ended Sept. 30, 2012 compared to Income from continuing operations of $0.6 million for the three months ended Sept. 30, 2011 as a result of:

Gross margin was comparable to the same period in the prior year.

Operations and maintenance was comparable to the same period in the prior year.

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

Interest expense, net decreased primarily due to lower interest rates.

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

Income tax benefit (expense): The deviation in the effective tax rate from the statutory rate is the result of a favorable true-up adjustment that had a more pronounced impact in 2012 due to significantly lower pre-tax net loss. The prior year also realized a favorable true up adjustment for flow-through treatment of certain property-related temporary differences.

Results of Operations for the Gas Utilities for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Income from continuing operations for the Gas Utilities was $16.4 million for the nine months ended Sept. 30, 2012 compared to Income from continuing operations of $24.3 million for the nine months ended Sept. 30, 2011 as a result of:

Gross margin decreased primarily due to a $9.6 million impact from milder weather compared to the same period in the prior year. Heating degree days were 25 percent lower for the nine months ended Sept. 30, 2012 compared to the same period in the prior year and 21 percent lower than normal. A reclassification adjustment was made in the current year, recording $4.9 million against gross margin in prior year that was included in operations and maintenance.

Operations and maintenance decreased primarily due to lower bad debt costs, cost efficiencies and a reclassification accounting adjustment that was made in the current year recording $4.9 million of operating costs in gross margin.

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

Interest expense, net decreased primarily due to lower interest rates.

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

Income tax benefit (expense): The effective tax rate increased as a result of an unfavorable state true-up adjustment. 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.

Regulatory Matters — Utilities Group

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

Revenue

Approved Capital

Structure

Type of

Service

Date

Requested

Date

Effective

Amount

Requested

Amount

Approved

Return on

Equity

Debt

Nebraska Gas (1)

Gas

12/2009

9/2010

12.1

8.3

10.1%

52.0%

48.0%

Iowa Gas (2)

Gas

6/2010

2/2011

4.7

3.4

Global Settlement

Colorado Electric (2)

Electric

4/2011

1/2012

40.2

28.0

9.8% - 10.2%

49.1%

50.9%

Cheyenne Light (3)

Electric/Gas

12/2011

7/2012

8.5

4.3

9.6%

54.0%

46.0%

Black Hills Power (2)

Electric

1/2011

6/2011

Not Applicable

3.1

Not Applicable

Colorado Gas (4)

Gas

6/2012

Pending

1.0

Pending

(1)

The Nebraska Public Advocate filed an appeal with the District Court related to the rate case decision which has been denied. Subsequently, the Nebraska Public Advocate filed a notice of appeal in the Court of Appeals. On March 20, 2012, the Court of Appeals affirmed the earlier decision of the District Court. The Nebraska Public Advocate petitioned the Nebraska Supreme Court to hear an appeal which was denied. Accordingly, the appeals of the rate case decision have been exhausted and the rate case decision is upheld as a final decision of the NPSC.


(2)	These rate settlements were the most recent for the jurisdiction and were previously described in our 2011 Annual Report on Form 10-K.

(3)

On June 18, 2012, the WPSC approved a settlement agreement resulting in annual revenue increases of $2.7 million for electric customers and $1.6 million for gas customers effective July 1, 2012. The cost adjustment mechanism relating to transmission, fuel and purchased power costs was modified to eliminate the $1.0 million threshold and changed the sharing mechanism to 85 percent to the customer for these cost adjustment mechanisms. The agreement approved a return on equity of 9.6 percent with a capital structure of 54 percent equity and 46 percent debt.

(4)

On June 4, 2012, Colorado Gas filed a request with the CPUC for an increase in annual gas revenues of $1.0 million to recover capital investments and increased operation and maintenance expenses. The CPUC required this rate case filing as part of a previous settlement agreement when we purchased Colorado Gas. All parties reached a rate case settlement, and the settlement hearing was held on Oct. 12, 2012. A decision is expected in the first quarter of 2013. The settlement, if approved, includes a $0.2 million revenue increase, a return on equity of 9.6 percent and a capital structure of 50 percent equity and 50 percent debt.

Non-regulated Energy Group

We report three segments within our Non-regulated Energy Group: Power Generation, Coal Mining and 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. We sold Enserco on Feb. 29, 2012, which resulted in our Energy Marketing segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations.

Power Generation



	Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance
	(in thousands)
Revenue	$	20,951		$	8,100		$	12,851		$	59,312		$	23,500		$	35,812

Operations and maintenance	7,788			4,602			3,186			22,486			12,881			9,605
Depreciation and amortization	1,165			1,064			101			3,395			3,168			227
Total operating expense	8,953			5,666			3,287			25,881			16,049			9,832

Operating income	11,998			2,434			9,564			33,431			7,451			25,980

Interest expense, net	(3,085		)	(1,835		)	(1,250		)	(11,800		)	(5,461		)	(6,339		)
Other (expense) income	(4		)	(5		)	1			10			1,220			(1,210		)
Income tax (expense) benefit	(3,781		)	(257		)	(3,524		)	(5,673		)	(1,139		)	(4,534		)

Income (loss) from continuing operations	$	5,128		$	337		$	4,791		$	15,968		$	2,071		$	13,897

The following table provides certain operating statistics for our plants within the Power Generation segment:



	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011
Contracted power plant fleet availability:
Coal-fired plant	99.4	%	97.1	%	99.5	%	98.9	%
Natural gas-fired plants	99.4	%	100.0	%	99.3	%	100.0	%
Total availability	99.4	%	98.1	%	99.4	%	99.3	%

Results of Operations for Power Generation for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Power Generation segment was $5.1 million for the three months ended Sept. 30, 2012 compared to Income from continuing operations of $0.3 million for the same period in 2011 as a result of:

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

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

Depreciation and amortization was 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 due to interest costs for financing the Pueblo generating facility. Interest costs were capitalized during construction in the prior year.

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

Income tax (expense) benefit: The effective tax rate was comparable to the same period in the prior year.

Results of Operations for Power Generation for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Income from continuing operations for the Power Generation segment was $16.0 million for the nine months ended Sept. 30, 2012 compared to Income from continuing operations of $2.1 million for the same period in 2011 as a result of:

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

Operations and maintenance increased primarily due to the costs to operate and corporate allocations relating to our new 200 megawatt generating facility in Pueblo, Colo. on Jan. 1, 2012.

Interest expense, net increased due to interest costs for financing the Pueblo generating facility. Interest costs were capitalized during construction in the prior year.

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

Income tax (expense) benefit: The effective tax rate in 2012 was impacted by a favorable state tax true-up that included certain tax credits. Such credits are the result of meeting certain applicable state requirements including the ability to utilize these tax credits. The tax credits pertain to qualified plant expenditures related to capital investment and research and development.

Coal Mining



	Three Months Ended Sept. 30,								Nine Months Ended Sept. 30,
	2012		2011			Variance			2012			2011			Variance
	(in thousands)
Revenue	$	14,675	$	17,835		$	(3,160	)	$	42,791		$	48,870		$	(6,079	)

Operations and maintenance	10,780		14,171			(3,391		)	32,141			41,754			(9,613		)
Depreciation, depletion and amortization	2,922		5,151			(2,229		)	9,573			14,364			(4,791		)
Total operating expenses	13,702		19,322			(5,620		)	41,714			56,118			(14,404		)

Operating income (loss)	973		(1,487		)	2,460			1,077			(7,248		)	8,325

Interest income, net	1		972			(971		)	1,159			2,868			(1,709		)
Other income	525		532			(7		)	2,052			1,650			402
Income tax benefit (expense)	191		538			(347		)	(364		)	1,606			(1,970		)

Income (loss) from continuing operations	$	1,690	$	555		$	1,135		$	3,924		$	(1,124	)	$	5,048

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



	Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
	2012	2011	2012	2011
Tons of coal sold	1,105	1,550	3,191	4,155
Cubic yards of overburden moved	1,827	3,873	6,749	10,261

Results of Operations for Coal Mining for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Coal Mining segment was $1.7 million for the three months ended Sept. 30, 2012 compared to Income from continuing operations of $0.6 million for the same period in 2011, as a result of:

Revenue decreased primarily due to a 29 percent decrease in tons sold as a result of the December 2011 expiration of an unprofitable train load-out contract which represented approximately 29 percent of our tons sold in 2011, partially offset by an increase in average sales price as a result of price escalators and adjustments in certain of our sales contracts. Approximately 50 percent of our current coal production is sold under contracts that include price adjustments based on actual mining costs.

Operations and maintenance decreased primarily due to reduced overburden moved related to lower sales volumes and mining efficiencies, including decreased fuel costs and headcount reductions as a result of the revised mine plan and termination of the train load-out contract at Dec. 31, 2011.

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 our parent.

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

Income tax benefit (expense): The change in the effective tax rate was primarily due to the impact of percentage depletion and a tax return true-up.

Results of Operations for Coal Mining for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Income from continuing operations for the Coal Mining segment was $3.9 million for the nine months ended Sept. 30, 2012 compared to Loss from continuing operations of $1.1 million for the same period in 2011, as a result of:

Revenue decreased primarily due to a 23 percent decrease in tons sold. This decrease was due to the December 2011 expiration of an unprofitable train load-out contract, which represented approximately 29 percent of our tons sold in 2011. Additionally, tons sold decreased due to a planned and unplanned outages at Neil Simpson II and a planned and extended outage at the Wygen II facility 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 primarily due to reduced overburden moved related to lower tons sold and mining efficiencies, including decreased fuel costs and headcount reductions resulting from the revised mine plan and termination of the train load-out contract at Dec. 31, 2011.

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 our parent.

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

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

Oil and Gas



	Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance
	(in thousands)
Revenue	$	24,728		$	19,163		$	5,565		$	66,994		$	55,907		$	11,087

Operations and maintenance	12,118			9,573			2,545			33,290			30,327			2,963
Gain on sale of operating assets	(27,285		)	—			(27,285		)	(27,285		)	—			(27,285		)
Depreciation, depletion and amortization	12,457			7,714			4,743			34,813			22,637			12,176
Impairment of long-lived assets	—			—			—			26,868			—			26,868
Total operating expenses	(2,710		)	17,287			(19,997		)	67,686			52,964			14,722

Operating income (loss)	27,438			1,876			25,562			(692		)	2,943			(3,635		)

Interest expense, net	(1,112		)	(1,460		)	348			(3,882		)	(4,232		)	350
Other income (expense), net	77			54			23			193			(43		)	236
Income tax benefit (expense)	(9,014		)	(229		)	(8,785		)	2,162			779			1,383

Income (loss) from continuing operations	$	17,389		$	241		$	17,148		$	(2,219	)	$	(553	)	$	(1,666	)

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



	Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
	2012	2011	2012	2011
Production:
Bbls of oil sold	184,423	98,950	485,262	303,401
Mcf of natural gas sold	2,278,801	2,147,172	7,119,087	6,264,460
Gallons of NGL sold	1,099,198	993,752	2,751,409	2,847,011
Mcf equivalent sales	3,542,367	2,882,837	10,423,717	8,491,582



	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011
Average price received: ^(a)
Oil/Bbl	$	88.69	$	82.76	$	81.65	$	76.25
Gas/Mcf	$	3.07	$	4.24	$	3.27	$	4.39
NGL/gallon	$	0.65	$	0.88	$	0.77	$	0.94

Depletion expense/Mcfe	$	3.26	$	2.38	$	3.07	$	2.38

____________


(a)	Net of hedge settlement gains and losses.

The following is a summary of certain average operating expenses per Mcfe:



	Three Months Ended Sept. 30, 2012								Three Months Ended Sept. 30, 2011
Producing Basin	LOE		Gathering, Compression and Processing		Production Taxes		Total		LOE		Gathering, Compression and Processing		Production Taxes		Total
San Juan	$	1.42	$	0.33	$	0.46	$	2.21	$	1.06	$	0.25	$	0.52	$	1.83
Piceance *	0.13		0.35		0.14		0.62		0.80		0.63		0.28		1.71
Powder River	1.00		—		1.11		2.11		1.20		—		1.26		2.46
Williston	0.70		—		1.48		2.18		1.01		—		1.74		2.75
All other properties	1.48		—		0.25		1.73		0.62		—		0.38		1.00
Total weighted average	$	0.99	$	0.17	$	0.74	$	1.90	$	0.99	$	0.18	$	0.72	$	1.89



	Nine Months Ended Sept. 30, 2012								Nine Months Ended Sept. 30, 2011
Producing Basin	LOE		Gathering, Compression and Processing		Production Taxes		Total		LOE		Gathering, Compression and Processing		Production Taxes		Total
San Juan	$	1.14	$	0.28	$	0.34	$	1.76	$	1.17	$	0.35	$	0.54	$	2.06
Piceance *	0.20		0.39		0.13		0.72		0.77		0.73		0.06		1.56
Powder River	1.33		—		1.17		2.50		1.31		—		1.31		2.62
Williston	0.65		—		1.35		2.00		0.59		—		1.58		2.17
All other properties	1.58		—		0.17		1.75		1.17		—		0.26		1.43
Total weighted average	$	0.96	$	0.17	$	0.63	$	1.76	$	1.11	$	0.23	$	0.70	$	2.04

___________

* Decrease in LOE is primarily due to increased volumes from two additional wells that commenced production in December 2011.

Results of Operations for Oil and Gas for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Oil and Gas segment was $17.4 million for the three months ended Sept. 30, 2012 compared to Income from continuing operations of $0.2 million for the same period in 2011 as a result of:

Revenue increased primarily due to an 86 percent increase in crude oil sales, due primarily to activities from new wells in our drilling program in the Bakken shale formation and a 7 percent increase in the average price received for crude oil sold. A 6 percent increase in natural gas and NGL volumes, due primarily to the production from three Mancos formation test wells in the San Juan and Piceance Basins, was partially offset by a 28 percent decrease in the average price received for natural gas.

Operations and maintenance costs 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 expected 2012 reserve additions due to the deferred drilling activities in the San Juan Mancos formation, as well as higher cost reserves associated with our Bakken activities and a higher depletion rate per Mcfe on higher volumes.

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 sales amount, not recognized as gain, reduces the full-cost pool and should significantly decrease the future depreciation, depletion and amortization rate.

Interest expense, net was comparable to the same period in the prior year.

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

Income tax (expense) benefit: For 2012, the benefit generated by percentage depletion had a significantly reduced impact on the effective tax rate compared to the same period in 2011.

Results of Operations for Oil and Gas for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Loss from continuing operations for the Oil and Gas segment was $2.2 million for the nine months ended Sept. 30, 2012 compared to Loss from continuing operations of $0.6 million for the same period in 2011 as a result of:

Revenue increased primarily due to a 60 percent increase in crude oil volume sold along with a 7 percent increase in the average price received for crude oil sales. Crude oil production increases reflect volumes from new wells in our drilling program in the Bakken shale formation. A 13 percent increase in natural gas and NGL volumes, due primarily to the production from three Mancos formation test wells in the San Juan and Piceance Basins, was partially offset by a 26 percent decrease in average price received for natural gas.

Operations and maintenance costs 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 reserve additions due to the deferred drilling activities in the San Juan Mancos formation, as well as higher cost reserves associated with our Bakken activities and a higher depletion rate per Mcfe on higher volumes.

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 will decrease our 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. 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 was comparable to the same period in the prior year.

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

Income tax (expense) benefit: The effective tax rate for the nine months ended Sept. 30, 2011 was positively impacted by a research and development credit and the benefit generated by percentage depletion had a significantly lesser impact on the effective tax rate in 2012 compared to the same period in 2011.

Corporate

Results of Operations for Corporate for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Loss from continuing operations for Corporate was $4.2 million for the three months ended Sept. 30, 2012 compared to Loss from continuing operations of $28.3 million for the three months ended Sept. 30, 2011. The loss for the quarter ended Sept. 30, 2012 was primarily due to an incentive compensation accrual recorded as a result of the Williston Basin asset sale offset by an unrealized, non-cash mark-to-market gain on certain interest rate swaps of approximately $0.6 million. The loss for the quarter ended Sept. 30, 2011 was primarily due to a $38.2 million unrealized, non-cash mark-to-market loss on these interest rate swaps.

Costs of $0.5 million after-tax previously allocated to our Energy Marketing segment were reclassified to the Corporate segment consistent with accounting for discontinued operations for the three months ended Sept. 30, 2011. There were no allocated costs related to our Energy Marketing segment for the three months ended Sept. 30, 2012.

Results of Operations for Corporate for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Loss from continuing operations for Corporate was $13.9 million for the nine months ended Sept. 30, 2012 compared to Loss from continuing operations of $37.3 million for the nine months ended Sept. 30, 2011. The loss for the nine months ended Sept. 30, 2012 was primarily due to an incentive compensation accrual recorded as a result of the Williston Basin asset sale and an unrealized, non-cash mark-to-market loss on certain interest rate swaps of approximately $2.9 million. The loss for the nine months ended Sept. 30, 2011 was primarily due to a $40.6 million unrealized, non-cash mark-to-market loss on these interest rate swaps.

Costs of $1.6 million after-tax previously allocated to our Energy Marketing segment were reclassified to the Corporate segment consistent with accounting for discontinued operations for the nine months ended Sept. 30, 2012 compared to after-tax costs of $1.5 million for the nine months ended Sept. 30, 2011.

Discontinued Operations

Results of Operations for Discontinued Operations for the Three and Nine Months Ended Sept. 30, 2012, Compared to Three and Nine Months Ended Sept. 30, 2011:

Loss from discontinued operations for the three months ended Sept. 30, 2012 was $0.2 million relating to additional operating costs to discontinue the operations and $6.8 million for the nine months ended Sept. 30, 2012, including an after-tax loss on sale of $2.4 million and transaction related costs, net of tax benefit of $2.5 million.

Pursuant to the provisions of the Stock Purchase Agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $1.4 million, which is accrued in the loss from discontinued operations for the nine months ended Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, resolution will occur through the dispute resolution provision of the Stock Purchase Agreement.

Critical Accounting Policies

Except as noted below, there have been no material changes in our critical accounting policies from those reported in our 2011 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting policies, see Part II, Item 7 of our 2011 Annual Report on Form 10-K.

Full-Cost Method of Accounting for Oil and Gas Activities

As previously disclosed in our 2011 Annual Report filed in Form 10-K, 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 Sept. 27, 2012 sale of oil and gas properties in the Williston Basin of North Dakota was significant as defined by Rule 4-10, and accordingly a $27.3 million pre-tax gain on sale was recorded. Total net cash proceeds from the sale were approximately $227 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 our future depletion expense recorded within our financial statements.

Liquidity and Capital Resources

All amounts are presented on a pre-tax basis unless otherwise indicated.

Cash Flow Activities

The following table summarizes our cash flows for the nine months ended Sept. 30, 2012 and 2011 (in thousands):



Cash provided by (used in):	2012			2011			Increase (Decrease)
Operating activities	$	269,667		$	206,526		$	63,141
Investing activities	$	98,306		$	(326,862	)	$	425,168
Financing activities	$	(179,549	)	$	162,676		$	(342,225	)

Year-to-Date 2012 Compared to Year-to-Date 2011

Operating Activities

Net cash provided by operating activities was $63.1 million higher for the nine months ended Sept. 30, 2012 than for the same period in 2011 primarily attributable to:


•	Cash earnings (net income plus non-cash adjustments) were $35.0 million higher for the nine months ended Sept. 30, 2012 than for the same period the prior year.


•	Net inflows from operating assets and liabilities were $38.1 million for the nine months ended Sept. 30, 2012, an increase of $33.5 million from the same period in the prior year. In addition to other normal working capital changes, the increase primarily related to decreased gas volumes in inventory and lower natural gas prices.


•	Cash contributions to the defined benefit pension plan were $25.0 million in 2012 compared to $11.0 million in 2011.

Investing Activities

Net cash provided by investing activities was $98.3 million in 2012 compared to net cash used by investing activities of $326.9 million in 2011 for a variance of $425.2 million. The variance was driven by cash proceeds from assets sold during 2012, including $243.3 million from the sale of 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 $108.8 million for the sale of Enserco. Additionally, in 2012 we had reduced capital expenditures of $65.1 million due to the completion of construction of our Pueblo generation facility and $21.8 million note receivable for oil and gas properties.

Financing Activities

Net cash used in financing activities in 2012 was $179.5 million compared to net cash provided by financing activities in 2011 of $162.7 million for a variance of $342.2 million. The variance was driven by applying the proceeds from the sale of Enserco to pay down short-term borrowings on the Revolving Credit Facility of approximately $110 million while in the same period in the prior year we increased borrowings $210 million primarily to finance our construction program in Pueblo, Colo. Cash dividends on common stock of $48.9 million were paid in 2012 compared to cash dividends paid of $43.2 million in 2011. In addition, in May 2012 Black Hills Power repaid its Pollution Control Revenue Bonds for $6.5 million.

Dividends

Dividends paid on our common stock totaled $48.9 million for the nine months ended Sept. 30, 2012, or $1.11 per share. On Oct. 30, 2012, our board of directors declared a quarterly dividend of $0.37 per share payable Dec. 1, 2012, which is equivalent to an annual dividend rate of $1.48 per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.

Financing Transactions and Short-Term Liquidity

Our principal sources of short-term liquidity are our Revolving Credit Facility and cash provided by operations. In addition to availability under our Revolving Credit Facility described below, as of Sept. 30, 2012 we had approximately $247 million of unrestricted cash included in Cash and cash equivalents on our Condensed Consolidated Balance Sheet resulting, in part, from the September 2012 sale of our Williston Basin assets. A portion of this cash was used on Oct. 31, 2012 to redeem our $225 million senior unsecured notes originally due in May 2013. In the first quarter of 2012, the net cash proceeds from the Enserco sale were utilized to reduce short-term debt on the Revolving Credit Facility by approximately $110 million.

Revolving Credit Facility

Our $500 million Revolving Credit Facility expiring Feb. 1, 2017 can be used for the issuance of letters of credit, to fund working capital needs and for general 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 ratings levels, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.50 percent, 1.50 percent and 1.50 percent, respectively. The facility contains a commitment fee that is charged on the unused amount of the facility. Based upon current credit ratings, the fee is 0.25 percent. The facility contains an accordion feature that allows us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million.

At Sept. 30, 2012, we had borrowings of $75 million and letters of credit outstanding of $36 million on our Revolving Credit Facility. Available capacity remaining was approximately $389 million at Sept. 30, 2012.

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 a recourse leverage ratio not to exceed 0.65 to 1.00. At Sept. 30, 2012, our recourse leverage ratio as calculated under our Revolving Credit Facility was approximately 0.56 to 1.0. At Sept. 30, 2012, our long-term debt ratio was 46.2 percent and our total debt leverage ratio (long-term debt and short-term debt) was 55.2 percent.

In addition to covenant violations, an event of default under the Revolving Credit Facility may be triggered by other events, such as a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to, other debt obligations of $35 million or more. Subject to applicable cure periods (none of which apply to a failure to timely pay indebtedness), an event of default would permit the lenders to restrict our ability to further access the credit facility for loans and new letters of credit, and could require both the immediate repayment of any outstanding principal and interest and the cash collateralization of outstanding letter of credit obligations.

We were in compliance with the covenants and were not in default of the terms of the Revolving Credit Facility as of Sept. 30, 2012.

Short-Term Corporate Term Loan

In June 2012, we extended our one-year $150 million unsecured, single draw term loan for one year. The cost of borrowing under the extended loan now due on June 24, 2013 is based on a spread of 1.10 percent over LIBOR (1.35 percent at Sept. 30, 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 Sept. 30, 2012.

Long-term Corporate Term Loan

In December 2010, we entered into a one-year $100 million term loan with J.P. Morgan and Union Bank due in December 2011. On Sept. 30, 2011, we extended that term loan under the existing terms to Sept. 30, 2013. The cost of borrowing under this term loan is based on a spread of 1.375 percent over LIBOR (1.63 percent at Sept. 30, 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 Sept. 30, 2012.

Repayment of Long-term Debt

On Oct. 31, 2012, we redeemed our 6.5 percent senior unsecured notes originally due to mature on May 15, 2013 for $225.0 million plus interest and a one-time after-tax make whole-provision payment of $4.6 million.

On May 15, 2012, Black Hills Power repaid its 4.8 percent Pollution Control Revenue Bonds in full for $6.5 million including principal and interest. These bonds were originally due to mature on Oct. 1, 2014.

Dividend Restrictions

Certain of our debt agreements impose restrictions on our ability to pay dividends. Any determination to pay dividends in the future will be at the discretion of our Board of Directors and will depend upon our results of operations, financial condition, restrictions imposed by applicable law and our financing agreements and other factors that our Board of Directors deems relevant.

As a result of certain statutory limitations or regulatory or financing agreements, we could have restrictions on the amount of distributions allowed to be made by our subsidiaries.


•	Our utility subsidiaries are generally limited by state regulatory authorities in the amount of dividends allowed that they can pay the utility holding company and also may have further restrictions under the Federal Power Act. As of Sept. 30, 2012, the restricted net assets at our Electric and Gas Utilities were approximately $227.2 million.


•	As required by the covenants in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted equity of at least $100.0 million. In addition, Black Hills Wyoming holds $7.3 million of restricted cash associated with the project financing requirements.

Future Financing Plans

We have substantial future capital expenditures planned, which primarily include construction of additional utility generation to serve Black Hills Power and Cheyenne Light customers and meet governmental pollution control mandates and potential capital deployment in oil and gas drilling to prove-up reserves. Our capital requirements are expected to be financed through a combination of available cash, operating cash flows, borrowings on our Revolving Credit Facility, term loans and long-term financings and other debt or equity issuances.

After the repayment of our $225 million senior unsecured 6.5 percent notes originally due to mature in 2013 discussed above, we have term loans of $250 million expiring in 2013 and debt due of $250 million in 2014. With these upcoming financing requirements, we continue to evaluate various financing options that include senior unsecured notes, first mortgage bonds, term loans and project financing opportunities.

We intend to maintain a consolidated debt-to-capitalization level in the range of 50 percent to 55 percent; however, due to capital projects, we may exceed this level on a temporary basis. We anticipate that our existing credit capacity and available cash will be sufficient to fund our working capital needs and our maintenance capital requirements.

Hedges and Derivatives

Interest Rate Swaps

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 these swaps are recorded within the Condensed Consolidated Statements of Income. For the three and nine months ended Sept. 30, 2012, respectively, we recorded $0.6 million pre-tax unrealized non-cash mark-to-market gain and $2.9 million pre-tax unrealized non-cash mark-to-market loss on the swaps. The mark-to-market value on these swaps was a liability of $95.6 million at Sept. 30, 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 curves over the term of the swaps would have a pre-tax impact of approximately $0.3 million. These swaps are for terms of 6.25 and 16.25 years and have early termination dates ranging from Dec. 15, 2012 to Dec. 16, 2013. 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 values on the termination dates.

In addition, we have $150 million notional amount floating-to-fixed interest rate swaps with a maximum remaining term of 4.3 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 Condensed Consolidated Balance Sheets. The mark-to-market value of these swaps was a liability of $25.7 million at Sept. 30, 2012.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2011 Annual Report on Form 10-K filed with the SEC.

Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms including collateral requirements. As of Sept. 30, 2012, our senior unsecured credit ratings, as assessed by the three major credit rating agencies, were as follows:



Rating Agency	Rating	Outlook

Fitch	BBB-	Stable
Moody's ^(a)	Baa3	Stable
S&P ^{(a) (b)}	BBB-	Stable

_______

(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.

In addition, as of Sept. 30, 2012, Black Hills Power's first mortgage bonds were rated as follows:



Rating Agency	Rating	Outlook
Fitch	A-	Stable
Moody's ^(a)	A3	Stable
S&P ^(a)	BBB+	Stable

_______

(a) In October 2012, both Moody's and S&P upgraded our outlook from Stable to Positive.

Capital Requirements

Actual and forecasted capital requirements for maintenance capital and development capital are as follows (in thousands):



	Expenditures for the		Total		Total		Total
	Nine Months Ended Sept. 30, 2012		2012 Planned Expenditures		2013 Planned Expenditures		2014 Planned Expenditures
Utilities:
Electric Utilities ^{(1) (2)}	$	119,668	$	163,500	$	285,500	$	216,000
Gas Utilities	31,982		52,000		56,000		57,600
Non-regulated Energy:
Power Generation	5,122		7,400		4,200		6,800
Coal Mining	10,806		18,850		5,100		6,000
Oil and Gas ⁽³⁾	88,223		97,200		98,300		84,300
Corporate	7,456		10,300		11,800		4,700
	$	263,257	$	349,250	$	460,900	$	375,400

____________

(1)

Planned expenditures in 2012 and 2013 of $22 million and $27 million, respectively, for the proposed 88 MW of gas-fired generation at Colorado Electric have been removed from the forecasted expenditures reported in our 2011 Annual Report on Form 10-K as a result of the denial of our request for a CPCN. Additionally, capital expenditures required to comply with environmental regulations at Neil Simpson II have been removed.


(2)	2012 forecasted capital expenditures include a reduction of $25 million for the sale of 50 percent of the Busch Ranch Wind project.

(3)

Capital expenditures at our Oil and Gas Segment are driven by economics and may vary depending on the pricing environment for crude oil and natural gas. Forecasted expenditures for 2012, 2013 and 2014 shown above for the Oil and Gas segment have been decreased from the amounts reported in our 2011 Annual Report on Form 10-K due to delaying our gas drilling program as a result of lower natural gas prices and the sale of the majority of our Williston Basin assets.

We continually evaluate all of our forecasted capital expenditures, and if determined prudent, we may defer some of these expenditures for a period of time. Future projects are dependent upon the availability of attractive economic opportunities, and as a result, actual expenditures may vary significantly from forecasted estimates.

Contractual Obligations

There have been no significant changes to contractual obligations or any off-balance sheet arrangements from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Guarantees

There have been no significant changes to guarantees from those previously disclosed in Note 20 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

New Accounting Pronouncements

Other than the pronouncements reported in our 2011 Annual Report on Form 10-K filed with the SEC and those discussed in Note 2 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial statements.

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking information. All statements, other than statements of historical fact, included in this report that address activities, events, or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Forward-looking information involves risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. The factors which may cause our results to vary significantly from our forward-looking statements include the risk factors described in Item 1A of our 2011 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q, and other reports that we file with the SEC from time to time, and the following:


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


•	We anticipate that our existing credit capacity, available cash and operating cash flows will be sufficient to fund our working capital needs and our maintenance capital requirements. Some important factors that could cause actual results to differ materially from those anticipated include:


•	Our access to revolving credit capacity depends on maintaining compliance with loan covenants. If we violate these covenants, we may lose revolving credit capacity and therefore may not have sufficient cash available for our peak winter needs and other working capital requirements, and our forecasted capital expenditure requirements.


•	Counterparties may default on their obligations to supply commodities, return collateral to us, or otherwise meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.


•	Capital market conditions and other economic or market uncertainties beyond our control may affect our ability to raise capital on favorable terms.


•	We have term loans of $250 million expiring in 2013. In addition, we have senior unsecured bonds of $250 million due in 2014. We are evaluating financing options including senior notes, first mortgage bonds, term loans, project financing and equity issuance in the capital markets. Some important factors that could impact our ability to complete one or more of these financings include:


•	Our ability to access the bank loan and debt and equity capital markets depends on market conditions beyond our control. If the capital markets deteriorate, we may not be able to refinance our short-term debt and fund our capital projects on reasonable terms, if at all.


•	Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things. If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.


•	We expect to make approximately $349.3 million, $460.9 million and $375.4 million of capital expenditures in 2012, 2013 and 2014, respectively. Some important factors that could cause actual expenditures to differ materially from those anticipated include:


•	The timing of planned generation, transmission or distribution projects for our Utilities Group is influenced by state and federal regulatory authorities and third parties. The occurrence of events that impact (favorably or unfavorably) our ability to make planned or unplanned capital expenditures have caused and could cause our forecasted capital expenditures to change.

•

Forecasted capital expenditures associated with our Oil and Gas segment are driven, in part, by current commodity prices, our ability to obtain permits, availability and costs of drilling and service equipment, and crews and other services, and our ability to negotiate agreements with property owners for land use. An inability to obtain permits, equipment or land use rights could delay drilling efforts. Our plans may also be negatively impacted by weather conditions and existing or proposed regulations, including possible hydraulic fracturing regulations.


•	Our ability to complete the planning, permitting, construction, start-up and operation of power generation facilities in a cost-efficient and timely manner.


•	We expect contributions to our defined benefit pension plans to be approximately $0.0 million and $4.5 million for the remainder of 2012 and for 2013, respectively. Some important factors that could cause actual contributions to differ materially from anticipated amounts include:


•	The actual value of the plans' invested assets.


•	The discount rate used in determining the funding requirement.


•	We expect the goodwill related to our utility assets to fairly reflect the long-term value of stable, long-lived utility assets. Some important factors that could cause us to revisit the fair value of this goodwill include:


•	A significant and sustained deterioration of the market value of our common stock.


•	Negative regulatory orders, condemnation proceedings or other events that materially impact our Utilities Groups' ability to generate sufficient stable cash flow over an extended period of time.


•	The effects of changes in the market including significant changes in the risk-adjusted discount rate or growth rates.

•

The timing, volatility, and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets, including the possibility that we may be required to take future impairment charges under the SEC's full cost ceiling test for natural gas and crude oil reserves.


•	Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emissions and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain or which could mandate or require closure of one or more of our generating units.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Utilities

Our utility customers are exposed to the effect of volatile natural gas prices. We produce, purchase and distribute power in four states and purchase and distribute natural gas in five states, and we utilize natural gas as fuel at our Electric Utilities. All of our gas utilities have PGA provisions that allow them to pass the prudently-incurred cost of gas and services 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. These adjustments are subject to periodic prudence reviews by the state utility commissions. We have ECA mechanisms in South Dakota, Colorado, Wyoming and Montana for our electric utilities that serve a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs and transmission 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.

As allowed or required by state utility commissions, we have entered into certain exchange-traded natural gas futures, options and basis swaps to reduce our customers' underlying exposure to the volatility of natural gas prices. These transactions are considered derivatives and are marked-to-market. Gains or losses, as well as option premiums on these transactions, are recorded in Regulatory assets or Regulatory liabilities. Once settled, the gains and losses are passed on to our customers through the PGA.

The fair value of our Utilities Group's derivative contracts is summarized below (in thousands) as of:



	Sept. 30, 2012			Dec. 31, 2011			Sept. 30, 2011
Net derivative (liabilities) assets	$	(7,253	)	$	(16,676	)	$	(10,064	)
Cash collateral	15,740			19,416			12,058
	$	8,487		$	2,740		$	1,994

Oil and Gas Activities

We have entered into agreements to hedge a portion of our estimated 2012, 2013 and 2014 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at Sept. 30, 2012 were as follows:

Natural Gas



	For the Three Months Ended
	March 31,		June 30,		Sept. 30,		Dec. 31,		Total Year
2012
Swaps - MMBtu							1,196,000		1,196,000
Weighted Average Price per MMBtu							$	3.74	$	3.74

2013
Swaps - MMBtu	1,220,000		1,233,000		1,246,000		1,155,250		4,854,250
Weighted Average Price per MMBtu	$	4.01	$	3.55	$	3.33	$	3.51	$	3.60

2014
Swaps - MMBtu	950,000		455,000						1,405,000
Weighted Average Price per MMBtu	$	3.71	$	3.45					$	3.63

Crude Oil



	For the Three Months Ended
	March 31,		June 30,		Sept. 30,		Dec. 31,		Total Year
2012
Swaps - Bbls							42,000		42,000
Weighted Average Price per Bbl							$	97.99	$	97.99

Puts - Bbls							21,000		21,000
Weighted Average Price per Bbl							$	76.43	$	76.43

Calls - Bbls							21,000		21,000
Weighted Average Price per Bbl							$	95.00	$	95.00

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		45,000						90,000
Weighted Average Price per Bbl	$	94.38	$	90.82					$	92.60

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. As of Sept. 30, 2012, we had $150 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of 4.25 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 income (loss) on the Condensed Consolidated Balance Sheets.

We also have interest rate swaps with a notional amount of $250 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. The swaps were originally designated as cash flow hedges and the mark-to-market value was recorded in Accumulated other comprehensive income (loss) on the Condensed Consolidated Balance Sheets. 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 Condensed Consolidated Statements of Income. For the three months and nine months ended Sept. 30, 2012, we recorded pre-tax unrealized non-cash mark-to-market gain of $0.6 million and a pre-tax unrealized non-cash mark-to-market loss of $2.9 million, respectively. For the three months and nine months ended Sept. 30, 2011, we recorded pre-tax unrealized non-cash mark-to-market losses of $38.2 million and $40.6 million, respectively. The mark-to-market value on these swaps was a liability of $95.6 million at Sept. 30, 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 curves over the term would have a pre-tax impact of approximately $0.3 million. These swaps are 6.25 and 16.25 year swaps which have early termination dates ranging from Dec. 15, 2012 to Dec. 16, 2013.

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 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 values on the stated termination dates.

Further details of the swap agreements are set forth in Note 11 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Our interest rate swaps and related balances were as follows (dollars in thousands) as of:



	Sept. 30, 2012						Dec. 31, 2011						Sept. 30, 2011
	Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*
Notional	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.25			1.25			5.00			2.00			5.25			0.25
Derivative liabilities, current	$	7,028		$	77,914		$	6,513		$	75,295		$	6,724		$	94,588
Derivative liabilities, non-current	$	18,660		$	17,668		$	20,363		$	20,696		$	21,108		$	—
Pre-tax accumulated other comprehensive loss included in Condensed Consolidated Balance Sheets	$	(25,688	)	$	—		$	(26,876	)	$	—		$	(27,832	)	$	—
Pre-tax (loss) gain included in Condensed Consolidated Statements of Income	$	—		$	(2,902	)	$	—		$	(42,010	)	$	—		$	(40,608	)
Cash collateral receivable (payable) included in accounts receivable	$	—		$	3,310		$	—		$	—		$	—		$	—

__________

Maximum terms in years for our de-designated interest rate swaps 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 on the termination date. When extended annually, de-designated swaps totaling $100 million terminate in 6.25 years and de-designated swaps totaling $150 million terminate in 16.25 years.

Based on Sept. 30, 2012 market interest rates and balances for our designated interest rate swaps, 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 change during the next 12 months as market interest rates change.

ITEM 4. CONTROLS AND PROCEDURES

This section should be read in conjunction with Item 9A, "Controls and Procedures" included in our Annual Report on Form 10-K for the year ended Dec. 31, 2011.

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 Sept. 30, 2012 and concluded that, because of the material weakness in our internal control over financial reporting related to accounting for income taxes as previously disclosed in Item 9A, “Controls and Procedures” in our Annual Report on Form 10-K for the year ended Dec. 31, 2011, our disclosure controls and procedures were not effective as of Sept. 30, 2012. Additional review, evaluation and oversight have been undertaken to ensure our unaudited Condensed Consolidated Financial Statements were prepared in accordance with generally accepted accounting principles and as a result, our management, including our Chief Executive Officer and Chief Financial Officer, have concluded that the Condensed Consolidated Financial Statements in this Form 10-Q fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in conformity with accounting principles generally accepted in the United States.

As discussed in our 2011 Annual Report on Form 10-K, management concluded that while we had appropriately designed control procedures for income tax accounting and disclosures, the existence of non-routine transactions, insufficient tax resources, and ineffective communications between the tax department and Controller organization caused us to poorly execute the controls for evaluating and recording income taxes. Management has developed and implemented a remediation plan to address this material weakness in internal controls surrounding accounting for income taxes. Key aspects of the remediation plan include enhanced resources and skill sets, and implementation of formal periodic meetings among the Chief Financial Officer, Controller and the tax department.

While we concluded our internal controls surrounding income taxes were not effective as of Sept. 30, 2012, we are remediating the material weakness and will continue to execute our remediation plan and track our performance against the plan.

During the quarter ended Sept. 30, 2012, there have been no other 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.

BLACK HILLS CORPORATION

Part II — Other Information


ITEM 1.	Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2011 Annual Report on Form 10-K and Note 14 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 14 is incorporated by reference into this item.


ITEM 1A.	Risk Factors

There are no material changes to the Risk Factors previously disclosed in Item 1A of Part I in our Annual Report on Form 10-K for the year ended Dec. 31, 2011.


ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities



Period	Total Number of Shares Purchased⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans for Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
July 1, 2012 -
July 31, 2012	—	$	—	—	—

Aug. 1, 2012 -
Aug. 31, 2012	262	$	31.46	—	—

Sept. 1, 2012 -
Sept. 30, 2012	—	$	—	—	—

Total	262	$	31.46	—	—

____________



(1)	Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for the payment of taxes associated with the vesting of shares of restricted stock.


ITEM 4.	Mine Safety 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 Quarterly Report on Form 10-Q.


ITEM 5.	Other Information

None.


ITEM 6.	Exhibits



	Exhibit 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).

	Exhibit 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.

	Exhibit 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.

	Exhibit 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.

	Exhibit 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.

	Exhibit 95	Mine Safety and Health Administration Safety Data

	Exhibit 101	Financial Statements for XBRL Format

BLACK HILLS CORPORATION

Signatures

Pursuant to the requirements 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



		/s/ David R. Emery
		David R. Emery, Chairman, President and
		Chief Executive Officer

		/s/ Anthony S. Cleberg
		Anthony S. Cleberg, Executive Vice President and
		Chief Financial Officer

Dated:	November 8, 2012

EXHIBIT INDEX



Exhibit Number	Description
Exhibit 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).

Exhibit 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.

Exhibit 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.

Exhibit 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.

Exhibit 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.

Exhibit 95	Mine Safety and Health Administration Safety Data

Exhibit 101	Financial Statements for XBRL Format

Exhibit 2 Non-OpPSA E&P

Execution Version

PURCHASE AND SALE AGREEMENT

BY AND AMONG

BLACK HILLS EXPLORATION AND PRODUCTION, INC.

UNIT PETROLEUM COMPANY

SUNDANCE ENERGY, INC.

HIGHLINE EXPLORATION, INC.

HOUSTON ENERGY, L.P.

NISKU ROYALTY, LP

EMPIRE OIL COMPANY

AND

KENT M. LYNCH

AS SELLERS

AND

QEP ENERGY COMPANY,

AS PURCHASER

_________________________________________

DATED AS OF AUGUST 23, 2012
_________________________________________

TABLE OF CONTENTS



		Page

ARTICLE 1 DEFINITIONS AND INTERPRETATION

Section 1.1	Defined Terms	1
Section 1.2	References and Rules of Construction	1

ARTICLE 2 PURCHASE AND SALE

Section 2.1	Purchase and Sale	2
Section 2.2	Assets	2
Section 2.3	Excluded Assets	4
Section 2.4	Effective Time; Proration of Costs and Revenues	4
Section 2.5	Procedures	5

ARTICLE 3 PURCHASE PRICE

Section 3.1	Purchase Price	6
Section 3.2	Allocation of Purchase Price	6
Section 3.3	Adjustment to Purchase Price	7
Section 3.4	Allocated Values	9

ARTICLE 4 TITLE AND ENVIRONMENTAL MATTERS

Section 4.1	Sellers' Title	10
Section 4.2	Title Defects	10
Section 4.3	Title Benefits	15
Section 4.4	Title Disputes	17
Section 4.5	Limitations on Applicability	19
Section 4.6	Consents to Assignment and Preferential Rights to Purchase	21
Section 4.7	Casualty or Condemnation Loss	22

ARTICLE 5 REPRESENTATIONS AND WARRANTIES OF SELLER

Section 5.1	Generally	23
Section 5.2	Existence and Qualification	24
Section 5.3	Power	24
Section 5.4	Authorization and Enforceability	24
Section 5.5	No Conflicts	24
Section 5.6	Liability for Brokers' Fees	25
Section 5.7	Intellectual Property	25
Section 5.8	Insurance	25
Section 5.9	Litigation	25

- 1 -



Section 5.10	Payment of Royalties and Rentals	25
Section 5.11	Taxes and Assessments	26
Section 5.12	Capital Commitments	26
Section 5.13	Compliance with Laws	26
Section 5.14	Contracts	27
Section 5.15	Payments for Production	27
Section 5.16	Consents and Preferential Purchase Rights	27
Section 5.17	Properties	27
Section 5.18	Non-Consent Operations	27
Section 5.19	Bankruptcy	28
Section 5.20	Helis as Operator
Section 5.21	Certain Disclaimers

ARTICLE 6 REPRESENTATIONS AND WARRANTIES OF PURCHASER

Section 6.1	Generally	29
Section 6.2	Existence and Qualification	29
Section 6.3	Power	29
Section 6.4	Authorization and Enforceability	29
Section 6.5	No Conflicts	30
Section 6.6	Liability for Brokers' Fees	30
Section 6.7	Litigation	30
Section 6.8	Financing	30
Section 6.9	Securities Law Compliance	30
Section 6.10	Independent Evaluation	30
Section 6.11	Consents, Approvals or Waivers	31
Section 6.12	Bankruptcy	31
Section 6.13	Qualification	31
Section 6.14	Limitation	31

ARTICLE 7 COVENANTS OF THE PARTIES

Section 7.1	Access	32
Section 7.2	Government Reviews	33
Section 7.3	Public Announcements; Confidentiality	34
Section 7.4	Operation of Business	35
Section 7.5	Non-Solicitation of Employees	36
Section 7.6	Change of Name	36
Section 7.7	Replacement of Bonds, Letters of Credit and Guaranties	36
Section 7.8	Notification of Breaches	36
Section 7.9	Amendment to Schedules	37
Section 7.10	Regulatory Matters	38
Section 7.11	Further Assurances	38
Section 7.12	Sellers' Waiver, Release and Conveyance	38
Section 7.13	Sellers' Representative	39

- 2 -




ARTICLE 8 CONDITIONS TO CLOSING

Section 8.1	Sellers' Conditions to Closing	39
Section 8.2	Purchaser's Conditions to Closing	40

ARTICLE 9 CLOSING

Section 9.1	Time and Place of Closing	41
Section 9.2	Obligations of Sellers at Closing	42
Section 9.3	Obligations of Purchaser at Closing	43
Section 9.4	Closing Payment and Post-Closing Purchase Price Adjustments	44

ARTICLE 10 TERMINATION; REMEDIES

Section 10.1	Termination	45
Section 10.2	Effect of Termination	46
Section 10.3	Remedies for Failure to Close	46

ARTICLE 11 ASSUMPTION; INDEMNIFICATION

Section 11.1	Assumption	47
Section 11.2	Indemnification	47
Section 11.3	Indemnification Actions	49
Section 11.4	Limitation on Actions	50

ARTICLE 12 TAX MATTERS

Section 12.1	Tax Filings	52
Section 12.2	Current Tax Period Taxes	53
Section 12.3	Tax Indemnity	53
Section 12.4	Characterization of Certain Payments	54
Section 12.5	Withholding Taxes	54

ARTICLE 13 MISCELLANEOUS

Section 13.1	Counterparts	54
Section 13.2	Notice	54
Section 13.3	Tax, Recording Fees, Similar Taxes & Fees	56
Section 13.4	Governing Law; Jurisdiction	57
Section 13.5	Waivers	57
Section 13.6	Assignment	57
Section 13.7	Entire Agreement	58
Section 13.8	Amendment	58
Section 13.9	No Third Party Beneficiaries	58

- 3 -



Section 13.10	Construction	58
Section 13.11	Limitation on Damages	58
Section 13.12	Recording	58
Section 13.13	Conspicuous	58
Section 13.14	Time of Essence	59
Section 13.15	Delivery of Records	59
Section 13.16	Severability	59
Section 13.17	Specific Performance	59
Section 13.18	Like-Kind Exchange	59

- 4 -

APPENDICES:


Appendix A	- Definitions

EXHIBITS:


Exhibit A-1	- Leases


Exhibit A-2	- Units


Exhibit A-3	- Gas Gathering Systems and Surface Interests


Exhibit B	- Form of Assignment


Exhibit C	- Form of Letter-in-Lieu of Transfer Order


Exhibit D	- Retained ORRIs

SCHEDULES:

Schedule 3.1 - Unadjusted Purchase Price for each Seller

Schedule 3.2 - Purchase Price Allocation Schedule

Schedule 3.4 - Allocated Values

Schedule 5.1 - Seller Knowledge Individuals

Schedule 5.8 - Insurance

Schedule 5.9 - Litigation

Schedule 5.11 - Taxes and Assessments

Schedule 5.12 - Capital Commitments

Schedule 5.14 - Contracts

Schedule 5.15 - Payments for Production and Imbalances

Schedule 5.16 - Consents and Preferential Rights to Purchase

Schedule 5.17 - Lease Notices

Schedule 5.18 - Non-Consent Operations

Schedule 6.1 - Purchaser Knowledge Individuals

Schedule 7.4 - Operations

Schedule 11.1 - Assumed Purchaser Obligations

- 5 -

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (as may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is dated as of August 23, 2012 (the “Execution Date”), by and among Black Hills Exploration and Production, Inc., a Wyoming Corporation (“Black Hills”), Unit Petroleum Company, an Oklahoma Corporation (“UPC”), Sundance Energy, Inc., a Colorado Corporation, Highline Exploration, Inc., an Alabama Corporation, Houston Energy, L.P. a Texas limited partnership, Nisku Royalty, LP, a Montana limited partnership, Empire Oil Company, a North Dakota corporation, and Kent M. Lynch (each a “Seller” and, collectively, the “Sellers”), on the one part, and QEP Energy Company, a Texas corporation (“Purchaser”), on the other part. Each of the Sellers and Purchaser are sometimes referred to herein individually as a “Party” and collectively as the “Parties.”

RECITALS:

A. Sellers own certain interests in oil and gas properties, rights and related assets that are defined and described herein as the “Assets.”

B. Sellers desire to sell to Purchaser and Purchaser desires to purchase from Sellers the Assets, in the manner and upon the terms and conditions hereafter set forth.

NOW, THEREFORE, in consideration of the premises and of the mutual promises, representations, warranties, covenants, conditions and agreements contained herein, and for other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound by the terms hereof, agree as follows:

ARTICLE 1
DEFINITIONS AND INTERPRETATION

Section 1.1 Defined Terms. In addition to the terms defined in the preamble and the Recitals of this Agreement, for purposes hereof, the capitalized terms used herein and not otherwise defined shall have the meanings set forth in Appendix A.

Section 1.2 References and Rules of Construction. All references in this Agreement to Exhibits, Schedules, Appendices, Articles, Sections, subsections, clauses and other subdivisions refer to the corresponding Exhibits, Schedules, Appendices, Articles, Sections, subsections, clauses and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Exhibits, Schedules, Appendices, Articles, Sections, subsections, clauses and other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement and shall be disregarded in construing the language hereof. The words “this Agreement,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular Article, Section, subsection, clause or other subdivision unless expressly so limited. The words “this Article,” “this Section,” “this subsection,” “this clause,” and words of similar import, refer only to the Article, Section, subsection and clause hereof in which such words occur. The word “including” (in its various forms) means including

without limitation. All references to “$” shall be deemed references to Dollars. Each accounting term not defined herein will have the meaning given to it under GAAP as interpreted as of the Execution Date. Unless expressly provided to the contrary, the word “or” is not exclusive. Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Appendices, Exhibits and Schedules referred to herein are attached to and by this reference incorporated herein for all purposes. Reference herein to any federal, state, local or foreign Law shall be deemed to also refer to all rules and regulations promulgated thereunder, unless the context requires otherwise.

ARTICLE 2

PURCHASE AND SALE

Section 2.1 Purchase and Sale. At the Closing, upon the terms and subject to the conditions of this Agreement, each Seller agrees to sell, transfer and convey the Assets to Purchaser and Purchaser agrees to purchase, accept and pay for the Assets and to assume the Assumed Purchaser Obligations.

Section 2.2 Assets. As used herein, subject to the terms and conditions of this Agreement, the term “Assets” means with respect to a Seller all of the Seller Assets and “Seller Assets” in each case means such Seller’s (and, as applicable, its Affiliates’) right, title and interest in and to the following:

(a) The oil and gas leases, oil, gas and mineral leases, subleases and other leaseholds, royalties, overriding royalties, net profits interests, mineral fee interests, carried interests, and other rights to Hydrocarbons that are identified on Exhibit A-1 (collectively, the “Leases”);

(b) All pooled, communitized or unitized acreage that includes all or a part of any Lease, including those shown on Exhibit A-2 (collectively, the “Units”), and all tenements, hereditaments and appurtenances belonging to the Leases and Units;

(c) All oil, gas, water, carbon dioxide, or injection wells located on the Leases or Units, whether producing, shut-in or temporarily abandoned, including the wells shown on Exhibit A-2 (collectively, the “Wells”);

(d) All tanks, flowlines, pipelines, gathering systems and appurtenances thereto located on the Leases or Units or used, or held for use, in connection with the operation of the Wells, including those identified on Exhibit A-3 (the “Gathering Systems”; and together with the Units, the Leases and the Wells, the “Properties”);

(e) [Reserved];

(f) All contracts, agreements and instruments to the extent applicable to the Properties or the production of Hydrocarbons from the Properties, including operating agreements, unitization, pooling and communitization agreements, declarations and orders, area of mutual interest agreements, joint venture agreements, farmin and farmout agreements, participation

agreements, exchange agreements, transportation agreements, agreements for the sale and purchase of Hydrocarbons and processing agreements, but excluding any contracts, agreements and instruments the transfer of which is restricted by its terms or applicable Law; provided, however, each Seller, as applicable, shall use its Commercially Reasonable Efforts to obtain waivers or consents for the transfer of such contracts, agreements or instruments pursuant to Section 4.6, only to the extent that such waiver or consent is not obtained by Helis under the Helis PSA (subject to such qualification, the “Contracts”);

(g) All surface fee interests, easements, Permits, licenses, servitudes, rights-of-way, surface leases and other surface rights appurtenant to, and used or held for use solely in connection with, the Properties, including those interests set forth on Exhibit A-3, but excluding, in all such instances, any items the transfer of which is restricted by its terms or applicable Law; provided, however, each Seller, as applicable, shall use its Commercially Reasonable Efforts to obtain waivers or consents for the transfer of such contracts, agreements or instruments pursuant to Section 4.6 to the extent not obtained by Helis under the Helis PSA;

(h) All equipment, materials, supplies, machinery, tools, fixtures and other tangible personal property (including but not limited to spare parts, casing, tubing, wellheads, etc.) and improvements located on the Properties or used or held for use solely in connection with the operation of the Properties or the production of Hydrocarbons from the Properties; but excepting and reserving any Hydrocarbons stored in stock tanks, pipelines or other storage as of the Effective Time other than such Hydrocarbons for which there is a purchase price adjustment pursuant to Section 3.3(a)(iv) (subject to such exclusion, the “Equipment”);

(i) The Leased Assets, except to the extent that any of the Leased Assets are transferable with the payment of a fee or other consideration (unless Purchaser has agreed in writing to pay such fee or other consideration) but excluding, in all such instances, any items the transfer of which is restricted by its terms or applicable Law; provided, however, each Seller, as applicable, shall use its Commercially Reasonable Efforts to obtain waivers or consents for the transfer of such contracts, agreements or instruments pursuant to Section 4.6 to the extent not obtained by Helis under the Helis PSA;

(j) All Hydrocarbons produced from or attributable to the Leases, the Units or the Wells at and after the Effective Time;

(k) All geophysical and other seismic data, and other technical data and information, relating to the Properties, but excluding, in all such instances, any data the transfer of which is restricted by its terms (unless such data is transferable with the payment of a fee or other consideration and Purchaser has agreed in writing to pay such fee or other consideration) or applicable Law;

(l) All (i) trade credits, accounts receivable, notes receivable, take-or-pay amounts receivable and other receivables and general intangibles, attributable to the Assets with respect to periods of time from and after the Effective Time, (ii) liens and security interests in favor of each Seller, whether choate or inchoate, under any law or contract, to the extent arising from, or relating to, the ownership, operation, or sale or other disposition at or after the Effective Time of

any of the Assets, and (iii) claims of indemnity, contribution or reimbursement relating to the Assumed Purchaser Obligations;

(m) All rights to audit the records of any Person and to receive refunds or payments of any nature, and all amounts of money, relating thereto, in each case, to the extent arising from, or relating to, the ownership, operation, or sale or other disposition at or after the Effective Time of the Assets;

(n) All intangible rights, inchoate rights, transferable rights under warranties made by prior owners, manufacturers, vendors and Third Parties, and rights accruing under applicable statute of limitation or prescription, to the extent related to or attributable to the Assets (excluding items that relate to matters for which Sellers are required to provide indemnification to Purchaser hereunder);

(o) All claims, rights, demands, complaints, causes of action, suits, actions, judgments, damages, awards, fines, penalties, recoveries, settlements, appeals, duties, obligations, liabilities, losses, debts, costs and expenses (including court costs, expert witness fees and reasonable attorneys’ fees) in favor of any Seller arising from acts, omissions or events, or damage to or destruction of the Properties (excluding items that relate to matters for which a Seller is required to provide indemnification to Purchaser hereunder); and

(p) The Records.

Section 2.3 Excluded Assets. The Assets shall not include, and there is excepted, reserved and excluded from this transaction, the Excluded Assets.

Section 2.4 Effective Time; Proration of Costs and Revenues.

(a) Subject to the other terms and conditions of this Agreement, possession of the Seller Assets shall be transferred from each Seller to Purchaser at the Closing, but certain financial benefits and burdens of the Assets shall be transferred effective as of 7:00 a.m., Mountain Time, on July 1, 2012 (the “Effective Time”), as described below.

(b) Purchaser shall be entitled to all production of Hydrocarbons from or attributable to the Leases, the Units and the Wells at and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets at and after the Effective Time (in accordance with their interests), and shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred at and after the Effective Time.

(c) Each Seller shall be entitled to all production of Hydrocarbons from or attributable to the Leases, the Units and the Wells prior to the Effective Time (and all products and proceeds attributable thereto), all other income, proceeds, receipts and credits earned with respect to its Seller Assets prior to the Effective Time, and shall be responsible for (and entitled to any refunds other than for those Property Costs paid or payable by Purchaser with respect to) all Property Costs attributable to its Seller Assets incurred prior to the Effective Time (in accordance with their interests).

(d) Should Purchaser receive any proceeds or other amounts to which any Seller is entitled under Section 2.4(c), Purchaser shall fully disclose, account for and promptly remit the same to such Seller (or, in the case of disclosure, to Sellers’ Representative) in accordance with such Seller’s applicable interests in such proceeds. If a Seller receives any proceeds or other amounts with respect to the Assets to which such Seller is not entitled pursuant to Section 2.4(c), such Seller shall fully disclose, account for, and promptly remit the same to Purchaser.

(e) Should Purchaser pay any Property Costs for which a Seller is responsible under Section 2.4(c), such Seller shall reimburse Purchaser promptly after receipt of an invoice with respect to such Property Costs, accompanied by copies of the relevant vendor or other invoice and proof of payment. Should a Seller pay any Property Costs for which such Seller is not responsible under Section 2.4(c), Purchaser shall reimburse such Seller promptly after receipt of an invoice with respect to such Property Costs, accompanied by copies of the relevant vendor or other invoice and proof of payment.

(f) Sellers shall have no further entitlement to amounts earned from the sale of Hydrocarbons produced from or attributable to the Assets and other income earned with respect to the Assets and no further responsibility for Property Costs (except to the extent such Property Costs are the responsibility of Sellers under Article 11 or Article 12) incurred with respect to the Assets following the final determination and payment of the Adjusted Purchase Price in accordance with Section 9.4(d).

(g) Consistent with Section 12.2 (as applicable), Taxes that are included in Property Costs, right-of-way fees, insurance premiums and other Property Costs that are paid periodically shall be prorated based on the number of days in the applicable period falling before and the number of days in the applicable period falling at and after the Effective Time, except that production, severance and similar Taxes (excluding, for the avoidance of doubt, ad valorem and similar property Taxes that are assessed based on the quantity of or the value of production during preceding annual periods) measured by the quantity of or the value of production shall be prorated based on the number of units or value of production actually produced or sold, as applicable, before, and at or after, the Effective Time. In each case, Purchaser shall be responsible for the portion allocated to the period at and after the Effective Time and each Seller shall be responsible for the portion attributable to its Seller Assets allocated to the period before the Effective Time.

Section 2.5 Procedures.

(a) For purposes of allocating production (and accounts receivable with respect thereto) under Section 2.4, (i) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Leases, the Units and the Wells when they pass through the inlet flange of the pipeline connecting into the storage facilities into which they are run or, if there are no such storage facilities, when they pass through the LACT meters or similar meters at the initial point of entry into the pipelines through which they are transported from the field and (ii) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Leases, the Units and the Wells when they pass through the delivery point sales meters on the pipelines through which they are transported. Sellers shall utilize reasonable interpolative procedures to arrive at an allocation of production when exact meter readings or gauging and strapping data is not available provided that Sellers may use and rely on

such allocation, or derivations thereof, made pursuant to the Helis PSA. To the extent not provided pursuant to the Helis PSA Sellers’ Representative shall provide to Purchaser evidence of all meter readings and all gauging and strapping procedures conducted on or about the Effective Time in connection with the Assets, if available, together with all data necessary to support any estimated allocation, for purposes of establishing the adjustment to the Unadjusted Purchase Price pursuant to Section 3.3. The terms “earned” and “incurred” shall be interpreted in accordance with generally accepted accounting principles and Council of Petroleum Accountants Society (“COPAS”) standards, and expenditures that are incurred pursuant to an operating agreement, unit agreement or similar agreement shall be deemed incurred when expended by the operator of the applicable Lease, Unit or Well, in accordance with the practices currently used by the operator.

(b) After Closing, and subject to each Seller retaining the right to require an audit of Helis or any third party as Operator for pre-Effective Time charges or costs pursuant to the applicable Contract, Purchaser shall handle joint interest audits and other audits of Property Costs covering the period for which Sellers are in whole or in part responsible under Section 2.4, provided that Purchaser shall not agree to any adjustments to previously assessed costs for which a Seller is liable, or any compromise of any audit claims to which a Seller would be entitled, without the prior written consent of such Seller, which consent shall not be unreasonably withheld, conditioned or delayed. Any expenses from such audit shall be borne by Purchaser and Sellers, respectively, in the same proportion as the Property Costs at issue are or would be borne by Purchaser and Sellers. Purchaser shall provide Sellers with a copy of all applicable audit reports and written audit agreements received by Purchaser or its Affiliates and relating to periods for which Sellers are wholly or partially responsible.

ARTICLE 3

PURCHASE PRICE

Section 3.1 Purchase Price. The aggregate purchase price for the Assets shall be Seven Hundred Forty-Four Million Four Hundred Sixty Nine Thousand Three Hundred and Seventeen Dollars ($744,469,317) (the “Aggregate Unadjusted Purchase Price”)], a portion of which is payable to each Seller in accordance with Schedule 3.1 (such portion with respect to a Seller, its “Unadjusted Purchase Price”), as adjusted and paid, as applicable, pursuant to and in accordance with Section 3.3, Section 9.3 and Section 9.4. Contemporaneously with the execution and delivery of this Agreement, Purchaser has delivered or caused to be delivered to an account established for each Seller (the “Escrow Account”) with JP Morgan Chase (the “Escrow Agent”), a wire transfer in the amount equal to (10%) of the Unadjusted Purchase Price for that Seller (the “Deposit”) to be held, invested, and disbursed in accordance with the terms of this Agreement and an escrow agreement of even date herewith among such Seller, Purchaser, and Escrow Agent (the “Escrow Agreement”). The balance in the Escrow Account for a Seller shall be distributed to such Sellers in accordance with Section 9.3(a) if the Closing occurs or shall be otherwise distributed in accordance with the terms of Section 10.3. Any reference in this Agreement to a Deposit or Escrow Agreement shall be a reference separately to the Deposit for each Seller or to the Escrow Agreement for each Seller, as appropriate.

Section 3.2 Allocation of Purchase Price. The Parties recognize that this transaction is a sale of the Assets to Purchaser subject to the requirements of Section 1060 of the Code and the

Treasury Regulations thereunder and, therefore, that an IRS Form 8594, Asset Acquisition Statement, will be required to be filed by the Parties. The Parties agree that the Aggregate Unadjusted Purchase Price and any liabilities associated with the Assets (to the extent properly taken into account as consideration under the Code) shall be allocated among the Assets for Tax purposes (and the aggregate amount allocated to each class of Assets shall be further allocated among the Sellers to reflect each Seller’s Seller Assets) as set forth on Schedule 3.2 (the “Purchase Price Allocation Schedule”). Such allocation shall be determined in accordance with Section 1060 of the Code and the Treasury Regulations thereunder and is intended by the Parties to be consistent with the Allocated Values as determined pursuant to Section 3.4. Within twenty (20) days following the final determination of the Aggregate Adjusted Purchase Price, Purchaser shall deliver to the Sellers’ Representative for its review and reasonable comment, a revised Purchase Price Allocation Schedule, adjusted to reflect the Aggregate Adjusted Purchase Price. The Purchase Price Allocation Schedule shall be revised to take into account subsequent adjustments to the Aggregate Unadjusted Purchase Price or the Aggregate Adjusted Purchase Price and any indemnification payments in the manner provided by applicable Law. If Purchaser and Sellers’ Representative are unable to agree on any revisions to the Purchase Price Allocation Schedule, any dispute arising in connection with the Purchase Price Allocation Schedule shall be resolved pursuant to procedures comparable to the procedures applicable under Section 9.4(d). The Parties shall, and shall cause their respective Affiliates to, use the Purchase Price Allocation Schedule (as adjusted pursuant to this Section 3.2) in reporting this transaction to the applicable Taxing authorities, including on IRS Form 8594 and any other information or Tax Returns and supplements thereto required to be filed under Section 1060 of the Code and the Treasury Regulations thereunder. No Party shall, or shall permit its Affiliates to, file any Tax Return or otherwise take any position for Tax purposes that is inconsistent with the Purchase Price Allocation Schedule (as adjusted pursuant to this Section 3.2); provided, however, that nothing contained herein shall prevent a Party from settling any proposed deficiency or adjustment by any Taxing authority based upon or arising out of the allocation (which may result in a change to the allocation), and no Party shall be required to litigate any proposed deficiency or adjustment by any Taxing authority challenging such allocation.

Section 3.3 Adjustments to Purchase Price. All adjustments to the Unadjusted Purchase Price for each Seller shall be made (x) in accordance with the terms of this Agreement and, to the extent not inconsistent with this Agreement, in accordance with GAAP (as of the Effective Time), (y) without duplication (in this Agreement or otherwise) and (z) only with respect to matters (A) in the case of Section 3.3(a)(vi) and Section 3.3(b)(v), for which notice is given on or before the Title Claim Date, and (B) in all of the other cases set forth in Section 3.3(a) and Section 3.3(b), identified on or before the 180th day after Closing (the “Cut-off Date”). Each adjustment to the Unadjusted Purchase Prices described in Section 3.3(a) and Section 3.3(b) shall be allocated among the Assets in accordance with Section 3.4.

Without limiting the foregoing, the Unadjusted Purchase Price for each Seller shall be adjusted as follows (with the resulting adjustments to such Unadjusted Purchase Price being the “Adjusted Purchase Price” for such Seller and the sum of all Adjusted Purchase Prices being the “Aggregate Adjusted Purchase Price”):

(h) The Unadjusted Purchase Price for each Seller shall be adjusted upward by the following amounts (without duplication):

(i) an amount equal to all Property Costs and other costs attributable to the ownership and operation of such Seller’s Seller Assets that are incurred at and after the Effective Time but paid by such Seller (as is consistent with Section 2.4(b) and Section 2.4(c)), but excluding any amounts previously reimbursed to such Seller pursuant to Section 2.4(e);

(ii) an amount equal to, to the extent that such amounts have been received by Purchaser and not remitted or paid to such Seller, to the extent attributable to such Seller’s Seller Assets (A) all proceeds from the production of Hydrocarbons from or attributable to the Leases, the Units and the Wells prior to the Effective Time, (B) all other income, proceeds, receipts and credits earned prior to the Effective Time and (C) any other amounts to which Seller is entitled pursuant to Section 2.4(c);

(iii) the amount of all prepaid expenses (including pre-paid bonuses, rentals, location building expenses, cash calls and advances to Third Party operators for expenses not yet incurred; prepaid production Taxes, severance Taxes and other similar Taxes; and scheduled payments) paid by such Seller with respect to the ownership or operation of the Seller Assets at or after the Effective Time;

(iv) to the extent that proceeds for such volumes have not been received by such Seller, an amount equal to the aggregated volumes of Hydrocarbons stored in stock tanks, pipelines or other storage as of the Effective Time that are attributable to the ownership and operation of its Seller Assets multiplied by the contract price therefor on the Effective Time;

(v) to the extent that such Seller is underproduced or overdelivered as of the Effective Time as shown with respect to the any net Imbalances for any product set forth in Schedule 5.15, as complete and final settlement of all such Imbalances for each such product, the value of such Imbalances (calculated on the basis of the average price of production of the applicable product for the 30 day period prior to the delivery of the Preliminary Settlement Statement referred to in Section 9.4(b));

(vi) any undisputed amounts for Title Benefits for such Seller determined pursuant to Section 4.3;

(vii) any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by the Parties as an upward adjustment to such Unadjusted Purchase Price.

(i) The Unadjusted Purchase Price for each Seller shall be adjusted downward by the following amounts (without duplication):

(i) an amount equal to all Property Costs and other costs attributable to the ownership and operation of such Seller’s Seller Assets owned by such Seller that are incurred prior to the Effective Time but paid by Purchaser (as is consistent with Section 2.4(b) and Section 2.4(c)), but excluding any amounts previously reimbursed to Purchaser pursuant to Section 2.4(e);

(ii) an amount equal to, to the extent that such amounts have been received by such Seller and not remitted or paid to Purchaser, to the extent attributable to such Seller’s Seller Assets (A) all proceeds from the production of Hydrocarbons from or attributable to the Leases, the Units and the Wells at and after the Effective Time, (B) all other income, proceeds, receipts and credits earned at and after the Effective Time and (C) any other amounts to which Purchaser is entitled pursuant to Section 2.4(b);

(iii) to the extent that such Seller is overproduced or underdelivered as of the Effective Time as shown with respect to any net Imbalances for any product set forth in Schedule 5.15, as complete and final settlement of all such Imbalances for each such product, the value of such Imbalances (calculated on the basis of the average price of production of the applicable product for the 30 day period prior to the delivery of the Preliminary Settlement Statement referred to in Section 9.4(b));

(iv) to the extent not transferred to Purchaser at the Closing, all funds held in suspense by such Seller with respect to the operation, ownership, production and developments, including those amounts set forth on Schedule 5.20;

(v) any undisputed amounts for Title Defects with respect to such Seller determined pursuant to Section 4.2 (which shall include, for purposes of certainty, an amount equal to such Seller’s Title Defect Percentage of the Allocated Value of any Assets excluded from this transaction pursuant to Section 4.2(c)) and Seller’s Title Defect Percentage of any amounts excluded pursuant to Section 4.2(e);

(vi) an amount equal to such Seller’s Title Defect Percentage of the Allocated Value of any Assets excluded from this transaction pursuant to Section 4.6, as applicable to such Seller;

(vii) an amount equal to such Seller’s Title Defect Percentage of the Allocated Value of any Assets excluded from this transaction pursuant to Section 4.7(a), as applicable to such Seller; and

(viii) any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by the Parties as a downward adjustment to the Unadjusted Purchase Price.

Section 3.4 Allocated Values. The “Allocated Values” for the Assets (which are provided for, and allocated amongst, each of the Units) are set forth on Schedule 3.4. The share of each adjustment allocated to each Seller in accordance with such Seller’s applicable Title Defect Percentage and allocated to a particular Asset shall be allocated to the particular Asset to which

such adjustment relates to the extent such adjustment relates to such Asset and to the extent that it is, in the commercially reasonable discretion of Sellers’ Representative, possible to do so. Any adjustment not allocated to a specific Asset pursuant to the immediately preceding sentence shall be allocated among the various Assets on a pro-rata basis in proportion to the Unadjusted Purchase Price allocated to such Asset on Schedule 3.4 and among the Sellers in accordance with their Seller’s Interest Percentages. Sellers have accepted such Allocated Values for purposes of this Agreement and the transactions contemplated hereby, but Sellers make no representation or warranty as to the accuracy of such values.

ARTICLE 4

TITLE AND ENVIRONMENTAL MATTERS

Section 4.1 Sellers’ Title. Except for the special warranty of title set forth in the Assignments, no Seller makes any warranty or representation, express, implied, statutory or otherwise, with respect to such Seller’s title to any of the Assets, and Purchaser hereby acknowledges and agrees that, subject to Section 4.5, Purchaser’s sole remedy for any defect of title, including any Title Defect, with respect to any of the Assets, (a) on or before the applicable Title Claim Date, shall be as set forth in Section 4.2 and, (b) subject to the following sentence, from and after the applicable Title Claim Date (without duplication), shall be pursuant to the special warranty of title set forth in the Assignments. Purchaser further acknowledges and agrees that Purchaser shall not be entitled to protection under (or the right to make a claim against) the special warranty of title provided in the Assignments for any Title Defect reported under this Article 4.

Section 4.2 Title Defects.

(j) To assert a claim of a Title Defect, Purchaser must deliver a claim notice to Sellers’ Representative (a “Title Defect Notice”) promptly after the discovery thereof, but in no event later than thirty (30) days after the Execution Date (such cut-off date, the “Title Claim Date”). To be effective, each Title Defect Notice shall be in writing and include (i) a description of the alleged Title Defect that is reasonably sufficient for Sellers’ Representative to determine the basis of the alleged Title Defect (including, if applicable, the Seller(s) affected by such Title Defect), (ii) if the Title Defect is an Environmental Defect, the Asset(s) adversely affected by such Title Defect and if the Title Defect is anything other than an Environmental Defect, the Unit (or the interests of the applicable Sellers in such Unit) adversely affected by such Title Defect (in each case, a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) all documents upon which Purchaser relies for its assertion of a Title Defect, including, at a minimum, supporting documents reasonably necessary for Sellers’ Representative (as well as any title attorney or examiner hired by Sellers’ Representative) to verify the existence of the alleged Title Defect and (v) the amount by which Purchaser reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect and the computations and information upon which Purchaser’s belief is based, including any analysis by any title attorney or examiner hired by Purchaser (or, in the case of an Environmental Defect, any environmental remediation analysis prepared by or for Purchaser). For the avoidance of doubt, an Environmental Defect shall be deemed to affect all Sellers with an interest in the Assets affected by such Environmental Defect.

(k) Each Seller (acting solely through Sellers’ Representative) shall have the right, but not the obligation, to attempt, at its sole cost, to cure or remove on or before 120 days after the Title Claim Date (the “Cure Period”) any Title Defects (other than Environmental Defects for which this Section 4.2(b) shall not apply) for which a Title Defect Notice from Purchaser has been delivered to Sellers’ Representative prior to the Title Claim Date, and Purchaser shall take all actions reasonably requested by Sellers’ Representative to assist any Seller electing to cure with the cure or removal of any such Title Defects. No reduction shall be made to the Closing Payment for such Seller with respect to any Title Defect for which such Sellers’ Representative has provided notice to Purchaser prior to or on the Closing Date that such Seller intends to attempt to cure the Title Defect during the Cure Period (a “Remedy Notice”) or for which a Seller (acting solely through Sellers’ Representative) disputes the existence (a “Disputed Defect”). If any Title Defect with respect to which Sellers’ Representative has provided a Remedy Notice to Purchaser is not cured within the Cure Period, such Title Defect shall be handled in accordance with Section 4.2(c); provided, however, that any downward adjustments to the affected Unadjusted Purchase Price for such Seller made pursuant to Section 4.2(c) shall occur at the times set forth in Section 9.4; and provided, further, that if, prior to 130 days after the Title Claim Date (the “Remedy Deadline”), the Purchaser and Sellers’ Representative cannot agree on (i) the proper and adequate cure for any such Title Defect, (ii) the Title Defect Amount or (iii) whether the alleged Title Defect constitutes a Title Defect, such dispute(s) shall be finally and exclusively resolved in accordance with the provisions of Section 4.4. An election by a Seller (acting solely through Sellers’ Representative) to attempt to cure a Title Defect shall be without prejudice to its rights under Section 4.4 and shall not constitute an admission against interest or a waiver of such Seller’s right (acting solely through Sellers’ Representative) to dispute the existence, nature or value of, or cost to cure, the alleged Title Defect. Any Disputed Defects that have not been cured, waived or otherwise resolved by the Purchaser and Sellers’ Representative prior to the Remedy Deadline shall be exclusively and finally resolved in accordance with the provisions of Section 4.4. For any Title Defect Notices delivered by Purchaser hereunder that are identical to Title Defect Notices delivered to Helis under the Helis PSA, the actions taken by Helis to cure or remove such Title Defects shall benefit Sellers in proportion to their interests in the Assets affected, to the extent such actions cure or remove such Title Defect.

(l) Subject to Section 4.2(e) regarding certain Environmental Defects, in the event that any Title Defect is not waived by Purchaser or, subject to Section 4.2(b), not cured prior to the expiration of the Cure Period or Environmental Cure Period, as applicable, subject to the Individual Defect Threshold and the Aggregate Defect Deductible:

(i) unless Purchaser and Sellers’ Representative make an election pursuant to Section 4.2(c)(ii)(A) or (B) or Sellers’ Representative makes an election pursuant to Section 4.2(c)(ii)(C) (if applicable), there shall be a downward adjustment made to the applicable Unadjusted Purchase Price(s) of the affected Seller(s) equal to an amount determined (the “Title Defect Amount”) pursuant to Section 4.2(d) as being the value of such Title Defect; or

(ii) (A) at the election of Purchaser and Sellers’ Representative, in the case of a Title Defect that is not an Environmental Defect, exclude or have Purchaser

reconvey, as applicable, the Title Defect Property that is adversely affected by such Title Defect;

(B) at the election of Purchaser and Sellers’ Representative, in the case of an Environmental Defect for which the asserted Title Defect Amount is less than the Allocated Value of the Title Defect Property, exclude the applicable Title Defect Property from the Assets; or

(C) in the case of a Title Defect that is an Environmental Defect for which the asserted Title Defect Amount is equal to or greater than the Allocated Value of such Title Defect Property, in Sellers’ Representative’s sole discretion, exclude the Title Defect Property from the Assets;

in any of which events the applicable Unadjusted Purchase Prices of the affected Sellers (which, for the avoidance of doubt, in the case of an Environmental Defect shall mean all Sellers with interests in such affected Asset) shall be adjusted downward, by an amount equal to the Allocated Value of such Title Defect Property and such Title Defect Property shall no longer be included within the definition of Assets for any purpose under this Agreement. Notwithstanding anything in this Agreement to the contrary, if any property is excluded from the Helis Transaction, Sellers’ interests in the same property shall be excluded from this Agreement with the same consequences as set forth in the preceding sentences.

Notwithstanding the foregoing provisions of this Section 4.2(c), no reduction shall be made in the Unadjusted Purchase Prices with respect to any Title Defect for which the applicable Parties agree to execute and deliver to one another a written indemnity agreement, under which all of the applicable Sellers agree to fully, unconditionally and irrevocably indemnify and hold harmless Purchaser from any and all Damages arising out of or resulting from such Title Defect. Upon the election of the remedy of a Title Defect pursuant to this Section 4.2(c), the Parties shall complete any further reconveyancing (or conveyancing in the case of an Environmental Defect Hold-Back Property) of the relevant Title Defect Property as is necessary to effect such remedy. In the case of any such reconveyancing, Purchaser shall assign the relevant Title Defect Property to the applicable Sellers with a special warranty of title, subject to the Permitted Encumbrances, by, through and under Purchaser. Any post-Closing conveyance of an Environmental Defect Hold-Back Property shall be effected by the execution of an Assignment in the form set forth on Exhibit B, and such Environmental Defect Hold-Back Property shall, from and after the date of such conveyance, be deemed to be an Asset for all purposes of this Agreement. Any downward adjustments to the Unadjusted Purchase Price pursuant to this Section 4.2 shall be made (and accounted for) at the times set forth in Section 9.4.

(m) The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of the Title Defect Property adversely affected by such Title Defect is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following methodology, terms and conditions:

(i) if Purchaser and the affected Sellers (acting solely through Sellers’ Representative) agree on the Title Defect Amount, that amount shall be the Title Defect Amount;

(ii) if the Title Defect is a lien, encumbrance or other charge that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the affected Sellers’ interest in the affected Title Defect Property;

(iii) if the Title Defect reflects a discrepancy (with a proportional decrease in the working interest for the affected Title Defect Property) between (A) the Net Revenue Interest for the affected Title Defect Property and (B) the Net Revenue Interest stated in Schedule 3.4 then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property multiplied by a fraction, the numerator of which is the amount of the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest stated in Schedule 3.4;

(iv) if the Title Defect is an Environmental Defect, the Title Defect Amount shall be the amount of the estimated costs and expenses to correct or remediate the Environmental Defect (as of the Closing Date) in such a manner that is consistent with applicable Environmental Laws;

(v) if the Title Defect represents an obligation, encumbrance, burden or charge upon or other defect in title to the Title Defect Property of a type not described in subsections (ii), (iii) or (iv) above, the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property adversely affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Purchaser and the affected Sellers and such other factors as are necessary to make a proper evaluation; provided, however, that, the foregoing considerations notwithstanding, in the event that the Title Defect is reasonably susceptible of being cured, the Title Defect Amount shall not be greater than the reasonable cost and expense of curing or remediating, as applicable, such Title Defect;

(vi) the Title Defect Amount with respect to a Title Defect shall be determined without duplication of any costs or losses included in any other Title Defect Amount hereunder, or for which Purchaser otherwise receives credit in the calculation of the Adjusted Purchase Price; and

(vii) notwithstanding anything to the contrary in this Article 4, the aggregate Title Defect Amounts attributable to the effects of all Title Defects (other than Environmental Defects) upon any Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

(n) (i) Notwithstanding anything to the contrary in this Section 4.2:


(A)	with respect to alleged Environmental Defects (for which the asserted Title Defect Amount is in excess of the Individual Defect Threshold) for which Purchaser and Sellers’ Representative have not, prior to the Closing, agreed to a Title Defect Amount (in accordance with Section 4.2(d)(iv)) or for which, prior to Closing, the Title Defect Amount has not been determined pursuant to Section 4.4;


(B)	in the event the Purchaser and Sellers’ Representative have not, prior to Closing, agreed that an alleged Environmental Defect constitutes a Title Defect;


(C)	with respect to alleged Environmental Defects for which the asserted Title Defect Amount is less than the Allocated Value of the Title Defect Property and an election has been made to exclude such Title Defect Property pursuant to Section 4.2(c);


(D)	with respect to an alleged Environmental Defect for which the asserted Title Defect Amount is equal to or greater than the Allocated Value of the Title Defect Property and Sellers’ Representative has made an election to exclude pursuant to Section 4.2(c); or


(E)	with respect to any alleged Environmental Defect for which Sellers’ Representative has provided notice to Purchaser prior to or on the Closing Date that one or more Sellers intend to cure or remove the Environmental Defect on or before 180 days after the Title Claim Date (the “Environmental Cure Period”),

the affected Title Defect Property that is subject to such alleged Environmental Defect (an “Environmental Defect Hold-Back Property”) shall (X) not be included in the Assets at Closing, and (Y) the Unadjusted Purchase Prices of all Sellers with an interest in such affected Assets shall be (in proportion to each Seller’s applicable Seller’s Title Defect Percentage) adjusted downward by an amount equal to the Allocated Value of such Environmental Defect Hold-Back Property (and, if not already reflected in the Preliminary Settlement Statement prepared prior to Closing pursuant to Section 9.4(b), the Allocated Value of such Environmental Defect Hold-Back Property shall be excluded from the Closing Payments payable to each Seller at Closing). For any Environmental Defect Notices delivered by Purchaser hereunder that are identical to Environmental Defect Notices delivered to Helis under the Helis PSA the actions taken by Helis to cure or remove such Environmental Defects shall benefit Sellers in proportion to their interests in the Assets affected.

(i) During the Environmental Cure Period, Sellers (acting solely through Sellers’ Representative) shall have the right, but not the obligation, at their sole cost, to cure or remove the Environmental Defect affecting any Environmental Defect Hold-Back Property, in which case Sellers shall release and indemnify Purchaser Group in accordance with Section 7.1, applied mutatis mutandis, if any of the Sellers Group (including the

Operator and its Representatives) access Purchaser’s property in their attempts to cure or remove the Environmental Defect affecting an Environmental Defect Hold-Back Property. Any Environmental Defect Hold-Back Property for which the Environmental Defect is cured or removed during the Environmental Cure Period shall promptly thereafter be conveyed from Sellers to Purchaser, provided that if the Parties cannot agree on the proper and adequate cure for an Environmental Defect or that an Environmental Defect has been cure or removed, such dispute shall be finally and exclusively resolved in accordance with the provisions of Section 4.4.

(ii) If an Environmental Defect affecting any Environmental Defect Hold-Back Property is not cured or removed by Sellers within the Environmental Cure Period, then the Purchaser and Sellers’ Representative or Sellers’ Representative, as applicable, shall determine the remedy with respect to such Environmental Defect pursuant to Section 4.2(c) no later than 10 days after the end of the Environmental Cure Period;

(iii) If any conveyance of an Environmental Defect Hold-Back Property is completed prior to the Final Settlement Statement Date, then the Unadjusted Purchase Price shall be adjusted upward by an amount equal to the Allocated Value of such conveyed Environmental Defect Hold-Back Property and further adjusted as applicable for the adjustments set forth in Section 3.3 that relate to such Environmental Defect Hold-Back Property. If any conveyance of an Environmental Defect Hold-Back Property is completed after the Final Settlement Statement Date, then Purchaser shall pay to Sellers (proportional to each Seller’s applicable Seller’s Title Defect Percentages applicable to such Environmental Defect Hold-Back Property) an amount equal to the Allocated Value of such conveyed Environmental Defect Hold-Back Property, adjusted as applicable for the adjustments set forth in Section 3.3 that relate to such Environmental Defect Hold-Back Property.

(f) It is understood and agreed that Environmental Defects shall constitute Title Defects for purposes of this Agreement (as is provided in the definition of “Title Defects” set forth in Appendix A) and, as such, will be handled in accordance with, and in all instances will be subject to, the provisions of this Section 4.2 (other than Section 4.2(b) and Section 4.2(d)(vii) which shall not apply to Environmental Defects) and the other applicable provisions of this Article 4 (including the thresholds and deductibles set forth in Section 4.5). For the avoidance of doubt, the Aggregate Defect Deductible is a single amount which includes both Title Defects and Environmental Defects. Without limiting the disclaimers and acknowledgements set forth in Article 5 and Article 6, respectively, PURCHASER HEREBY WAIVES AND RELEASES ANY REMEDIES OR CLAIMS (WHETHER AT LAW OR IN EQUITY) THAT IT MAY HAVE AGAINST SELLERS, THEIR AFFILIATES OR ANY OTHER MEMBER OF THE SELLERS GROUP UNDER APPLICABLE LAWS WITH RESPECT TO ENVIRONMENTAL DEFECTS, EXCEPT SOLELY FOR THOSE REMEDIES SET FORTH IN THIS ARTICLE 4 AND SECTION 11.2(B)(IV).

Section 4.3 Title Benefits.

(c) Sellers’ Representative has the right, but not the obligation, to deliver to Purchaser on or before the Title Claim Date with respect to each Title Benefit discovered by Sellers’ Representative a notice (a “Title Benefit Notice”) in writing and including (i) a description of the Title Benefit reasonably sufficient to determine the basis of the alleged Title Benefit (including, if applicable, the Seller(s) affected by such Title Benefit), (ii) the Unit affected by such Title Benefit (a “Title Benefit Property”), (iii) the Allocated Value of each Title Benefit Property, (iv) all documents upon which Sellers’ Representative relies for its assertion of a Title Benefit, including, at a minimum, supporting documents reasonably necessary for Purchaser (as well as any title attorney or examiner hired by Purchaser) to verify the existence of the alleged Title Benefit and (v) the amount by which Sellers’ Representative reasonably believes the Allocated Value of each Title Benefit Property is increased by such Title Benefit and the computations and information upon which Sellers’ Representative’s belief is based on or before the Title Claim Date with respect to each Title Benefit discovered by any Seller. If Helis delivers a Title Benefit Notice to Purchaser for Assets in which Sellers own interests, Sellers shall be deemed to have delivered to Purchaser an identical Title Benefit Notice covering their respective interests in such Assets, as applicable, and Sellers shall be entitled to receive the benefits of any Title Benefit Amount to which Helis establishes its entitlement, pursuant to the Helis PSA, proportionate to the interest of each Seller in the affected Asset.

(d) Subject to the Individual Benefit Threshold and the Aggregate Benefit Deductible, with respect to each Title Benefit Property affected by Title Benefits reported under Section 4.3(a), the Unadjusted Purchase Prices of the affected Sellers shall be increased by an amount (the “Title Benefit Amount”) equal to the increase in the Allocated Value for such Title Benefit Property, as determined pursuant to Section 4.3(c). Any upward adjustments to the Unadjusted Purchase Prices pursuant to this Section 4.3 shall be made (and accounted for) at the times set forth in Section 9.4.

(e) The Title Benefit Amount resulting from a Title Benefit shall be the amount by which the Allocated Value of the Title Benefit Property affected by such Title Benefit is increased as a result of the existence of such Title Benefit and shall be determined in accordance with the following methodology, terms and conditions:

(i) if Purchaser and Sellers’ Representative agree on the Title Benefit Amount, that amount shall be the Title Benefit Amount;

(ii) if the Title Benefit reflects a difference (with a proportional increase in the working interest for the affected Title Defect Property) between (A) the Net Revenue Interest for the affected Title Benefit Property and (B) the Net Revenue Interest stated in Schedule 3.4, then the Title Benefit Amount shall be the product of the Allocated Value of such Title Benefit Property multiplied by a fraction, the numerator of which is the amount of the Net Revenue Interest increase of the affected Seller(s) and the denominator of which is the Net Revenue Interest of such Seller(s) stated in Schedule 3.4; and

(iii) if the Title Benefit represents a benefit in the ownership or title to the Title Benefit Property of a type not described in subsections (i) or (ii) above, the Title Benefit Amount shall be determined by taking into account the Allocated Value of the Title Benefit

Property, the portion of the Title Benefit Property benefitted by the Title Benefit, the legal effect of the Title Benefit, the potential economic effect of the Title Benefit over the life of the Title Benefit Property, the values placed upon the Title Benefit by Purchaser and the affected Sellers, the affected Sellers’ interest in the Property affected, and such other factors as are necessary to make a proper evaluation.

(f) If the Purchaser and Sellers’ Representative cannot reach an agreement on alleged Title Benefits and Title Benefit Amounts by the scheduled Closing, the provisions of Section 4.4 shall apply.

Section 4.4 Title Disputes. The Parties (with Sellers acting solely through Sellers’ Representative) shall attempt to agree on all Title Defects and Title Benefits and Title Defect Amounts and Title Benefit Amounts, respectively, prior to Closing. To the extent Title Defects and Title Benefits and Title Defect Amounts and Title Benefit Amounts affect Assets in which Helis also owns interests, Sellers and Purchaser shall be bound by any resolution of such matters effected under the Helis PSA, except as otherwise set forth in this Section 4.4. Should any Seller provide notice of disagreement, such Seller shall be entitled to take such action as permitted under this Agreement with respect to such Title Defect to the extent it affects such Seller’s interest in the Properties, including, to the extent permitted by Helis, the participation in resolution of any Disputed Title Matters between Helis and Purchaser by a Title Arbitrator under the Helis PSA regarding such matter (but not in any separate or subsequent proceeding by a Title Arbitrator, it being agreed that any resolution of a Disputed Title Matter by a Title Arbitrator under the Helis PSA will be binding on each Seller to the extent such resolution affects its interests in the affected Properties, whether or not such Seller participates in the arbitration). Each Seller shall reimburse Helis for its proportionate shares, subject to the preceding sentence, of any out of pocket costs and legal fees incurred by Helis in submitting Disputed Title Matters to the Title Arbitrator; provided that if a Seller participates in the arbitration such Seller shall pay for its own costs and legal fees related to the arbitration of Disputed Title Matters and its proportionate share of the costs of the arbitrators of Disputed Title Matters, but shall not be required to reimburse Helis for its proportionate share of any out of pocket costs and legal fees incurred by Helis in submitting Disputed Title Matters to the Title Arbitrator. Subject to the foregoing, if Purchaser and Sellers’ Representative are unable to agree on Title Defects and Title Benefits and Title Defect Amounts and Title Benefit Amounts, respectively, by the scheduled Closing, then Sellers’ Representative’s good faith estimate shall be used to determine the Closing Payment pursuant to Section 9.4. If, after the Remedy Deadline, the Purchaser and Sellers’ Representative are unable to agree on an alleged Title Defect or Title Benefit or Title Defect Amount or Title Benefit Amount (the “Disputed Title Matters”) such dispute(s), and only such dispute(s), shall be exclusively and finally resolved in accordance with the following provisions of this Section 4.4. Purchaser shall provide to Sellers’ Representative by not later than the tenth (10^th) Business Day following the Remedy Deadline a written description meeting the requirements of Section 4.2(a) or Section 4.3(a), as applicable, together with all supporting documentation, of the Disputed Title Matters. By not later than ten (10) Business Days after Sellers’ Representative’s receipt of Purchaser’s written description of the Disputed Title Matters, Sellers’ Representative shall provide to Purchaser a written response setting forth Sellers’ Representative’s position with respect to the Disputed Title Matters together with all supporting documentation.

(a) By not later than ten (10) Business Days after Purchaser’s receipt of Sellers’ Representative’s written response to Purchaser’s written description of the Disputed Title Matters, Purchaser may initiate a non-administered arbitration of any such dispute(s) conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent that such rules do not conflict with the terms of this Section 4.4, by written notice (the “Title Arbitration Notice”) to Sellers’ Representative of any Disputed Title Matters not otherwise resolved or waived that are to be resolved by arbitration (“Final Disputed Title Matters”).

(b) The arbitration shall be held before a one member arbitration panel (the “Title Arbitrator”), determined as follows. The Title Arbitrator shall be an attorney with at least ten (10) years’ experience (i) in the case of Title Defects other than Environmental Defects, examining oil and gas titles in the State of North Dakota and (ii) in the case of Environmental Defects, as an environmental attorney practicing in the State of North Dakota. Within two (2) Business Days following Sellers’ Representative’s receipt of the Title Arbitration Notice, Sellers’ Representative and Purchaser shall each exchange lists of three (3) acceptable, qualified arbitrators. Within two (2) Business Days following the exchange of lists of acceptable arbitrators, the Purchaser and Sellers’ Representative shall select by mutual agreement the Title Arbitrator from their original lists of three (3) acceptable arbitrators. If no such agreement is reached within seven (7) Business Days following the delivery of Title Arbitration Notice, the Houston, Texas office of the American Arbitration Association shall select an arbitrator from the original lists provided by the Purchaser and Sellers’ Representative to serve as the Title Arbitrator.

(c) Within three (3) Business Days following the selection of the Title Arbitrator, the Purchaser and Sellers’ Representative shall submit one copy to the Title Arbitrator of (i) this Agreement, with specific reference to this Section 4.4 and the other applicable provisions of this Article 4, (ii) Purchaser’s written description of the Final Disputed Title Matters, together with the supporting documents that were provided to Seller, (iii) Sellers’ Representative’s written response to Purchaser’s written description of the Final Disputed Title Matters, together with the supporting documents that were provided to Purchaser and (iv) the Title Arbitration Notice. The Title Arbitrator shall resolve the Final Disputed Title Matters based only on the foregoing submissions, and shall select either the position of Sellers’ Representative or Purchaser with respect to each Final Disputed Title Matter. Neither Purchaser nor Sellers’ Representative (nor any of the Sellers individually) shall have the right to submit additional documentation to the Title Arbitrator nor to demand discovery on the other Party.

(d) The Title Arbitrator shall make its determination by written decision within thirty (30) days following Sellers’ Representative’s receipt of the Title Arbitration Notice (the “Arbitration Decision”). The Arbitration Decision shall be final and binding upon the Parties, without right of appeal. In making its determination, the Title Arbitrator shall be bound by the provisions of this Article 4. The Title Arbitrator may consult with and engage disinterested Third Parties to advise the Title Arbitrator, but shall disclose to the Parties the identities of such consultants and shall only use such Third Parties to the extent necessary to resolve the Final Disputed Title Matters. Any such consultant shall not have worked as an employee or consultant for either Party or its Affiliates during the five (5) year period preceding the arbitration nor have any financial interest in the dispute.

(e) The Title Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Title Defects and Title Defect Amounts or Title Benefits and Title Benefit Amounts and shall not be empowered to award damages, interest or penalties to either Party with respect to any matter.

(f) Each Party shall each bear its own legal fees and other costs of preparing and presenting its case. Sellers’ Representative on behalf of the affected Sellers shall bear one-half and Purchaser shall bear one-half of the costs and expenses of the Title Arbitrator, including any costs incurred by the Title Arbitrator that are attributable to the consultation of any Third Party.

(g) The Parties shall implement the Arbitration Decision as follows: (i) in the case of alleged Title Defects determined to be Title Defects, such Title Defects shall be remedied pursuant to Section 4.2(c) within ten (10) Business Days following Sellers’ Representative’s receipt of the Arbitration Decision (with any amounts owed, as a result of such remedy, to be made and accounted for at the times set forth in Section 9.4(d)), and (ii) in the case of disputed Title Benefits, Title Benefit Amounts or Title Defect Amounts, any amounts determined to be owed by any Party shall be accounted for in the determination of the Adjusted Purchase Price pursuant to Section 9.4(d). Any alleged Title Defects or Title Benefits determined not to be Title Defects or Title Benefits under the Arbitration Decision shall be final and binding as not being Title Defects or Title Benefits. The Parties shall complete any reconveyancing of property as is necessary to effect the remedy determined pursuant to subsection (i) above. In the case of any such reconveyancing, Purchaser shall assign the relevant Lease or Well to the affected Sellers with a special warranty of title, subject to no burdens, liens or encumbrances other than the Permitted Encumbrances, by, through and under Purchaser.

(h) Any dispute over the interpretation or application of this Section 4.4 shall be decided by the Title Arbitrator with reference to the Laws of the State of Texas.

Section 4.5 Limitations on Applicability.

(a) The right of Purchaser or Sellers (through Sellers’ Representative or otherwise) to assert a Title Defect or Title Benefit, respectively, under this Article 4 shall terminate on the Title Claim Date, except that until the alleged Title Defect or Title Benefit or Title Defect Amount or Title Benefit Amount, as applicable, is resolved in accordance with this Agreement, there shall be no termination of Purchaser’s or Sellers’ Representative’s rights under this Article 4 with respect to any alleged Title Defect or Title Benefit or Title Defect Amount or Title Benefit Amount properly reported in accordance with Section 4.4 on or before the Title Claim Date. Thereafter, Purchaser’s and Sellers’ sole and exclusive rights and remedies with regard to title to the Assets shall be as set forth in the respective Assignments. Without limiting the foregoing, if a Title Defect under this Article 4 results from any matter that could also result in the breach of any representation or warranty of Sellers as set forth in Article 5 or a breach of Sellers’ special warranty of title in the Assignments, and Purchaser has knowledge of such matter prior to the Title Claim Date, Purchaser shall only be entitled to assert such matter as a Title Defect to the extent permitted by Article 4; and, for the avoidance of doubt, Purchaser shall be precluded from also asserting any such matter as the basis of the breach of any such representation or warranty or as a claim against Sellers’ special warranty of title provided in the Assignments.

(b) Notwithstanding anything to the contrary in this Agreement, in no event shall there be any adjustments to the Unadjusted Purchase Prices or other remedies available in respect of Title Defects (including Title Defects constituting Environmental Defects) or Title Benefits, under this Article 4:

(i) With respect to Title Defects, in the case of each Seller (A) for any Title Defect Amount affecting such Seller with respect to an individual Title Defect Property if such amount does not exceed such Seller’s applicable Seller’s Title Defect Percentage, multiplied by One Hundred Thousand Dollars ($100,000) (for each such Seller, the “Individual Defect Threshold” applicable to such Seller), provided that, Purchaser shall be entitled to recover the full Title Defect Amount once the Individual Defect Threshold is met, subject to the Aggregate Defect Deductible; and (B) unless the amount of all such Title Defect Amounts (provided that each such Title Defect Amount exceeds the applicable Individual Defect Threshold), in the aggregate (excluding any Title Defect Amounts with respect to Title Defects cured or indemnified by Seller in accordance with this Article 4) exceeds two and one-half percent (2.5%) of such Seller’s Unadjusted Purchase Price (for each such Seller, the “Aggregate Defect Deductible” applicable to such Seller), after which point, subject to the Individual Defect Threshold, Purchaser shall be entitled to adjustments to the applicable Unadjusted Purchase Price or other remedies in accordance with Section 4.2(c) only with respect to Title Defect Amounts in excess of such Aggregate Defect Deductible and only to the extent that Title Defect Amounts exceed the Aggregate Defect Deductible. Notwithstanding the foregoing, Title Defects which would otherwise constitute breaches of the special warranty of title set forth in the Assignments but which are asserted prior to the Title Claim Date shall not be subject to the Individual Defect Thresholds or the Aggregate Defect Deductibles.

(ii) With respect to Title Benefits, in the case of each Seller (A) for any Title Benefit Amount affecting such Seller with respect to an individual Title Benefit Property: if such amount does not exceed such Seller’s applicable Seller’s Title Defect Percentage, multiplied by One Hundred Thousand Dollars ($100,000) (for each such Seller, the “Individual Benefit Threshold” for such Seller), provided that, Seller shall be entitled to recover the full Title Benefit Amount once the Individual Benefit Threshold is met, subject to the Aggregate Benefit Deductible; and (B) unless the amount of all such Title Benefit Amounts (provided that each such Title Benefit Amount exceeds the Individual Benefit Threshold), in the aggregate exceeds two and one-half percent (2.5%) of such Seller’s Unadjusted Purchase Price (for each Seller, the “Aggregate Benefit Deductible” applicable to such Seller), after which point, subject to the Individual Benefit Threshold, such Seller shall be entitled to adjustments to its Unadjusted Purchase Price only with respect to Title Benefit Amounts in excess of such Aggregate Benefit Deductible and only to the extent that Title Benefit Amounts exceed the Aggregate Benefit Deductible.

(c) Without prejudice to any of the other dates by which performance or the exercise of rights is due hereunder, or the Parties’ rights or obligations in respect thereof, the Parties hereby acknowledge that, as set forth more fully in Section 13.14, time is of the essence in performing their obligations and exercising their rights under this Article 4, and, as such, that each and every

date and time by which such performance or exercise is due shall be the firm and final date and time.

Section 4.6 Consents to Assignment and Preferential Rights to Purchase.

(a) The following terms of this Section 4.6 shall apply only to the extent they are not addressed pursuant to the Helis PSA. To the extent matters covered by this Section 4.6 are resolved under the Helis PSA, the same resolution shall be deemed to apply to Sellers and Purchaser under this Agreement, with respect to the interests of Sellers in the affected Assets.

(b) Promptly after the Execution Date, Sellers (or Sellers’ Representative) shall prepare and send (i) notices to the holders of any required consents to assignment (including the Specified Consent Requirements that are set forth on Schedule 5.16) requesting consents to the Assignments; (ii) notices to the holders of any applicable preferential rights to purchase or similar rights (including rights to purchase or similar rights arising in connection with change in control provisions) (collectively, “Preferential Rights”) that are set forth on Schedule 5.16 in compliance with the terms of such rights and requesting waivers of such rights; and (iii) upon Purchaser’s review and written request, notices under each Contract and for each interest described under Section 2.2(g) or Section 2.2(i) for which consent or a waiver is required from a counterparty or under applicable Law in order to transfer, assign or amend such Contract. Each Seller shall use Commercially Reasonable Efforts to cause such consents and waivers of Preferential Rights (or the exercise thereof), to be obtained and delivered prior to Closing with respect to such Seller’s interest in the affected Property or Consent. Purchaser shall cooperate with Sellers and Sellers’ Representative in seeking to obtain such consents to assignment and waivers of Preferential Rights. Any Preferential Right must be exercised subject to all terms and conditions set forth in this Agreement, including the successful Closing of this Agreement pursuant to Article 9 as to those Assets for which Preferential Rights have not been exercised. The consideration payable under this Agreement for any particular Asset for purposes of Preferential Right notices shall be the Allocated Value for such Asset, subject to adjustment pursuant to Section 3.3. If, prior to the Closing Date, any Party discovers any required consents or Preferential Rights (applying to the Assets) for which notices have not been delivered pursuant to the first sentence of this Section 4.6(b), then (A) the Party making such discovery shall provide the other Parties with written notification of such consents or Preferential Rights, as applicable, (B) Sellers (or Sellers’ Representative), following delivery or receipt of such written notification, will promptly send notices to the holders of such required consents requesting consents and notices to the holders of such Preferential Rights in compliance with the terms of such rights and requesting waivers of such rights and (C) the terms and conditions of this Section 4.6 shall apply to the Assets subject to such consents or Preferential Rights, as applicable.

(c) In no event shall there be included in the Assignments any Asset for which a Specified Consent Requirement has not been satisfied. In cases in which the Asset subject to such a requirement is a Contract and Purchaser is assigned the Property or Properties to which the Contract relates, but the Contract is not transferred to Purchaser due to the unwaived Specified Consent Requirement, (i) each Seller (as applicable) shall continue after Closing to use Commercially Reasonable Efforts to satisfy the Specified Consent Requirement so that such Contract can be transferred to Purchaser upon receipt of the Specified Consent Requirement, (ii) the Contract shall be held by Sellers (as applicable) for the benefit of Purchaser until the Specified Consent

Requirement is satisfied or the Contract has terminated and (iii) Purchaser shall pay all amounts due thereunder, perform all obligations thereunder and indemnify the applicable Sellers against any Damages incurred or suffered by such Sellers as a consequence of remaining a party to such Contract until the Specified Consent Requirement is satisfied or the Contract has terminated. In cases in which the Asset subject to such a Specified Consent Requirement is a Property and such consent is not satisfied by Closing, the affected Property and the Assets related to that Property shall not be transferred at Closing and the Unadjusted Purchase Price(s) shall be reduced by the Allocated Value of the Property and related Assets, provided that each Seller (as applicable) shall continue after Closing to use Commercially Reasonable Efforts to satisfy the Specified Consent Requirement so that such Property and the Assets related to the Property can be transferred to Purchaser upon receipt of the Specified Consent Requirement, subject to the remainder of this Section 4.6(c). If an unsatisfied Specified Consent Requirement with respect to which an adjustment to the Unadjusted Purchase Price(s) is made under Section 3.3 is subsequently satisfied prior to the date of delivery of the final settlement statement under Section 9.4(d), a separate closing shall be held within five (5) Business Days thereof at which (i) the applicable Sellers shall convey the affected Property and related Assets to Purchaser in accordance with this Agreement and (ii) Purchaser shall pay an amount equal to the Allocated Value of such Property and related Assets, adjusted in accordance with Section 3.3, to the applicable Sellers (in proportion to their Seller’s Title Defect Percentages). If such consent requirement is not satisfied by the date of delivery of the final settlement statement, Sellers shall have no further obligation to sell and convey such Property and related Assets and Purchaser shall have no further obligation to purchase, accept and pay for such Property, and the affected Property and related Assets shall be deemed to be deleted from Exhibit A‑1, Exhibit A‑2, Schedule 3.4 and the other applicable Exhibits and Schedules to this Agreement for all purposes.

(d) If any Preferential Right affecting an Asset is exercised prior to Closing, the Unadjusted Purchase Price(s) shall be decreased by the Allocated Value for such Assets, and the affected Assets shall be deemed to be deleted from Exhibit A-1, Exhibit A-2, Schedule 3.4 and the other applicable Exhibits and Schedules to this Agreement for all purposes. Sellers shall retain the consideration paid by the Third Party, and shall have no further obligation with respect to such affected Assets under this Agreement. Should a Third Party fail to exercise its Preferential Right as to any portion of the Assets prior to Closing and the time for exercise or waiver has not yet expired, the affected Assets shall not be transferred at Closing and the Unadjusted Purchase Price(s) shall be reduced by the Allocated Values of such Assets. In the event that such Third Party exercises its Preferential Right following the Closing, Sellers shall have no further obligation to sell and convey the affected Assets and Purchaser shall have no further obligation to purchase, accept and pay for such affected Assets, and the affected Assets shall be deemed to be deleted from Exhibit A-1, Exhibit A-2, Schedule 3.4 and the other applicable Exhibits and Schedules to this Agreement for all purposes. If, on the other hand, the applicable Preferential Rights are waived or expire, a separate closing shall be held within five (5) Business Days thereof at which (i) the applicable Sellers shall convey the affected Assets to Purchaser in accordance with this Agreement and (ii) Purchaser shall pay an amount equal to the Allocated Value of such Assets, adjusted in accordance with Section 3.3, to the applicable Sellers (in proportion to their Seller’s Title Defect Percentages).

Section 4.7 Casualty or Condemnation Loss.

(a) If, after the Execution Date, but prior to the Closing Date, any portion of the Assets is damaged, destroyed or made unavailable or unusable for the intended purpose by fire or other casualty or is taken in condemnation or under right of eminent domain (each a “Casualty Loss”), and the loss as a result of such individual Casualty Loss exceeds five percent (5%) of the applicable Unadjusted Purchase Price(s), Purchaser shall nevertheless be required to close, and Sellers’ Representative shall elect by written notice to Purchaser prior to Closing either (i) to cause the Assets adversely affected by any such individual Casualty Loss to be repaired or restored to at least their condition prior to such Casualty Loss, at the applicable Sellers’ sole cost and expense, as promptly as reasonably practicable (which work may extend after the Closing Date), (ii) to indemnify Purchaser against any costs or expenses that Purchaser reasonably incurs to repair or restore the Assets subject to any such Casualty Loss or (iii) to exclude the affected Assets from this Agreement and reduce the applicable Unadjusted Purchase Price(s) by the Allocated Value of such Assets. In each case, Sellers shall retain all rights to insurance, unpaid awards, condemnation payments and other rights and claims against Third Parties with respect to the Casualty Loss, except to the extent the Parties otherwise agree in writing.

(b) If, after the Execution Date, but prior to the Closing Date, any Casualty Loss occurs, and the loss as a result of such individual Casualty Loss is five percent (5%) or less of the applicable Unadjusted Purchased Price(s), Purchaser shall nevertheless be required to close and Sellers shall, at Closing, pay to Purchaser all sums paid to Sellers by Third Parties by reason of such individual Casualty Loss and, to the extent necessary, shall assign, transfer and set over to Purchaser or subrogate Purchaser to all of Sellers’ right, title and interest (if any) in unpaid awards, condemnation payments and other rights and claims against Third Parties (other than Persons within the Sellers Group) arising out of the Casualty Loss.

(c) To the extent a Casualty Loss occurs with respect to Assets which are also covered by the Helis PSA, the Parties shall take such action under this Section 4.7 that is consistent with the action by Helis and Purchaser under the Helis PSA.

ARTICLE 5

REPRESENTATIONS AND WARRANTIES OF SELLER

Section 5.1 Generally.

(o) Any representation or warranty qualified to the “knowledge of Seller” or “to Seller’s knowledge” or with any similar knowledge qualification is limited to matters, with respect to each Seller, within the Actual Knowledge of the individuals listed for such Seller in Schedule 5.1. As used in this Agreement, the term “Actual Knowledge” with respect to any individual means information personally known by such individual.

(p) Inclusion of a matter on a Schedule in relation to a representation or warranty that addresses matters having a Material Adverse Effect shall not be deemed an indication that such matter does, or may, have a Material Adverse Effect. Likewise, the inclusion of a matter on a Schedule to this Agreement in relation to a representation or warranty shall not be deemed an indication that such matter necessarily would, or may, breach such representation or warranty absent

its inclusion on such Schedule. Matters may be set forth on a Schedule for information purposes only.

(q) Subject to the foregoing provisions of this Section 5.1, the disclaimers and waivers contained in and the other terms and conditions of this Agreement, subject to Section 5.1(d) each Seller represents and warrants to Purchaser the matters set forth in Section 5.2 through Section 5.20 as of the Execution Date and on the Closing Date, as applicable (except for the representations and warranties that refer to a specified date which will be deemed made as of such date).

(r) In respect of each representation and warranty made in this Article 5, each Seller, on a several and not a joint or joint and several basis, makes such representations and warranties to Purchaser only as to itself or, as the context so requires, as to (and to the extent of) its interests in the Assets (but not as to the other Sellers or as to their interests in the Assets).

(s) Any reference to Assets in this Article 5 is to Seller Assets, and any reference to Properties in this Article 5 is to Seller’s interest in the Properties.

Section 5.2 Existence and Qualification. Seller is duly organized, validly existing and in good standing under the Laws of its state of incorporation or formation and is duly qualified to do business in the State of North Dakota.

Section 5.3 Power. Seller has the requisite power to enter into and perform this Agreement and to consummate the transactions contemplated by this Agreement.

Section 5.4 Authorization and Enforceability. The execution, delivery and performance of this Agreement and all documents required to be executed and delivered by Seller at Closing, and the performance of the transactions contemplated hereby and thereby, have been duly and validly authorized by all necessary limited liability company, corporate, or partnership action on the part of Seller, as applicable. This Agreement has been duly executed and delivered by Seller (and all documents required hereunder to be executed and delivered by Seller at Closing will be duly executed and delivered by Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Seller, enforceable in accordance with their terms, except as such enforceability may be limited by applicable bankruptcy or other similar Laws affecting the rights and remedies of creditors generally, as well as by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 5.5 No Conflicts. Assuming the receipt of all consents and approvals from Third Parties in connection with the transactions contemplated hereby and the waiver of or compliance with all Preferential Right rights applicable to the transfer of the Assets contemplated hereby, the execution, delivery and performance of this Agreement by Seller, and the transactions contemplated by this Agreement, will not (a) violate any provision of the limited liability company agreement or other organizational documents of Seller, (b) result in default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any material note, bond, mortgage, indenture, license or agreement to which Seller is a party or that affects the Assets, (c) violate any judgment, order, ruling or decree applicable

to Seller as a party in interest, or (d) violate any Laws applicable to Seller or any of the Assets, except any matters described in subsections (b) or (c) above which would not have a Material Adverse Effect.

Section 5.6 Liability for Brokers’ Fees. Purchaser shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Seller or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 5.7 Intellectual Property. Seller owns, or has the licenses or rights to use all material Intellectual Property used in the ownership or operation of the Assets. Seller has not received from any Third Party a claim in writing that Seller is infringing on the Intellectual Property of such Third Party.

Section 5.8 Insurance. To the extent Seller has policies of insurance applicable to the Assets in addition to those maintained by Helis, Seller has made available to Purchaser copies of all such policies of insurance (with redactions of those portions of the policies not applicable to the Assets), which are set forth on Schedule 5.8, and, for recently renewed policies (to the extent applicable to the Assets), binders to which Seller is a party or under which the Assets are covered. Except as set forth in Schedule 5.8, (a) all such policies of insurance to which Seller is a party and which relate to the Assets are valid, outstanding, and enforceable, (b) will continue in full force and effect immediately prior to the Closing and (c) Seller has paid all premiums due, and has otherwise performed all of its obligations, under each policy to which Seller is a party (or that provides coverage to Seller) and which relate to the Assets.

Section 5.9 Litigation. Except as set forth on Schedule 5.9, there are no actions, suits or proceedings pending, or to Seller’s knowledge, threatened in writing, before any Governmental Body or arbitrator with respect to Seller or the Assets that would materially impair Seller’s ability to perform its obligations under this Agreement or that would affect the Assets.

Section 5.10 Payment of Royalties and Rentals. To the knowledge of Seller, all royalties, overriding royalties and other burdens on production that have been paid by Operator or a third party operator, as applicable, on behalf of Seller relating to the Assets have been properly and legally paid before the same became delinquent. With respect to Leases and other agreements, to the knowledge of Seller, all delay rentals and royalties that perpetuate Leases and similar payments under surface use agreements have been properly and legally paid by Operator or a third party operator, as applicable, on behalf of Seller before the same became delinquent.

Taxes and Assessments

(a)To the knowledge of Seller, all Asset Taxes that have become due and payable have been properly paid in full by Helis or other designated operator.

(b)To the knowledge of Seller, all Tax Returns with respect to Asset Taxes that are required to be filed with respect to the Assets have been filed by Helis or other designated operator and all such Tax Returns are true, correct and complete in all material respects.

(c)To the knowledge of Seller, there are no liens for unpaid Taxes against the Assets other than liens for current period Taxes not yet due and payable.

(d)To the knowledge of Seller, except as set forth on Schedule 5.11, no action, suit, Governmental Body proceeding or audit is now in progress or pending with respect to Asset Taxes, and Seller has not received written notice of any pending claim against the Assets from any applicable Governmental Body for assessment of Asset Taxes and to Seller’s knowledge no such claim has been threatened.

(e)Seller has not granted an extension or waiver of the statute of limitations applicable to any Tax Return, which period has not yet expired. No power of attorney that is currently in force has been granted with respect to any matter relating to Asset Taxes that could be binding on Purchaser with respect to the Assets after Closing.

(f)Seller is not a party to or bound by any Tax allocation or Tax sharing or indemnification agreement with respect to the Assets.

(g)Except as disclosed on Schedule 5.11, none of the Assets is held in an arrangement that is classified as, or deemed by law or agreement to be, a partnership for U.S. federal income tax purposes. Any tax partnership set forth on Schedule 5.11 shall have in effect for the taxable year that includes the Closing Date an election under Section 754 of the Code.

(h)To the knowledge of Seller, all of the Assets have been properly listed and described on the property tax rolls for the Tax units in which the Assets are located and no portion of the Assets constitutes omitted property for property tax purposes.

(i)Neither Purchaser nor any of its Affiliates will be held liable for any unpaid Taxes of Seller or with respect to the Assets (other than Asset Taxes for the period from and after the Effective Time) as a successor or transferee, by statute, contract or otherwise.

Section 5.11 Capital Commitments. Except as set forth on Schedule 5.12, as of the Effective Time, there were no outstanding AFEs or other capital commitments to Third Parties received by Seller and currently pending or approved by Seller that were binding on the Assets and could reasonably be expected to require expenditures by the owner of such Assets after the Effective Time in excess of Seller’s proportionate share of $250,000.

Section 5.12 Compliance with Laws. To Seller’s knowledge, Seller has complied with, and the Assets have been operated in, compliance with all applicable Laws in all material respects.

Section 5.13 Contracts. Except as set forth on Schedule 5.14,

To Seller’s knowledge, neither Seller nor Operator is in default under any Contract.

(a) There are no (i) Contracts with Affiliates of Seller or, to Seller’s knowledge, of Operator that will be binding on the Assets after Closing or (ii) hedges, swaps, derivatives or other similar contracts that will be binding on the Assets after Closing.

(b) None of the Properties are subject to or burdened by and, to Seller’s knowledge, Operator is not a party to any Contract with respect to Seller’s operation of the Assets, that can be reasonably expected to result in aggregate payments or receipts of revenue of more than $500,000 annually in the current year or any subsequent year.

(d) None of the Properties are subject to or burdened by any pending farmout agreement, exploration agreement, participation agreement or other similar contract.

(e) There are no material surface use agreements or similar contracts that benefit or burden the Properties.

(f) None of the Properties are subject to or burdened by any (i) operating agreement, transportation, gathering, processing or similar contract or Hydrocarbon sales contract (in each case) that is not terminable without penalty on sixty (60) days’ or less notice or (ii) any indenture, mortgage, loan, credit or sale-leaseback or similar contract that will not be terminated at or prior to the Closing.

Section 5.14 Payments for Production. Except as set forth on Schedule 5.15, Seller is not obligated by virtue of any take-or-pay payment, advance payment or other similar payment (other than royalties, overriding royalties and similar arrangements reflected in the Net Revenue Interest figures set forth on Schedule 3.4; gas balancing arrangements; and non-consent provisions in the Contracts) to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to the Properties at some future time without receiving payment therefor at or after the time of delivery, and, similarly, except as set forth on Schedule 5.15, there are not any Imbalances attributable to the Properties.

Section 5.15 Consents and Preferential Purchase Rights. Except as set forth on Schedule 5.16, to Seller’s knowledge, none of the Properties, or any portion thereof, is subject to any Preferential Right or Specified Consent Requirement that may be applicable to the transactions contemplated by this Agreement, except Customary Post-Closing Consents.

Section 5.16 Properties. To Seller’s knowledge, (a) no default exists in the performance of any obligation of Seller or Operator under the Leases that would entitle the lessor thereunder to cancel or terminate any such Leases, and (b) except as set forth in Schedule 5.17, no party to any Lease or any successor to the interest of such party has filed or threatened in writing to file any action to terminate, cancel, rescind or procure judicial reformation of any such Lease.

Non-Consent Operations

Section 5.17 Bankruptcy. There are no bankruptcy, insolvency, reorganization, receivership or similar proceedings pending against, being contemplated by or, to Seller’s knowledge, threatened against Seller.

Section 5.18 Helis as Operator

No Seller is an operator for any portion of the Assets. Except for Properties operated by a third party operator, Helis is the operator of those Properties in which Helis and Seller both own an interest.

Section 5.19 Certain Disclaimers.

(A) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE 4, THIS ARTICLE 5, IN THE CERTIFICATES OF SELLERS TO BE DELIVERED PURSUANT TO SECTION 9.2(B) OR IN THE ASSIGNMENTS TO BE DELIVERED BY SELLERS TO PURCHASER HEREUNDER, (i) SELLERS MAKE NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (ii) SELLERS EXPRESSLY DISCLAIM ALL LIABILITY AND RESPONSIBILITY FOR ANY STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO THE PURCHASER GROUP (INCLUDING ANY OPINION, INFORMATION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO PURCHASER BY ANY PERSON OF THE SELLERS GROUP).

(B) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE 4, THIS ARTICLE 5, IN THE CERTIFICATES OF SELLERS TO BE DELIVERED PURSUANT TO SECTION 9.2(B) OR IN THE ASSIGNMENTS TO BE DELIVERED BY SELLERS TO PURCHASER HEREUNDER, WITHOUT LIMITING THE GENERALITY OF SECTION 5.21(A), SELLERS EXPRESSLY DISCLAIM ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, ORAL OR WRITTEN, AS TO (i) TITLE TO ANY OF THE ASSETS, (ii) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (iii) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (iv) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (v) THE PRODUCTION OF PETROLEUM SUBSTANCES FROM THE ASSETS, OR WHETHER PRODUCTION HAS BEEN CONTINUOUS OR IN PAYING QUANTITIES, (vi) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS OR (vii) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO THE PURCHASER GROUP IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO (INCLUDING ANY ITEMS PROVIDED IN CONNECTION WITH SECTION 7.1), AND FURTHER DISCLAIM ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT PURCHASER SHALL BE DEEMED TO BE OBTAINING THE EQUIPMENT AND OTHER TANGIBLE PROPERTY INCLUDED AS PART OF THE ASSETS IN ITS PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS, AND THAT, AS OF

CLOSING, PURCHASER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS PURCHASER DEEMS APPROPRIATE.

(C) EXCEPT AS AND TO THE EXTENT EXPRESSLY PROVIDED IN ARTICLE 4 AND SECTION 11.2(B)(IV), SELLERS SHALL NOT HAVE ANY LIABILITY IN CONNECTION WITH AND HAVE NOT AND WILL NOT MAKE (AND HEREBY DISCLAIMS) ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, ENVIRONMENTAL DEFECTS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF HAZARDOUS SUBSTANCES, HYDROCARBONS OR NORM INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND PURCHASER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION.

ARTICLE 6

REPRESENTATIONS AND WARRANTIES OF PURCHASER

Section 6.1 Generally.

(a) Any representation or warranty qualified to the “knowledge of Purchaser” or “to Purchaser’s knowledge” or with any similar knowledge qualification is limited to matters within the Actual Knowledge of the individuals listed in Schedule 6.1.

(b) Purchaser represents and warrants to each Seller the matters set forth in Section 6.2 through Section 6.13 as of the Execution Date and on the Closing Date (except for representations and warranties that refer to a specified date which will be deemed made as of such date); provided, however, that Purchaser’s liability pursuant to Article 11 to any given Seller for a breach of Purchaser’s representations and warranties set forth in this Article 5 shall be limited as to each Seller to such Seller’s applicable Seller’s Interest Percentage of the aggregate Damages resulting as a result of such breach (subject, in each case, to the other limitations of Article 11).

Section 6.2 Existence and Qualification. Purchaser is a Texas corporation, validly existing, and in good standing under the Laws of the State of Texas and is duly qualified to do business in the State of North Dakota.

Section 6.3 Power. Purchaser has the requisite power to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

Section 6.4 Authorization and Enforceability. The execution, delivery and performance of this Agreement and all documents required to be executed and delivered by Purchaser at Closing, and the performance of the transactions contemplated hereby and thereby, have been duly and validly authorized by all necessary limited liability company, corporate or partnership action on the part of Purchaser. This Agreement has been duly executed and delivered by Purchaser (and all documents

required hereunder to be executed and delivered by Purchaser at Closing will be duly executed and delivered by Purchaser) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Purchaser, enforceable in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar Laws affecting the rights and remedies of creditors generally as well as by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 6.5 No Conflicts. The execution, delivery and performance of this Agreement by Purchaser, and the transactions contemplated by this Agreement, will not (a) violate any provision of the certificate of incorporation, bylaws, agreement of limited partnership or other organizational documents of Purchaser, (b) result in a material default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license or agreement to which Purchaser is a party, (c) violate any judgment, order, ruling, or regulation applicable to Purchaser as a party in interest, or (d) violate any Laws applicable to Purchaser or any of its assets, except any matters described in subsections (b), (c) or (d) above which would not have a material adverse effect on Purchaser’s ability to consummate the transactions contemplated herein and to perform its obligations in connection therewith pursuant to the terms hereof.

Section 6.6 Liability for Brokers’ Fees. Sellers shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Purchaser or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 6.7 Litigation. There are no actions, suits or proceedings pending, or to Purchaser’s knowledge, threatened in writing, before any Governmental Body or arbitrator against Purchaser that are reasonably likely to materially impair Purchaser’s ability to perform its obligations under this Agreement or any document required to be executed and delivered by Purchaser at Closing.

Section 6.8 Financing. Purchaser has and will maintain between the Execution Date and Closing sufficient cash, available lines of credit or other sources of immediately available funds (in Dollars) to enable it to pay the Closing Payment to Sellers at the Closing.

Section 6.9 Securities Law Compliance. Purchaser is acquiring the Assets for its own account for use in its trade or business, and not with a view toward or for sale associated with any distribution thereof, nor with any present intention of making a distribution thereof within the meaning of the Securities Act and applicable state securities Laws.

Section 6.10 Independent Evaluation.

(a) Purchaser is knowledgeable of the oil and gas business and of the usual and customary practices of oil and gas producers, including those in the areas where the Assets are located.

(b) Purchaser is a party capable of making such investigation, inspection, review and evaluation of the Assets as a prudent purchaser would deem appropriate under the circumstances including with respect to all matters relating to the Assets, their value, operation and suitability.

(c) In making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Purchaser has relied solely on the basis of its own independent due diligence investigation of the Assets and the terms and conditions of this Agreement.

Section 6.11 Consents, Approvals or Waivers. Purchaser’s execution, delivery and performance of this Agreement (and any document required to be executed and delivered by Purchaser at Closing) is not and will not be subject to any consent, approval, or waiver from any Governmental Body or other Third Party, except consents and approvals of assignments by Governmental Bodies that are customarily obtained after Closing.

Section 6.12 Bankruptcy. There are no bankruptcy, insolvency, reorganization or receivership proceedings pending against, being contemplated by, or threatened against Purchaser.

Section 6.13 Qualification. Purchaser is, or as of the Closing Date will be, qualified under applicable Law to own the Assets and has, or as of the Closing Date will have, complied with all necessary bonding requirements of Governmental Bodies required for Purchaser’s ownership or operation of the Assets.

Section 6.14 Limitation. Purchaser acknowledges the following:

(A) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE 4, ARTICLE 5, IN THE CERTIFICATES OF SELLERS TO BE DELIVERED PURSUANT TO SECTION 9.2(B) OR IN THE ASSIGNMENTS TO BE DELIVERED BY SELLERS TO PURCHASER HEREUNDER, THERE ARE NO REPRESENTATIONS AND WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, BY SELLERS AS TO THE ASSETS OR PROSPECTS THEREOF AND PURCHASER HAS NOT RELIED UPON ANY ORAL OR WRITTEN INFORMATION PROVIDED BY SELLERS.

(B) EXCEPT AS AND TO THE EXTENT EXPRESSLY PROVIDED IN ARTICLE 4 AND SECTION 11.2(B)(IV), SELLERS AND THE OTHER MEMBERS OF THE SELLERS GROUP SHALL NOT HAVE ANY LIABILITY IN CONNECTION WITH AND SELLERS HAVE DISCLAIMED, HAVE NOT MADE AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, ENVIRONMENTAL DEFECTS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF HAZARDOUS SUBSTANCES, HYDROCARBONS OR NORM INTO THE ENVIRONMENT OR PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS.

(C) THE ASSETS HAVE BEEN USED FOR EXPLORATION, DEVELOPMENT AND PRODUCTION OF HYDROCARBONS AND THERE MAY BE PETROLEUM, PRODUCED WATER, WASTE, OR OTHER SUBSTANCES OR MATERIALS LOCATED IN, ON OR UNDER THE PROPERTIES OR ASSOCIATED

WITH THE ASSETS. EQUIPMENT AND SITES INCLUDED IN THE ASSETS MAY CONTAIN ASBESTOS, NORM OR OTHER HAZARDOUS SUBSTANCES. NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, MATERIALS AND EQUIPMENT AS SCALE, OR IN OTHER FORMS. THE WELLS, MATERIALS AND EQUIPMENT LOCATED ON THE PROPERTIES OR INCLUDED IN THE ASSETS MAY CONTAIN NORM AND OTHER WASTES OR HAZARDOUS SUBSTANCES. NORM CONTAINING MATERIAL OR OTHER WASTES OR HAZARDOUS SUBSTANCES MAY HAVE COME IN CONTACT WITH VARIOUS ENVIRONMENTAL MEDIA, INCLUDING WATER, SOILS OR SEDIMENT. SPECIAL PROCEDURES MAY BE REQUIRED FOR THE ASSESSMENT, REMEDIATION, REMOVAL, TRANSPORTATION OR DISPOSAL OF ENVIRONMENTAL MEDIA, WASTES, ASBESTOS, NORM AND OTHER HAZARDOUS SUBSTANCES FROM THE ASSETS.

ARTICLE 7

COVENANTS OF THE PARTIES

Section 7.1 Access.

(i) The following terms of this Section 7.1 shall apply only to the extent Purchaser has not obtained the relevant information regarding or access to the Assets pursuant to the Helis PSA.

(j) Between the Execution Date and the Closing Date, each Seller shall give Purchaser access to the Assets and access to and the right to copy, at Purchaser’s sole cost, risk and expense, the Records (or originals thereof) in such Seller’s possession, for the purpose of conducting a reasonable due diligence review of the Seller Assets of such Seller, but only to the extent that such Seller may do so without violating any obligations to any Third Party and to the extent that such Seller has the authority to grant such access without breaching any restriction binding on it (and each Seller shall use its Commercially Reasonable Efforts to seek waivers of such restrictions if and to the extent requested by Purchaser). Subject to the foregoing, Purchaser shall be entitled to conduct (i) a Phase I Environmental Site Assessment of the Assets and may conduct visual inspections and record reviews relating to the Assets, including their condition and compliance with Environmental Laws, and (ii) a Phase II Environmental Site Assessment of the Assets, subject to, prior to performing such actions, (A) receipt of Operator or Sellers’ Representative’s written permission (such permission not to be unreasonably withheld, conditioned or delayed) to perform the Phase II Environmental Site Assessment and (B) written protocol with Operator’s or Sellers’ Representative for the conduct of any such Phase II Environmental Site Assessment and further subject to the agreement to provide Seller’s copies of any final reports. Otherwise, Purchaser shall not operate any equipment or conduct any testing or sampling of soil, groundwater or other materials (including any testing or sampling for Hazardous Substances, Hydrocarbons or NORM) on or with respect to the Assets prior to Closing. Purchaser shall abide by Sellers’, and any Third Party operator’s, safety rules, regulations, and operating policies (including the execution and delivery of any documentation or paperwork, e.g., boarding agreements or liability releases, required by Third Party operators with respect to Purchaser’s access to any of the Assets) while conducting its

due diligence evaluation of the Assets. Any conclusions made from any examination done by Purchaser shall result from Purchaser’s own independent review and judgment.

(k) The access granted to Purchaser under this Section 7.1 shall be limited to Sellers’ normal business hours, and Purchaser’s investigation shall be conducted in a manner that minimizes interference with the operation of the Assets. Purchaser shall coordinate its access rights of the Assets with Sellers to reasonably minimize any inconvenience to or interruption of the conduct of business by Sellers. Purchaser shall provide Sellers’ Representative with at least forty-eight (48) hours’ written notice before the Assets are accessed pursuant to this Section 7.1, along with a listing of its representatives involved and a description of the activities Purchaser intends to undertake.

(l) Purchaser acknowledges that, pursuant to its right of access to the Assets, Purchaser will become privy to confidential and other information of Sellers and that such confidential information (which includes Purchaser’s conclusions with respect to its evaluations) shall be held confidential by Purchaser in accordance with any applicable privacy Laws regarding personal information.

(M) In connection with the rights of access, examination and inspection granted to Purchaser under this Section 7.1, (i) PURCHASER WAIVES AND RELEASES ALL CLAIMS AGAINST THE SELLERS GROUP ARISING IN ANY WAY THEREFROM OR IN ANY WAY CONNECTED THEREWITH AND (ii) PURCHASER HEREBY AGREES TO INDEMNIFY, DEFEND AND HOLD HARMLESS EACH MEMBER OF THE SELLERS GROUP AND THIRD PARTY OPERATORS FROM AND AGAINST ANY AND ALL DAMAGES ATTRIBUTABLE TO PERSONAL INJURY, DEATH OR PHYSICAL PROPERTY DAMAGE, OR VIOLATION OF THE SELLERS GROUP’S OR ANY THIRD PARTY OPERATOR’S RULES, REGULATIONS, OR OPERATING POLICIES, ARISING OUT OF, RESULTING FROM OR RELATING TO ANY FIELD VISIT OR OTHER DUE DILIGENCE ACTIVITY CONDUCTED BY PURCHASER WITH RESPECT TO THE ASSETS, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, SOLELY OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW BY THE SELLERS GROUP OR THIRD PARTY OPERATORS EXCEPT IN EACH CASE TO THE EXTENT CAUSED BY THE WILLFUL MISCONDUCT OR GROSS NEGLIGENCE OF THE SELLERS GROUP.

Section 7.2 Government Reviews. In a timely manner, the Parties shall (a) make all required filings, prepare all required applications and conduct negotiations with each Governmental Body as to which such filings, applications or negotiations are necessary or appropriate in the consummation of the transactions contemplated hereby and (b) provide such information as each may reasonably request to make such filings, prepare such applications and conduct such negotiations. Each Party shall reasonably cooperate with and use all reasonable efforts to assist the other with respect to such filings, applications, and negotiations.

Section 7.3 Public Announcements; Confidentiality.

(a) Neither Purchaser, nor any Seller, shall make any press release or other public announcement regarding the existence of this Agreement, the contents hereof or the transactions contemplated hereby without the prior written consent of, as the case may be, Purchaser or Sellers’ Representative (collectively, the “Public Announcement Restrictions”). Notwithstanding the foregoing, the Public Announcement Restrictions shall not restrict disclosures to the extent (i) necessary for a Party to perform this Agreement (including disclosures to Governmental Bodies or Third Parties holding Preferential Rights, rights of consent or other rights that may be applicable to the transaction contemplated by this Agreement, as reasonably necessary to provide notices, seek waivers, amendments or termination of such rights, or seek such consents); (ii) required (upon advice of counsel) by applicable securities or other Laws or regulations or the applicable rules of any stock exchange on a Party’s or its respective Affiliates’ stock is listed, and in such event, the disclosures may include at the option of the disclosing Party an 8-K disclosure (or comparable filing for any non-United States disclosure), a press release, a detailed power point presentation and a conference call, and, to the extent required by Law, filing this Agreement with the Securities and Exchange Commission as an exhibit to an 8-K or 10-Q; (iii) that such Party has given the other Party a reasonable opportunity to review such disclosure prior to its release and no objection is raised, or (iv) of any disclosures made by Purchaser or Helis in connection with the Helis Transaction to the extent permitted under the Helis PSA. In the case of the disclosures described under subsections (i) and (ii) of this Section 7.3(a), each Purchaser or Sellers’ Representative, as the case may be, shall use its reasonable efforts to consult with the other Party regarding the contents of any such release or announcement prior to making such release or announcement, it being understood that no Party may deny the other from making such disclosure.

(b) Except as set forth in this Section 7.3, the Parties shall keep all information and data relating to this Agreement and the Assets strictly confidential except for disclosures to Representatives of the Parties (in which event, the disclosing Party will be responsible for making sure that the Representatives keep such information and data confidential) and any disclosures required to perform this Agreement (collectively, the “Confidentiality Restrictions”). However, prior to making any disclosures permitted under the preceding sentence, the Party disclosing such information shall obtain an undertaking of confidentiality from the Person receiving such information. The Confidentiality Restrictions shall not restrict disclosures that are required (upon advice of counsel) by applicable securities or other Laws or regulations or the applicable rules of any stock exchange having jurisdiction over the Parties or their respective Affiliates. Following Closing, subject to the preceding sentence, Purchaser shall not be bound by Confidentiality Restrictions relating to information concerning the Assets and Sellers (and Sellers’ Representative) shall be bound by Confidentiality Restrictions relating to information concerning the Assets for a period of twelve (12) months, except to the extent such information concerning the Assets (i) is or becomes generally available to the public other than as a result of a disclosure by Sellers, (ii) was provided to Sellers by, or becomes available to Sellers from, a Third Party, provided that such Third Party was not known by Sellers, after reasonable investigation, to be bound by a confidentiality agreement with or other contractual, legal or fiduciary obligation of confidentiality to Purchaser or (iii) is required to be disclosed under applicable law, the rules of any securities exchange to which the Reviewing Party is subject or by a governmental order, decree, regulation or rule.

Section 7.4 Operation of Business. Except (i) as otherwise contemplated by this Agreement, (ii) as to the matters set forth on Schedule 7.4 or (iii) as otherwise approved by Purchaser, from the Execution Date until the Closing Date, each Seller shall, with respect to its Seller Assets and its interest in Contracts (and as applicable shall vote its interests under the applicable joint operating agreements in a manner consistent with the following if the matter is the subject of a vote and/or shall use its Commercially Reasonable Efforts to cause the applicable operator to if permissible under the applicable joint operating agreement):

(d) conduct Seller’s business related to the Assets in the ordinary course consistent with Seller’s recent exploration and drilling program and other recent practices;

(e) not commit to any new operation reasonably anticipated to require future capital expenditures by all the owners of the Assets in excess of $250,000;

(f) not voluntarily terminate, materially amend, execute or extend Seller’s interest in any material Contracts or enter into any new contract that would have to be disclosed on Schedule 5.14 if in existence on the Execution Date;

(g) maintain Seller’s insurance coverage on the Assets presently furnished by nonaffiliated Third Parties and not furnished by Operator in the amounts and of the types presently in force;

(h) not transfer, sell, hypothecate, encumber or otherwise dispose of any material Properties or Equipment except for sales and dispositions of Equipment or Hydrocarbons made in the ordinary course of business consistent with past practices;

(i) unless already provided to Purchaser by Helis, provide Purchaser with all well proposals (including all AFEs and related documents in connection with such well proposals) within five (5) Business Days after receipt thereof;

(j) not elect to be treated as a non-consenting party under the rules and regulations of the North Dakota Industrial Commission or any applicable joint operating agreement with respect to any operation;

(k) not make, revoke or amend any Tax election with respect to Asset Taxes, enter into any settlement of any material issue with respect to Asset Taxes, or execute or consent to any waivers extending the statutory period of limitations with respect to the collection of any Asset Taxes, in each case, to the extent such action would bind or otherwise affect the Purchaser at or after the Effective Time; and

(l) not enter into an agreement in contravention of any of the foregoing.

Requests for approval of any action restricted by this Section 7.4 shall be delivered to all of the following individuals by electronic correspondence (at the email addresses set forth below) and a facsimile transmission (a the fax numbers set forth below), each of whom shall have full authority or have access to the requisite authority to grant or deny such requests for approval on behalf of

Purchaser, which such approval may be withheld, conditioned or delayed in Purchaser’s reasonable discretion:



Matt Thompson	Vinnie Rigatti
Telephone: 303-640-4226	Telephone: 303-672-6935
Fax: 303-295-0222	Fax: 303-573-0307
Email:matt.thompson@qepres.com	Email: vinnie.rigatti@qepres.com

With a copy (in the case of any written notice) to:

Cory Miller

Telephone: 303-672-6944

Fax: 303-295-0222

Email: cory.miller@qepres.com; and to:

Austin Murr

Telephone: 303-672-6941

Fax: 303-573-0307

Email: Austin.murr@qepres.com

Any approval required in this Section 7.4 will be deemed given if first approved pursuant to the terms of the Helis PSA.

Section 7.5 Non-Solicitation of Employees. From the Execution Date through the Closing, Purchaser will not, and will cause its Affiliates not to, directly or indirectly, formally make an offer of employment or employ any officer or employee of Sellers or their Affiliates with whom Purchaser or its Affiliates have had direct contact with as part of its evaluation, negotiation or consummation of the transactions contemplated herein without obtaining the prior written consent of Sellers’ Representative. This Section 7.5 shall not include general solicitations of employment not specifically directed towards officers or employees of Sellers or their Affiliates.

Section 7.6 Change of Name. Within ninety (90) days after Closing, Purchaser shall eliminate or obscure the names of the Sellers from the Assets and shall have no right to use any logos, trademarks or trade names belonging to Sellers or any of their Affiliates.

Section 7.7 Replacement of Bonds, Letters of Credit and Guaranties. The Parties understand that none of the bonds, letters of credit and guaranties, if any, posted by Sellers or their Affiliates with Governmental Bodies or co-owners and relating to the Assets will be transferred to Purchaser. On or prior to Closing, Purchaser shall obtain, or cause to be obtained in the name of Purchaser, replacements for such bonds, letters of credit and guaranties, to the extent such replacements are necessary to permit the cancellation of the bonds, letters of credit and guaranties posted by Sellers or to consummate the transactions contemplated by this Agreement.

Section 7.8 Notification of Breaches. Between the Execution Date and the Closing Date:

(a) Purchaser shall notify Sellers’ Representative promptly after Purchaser obtains actual knowledge that any representation or warranty of Sellers contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Sellers prior to or on the Closing Date has not been so performed or observed in any material respect.

(b) Each Seller and Sellers’ Representative shall notify Purchaser promptly after such Seller or Sellers’ Representative obtains actual knowledge that any representation or warranty of Purchaser contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Purchaser prior to or on the Closing Date has not been so performed or observed in any material respect.

(c) If any of Purchaser’s or Sellers’ representations or warranties is untrue or shall become untrue in any material respect between the Execution Date and the Closing Date, or if any of Purchaser’s or Sellers’ covenants or agreements to be performed or observed prior to or on the Closing Date shall not have been so performed or observed in any material respect, but if such breach of representation, warranty, covenant or agreement shall (if curable) be cured by the Closing (or, if the Closing does not occur, by the date set forth in Section 9.1), then such breach shall be considered not to have occurred for all purposes of this Agreement.

Section 7.9 Amendment to Schedules.

(d) As of the Closing Date, all Schedules to this Agreement, as applicable, shall be deemed amended and supplemented by Sellers to include reference to any matter which results in an adjustment to the Adjusted Purchase Price pursuant to Section 3.3 as a result of the removal under the terms of this Agreement of any of the Assets.

(e) Prior to Closing, any Seller or Sellers’ Representative shall have the right to supplement Seller’s Schedules relating to the representations and warranties set forth in Article 5 with respect to any matters discovered or occurring subsequent to the Execution Date which, if existing or known at the date hereof or thereafter, would have been required to be set forth or described in such Schedules, including amendments to reflect actions taken in compliance with Section 7.4 (“Section 7.4 Updates”). For all purposes of this Agreement, including for purposes of determining whether the conditions set forth in Article 8 have been fulfilled, the Schedules to Sellers’ representations and warranties contained in this Agreement shall be deemed to include only that information contained therein on the Execution Date and shall be deemed to exclude all information contained in any addition, supplement or amendment thereto; provided, however, that (a) if Closing shall occur, then only those matters disclosed pursuant to any such addition, supplement or amendment at or prior to Closing which arose and/or occurred, as applicable, from and after the Execution Date up to Closing and which were not caused by any Seller shall be waived and Purchaser shall not be entitled to make a claim with respect thereto pursuant to the terms of this Agreement or otherwise and (b) Section 7.4 Updates shall be deemed to have been made on the Execution Date and shall be included for all purposes of this Agreement. For the avoidance of doubt, if any matter disclosed pursuant to any such addition, supplement or amendment at or prior to Closing did not arise and/or occur, as applicable, from and after the Execution Date up to Closing or relates to a

matter caused by any Seller (other than Section 7.4 Updates), regardless of when Sellers obtained knowledge of such matter, such addition, supplement or amendment shall not be waived and Purchaser shall be entitled to make a claim with respect thereto pursuant to the terms of this Agreement.

Section 7.10 Regulatory Matters. From and after the date of this Agreement until December 31, 2017 (the “Records Period”), Sellers shall, and shall cause their Affiliates and their respective officers, directors, managers, employees, agents and representatives to, provide reasonable cooperation to Purchaser, its Affiliates and their agents and representatives in connection with Purchaser’s or its Affiliates’ filings, if any, that are required by the Securities and Exchange Commission, under securities laws applicable to Purchaser and its Affiliates (collectively, the “Filings”). During the Records Period, each Seller agrees to make available to Purchaser and its Affiliates and their agents and representatives any and all books, records, information and documents that are attributable to the Assets in Seller’s or its Affiliates’ possession or control and access to such Seller’s and its Affiliates’ personnel, in each case as reasonably required by Purchaser, its Affiliates and their agents and representatives in order to prepare, if required, in connection with the Filings, financial statements meeting the requirements of Regulation S-X under the Securities Act of 1933, as amended (the “Securities Act”), along with any documentation attributable to the Assets required to complete any audit associated with such financial statements. During the Records Period, each Seller shall, and shall cause its Affiliates to, provide reasonable cooperation to the independent auditors chosen by Purchaser (“Purchaser’s Auditor”) in connection with any audit by Purchaser’s Auditor of any financial statements of such Seller or its Affiliates with respect to the Assets that Purchaser or any of its Affiliates requires to comply with the requirements of the Securities Act or the Securities Exchange Act of 1934 with respect to any Filings. During the Records Period, each Seller and its Affiliates shall retain all books, records, information and documents relating to the Assets for the three (3) fiscal years prior to January 1, 2012 and the period from January 1, 2012 through the Closing Date. Purchaser will reimburse each Seller and its Affiliates, within ten (10) business days after demand in writing therefor, for any reasonable out-of-pocket costs incurred by such Seller and its Affiliates in complying with the provision of this Section 7.10.

Section 7.11 Further Assurances. After Closing, the Parties agree to take such further actions and to execute, acknowledge and deliver all such further documents as are reasonably requested by the other Party for carrying out the purposes of this Agreement or of any document delivered pursuant to this Agreement.

Section 7.12 Sellers’ Waiver, Release and Conveyance.

Except with respect to the Retained ORRIs, each Seller hereby waives, releases and conveys to Purchaser (i) any rights it has against Helis to acquire any additional interest in the Properties (as defined herein and as defined in the Helis PSA) and (ii) any and all rights each Seller, as applicable, has against Helis or any other Person pursuant to the ORRI Agreement. For the avoidance of doubt, each Seller that is a party to the ORRI Agreement agrees that Purchaser shall have no obligations pursuant to the ORRI Agreement and that the ORRI Agreement shall be of no further force and effect from and after Closing.

Section 7.13 Sellers’ Representative. Each Seller hereby constitutes and appoints UPC as such Seller’s “Sellers’ Representative”, to take such actions by such Seller as may be expressly required or permitted to be taken by the Sellers’ Representative in this Agreement. It being understood and agreed that no fiduciary or agency relationship is created by this designation of Unit as Sellers’ Representative, and Unit does not have the authority to execute any agreement or other document on behalf of Sellers, or assume any obligation on their behalf, except as expressly stated in this Agreement. Each Seller acknowledges and agrees that (i) Sellers’ Representative may bind such Seller only for expressly defined purposes under this Agreement; and (ii) Purchaser may rely on and is a beneficiary of this Section 7.13. Purchaser acknowledges that Sellers’ Representative may deliver notices or make elections on behalf of each Seller that vary from notices or elections delivered on behalf of other Sellers. In the absence of any indication in such notices or elections delivered by Sellers’ Representative, Purchaser may rely on such notices or elections as binding on all Sellers.

ARTICLE 8

CONDITIONS TO CLOSING

Section 8.1 Sellers’ Conditions to Closing. The obligations of each of the Sellers to consummate the transactions contemplated by this Agreement are subject to the satisfaction (or waiver by each of the Sellers) on or prior to Closing of each of the following conditions precedent:

(d) Representations. The representations and warranties of Purchaser set forth in Article 6 shall be true and correct in all material respects as of the Execution Date and as of the Closing Date as though made on and as of the Closing Date;

(e) Performance. Purchaser shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date;

(f) No Action. On the Closing Date, no injunction, order or award restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated by this Agreement, or granting material damages in connection therewith, shall have been issued and remain in force, and no suit, action or other proceeding by a Third Party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement, or seeking substantial damages in connection therewith, shall be pending before any Governmental Body or arbitrator;

(g) Title Defects; Environmental Defects; Casualty; Preferential Rights; Consents. In each case subject to the Individual Defect Threshold and the Aggregate Defect Deductible, as applicable, the sum of (a) all Title Defect Amounts (including Environmental Defects) that have been determined pursuant to Section 4.2 prior to Closing, less the sum of all Title Benefit Amounts that have been determined under Section 4.3 prior to Closing, plus (b) the Allocated Value of any Assets excluded from the transactions as contemplated by Section 4.6, Section 4.7 or Section 4.2(c)(ii) shall be less than twenty percent (20%) of the Aggregate Unadjusted Purchase Price;

(h) Governmental Consents. All material consents and approvals of any Governmental Body required for the transfer of the Assets from Sellers to Purchaser as contemplated under this Agreement, except Customary Post-Closing Consents, shall have been granted, or the necessary waiting period shall have expired, or early termination of the waiting period shall have been granted; and

(i) Deliveries. Purchaser shall deliver (or be ready, willing and able to deliver at Closing) to Sellers duly executed counterparts of the documents and certificates to be delivered by Purchaser under Section 9.3.

Section 8.2 Purchaser’s Conditions to Closing. The obligations of Purchaser to consummate the transactions contemplated by this Agreement with respect to any Seller are subject to the satisfaction (or waiver by Purchaser) on or prior to Closing of each of the following conditions precedent, provided, however, that if Purchaser waives a condition under the Helis PSA that is comparable to a condition in this Agreement, Purchaser shall be deemed to have waived the comparable condition in this Agreement to the extent relating to the same facts and circumstances that are the subject of the Purchaser’s waiver under the Helis PSA:

(e) Representations. The representations and warranties of such Seller set forth in Article 5 shall be true and correct as of the Execution Date and as of the Closing Date as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for such breaches, if any, as would not, individually or in the aggregate, have a Material Adverse Effect (except to the extent that such representation or warranty is qualified in terms of materiality), provided, however, that any such breach by a Seller asserted by Purchaser to be a failure of condition shall be deemed the failure of condition only as to such Seller and not as to any other Seller that has not committed such breach;

(f) Performance. Such Seller, as to its interest and obligations, shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date, except, in the case of breaches of Section 7.4, for such breaches, if any, as would not, individually or in the aggregate, have a Material Adverse Effect (except to the extent such covenant or agreement is qualified in terms of materiality), provided, however, that any breach in such performance by a Seller asserted by Purchaser to be a failure of condition shall be deemed the failure of condition only as to such Seller and not as to any other Seller that has not committed such breach;

(g) No Action. On the Closing Date, no injunction, order or award restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated by this Agreement, or granting material damages in connection therewith, shall have been issued and remain in force, and no suit, action or other proceeding by a Third Party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement, or seeking substantial damages in connection therewith, shall be pending before any Governmental Body or arbitrator;

(h) Title Defects; Environmental Defects; Casualty; Preferential Rights; Consents. In each case subject to the Individual Defect Threshold and the Aggregate Defect Deductible, as applicable, the sum of (a) all Title Defect Amounts (including Environmental Defects) that have been determined pursuant to Section 4.2 prior to Closing, less the sum of all Title Benefit Amounts that have been determined under Section 4.3 prior to Closing, plus (b) the Allocated Value of any Assets excluded from the transactions as contemplated by Section 4.6, Section 4.7 or Section 4.2(c)(ii) shall be less than twenty percent (20%) of the Aggregate Unadjusted Purchase Price;

(i) Governmental Consents. All material consents and approvals of any Governmental Body required for the transfer of the Assets from Sellers to Purchaser as contemplated under this Agreement, except Customary Post-Closing Consents, shall have been granted, or the necessary waiting period shall have expired, or early termination of the waiting period shall have been granted;

(j) Deliveries. Such Seller shall deliver (or be ready, willing and able to deliver simultaneously at Closing) to Purchaser duly executed counterparts of the documents and certificates to be delivered by Sellers under Section 9.2, provided, however, except as set forth in Section 8.2(h), that any failure in such delivery by a Seller asserted by Purchaser to be a failure of condition shall be deemed the failure of condition only as to such Seller and not as to any other Seller that has not committed such failure;

(k) Helis Closure. The Helis Transaction shall have closed in accordance with the terms of the Helis PSA (or closing thereunder will occur simultaneously with Closing hereunder); and

(l) Black Hills and UPC Closure. The closing hereunder with respect to Black Hills and UPC shall have occurred or be occurring simultaneously.

Section 8.3 Obligation of Purchaser To Close. In the event the Helis Transaction has closed in accordance with the terms of the Helis PSA and all of Purchaser’s conditions to close set out in Section 8.2 have been satisfied or waived by Purchaser (either under this Agreement or under the Helis PSA insofar as Purchaser has waived the comparable condition under the Helis PSA to the extent relating to the same facts and circumstances that are the subject of Purchaser’s waiver under the Helis PSA), then Purchaser is obligated to consummate the Closing hereunder.

ARTICLE 9

CLOSING

Section 9.1 Time and Place of Closing. Consummation of the purchase and sale transaction as contemplated by this Agreement (the “Closing”), shall, unless otherwise agreed to in writing by Purchaser and a Seller, take place at 10:00 a.m., Central Time, on September 27, 2012 at the offices of Vinson & Elkins LLP located at 1001 Fannin Street, Suite 2500, Houston, Texas 77002 (provided, however, that the Parties agree that the Closing shall take place simultaneously with the closing of the Helis Transaction under the Helis PSA, except (i) in the event that all

conditions in Article 8 to be satisfied prior to Closing have not yet been satisfied or waived, in which case Closing shall occur within five (5) Business Days of such conditions having been satisfied or waived, subject to the rights of the Parties under Article 10, at such time and place as Purchaser may establish by at least three (3) Business Days written notice to Seller, or (ii) in the event the closing under the Helis PSA occurs on a different date, Purchaser shall be permitted to change the date of the Closing to be simultaneous with or to follow the Helis closing; provided that Purchaser provides Sellers’ Representative with at least three (3) Business Days written notice. The date on which the Closing occurs is herein referred to as the “Closing Date.”

Section 9.2 Obligations of Sellers at Closing. At the Closing, upon the terms and subject to the conditions of this Agreement, and subject to the simultaneous performance by Purchaser of its obligations pursuant to Section 9.3, each Seller shall deliver or cause to be delivered to Purchaser, among other things, the following:

(m) Counterparts of the Assignments of such Seller’s Seller Assets, in sufficient duplicate originals to allow recording in all appropriate jurisdictions and offices, duly executed by such Seller and acknowledged before a notary public;

(n) Certificates duly executed by an authorized officer of such Seller, dated as of Closing, certifying on behalf of such Seller that the conditions set forth in Section 8.2(a) and Section 8.2(b) in relation to such Seller have been fulfilled;

(o) Counterparts of the Letter-in-lieu of Transfer Order covering the relevant Seller Assets, duly executed by such Seller;

(p) [Reserved];

(q) Certificate duly executed by the secretary or any assistant secretary of such Seller, dated as of the Closing, (i) attaching and certifying on behalf of such Seller complete and correct copies of (A) the certificate of incorporation or formation, as applicable, of such Seller, (B) the resolutions of the Board of Directors or members or shareholders or partners, as applicable, of such Seller authorizing the execution, delivery, and performance by such Seller of this Agreement and the transactions contemplated hereby and (C) any required approval by such Seller’s members or shareholders or partners of this Agreement and the transactions contemplated hereby and (ii) certifying the incumbency and true signatures of the officers who execute this Agreement and any other agreement, certificate or document related hereto or executed in connection herewith on behalf of such Seller;

(r) A certification of non-foreign status with respect to such Seller which meets the requirements of Treasury Regulation § 1.1445-2(b)(2);

(s) An executed IRS Form W-9 for such Seller;

(t) Executed releases for the Existing Sundance Mortgage and any and all liens, mortgages and other encumbrances on the Assets incurred by such Seller or its Affiliates in connection with borrowed monies;

(u) Where approvals are received by such Seller pursuant to a filing or application under Section 7.2, copies of those approvals; and

(v) All other instruments, documents and other items reasonably necessary to effectuate the terms of this Agreement, as may be reasonably requested by Purchaser.

Section 9.3 Obligations of Purchaser at Closing. At the Closing, upon the terms and subject to the conditions of this Agreement, and subject to the simultaneous performance by Sellers of their obligations pursuant to Section 9.2, provided that, subject to Section 8.2(h), failure of any Seller to perform its obligations under Section 9.2 shall not excuse Purchaser from performing its obligations under this Section 9.3 with respect to those Sellers that perform their obligations under Section 9.2 (each Seller that performs its obligations under Section 9.2 being referred to as a “Closing Seller”), Purchaser shall deliver or cause to be delivered to Closing Seller, among other things, the following:

(a) Wire transfers of the applicable Closing Payments to the accounts designated on the Preliminary Settlement Statement in immediately available funds, and in accordance with the Escrow Agreement, an instruction to the Escrow Agent to distribute the balance in the Escrow Account of each Closing Seller to the account of such Closing Seller and in the amounts designated on the Preliminary Settlement Statement;

(b) A certificate by an authorized officer of Purchaser, dated as of Closing, certifying on behalf of Purchaser that the conditions set forth in Section 8.1(a) and Section 8.1(b) have been fulfilled;

(c) Counterparts of the Assignments of the Assets, in sufficient duplicate originals to allow recording in all appropriate jurisdictions and offices, duly executed by Purchaser and acknowledged before a notary public;

(d) Counterparts of the Letter-in-lieu of Transfer Order covering the relevant Assets, duly executed by Purchaser;

(e) [Reserved];

(f) A certificate duly executed by the secretary or any assistant secretary of Purchaser, dated as of the Closing, (i) attaching, and certifying on behalf of Purchaser as complete and correct, copies of (A) the certificate of incorporation of Purchaser, (B) the resolutions of the Board of Directors (or body of similar power and authority) of Purchaser or its general partner authorizing the execution, delivery, and performance by Purchaser of this Agreement and the transactions contemplated hereby and (C) any required approval by the shareholders, unit holders or other equity holders of Purchaser of this Agreement and the transactions contemplated hereby and (ii) certifying the incumbency and true signatures of the officers who execute this Agreement and any other agreement, certificate or document related hereto or executed in connection herewith on behalf of Purchaser;

(g) Where approvals are received by Purchaser pursuant to a filing or application under Section 7.2, copies of those approvals;

(h) Evidence of replacement bonds, guaranties and letters of credit pursuant to Section 7.7; and

(i) All other instruments, documents and other items reasonably necessary to effectuate the terms of this Agreement, as may be reasonably requested by Seller.

Section 9.4 Closing Payment and Post-Closing Purchase Price Adjustments.

(a) Not later than four (4) Business Days prior to the Closing Date, Purchaser shall deliver to Sellers’ Representative a copy of the “Preliminary Settlement Statement” prepared pursuant to the terms of the Helis PSA (the “Helis PSS”).

(b) Not later than three (3) Business Days prior to the Closing Date, Sellers’ Representative shall prepare and deliver to Purchaser, using and based upon the best information available to Sellers, a preliminary settlement statement (the “Preliminary Settlement Statement”) estimating the initial Adjusted Purchase Price for each Closing Seller, after giving effect to all adjustments to the Unadjusted Purchase Price set forth in Section 3.3. It is understood and agreed that the Closing Sellers may adopt and elect to use as the Preliminary Settlement Statement the Helis PSS or portions thereof, proportionate to their respective Seller Assets. The Preliminary Settlement Statement shall include wire transfer information for the Closing Payments and for the release of the Deposit and shall be signed by each Closing Seller. The estimates delivered in accordance with this Section 9.4(b) less the Deposit for each Closing Seller shall constitute the Dollar amounts to be paid by Purchaser to each Closing Seller at the Closing (the “Closing Payment” for each Closing Seller).

(c) The following Section 9.4(d) shall only apply to the extent any reporting required to be made to Purchaser by Sellers therein is not addressed by reports prepared pursuant to the terms of the Helis PSA and in such event Sellers reporting shall be due the later of five (5) Business Days after receipt of the report prepared pursuant to the Helis PSA or such later date provided in Section 9.4(d).

(d) Sellers’ Representative shall prepare and deliver to Purchaser a statement setting forth the final calculation of each Adjusted Purchase Price and showing the calculation of each adjustment, based, to the extent possible, on actual credits, charges, receipts and other items before and after the Effective Time no later than the later of (x) thirty (30) days following the Cure Period and (y) the date on which the Parties or the Title Arbitrator, as applicable, finally determines all Title Defect Amounts and Title Benefit Amounts under Section 4.4 (such later date, the “Final Settlement Statement Date”). Sellers and Sellers’ Representative shall, at Purchaser’s request, supply reasonable documentation available to support any credit, charge, receipt or other item included in such statement. Purchaser shall deliver to Sellers’ Representative a written report containing any changes that Purchaser proposes be made to Sellers’ statement no later than sixty (60) days following Purchaser’s receipt thereof. Sellers’ Representative may deliver a written report to Purchaser during this same period reflecting any changes that Sellers’ Representative proposes

to be made to such statement as a result of additional information received after the statement was prepared. Sellers’ Representative and Purchaser shall undertake to agree on the final statement of the Adjusted Purchase Price no later than ninety (90) after the Final Settlement Statement Date. In the event that Sellers’ Representative and Purchaser cannot reach agreement within such period of time, either Sellers’ Representative or Purchaser may refer the remaining matters in dispute to the Houston, Texas office of Deloitte for review and final determination by arbitration. The accounting firm shall conduct the arbitration proceedings in Houston, Texas in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent that such rules do not conflict with the terms of this Section 9.4(d). The accounting firm’s determination shall be made within thirty (30) days after submission of the matters in dispute and shall be final and binding on both Parties, without right of appeal. In determining the proper amount of any adjustment to any Unadjusted Purchase Price, the accounting firm shall not increase such Unadjusted Purchase Price more than the increase proposed by Sellers’ Representative nor decrease such Unadjusted Purchase Price more than the decrease proposed by Purchaser, as applicable. The accounting firm shall act as an expert for the limited purpose of determining the specific disputed matters submitted by Sellers’ Representative and Purchaser and may not award damages or penalties to the Parties with respect to any matter. Each Party shall bear its own legal fees and other costs of presenting its case. Sellers shall bear one-half and Purchaser shall bear one-half of the costs and expenses of the accounting firm. Within ten (10) days after the earlier of (i) the expiration of Purchaser’s sixty (60) day review period without delivery of any written report or (ii) the date on which the Parties finally determine each Adjusted Purchase Price or the accounting firm finally determines the disputed matters, as applicable, (A) Purchaser shall pay to each Seller the amount by which the Adjusted Purchase Price for such Seller (after deducting a portion of the Deposit amount equal to the Deposit multiplied by such Seller’s applicable Seller’s Interest Percentage) exceeds the applicable Closing Payment for such Seller or (B) each Seller, as applicable, shall pay to Purchaser the amount by which such Seller’s Closing Payment exceeds the Adjusted Purchase Price applicable to such Seller (after deducting a portion of the Deposit amount equal to the Deposit multiplied by such Seller’s applicable Seller’s Interest Percentage), as applicable. Any post-Closing payment pursuant to this Section 9.4(d) shall bear interest from the Closing Date to the date of payment at the Prime Rate.

(e) Purchaser shall assist Sellers’ Representative in the preparation of the final statement of the Adjusted Purchase Price under Section 9.4(d) by furnishing invoices, receipts, reasonable access to personnel, and such other assistance as may be requested by Seller to facilitate such process post-Closing.

(f) All payments made or to be made under this Agreement to Closing Sellers shall be made by electronic transfer of immediately available funds to the accounts designated on the Preliminary Settlement Statement. All payments made or to be made hereunder to Purchaser shall be by electronic transfer of immediately available funds to a bank and account specified by Purchaser in writing to Sellers’ Representative.

ARTICLE 10

TERMINATIONS; REMEDIES

Section 10.1 Termination. This Agreement may be terminated at any time prior to Closing:

(a) With respect to any Seller, by the mutual prior written consent of such Seller and Purchaser; or

(b) With respect to any Seller, by either (i) Purchaser, or (ii) such Seller; if Closing has not occurred on or before October 31, 2012. However, neither such Seller, on the one hand, nor Purchaser, on the other hand, shall be entitled to terminate this Agreement under this Section 10.1(b) if the Closing has failed to occur because such Seller, on the one hand, or Purchaser, on the other hand, negligently or willfully failed to perform or observe in any material respect its covenants or agreements hereunder.

(c) By Purchaser, unilaterally, by notice to Sellers’ Representative if the Helis PSA is terminated in accordance with its terms prior to the closing of the Helis Transaction.

Section 10.2 Effect of Termination. If this Agreement is terminated pursuant to Section 10.1, this Agreement shall become void and of no further force or effect (except for the provisions of Section 5.6, Section 5.21, Section 6.6, Section 7.1(e), Section 7.3, Article 1, Article 10, Article 13 (other than Section 13.12, Section 13.15, Section 13.17 and Section 13.18) and Appendix A, which shall continue in full force and effect) and, without prejudice to their rights under Section 10.3(a) (if applicable), Sellers shall be free immediately to enjoy all rights of ownership of the Assets and to sell, transfer, encumber or otherwise dispose of the Assets to any Person without any restriction under this Agreement. Notwithstanding anything to the contrary in this Agreement, the termination of this Agreement under Section 10.1 shall not relieve either Party, subject to Section 13.11, from liability for any willful or negligent failure to perform or observe in any material respect any of its agreements or covenants contained herein that are to be performed or observed at or prior to Closing; provided that Sellers’ remedy shall be solely as set forth in Section 10.3(a).

Section 10.3 Remedies for Failure to Close.

(a) If any Seller terminates this Agreement under Section 10.1(b), and Purchaser has willfully failed to perform or observe its covenants and agreements or is in breach of its representations and warranties hereunder, or Closing has otherwise not occurred as a result of an act or omission of Purchaser (other than an act or omission expressly permitted by this Agreement), then in addition to its rights under Section 10.2 above, each Seller will, as liquidated damages for lost opportunities (and not as a penalty), be entitled to receive (and Purchaser shall direct the Escrow Agent to deliver to Sellers) such Seller’s applicable Seller’s Interest Percentage of the Deposit together with any interest or income thereon, free of any claims by Purchaser or any other Person, as its sole and exclusive remedy with respect to the termination of this Agreement; provided, however, that if Purchaser breaches its obligation under Section 8.3 to consummate the Closing with respect to any Seller, such Seller shall have the right to (i) in lieu of termination of this Agreement, exercise its rights under Section 13.17 to enforce Purchaser’s obligation to close under Section 8.3 or (ii) retain the Deposit as specified above as liquidated damages.

(b) If this Agreement is subject to termination for any reason other than the reasons set forth in Section 10.1(a) or Section 10.1(c) (in each of which cases Sellers shall direct the Escrow Agent to deliver to Purchaser the Deposit and any interest accrued thereon, free of any claims by Sellers or any other Person with respect thereto) or Section 10.3(a), Purchaser may either

(i) elect to terminate this Agreement and cause Sellers to direct the Escrow Agent to deliver to Purchaser the Deposit and any interest accrued thereon, free of any claims by Sellers or any other Person with respect thereto, as its sole and exclusive remedy with respect to the termination of this Agreement or (ii) in lieu of terminating this Agreement, exercise its rights under Section 13.17.

ARTICLE 11

ASSUMPTIONS; INDEMNIFICATION

Section 11.1 Assumption. Without limiting Purchaser’s rights to indemnity under Section 11.2 and Purchaser’s remedy for Title Defects in Article 4 and pursuant to the special warranty in the Assignments, from and after the Closing, Purchaser shall assume and fulfill, perform, pay and discharge all of the Assumed Purchaser Obligations.

Section 11.2 Indemnification.

(c) From and after Closing, Purchaser shall indemnify, defend and hold harmless the Sellers Group from and against all Damages incurred, suffered by or asserted against such Persons:

(i) caused by or arising out of or resulting from the Assumed Purchaser Obligations (including, for purposes of certainty, Environmental Liabilities under CERCLA that constitute Assumed Purchaser Obligations);

(ii) caused by or arising out of or resulting from Purchaser’s breach of any of Purchaser’s covenants or agreements contained in Article 7 or Article 12; or

(iii) caused by or arising out of or resulting from any breach of any representation or warranty made by Purchaser contained in Article 6 of this Agreement or in the certificate delivered by Purchaser at Closing pursuant to Section 9.3(b);

EVEN IF SUCH DAMAGES ARE CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF THE SELLERS GROUP.

(d) From and after Closing, each Seller shall (on a several and not a joint and several basis and in proportion among the relevant Seller(s) equal to such Seller(s)’ relative Seller’s Interest Percentages or such Seller(s)’ Seller’s Title Defect Percentages in the case of claims relating to the Assets) indemnify, defend and hold harmless the Purchaser Group from and against all Damages incurred, suffered by or asserted against such Persons:

(i) caused by or arising out of or resulting from such Seller’s breach of Sellers’ covenants or agreements contained in Article 7 or Article 12; or

(ii) caused by or arising out of or resulting from any breach of any representation or warranty made by such Seller contained in Article 5, or in the certificate delivered by such Seller at Closing pursuant Section 9.2(b);

(iii) caused by or arising out of any personal injury or death relating to the ownership, use or operation of the Assets that occurs prior to the Closing Date;

(iv) caused by or arising out of any off-site Environmental Liabilities that arise from ownership, use or operation of the Assets and are attributable to Sellers’ ownership thereof that occurs prior to the Effective Time or, in the event Operator was not acting as a reasonable and prudent operator, that occurs prior to the Closing Date; or

(v) caused by or arising out of the Excluded Assets.

EVEN IF SUCH DAMAGES ARE CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF THE PURCHASER GROUP.

(E) Notwithstanding anything to the contrary contained in this Agreement, this Section 11.2 contains the Parties’ exclusive remedies against each other with respect to breaches of the representations, warranties, covenants and agreements of the Parties in Article 5, Article 6, Article 7 and Article 12 and the affirmations of such representations, warranties, covenants and agreements contained in the certificate delivered by each Party at Closing pursuant to Section 9.2(b) or Section 9.3(b), as applicable. Except for the remedies contained in this Section 11.2, Section 10.2, and Section 10.3, and any other remedies available to the Parties at Law or in equity for breaches of provisions of this Agreement other than Article 5, Article 6, Article 7 and Article 12, EACH OF SELLERS AND PURCHASER RELEASE, REMISE AND FOREVER DISCHARGE THE OTHER AND ITS AFFILIATES AND ALL SUCH PARTIES’ OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, ADVISORS AND OTHER REPRESENTATIVES FROM ANY AND ALL SUITS, LEGAL OR ADMINISTRATIVE PROCEEDINGS, CLAIMS, DEMANDS, DAMAGES, LOSSES, COSTS, LIABILITIES, INTEREST, OR CAUSES OF ACTION WHATSOEVER, IN LAW OR IN EQUITY, KNOWN OR UNKNOWN, WHICH SUCH PARTIES MIGHT NOW OR SUBSEQUENTLY MAY HAVE, BASED ON, RELATING TO OR ARISING OUT OF (i) THIS AGREEMENT, (ii) SELLERS’ OWNERSHIP, USE OR OPERATION OF THE ASSETS OR (iii) THE CONDITION, QUALITY, STATUS OR NATURE OF THE ASSETS, INCLUDING, IN EACH SUCH CASE, RIGHTS TO CONTRIBUTION UNDER CERCLA OR ANY OTHER ENVIRONMENTAL LAW, BREACHES OF STATUTORY OR IMPLIED WARRANTIES, NUISANCE OR OTHER TORT ACTIONS, RIGHTS TO PUNITIVE DAMAGES AND COMMON LAW RIGHTS OF CONTRIBUTION, RIGHTS UNDER AGREEMENTS BETWEEN SELLERS AND ANY PERSONS WHO ARE AFFILIATES OF SELLERS, AND RIGHTS UNDER INSURANCE MAINTAINED BY SELLERS OR ANY PERSON WHO IS AN AFFILIATE OF SELLERS, EVEN IF CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF ANY RELEASED PERSON.

(f) The indemnity of each Party provided in this Section 11.2 shall be for the benefit of and extend to each Person included in the Sellers Group and the Purchaser Group, as applicable. Any claim for indemnity under this Section 11.2 by any Third Party must be brought and administered by a Party to this Agreement. No Indemnified Person (including any Person within

the Sellers Group and the Purchaser Group) other than the Parties shall have any rights against either Sellers or Purchaser under the terms of this Section 11.2 except as may be exercised on its behalf by Purchaser or Sellers’ Representative as applicable, pursuant to this Section 11.2(d). The Parties may elect to exercise or not exercise indemnification rights under this Section 11.2(d) on behalf of the other Indemnified Persons affiliated with it in its sole discretion and shall have no liability to any such other Indemnified Person for any action or inaction under this Section 11.2(d). Sellers’ Representative shall have the authority to give and receive notices under this Article 11 on behalf of Sellers, and such notices shall be binding on Sellers, but no other action or failure to act of Sellers’ Representative shall bind Sellers or constitute a waiver by Sellers of any right hereunder.

Section 11.3 Indemnification Actions. All claims for indemnification under Section 11.2 shall be asserted and resolved as follows:

(a) For purposes hereof, (i) the term “Indemnifying Person” when used in connection with particular Damages shall mean the Person or Persons having an obligation to indemnify another Person or Persons with respect to such Damages pursuant to this Article 11 and (ii) the term “Indemnified Person” when used in connection with particular Damages shall mean the Person or Persons having the right to be indemnified with respect to such Damages by another Person or Persons pursuant to this Article 11.

(b) To make a claim for indemnification under Section 11.2, an Indemnified Person shall notify the Indemnifying Person of its claim under this Section 11.3, including the specific details of and specific basis under this Agreement for its claim (the “Claim Notice”). In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Person (a “Third Person Claim”), the Indemnified Person shall provide its Claim Notice promptly after the Indemnified Person has actual knowledge of the Third Person Claim and shall enclose a copy of all papers (if any) served with respect to the Third Person Claim; provided that the failure of any Indemnified Person to give notice of a Third Person Claim as provided in this Section 11.3 shall not relieve the Indemnifying Person of its obligations under Section 11.2 except to the extent such failure results in insufficient time being available to permit the Indemnifying Person to effectively defend against the Third Person Claim or otherwise prejudices the Indemnifying Person’s ability to defend against the Third Person Claim. In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement that was inaccurate or breached.

(c) In the case of a claim for indemnification based upon a Third Person Claim, the Indemnifying Person shall have thirty (30) days from its receipt of the Claim Notice to notify the Indemnified Person whether it admits or denies its obligation to defend the Indemnified Person against such Third Person Claim under this Article 11. If the Indemnifying Person does not notify the Indemnified Person within such thirty (30) day period whether the Indemnifying Person admits or denies its obligation to defend the Indemnified Person, it shall be conclusively deemed to have denied such indemnification obligation hereunder. The Indemnified Person is authorized, prior to and during such thirty (30) day period, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Person and that is not prejudicial to the Indemnifying Person.

(d) If the Indemnifying Person admits its obligation, it shall have the right and obligation to diligently defend, at its sole cost and expense, the Third Person Claim. The Indemnifying Person shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Person, the Indemnified Person agrees to cooperate in contesting any Third Person Claim that the Indemnifying Person elects to contest (provided, however, that the Indemnified Person shall not be required to bring any counterclaim or cross-complaint against any Person). The Indemnified Person may at its own expense participate in, but not control, any defense or settlement of any Third Person Claim controlled by the Indemnifying Person pursuant to this Section 11.3(d). An Indemnifying Person shall not, without the written consent of the Indemnified Person, settle any Third Person Claim or consent to the entry of any judgment with respect thereto which (i) does not result in a final resolution of the Indemnified Person’s liability with respect to the Third Person Claim (including, in the case of a settlement, an unconditional written release of the Indemnified Person) or (ii) may materially and adversely affect the Indemnified Person (other than as a result of money damages covered by the indemnity).

(e) If the Indemnifying Person does not admit its obligation or admits its obligation but fails to diligently defend or settle the Third Person Claim, then the Indemnified Person shall have the right to defend against the Third Person Claim (at the sole cost and expense of the Indemnifying Person, if the Indemnified Person is entitled to indemnification hereunder), with counsel of the Indemnified Person’s choosing, subject to the right of the Indemnifying Person to admit its obligation and assume the defense of the Third Person Claim at any time prior to settlement or final determination thereof. If the Indemnifying Person has not yet admitted its obligation to provide indemnification with respect to a Third Person Claim, the Indemnified Person shall send written notice to the Indemnifying Person of any proposed settlement and the Indemnifying Person shall have the option for ten (10) days following receipt of such notice to (i) admit in writing its obligation to provide indemnification with respect to the Third Person Claim and (ii) if its obligation is so admitted, reject, in its reasonable judgment, the proposed settlement. If the Indemnified Person settles any Third Person Claim over the objection of the Indemnifying Person after the Indemnifying Person has timely admitted its obligation in writing and assumed the defense of a Third Person Claim, the Indemnified Person shall be deemed to have waived any right to indemnity therefor.

(f) In the case of a claim for indemnification not based upon a Third Person Claim, the Indemnifying Person shall have thirty (30) days from its receipt of the Claim Notice to (i) cure the Damages complained of, (ii) admit its obligation to provide indemnification with respect to such Damages or (iii) dispute the claim for such indemnification. If the Indemnifying Person does not notify the Indemnified Person within such thirty (30) day period that it has cured the Damages or that it disputes the claim for such indemnification, the Indemnifying Person shall be deemed to have disputed such claim for indemnification.

Section 11.4 Limitation on Actions.

(a) The representations and warranties of the Parties in Article 5 and Article 6 and the covenants and agreements of the Parties in Article 7 and the corresponding representations and warranties given in the certificates delivered at Closing pursuant to Section 9.2(b) and Section 9.3(b), as applicable, shall survive the Closing for a period of twelve (12) months (unless a shorter

period is expressly provided within the applicable Section), except that (i) the representations, warranties and acknowledgements, as applicable, in Section 5.2, Section 5.3, Section 5.4, Section 5.6, Section 6.2, Section 6.3, Section 6.4, and Section 6.14 shall survive indefinitely, (ii) the representations and warranties in Section 5.10, Section 5.12 and Section 5.15 and the covenants in Section 7.4 shall survive the Closing for a period of twenty-four (24) months (iii) the representations and warranties in Section 5.11 shall survive Closing until sixty (60) days after the expiration of the applicable statute of limitations (including extension) for the subject Taxes and (iv) the covenants and agreements, as applicable, in Section 7.1(e), Section 7.3, Section 7.6, Section 7.7 and Section 7.10 shall survive indefinitely. The remainder of this Agreement (including the disclaimers in Section 5.21) shall survive the Closing without time limit except (A) as may otherwise be expressly provided herein and (B) for the covenants and agreements contained in Article 12, which shall survive Closing until sixty (60) days after the expiration of the applicable statute of limitations (including extension) for the subject Taxes. Representations, warranties, covenants and agreements shall be of no further force and effect after the date of their expiration, provided that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant or agreement prior to its expiration date.

(b) The indemnities in Section 11.2(a)(ii), Section 11.2(a)(iii), Section 11.2(b)(i) and Section 11.2(b)(ii) shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification thereunder, except in each case as to matters for which a specific written claim for indemnity has been delivered to the Indemnifying Person on or before such termination date. The indemnities in Section 11.2(a)(i), Section 11.2(b)(iii), Section 11.2(b)(iv) and Section 11.2(b)(v) shall continue without time limit.

(c) No Seller shall have any liability for any indemnification under Section 11.2(b)(i) or Section 11.2(b)(ii) (other than in respect to claims relating to a breach of a representation or warranty in Section 5.10, Section 5.11, Section 5.12, Section 5.15 or a breach of a covenant or agreement in Section 7.4 or Article 12), until and unless the aggregate amount of the liability for all Damages for which Claim Notices are delivered by Purchaser therefor exceeds two and one-half percent (2.5%) of the applicable Unadjusted Purchase Price for such Seller, and then only to the extent such Damages exceed two and one-half percent (2.5%) of the applicable Unadjusted Purchase Price for such Seller. Purchaser shall not have any liability for any indemnification under Section 11.2(a)(ii) (other than with respect to claims relating to a breach of a covenant or agreement in Article 12) or Section 11.2(a)(iii) until and unless the aggregate amount of the liability for all Damages for which Claim Notices are delivered by Sellers therefor exceeds two and one-half percent (2.5%) of the Aggregate Unadjusted Purchase Price, and then only to the extent such Damages exceed two and one-half percent (2.5%) of the Aggregate Unadjusted Purchase Price.

(d) Except with respect to liability for indemnification under Section 11.2(b)(i) with respect to breaches of covenants and agreements under Article 12, Section 11.2(b)(iii), Section 11.2(b)(iv), or Section 11.2(b)(v) no Seller shall be required to indemnify the Purchaser Group under this Article 11 for aggregate Damages in excess of ten percent (10%) of such Seller’s applicable Unadjusted Purchase Price.

(e) The amount of any Damages for which an Indemnified Person is entitled to indemnity under this Article 11 shall be reduced by (i) the amount of insurance proceeds realized by the Indemnified Person or its Affiliates with respect to such Damages (net of any collection costs, and excluding the proceeds of any insurance policy issued or underwritten by the Indemnified Person or its Affiliates) and (ii) an amount equal to the amount of any net Tax benefit actually realized by the Indemnified Person or its Affiliates as a result of such Damages in the year such Damages are incurred.

(f) Purchaser shall not be entitled to indemnification or any other remedy under this Agreement with respect to any Damages or other liability, loss, cost, expense, claim, award or judgment to the extent attributable to or arising out of the actions of Purchaser or Helis as operator of any of the Properties.

(g) Notwithstanding anything in this Agreement to the contract, in no event shall (i) any Indemnified Person be entitled to duplicate compensation with respect to the same Damage, liability, loss, cost, expense, claim, award or judgment under more than one provision of this Agreement and the various documents delivered in connection with the Closing, (ii) any Person be entitled to indemnification hereunder with respect to a breach by an Indemnifying Person of any of the representations, warranties or covenants made or agreed to by such Indemnifying Person hereunder of which such Person had actual knowledge prior to the Closing Date, and (iii) Purchaser be required to indemnify any Seller (together with the members of the Sellers Group related to such Seller) for more than such Seller’s applicable Seller’s Interest Percentage of any Damages relating to an indemnification claim hereunder.

ARTICLE 12

TAX MATTERS

Section 12.1 Tax Filings.

Purchaser and each Seller acknowledge that from the Effective Time through the Closing Date, Helis (or, if applicable, other designated operator) shall be responsible for filing with the Taxing authorities the applicable Tax Returns for all Asset Taxes relating to the Assets in which such Seller has an interest that are required to be filed on or before the Closing Date and paying the Taxes reflected on all such Tax Returns as due and owing (provided that to the extent such Taxes relate to the periods from and after the Effective Time, as determined pursuant to Section 12.2, promptly following a Seller’s request (and in accordance with Section 12.2), Purchaser shall pay to such Seller its share of any such Taxes, but only to the extent that such amounts have not already been accounted for under Section 3.3 and have actually been paid by such Seller to the applicable Governmental Body or designated operator). Purchaser (or, if applicable, other designated operator) shall be responsible for the filing with the appropriate Taxing authorities the applicable Tax Returns for all Asset Taxes that are required to be filed after the Closing Date and paying the Taxes reflected on such Tax Returns as due and owing (provided that to the extent such Taxes relate to the periods before the Effective Time, as determined pursuant to Section 12.2, promptly following Purchaser’s request provided to the Sellers’ Representative (and in accordance with Section 12.2), the applicable Seller(s) shall pay to Purchaser any such Taxes, but only to the extent that such amounts have not already been accounted for under Section 3.3 and have actually been paid by Purchaser to the

applicable Governmental Body or designated operator); provided, however, that in the event that Helis (or other designated operator) is required by applicable Tax Law to file a Tax Return with respect to Asset Taxes after the Closing Date that includes all or a portion of a Tax period for which Purchaser is liable for such Taxes, Helis (or other designated operator) shall file such Tax Return and shall pay the Taxes reflected on such Tax Return as due and owing, and promptly following a Seller’s request (and in accordance with Section 12.2), Purchaser shall pay to such Seller its share of all such Taxes allocable to the period or portion thereof beginning at or after the Effective Time, as determined pursuant to Section 12.2 (but only to the extent that such amounts have not already been accounted for under Section 3.3 and have actually been paid by such Seller to the applicable Governmental Body or designated operator), but only if such Taxes arise out of the filing of an original return. Each Seller shall be entitled to its share of all Tax refunds that relate to any Taxes relating to the Assets in which such Seller has an interest allocable to any Tax period, or portion thereof, ending before the Effective Time. Notwithstanding anything to the contrary (including Section 2.4(g)), to the extent that a Seller or Purchaser receives any Tax refund to which such Seller or Purchaser (as the case may be) is entitled, such Seller or Purchaser (as the case may be) shall immediately pay such amount to the other Party to the extent the Adjusted Purchase Price has not been increased pursuant to Section 3.3 on account thereof.

Section 12.2 Current Tax Period Taxes. Asset Taxes assessed against the Assets with respect to the Tax period in which the Effective Time occurs (the “Current Tax Period”), but excluding severance production or similar Taxes that are based on quantity of or the value of production of Hydrocarbons and sales and use Taxes, shall be apportioned between the Parties as of the Effective Time with (a) the applicable Seller being obligated to pay a proportionate share of the actual amount of such Taxes for the Current Tax Period determined by multiplying such actual Taxes by a fraction, the numerator of which is the number of days in the Current Tax Period prior to the Effective Time and the denominator of which is the total number of days in the Current Tax Period and (b) Purchaser being obligated to pay a proportionate share of the actual amount of such Taxes for the Current Tax Period determined by multiplying such actual Taxes by a fraction, the numerator of which is the number of days (including the Closing Date) in the Current Tax Period at and after the Effective Time and the denominator of which is the total number of days in the Current Tax Period. As described in Section 2.4(g), severance, production and similar Taxes that are based on quantity of or the value of production of Hydrocarbons shall be apportioned between the applicable Seller and Purchaser based on the number of units or value of production actually produced or sold, as applicable, before, and at or after, the Effective Time. Sales and use Taxes shall be apportioned between the Parties based on transactions occurring before, and at or after, the Effective Time. In the event that Purchaser or a Seller makes any payment (directly or indirectly) for which it is entitled to reimbursement under this Article 12, the applicable Party shall make such reimbursement promptly but in no event later than ten (10) days after the presentation of a statement setting forth the amount of reimbursement to which the presenting Party is entitled along with such supporting evidence as is reasonably necessary to calculate the amount of the reimbursement.

Section 12.3 Tax Indemnity. From and after Closing, each Seller shall (on a several and not a joint and several basis and in proportion among the relevant Seller(s) equal to such Seller(s)’ Seller’s Interest Percentage), in proportion to each Seller’s applicable Seller’s Interest Percentage in the Assets affected (except in the case of Taxes described in subparagraph (iii), below, which

shall be borne solely by the applicable Seller), indemnify, defend and hold harmless the Purchaser Group from and against all Damages incurred, suffered by or asserted against such Persons that are caused by or arising out of (i) Asset Taxes for which Sellers are responsible pursuant to Section 12.1 or Section 12.2, (ii) any Asset Taxes not described in (i) that are attributable to the ownership or operation of the Assets prior to the Effective Time; and (iii) any other Taxes (other than Asset Taxes) imposed on a Seller or for which a Seller is otherwise liable.

Section 12.4 Characterization of Certain Payments. The Parties agree that any payments made pursuant to this Article 12, Article 11, Section 2.4 or Section 9.4 shall be treated for all Tax purposes as an adjustment to the Unadjusted Purchase Price unless otherwise required by Law.

Section 12.5 Withholding Taxes. All payments due to each Seller under this Agreement shall be made net of any applicable deduction or withholding for or on account of any Tax provided, however, that Purchaser shall provide at least ten (10) days’ notice to Sellers’ Representative if any such amounts will be withheld. In the event Purchaser is required to withhold or deduct an amount for or on account of Tax from any payment due under this Agreement, the amount deducted or withheld shall be treated as paid to the applicable Seller for all purposes of this Agreement.

ARTICLE 13

MISCELLANEOUS

Section 13.1 Counterparts. This Agreement may be executed in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement. A Party’s delivery of an executed counterpart signature page by facsimile (or email) is as effective as executing and delivering this Agreement in the presence of the other Party. Purchaser and any Seller executing counterparts of this Agreement shall be bound regardless whether any other Seller executes a counterpart, except that Purchaser shall not be bound with respect to any Seller until Black Hills and UPC have executed and delivered their signature pages to this Agreement.

Section 13.2 Notice. All notices and other communications that are required or may be given pursuant to this Agreement must be given in writing, in English and delivered personally, by courier, by facsimile or by registered or certified mail, postage prepaid, as follows:

If to Sellers:

For those matters for which Sellers’ Representative is expressly authorized under this Agreement to give or receive notices on behalf of Sellers:

Contact Copy

Unit Petroleum Company Unit Petroleum Company

7130 South Lewis, Suite 1000 7130 South Lewis, Suite 1000

Tulsa, Oklahoma 74136 Tulsa, Oklahoma 74136

Attn: Michael Earl Attn: Josh Dickens

Facsimile: 918-493-7711 Facsimile: 918-496-6302

Email: michael.earl@unitcorp.com Email: josh.dickens@unitcorp.com

For all other matters, to the above, and, as applicable:

Contact Copy

Black Hills Exploration And Production Black Hills Exploration And Production

1515 Wynkoop Street, Suite 500 1515 Wynkoop Street, Suite 500

Denver, Colorado 80202 Denver, Colorado 80202

Attn: John H. Benton Attn: Carleton Ekberg

Facsimile: 303-566-3345 Facsimile: 720-210-1301

Email: john.benton@blackhillscorp.com Email: carleton.ekberg@blackhillscorp.com

Sundance Energy Hogan Lovells

633 17^th Street, Suite 1950 1200 Seventeenth Street, Suite 1500

Denver, Colorado 80202 Denver, Colorado 80202

Attn: Eric McCrady Attn: Howard L. Boigon

Facsimile: 303-543-5701 Facsimile: 303-899-7333

Highline Exploration, Inc. Highline Exploration, Inc.

100 Towncenter Blvd., Suite 302 P.O. Box 20057

Tuscaloosa, AL 35406 Tuscaloosa, AL 35402

Attn: Gary Cox Attn: Mike Farrens

Facsimile: 205-752-3977 Facsimile: 205-752-3977

Email: gcox@hexpl.com Email: mfarrens@bellsouth.net

Houston Energy, L.P.

1415 Louisiana, Suite 2400

Houston, Texas 77002

Attn: Ronald E. Neal

Facsimile: (713) 650-8305

Nisku Royalty, LP

100 N. 27^th Street, Suite 400

Billings, MT 59101

Attn: Frank B. Haughton, Jr.

Facsimile: (406) 245-1615

Empire Oil Company

PO Box 1835

510 2^nd Street West

Williston, ND 58801

Attn: William R. LaCrosse

Fascimile: (701) 774-3537

Email: bill@empireoil.net

Kent M. Lynch

121 8th St West

Williston, ND 58801

Attn: Kent M. Lynch

Facsimile: (701) 774-0541

Email: mclynch@midco.net

If to Purchaser:

QEP Resources, Inc.

Independence Plaza

1050 17^th Street, Suite 500

Denver, CO 80265
Attn: Austin Murr, VP – Land and Business Development
Facsimile: 303-573-0307

Email: Austin.murr@qepres.com

With a copy (which shall not constitute notice) to:

QEP Resources, Inc.

Independence Plaza

1050 17^th Street, Suite 500

Denver, CO 80265
Attn: Abigail L. Jones, Vice President Compliance, and Corporate Secretary
Facsimile: 866.400.8834

Abby.jones@qepres.com

Either Party may change its address for notice by notice to the other Party in the manner set forth above. All notices shall be deemed to have been duly given at the time of receipt by the Party to which such notice is addressed.

Section 13.3 Tax, Recording Fees, Similar Taxes & Fees.

(a) Purchaser shall bear any sales, use, excise, real property transfer, gross receipts, goods and services, registration, capital, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees incurred and imposed upon, or with respect to, the property transfers or other transactions contemplated hereby. If such transfers or transactions are exempt from any such Taxes or fees upon the filing of an appropriate certificate or other evidence of exemption, the Party required to furnish such certificate or evidence will timely furnish such certificate or evidence to the other Party or the appropriate Government Body. The Parties anticipate that the transfer of tangible personal property contemplated hereby, if any, is exempt from North Dakota sales and use Taxes as a casual or occasional sale pursuant to North Dakota Sales Tax Rule 81-04.1-01-16.

(b) Except as otherwise provided herein, all costs and expenses (including legal and financial advisory fees and expenses) incurred in connection with, or in anticipation of, this Agreement and the transactions contemplated hereby shall be paid by the Party incurring such expenses.

Section 13.4 Governing Law; Jurisdiction.

(A) THIS AGREEMENT AND THE LEGAL RELATIONS BETWEEN THE PARTIES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW THAT WOULD REQUIRE THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION.

(B) THE PARTIES HEREBY IRREVOCABLY SUBMIT TO THE EXCLUSIVE JURISDICTION OF THE FEDERAL COURTS OF THE UNITED STATES OF AMERICA LOCATED IN HARRIS COUNTY, TEXAS (OR, IF REQUIREMENTS FOR FEDERAL JURISDICTION ARE NOT MET, STATE COURTS LOCATED IN HARRIS COUNTY, TEXAS) AND APPROPRIATE APPELLATE COURTS THEREFROM FOR THE RESOLUTION OF ANY DISPUTE, CONTROVERSY, OR CLAIM ARISING OUT OF OR IN RELATION TO THIS AGREEMENT, AND EACH PARTY HEREBY IRREVOCABLY AGREES THAT ALL CLAIMS IN RESPECT OF SUCH DISPUTE, CONTROVERSY OR CLAIM MAY BE HEARD AND DETERMINED IN SUCH COURTS. THE PARTIES HEREBY IRREVOCABLY WAIVE, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAWS, ANY OBJECTION WHICH THEY MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUCH DISPUTE, CONTROVERSY OR CLAIM BROUGHT IN ANY SUCH COURT OR ANY DEFENSE OF INCONVENIENT FORUM FOR THE MAINTENANCE OF SUCH DISPUTE, CONTROVERSY OR CLAIM. EACH PARTY AGREES THAT A JUDGMENT IN ANY SUCH DISPUTE MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY APPLICABLE LAW.

(C) EACH OF THE PARTIES HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THIS AGREEMENT.

Section 13.5 Waivers. Any failure by any Party to comply with any of its obligations, agreements or conditions herein contained may be waived by the Party to whom such compliance is owed by an instrument signed by such Party and expressly identified as a waiver, but not in any other manner. No waiver of, consent to a change in, or any delay in timely exercising any rights arising from, any of the provisions of this Agreement shall be deemed or shall constitute a waiver of, or consent to a change in, other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

Section 13.6 Assignment. No Party shall assign all or any part of this Agreement, nor shall any Party assign or delegate any of its rights or duties hereunder, without the prior written consent of the Sellers’ Representative in the case of an assignment by Purchaser and of Purchaser

in the case of an assignment by a Seller (which consent may be withheld for any reason) and any assignment or delegation made without such consent shall be void. Subject to the foregoing, this Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and assigns.

Section 13.7 Entire Agreement. This Agreement (including, for purposes of certainty, the Appendix, Exhibits and Schedules attached hereto), the documents to be executed hereunder constitute the entire agreement between the Parties pertaining to the subject matter hereof, and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof.

Section 13.8 Amendment. This Agreement may be amended or modified only by an agreement in writing executed by all Parties and expressly identified as an amendment or modification.

Section 13.9 No Third Party Beneficiaries. Nothing in this Agreement shall entitle any Person other than Purchaser and Sellers to any claims, cause of action, remedy or right of any kind, except the rights expressly provided in Section 4.2(f), Section 7.1(e) and Section 11.2 to the Persons described therein.

Section 13.10 Construction. The Parties acknowledge that (a) the Parties have had the opportunity to exercise business discretion in relation to the negotiation of the details of the transaction contemplated hereby, (b) this Agreement is the result of arms-length negotiations from equal bargaining positions and (c) the Parties and their respective counsel participated in the preparation and negotiation of this Agreement. Any rule of construction that a contract be construed against the drafter shall not apply to the interpretation or construction of this Agreement.

Section 13.11 Limitation on Damages. NOTWITHSTANDING ANYTHING TO THE CONTRARY, EXCEPT IN CONNECTION WITH ANY DAMAGES INCURRED BY THIRD PARTIES FOR WHICH INDEMNIFICATION IS SOUGHT UNDER THE TERMS OF THIS AGREEMENT, NONE OF PURCHASER, SELLERS OR ANY OF THEIR RESPECTIVE AFFILIATES SHALL BE ENTITLED TO CONSEQUENTIAL, SPECIAL, INDIRECT, PUNITIVE OR EXEMPLARY DAMAGES IN CONNECTION WITH THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY AND, EXCEPT AS OTHERWISE PROVIDED IN THIS SENTENCE, EACH OF PURCHASER AND SELLERS, FOR ITSELF AND ON BEHALF OF ITS AFFILIATES, HEREBY EXPRESSLY WAIVES ANY RIGHT TO CONSEQUENTIAL, SPECIAL, INDIRECT, PUNITIVE OR EXEMPLARY DAMAGES IN CONNECTION WITH THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 13.12 Recording. As soon as practicable after Closing, Purchaser shall record the Assignments and other assignments, if any, delivered at Closing in the appropriate counties as well as with any appropriate governmental agencies and provide Sellers’ Representative with copies of all recorded or approved instruments.

Section 13.13 Conspicuous. THE PARTIES AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE OR ENFORCEABLE, THE

PROVISIONS IN THIS AGREEMENT IN BOLD-TYPE FONT ARE “CONSPICUOUS” FOR THE PURPOSE OF ANY APPLICABLE LAW.

Section 13.14 Time of Essence. This Agreement contains a number of dates and times by which performance or the exercise of rights is due, and the Parties intend that each and every such date and time be the firm and final date and time, as agreed. For this reason, each Party hereby waives and relinquishes any right it might otherwise have to challenge its failure to meet any performance or rights election date applicable to it on the basis that its late action constitutes substantial performance, to require the other Party to show prejudice, or on any equitable grounds. Without limiting the foregoing, time is of the essence in this Agreement. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day that is a Business Day.

Section 13.15 Delivery of Records. Each Seller, at Purchaser’s cost and expense, shall deliver the Records to Purchaser within ten (10) days following Closing.

Section 13.16 Severability. The invalidity or unenforceability of any term or provision of this Agreement in any situation or jurisdiction shall not affect the validity or enforceability of the other terms or provisions hereof or the validity or enforceability of the offending term or provision in any other situation or in any other jurisdiction and the remaining terms and provisions shall remain in full force and effect, unless doing so would result in an interpretation of this Agreement that is manifestly unjust.

Section 13.17 Specific Performance. The Parties agree that if any of the provisions of this Agreement were not performed in accordance with their specific terms, irreparable damage would occur, no adequate remedy at Law would exist and damages would be difficult to determine, and the Parties shall be entitled to specific performance of the terms hereof and immediate injunctive relief, without the necessity of proving the inadequacy of money damages as a remedy, in addition to any other remedy available at law or in equity, subject to Section 10.3.

Section 13.18 Like-Kind Exchange. Each of Sellers and Purchaser agree that the other Party may elect to treat the acquisition or sale of the Assets or any portion thereof as an exchange of like-kind property under Section 1031 of the Code (“Exchange”). The applicable Seller and Purchaser each agrees to use reasonable efforts to cooperate with the other Party in the completion of such an Exchange including an Exchange subject to the procedures outlined in Treasury Regulation Section 1.1031(k)-1 and/or IRS Revenue Procedure 2000-37, 2000-2 C.B. 308 (as modified by IRS Revenue Procedure 2004-51, 2004-2 C.B. 294). Each of Sellers and Purchaser shall have the right at any time prior to Closing to assign its rights under this Agreement to a qualified intermediary (as that term is defined in Treasury Regulation Section 1.1031(k)-1(g)(4)(iii)) or an exchange accommodation titleholder (as that term is defined in IRS Revenue Procedure 2000-37, 2000-2 C.B. 308) to effect an Exchange. In connection with any such Exchange, any exchange accommodation title holder shall have taken all steps necessary to own the relevant Assets under applicable Law. Each of Sellers and Purchaser acknowledges and agrees that neither an assignment

of a Party’s rights under this Agreement nor any other actions taken by a Party or any other Person in connection with the Exchange shall release either Party from, or modify, any of their respective liabilities and obligations (including indemnity obligations to each other) under this Agreement, and neither Sellers nor Purchaser makes any representations as to any particular tax treatment that may be afforded to the other Party by reason of such assignment or any other actions taken in connection with the Exchange. Any Party electing to treat the acquisition or sale of the Assets as an Exchange shall be obligated to pay all additional costs incurred hereunder as a result of the Exchange, and in consideration for the cooperation of the other Party, the Party electing Exchange treatment shall agree to pay all costs associated with the Exchange and to indemnify and hold such other Party and its Affiliates, officers, directors, partners, members, employees, and agents harmless from and against any and all liabilities and Taxes arising out of, based upon, attributable to or resulting from the Exchange or transactions or actions taken in connection with the Exchange that would not have been incurred by the other Party but for the electing Party’s Exchange election.

[Signature page follows]

IN WITNESS WHEREOF, this Agreement has been signed by each of the Parties on the Execution Date.

SELLERS:

UNIT PETROLEUM COMPANY

By: /s/ Mark E. Schell
Name: Mark E. Schell
Title: Senior Vice President

SELLERS:

BLACK HILLS EXPLORATION AND PRODUCTION, INC.

By: /s/ David R. Emery
Name: David R. Emery
Title: Chairman, President and CEO