SEC Filing | QEP Resources, Inc.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2016



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: 001-34778

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)



STATE OF DELAWARE		87-0287750
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

1050 17^th Street, Suite 800, Denver, Colorado 80265

(Address of principal executive offices)

Registrant’s telephone number, including area code (303) 672-6900

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 ý 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 (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý 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. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act:



Large accelerated filer	ý	Accelerated filer	o
Non-accelerated filer	o (Do not check if a smaller reporting company)	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 oNo ý

At June 30, 2016, there were 239,605,692 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2016

TABLE OF CONTENTS



			Page
PART I. FINANCIAL INFORMATION			2

	ITEM 1.	FINANCIAL STATEMENTS	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2016 AND 2015	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2016 AND 2015	3

		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT JUNE 30, 2016 AND DECEMBER 31, 2015	4

		UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF EQUITY FOR THE SIX MONTHS ENDED JUNE 30, 2016	5

		UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2016 AND 2015	6

		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	7

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	38

	ITEM 4.	CONTROLS AND PROCEDURES	43

PART II. OTHER INFORMATION			43

	ITEM 1.	LEGAL PROCEEDINGS	43

	ITEM 1A.	RISK FACTORS	43

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	45

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	45

	ITEM 4.	MINE SAFETY DISCLOSURES	45

	ITEM 5.	OTHER INFORMATION	45

	ITEM 6.	EXHIBITS	45

SIGNATURES			47

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
REVENUES	(in millions, except per share amounts)
Gas sales	$	79.2		$	111.9		$	164.3		$	233.9
Oil sales	207.7			250.4			351.5			429.2
NGL sales	22.8			26.1			36.4			45.2
Other revenue (loss)	(0.5		)	5.2			1.8			9.6
Purchased gas and oil sales	24.5			181.0			41.0			324.8
Total Revenues	333.7			574.6			595.0			1,042.7
OPERATING EXPENSES
Purchased gas and oil expense	26.8			183.2			43.7			329.1
Lease operating expense	52.6			57.1			112.6			118.9
Gas, oil and NGL transportation and other handling costs	69.5			73.0			143.1			138.1
Gathering and other expense	1.6			1.4			2.9			3.1
General and administrative	43.7			51.3			92.4			98.7
Production and property taxes	20.7			32.7			38.5			60.5
Depreciation, depletion and amortization	209.7			215.8			449.7			411.2
Exploration expenses	0.4			0.8			0.7			1.9
Impairment	0.8			0.5			1,183.2			20.5
Total Operating Expenses	425.8			615.8			2,066.8			1,182.0
Net gain (loss) from asset sales	(0.8		)	24.5			(0.3		)	(6.0		)
OPERATING INCOME (LOSS)	(92.9		)	(16.7		)	(1,472.1		)	(145.3		)
Realized and unrealized gains (losses) on derivative contracts (See Note 7)	(180.5		)	(66.0		)	(129.6		)	14.9
Interest and other income (expense)	(0.3		)	3.8			2.0			1.2
Interest expense	(36.6		)	(36.2		)	(73.3		)	(73.0		)
INCOME (LOSS) BEFORE INCOME TAXES	(310.3		)	(115.1		)	(1,673.0		)	(202.2		)
Income tax (provision) benefit	113.3			38.8			612.2			70.3
NET INCOME (LOSS)	$	(197.0	)	$	(76.3	)	$	(1,060.8	)	$	(131.9	)

Earnings (loss) per common share
Basic	$	(0.90	)	$	(0.43	)	$	(5.21	)	$	(0.75	)
Diluted	$	(0.90	)	$	(0.43	)	$	(5.21	)	$	(0.75	)

Weighted-average common shares outstanding
Used in basic calculation	217.7			176.7			203.7			176.4
Used in diluted calculation	217.7			176.7			203.7			176.4
Dividends per common share	$	—		$	0.02		$	—		$	0.04

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	(in millions)
Net income (loss)	$	(197.0	)	$	(76.3	)	$	(1,060.8	)	$	(131.9	)
Other comprehensive income, net of tax:
Pension and other postretirement plans adjustments:
Amortization of net actuarial losses ⁽¹⁾	0.2			—			0.3			0.2
Amortization of prior service costs ⁽²⁾	0.2			0.1			0.3			0.6
Other comprehensive income	0.4			0.1			0.6			0.8
Comprehensive income (loss)	$	(196.6	)	$	(76.2	)	$	(1,060.2	)	$	(131.1	)

____________________________


⁽¹⁾	Presented net of income tax expense of $0.2 million and $0.3 million during the three and six months ended June 30, 2016, respectively. Presented net of income tax expense of $0.1 million for the six months ended June 30, 2015.


⁽²⁾	Presented net of income tax of $0.2 million for the three and six months ended June 30, 2016. Presented net of income tax expense of $0.1 million and $0.4 million during the three and six months ended June 30, 2015, respectively.

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2016			December 31, 2015
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	1,038.3		$	376.1
Accounts receivable, net	132.5			278.2
Income tax receivable	170.5			87.3
Fair value of derivative contracts	1.4			146.8
Gas, oil and NGL inventories, at lower of average cost or market	7.2			13.3
Prepaid expenses and other	21.4			30.1
Total Current Assets	1,371.3			931.8
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	13,556.8			13,314.9
Unproved properties	670.2			691.0
Marketing and other	297.9			297.9
Materials and supplies	29.4			38.5
Total Property, Plant and Equipment	14,554.3			14,342.3
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	8,440.6			6,870.2
Marketing and other	95.1			87.5
Total Accumulated Depreciation, Depletion and Amortization	8,535.7			6,957.7
Net Property, Plant and Equipment	6,018.6			7,384.6
Fair value of derivative contracts	—			23.2
Other noncurrent assets	91.8			58.6
TOTAL ASSETS	$	7,481.7		$	8,398.2
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	—		$	29.8
Accounts payable and accrued expenses	213.8			351.7
Production and property taxes	39.7			46.1
Interest payable	37.9			36.4
Fair value of derivative contracts	46.6			0.8
Current portion of long-term debt	176.8			176.8
Total Current Liabilities	514.8			641.6
Long-term debt	2,017.8			2,014.7
Deferred income taxes	920.2			1,479.8
Asset retirement obligations	207.7			204.9
Fair value of derivative contracts	33.1			4.0
Other long-term liabilities	108.0			105.3
Commitments and contingencies (Note 10)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 240.6 million and 177.3 million shares issued, respectively	2.4			1.8
Treasury stock – 1.0 million and 0.5 million shares, respectively	(20.6		)	(14.6		)
Additional paid-in capital	1,352.6			554.8
Retained earnings	2,357.5			3,418.3
Accumulated other comprehensive income	(11.8		)	(12.4		)
Total Common Shareholders' Equity	3,680.1			3,947.9
TOTAL LIABILITIES AND EQUITY	$	7,481.7		$	8,398.2

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)



	Common Stock			Treasury Stock					Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income(Loss)			Total
	Shares	Amount		Shares		Amount			Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income(Loss)			Total
	(in millions)
Balance at December 31, 2015	177.3	$	1.8	(0.5	)	$	(14.6	)	$	554.8	$	3,418.3		$	(12.4	)	$	3,947.9
Net income (loss)	—	—		—		—			—		(1,060.8		)	—			(1,060.8		)
Equity issuance, net of offering costs	61.0	0.6		—		—			781.0		—			—			781.6
Share-based compensation	2.3	—		(0.5	)	(6.0		)	16.8		—			—			10.8
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—			0.6			0.6
Balance at June 30, 2016	240.6	$	2.4	(1.0	)	$	(20.6	)	$	1,352.6	$	2,357.5		$	(11.8	)	$	3,680.1

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended
	June 30,
	2016			2015
	(in millions)
OPERATING ACTIVITIES
Net income (loss)	$	(1,060.8	)	$	(131.9	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	449.7			411.2
Deferred income taxes	(559.9		)	(29.4		)
Impairment	1,183.2			20.5
Share-based compensation	19.1			15.6
Pension curtailment loss	—			11.2
Amortization of debt issuance costs and discounts	3.2			3.3
Net (gain) loss from asset sales	0.3			6.0
Unrealized (gains) losses on marketable securities	(0.5		)	—
Unrealized (gains) losses on derivative contracts	243.5			181.8
Changes in operating assets and liabilities	(58.2		)	(490.9		)
Net Cash Provided by (Used in) Operating Activities	219.6			(2.6		)
INVESTING ACTIVITIES
Property acquisitions	(23.6		)	—
Acquisition deposit held in escrow	(30.0		)	—
Property, plant and equipment, including dry exploratory well expense	(276.6		)	(651.3		)
Proceeds from disposition of assets	23.7			(2.4		)
Net Cash Provided by (Used in) Investing Activities	(306.5		)	(653.7		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(29.8		)	(47.3		)
Treasury stock repurchases	(3.1		)	(1.9		)
Other capital contributions	0.2			(0.1		)
Dividends paid	—			(7.1		)
Proceeds from issuance of common stock, net	781.6			—
Excess tax (provision) benefit on share-based compensation	0.2			(1.8		)
Net Cash Provided by (Used in) Financing Activities	749.1			(58.2		)
Change in cash and cash equivalents	662.2			(714.5		)
Beginning cash and cash equivalents	376.1			1,160.1
Ending cash and cash equivalents	$	1,038.3		$	445.6

Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	68.6		$	69.7
Cash paid for income taxes	$	32.4		$	548.5
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$	(27.7	)	$	(91.6	)

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation

Nature of Business

QEP Resources, Inc. is an independent natural gas and crude oil exploration and production company focused in two regions of the United States: the Northern Region (primarily in Wyoming, North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

Basis of Presentation of Interim Condensed Consolidated Financial Statements

The interim Condensed Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Condensed Consolidated Financial Statements were prepared in accordance with United States Generally Accepted Accounting Principles (GAAP) and with the instructions for Quarterly Reports on Form 10-Q and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.

The Condensed Consolidated Financial Statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements and the year-end balance sheet do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.

The preparation of the Condensed Consolidated Financial Statements and Notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three and six months ended June 30, 2016, are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

Equity Offerings

In June 2016, QEP issued 23.0 million additional shares of common stock through a public offering and received net proceeds of approximately $413.0 million. QEP intends to use the net proceeds from this offering to partially fund the 2016 Permian Acquisition (defined below). If the acquisition is not consummated, QEP intends to use the net proceeds from this offering for general corporate purposes, which may include, among other things, reducing indebtedness, acquiring properties and funding a portion of our exploration and production activities and working capital.

In March 2016, QEP issued 37.95 million additional shares of common stock through a public offering and received net proceeds of approximately $368.6 million. QEP used the net proceeds from this offering for general corporate purposes.

Termination of Marketing Agreements and QEP Marketing Segment

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and the Haynesville gathering system. As a result, QEP Energy is directly marketing its own gas, oil and NGL production. While QEP will continue to act as an agent for the sale of gas, oil and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had in prior periods. In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP has one reportable segment effective January 1, 2016.

Revision of Financial Statements

In the fourth quarter of 2015, the Company determined that certain transactions that had been reported on a gross basis and included in "Purchased gas and oil sales" and "Purchased gas and oil expense" on the Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2015, should have been reported on a net basis, as the transactions were with the same counterparty and were entered into in contemplation of one another. The Company revised its financial statements to reflect the net accounting treatment and assessed the cumulative impact of the revisions on each period affected. The revisions had no effect on the Company’s operating income, net income, earnings per share, cash flows or retained earnings. The Company determined that the impact of the change from gross to net accounting was not material, either individually or in the aggregate, to previously issued financial statements. The Company has, for comparability purposes, recast its Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2015.

The following table details the impact of these revisions for the three and six months ended June 30, 2015, on the Condensed Consolidated Statement of Operations.



	Three Months Ended June 30, 2015							Six Months Ended June 30, 2015
	As reported		As revised		Change			As reported		As revised		Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	215.0	$	181.0	$	(34.0	)	$	382.3	$	324.8	$	(57.5	)
Total Revenues	608.6		574.6		(34.0		)	1,100.2		1,042.7		(57.5		)
OPERATING EXPENSES
Purchased gas and oil expense	$	217.2	$	183.2	$	(34.0	)	$	386.6	$	329.1	$	(57.5	)
Total Operating Expenses	649.8		615.8		(34.0		)	1,239.5		1,182.0		(57.5		)

Reclassifications

Certain prior period balances in the Condensed Consolidated Balance Sheets have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's operating income, net income, earnings per share, cash flows or retained earnings previously reported.

Impairment of Long-Lived Assets

During the six months ended June 30, 2016, QEP recorded impairment expense of $1,183.2 million, of which $1,167.9 million was related to proved properties due to lower future oil and gas prices, $11.6 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill. Of the $1,167.9 million impairment on proved properties, $1,164.0 million related to Pinedale properties, $3.5 million related to Other Northern properties and $0.4 million related to Other Southern properties.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclosing key quantitative and qualitative information about leasing arrangements. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment will be effective prospectively for reporting periods beginning on or after December 31, 2016, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-08, Revenue from contracts with customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principle versus agent considerations. The amendment will be effective prospectively for reporting periods beginning on or after December 31,

2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In April 2016, the FASB issued ASU No. 2016-10, Revenue from contracts with customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In May 2016, the FASB issued ASU No. 2016-11, Revenue recognition (Topic 605) and Derivatives and hedging (Topic 815): Rescission of SEC guidance because of ASU 2014-09 and 2014-16, which rescinds certain SEC staff observer comments that are codified in Topic 605, Revenue Recognition. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from contracts with customers (Topic 606): Narrow-scope improvements and practical expedients, which intends to reduce the cost and complexity of applying the new revenue standard by narrowing the scope of improvements to the guidance on collectability, non-cash consideration, and completed contracts at transition. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

Note 2 – Acquisitions and Divestitures

In June 2016, QEP entered into a purchase and sale agreement to acquire oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $600.0 million, subject to customary purchase price adjustments (the 2016 Permian Acquisition). The 2016 Permian Acquisition consists of approximately 9,400 net acres in Martin County, Texas, which are primarily held by production from 96 vertical wells. The 2016 Permian Acquisition is expected to close in September 2016, and the Company plans to fund the transaction with proceeds from the June 2016 equity offering and cash on hand.

During the six months ended June 30, 2016, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for an aggregate purchase price of $29.8 million, which primarily included additional interests in QEP's operated wells and additional undeveloped leasehold. As a part of the purchase price allocation, the Company recorded $3.7 million of goodwill.

During the six months ended June 30, 2016, QEP received proceeds of $23.7 million and recorded a pre-tax loss on sale of $0.3 million primarily related to the divestiture of certain non-core properties in Other Southern. Additionally, during the six months ended June 30, 2015, QEP recorded a pre-tax loss on sale of $6.0 million, primarily due to post-closing purchase price adjustments related to 2014 divestitures.

Note 3 – Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP’s unvested restricted shares are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted shares are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares are eligible to receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company’s unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company’s unvested restricted stock does not have a contractual

obligation to share in losses of the Company. The Company’s unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. During the three and six months ended June 30, 2016, there were anti-dilutive shares of 0.1 million not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss. During the three and six months ended June 30, 2015, there were no anti-dilutive shares.

A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
	(in millions)
Weighted-average basic common shares outstanding	217.7	176.7	203.7	176.4
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	—	—	—	—
Average diluted common shares outstanding	217.7	176.7	203.7	176.4

Note 4 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below. The balance at June 30, 2016, represents the amount of capitalized exploratory well costs that are pending the determination of proved reserves.



	Capitalized Exploratory Well Costs
	2016
	(in millions)
Balance at January 1,	$	2.6
Additions to capitalized exploratory well costs pending the determination of proved reserves	11.0
Reclassification to proved properties after the determination of proved reserves	—
Capitalized exploratory well costs charged to expense	(0.1		)
Balance at June 30,	$	13.5

Note 5 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $211.0 million and $206.8 million ARO liability for the periods ended June 30, 2016 and December 31, 2015, respectively, $3.3 million and $1.9 million, respectively, were included as a liability within "Accounts payable and accrued expenses" on the Condensed Consolidated Balance Sheets.

The following is a reconciliation of the changes in the Company's ARO for the period specified below:



	Asset Retirement Obligations
	2016
	(in millions)
ARO liability at January 1,	$	206.8
Accretion	4.3
Additions	2.4
Liabilities settled	(2.5		)
ARO liability at June 30,	$	211.0

Note 6 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (see Note 7 – Derivative Contracts) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.

Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists.

The fair value of financial assets and liabilities at June 30, 2016 and December 31, 2015, is shown in the table below:



	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
	June 30, 2016
	(in millions)
Financial Assets
Commodity derivative instruments – short-term	$	—	$	7.7	$	—	$	(6.3	)	$	1.4
Commodity derivative instruments – long-term	—		0.6		—		(0.6		)	—
Total financial assets	$	—	$	8.3	$	—	$	(6.9	)	$	1.4

Financial Liabilities
Commodity derivative instruments – short-term	$	—	$	52.9	$	—	$	(6.3	)	$	46.6
Commodity derivative instruments – long-term	—		33.7		—		(0.6		)	33.1
Total financial liabilities	$	—	$	86.6	$	—	$	(6.9	)	$	79.7

	December 31, 2015
	(in millions)
Financial Assets
Commodity derivative instruments – short-term	$	—	$	147.8	$	—	$	(1.0	)	$	146.8
Commodity derivative instruments – long-term	—		23.2		—		—			23.2
Total financial assets	$	—	$	171.0	$	—	$	(1.0	)	$	170.0

Financial Liabilities
Commodity derivative instruments – short-term	$	—	$	1.8	$	—	$	(1.0	)	$	0.8
Commodity derivative instruments – long-term	—		4.0		—		—			4.0
Total financial liabilities	$	—	$	5.8	$	—	$	(1.0	)	$	4.8

_______________________


⁽¹⁾	The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Condensed Consolidated Balance Sheets, as the contracts contain netting provisions. Refer to Note 7 – Derivative Contracts, for additional information regarding the Company's derivative contracts.

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes accompanying the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q:



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	June 30, 2016				December 31, 2015
	(in millions)
Financial Assets
Cash and cash equivalents	$	1,038.3	$	1,038.3	$	376.1	$	376.1
Financial Liabilities
Checks outstanding in excess of cash balances	$	—	$	—	$	29.8	$	29.8
Long-term debt	$	2,194.6	$	2,150.1	$	2,191.5	$	1,784.6

The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company’s debt at the end of the quarter. The carrying amount of variable-rate, long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company’s ARO is presented in Note 5 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a nonrecurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the six months ended June 30, 2016 and 2015, the Company recorded impairments on certain proved oil and gas properties of $1,167.9 million and $19.4 million, respectively, resulting in a reduction of the associated carrying value to fair value. The fair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. Given the unobservable nature of the inputs, proved oil and gas property impairments are considered Level 3 within the fair value hierarchy.

Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date which utilizes the following inputs to estimate future net cash flows: estimated quantities of gas, oil and NGL reserves; estimates of future commodity prices; and estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the properties is considered Level 3 within the fair value hierarchy.

Note 7 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production from proved reserves, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. In addition, QEP may enter into commodity derivative contracts on a portion of its storage transactions. QEP does not enter into commodity derivative instruments for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps or collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of gas or oil between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Gas price derivative instruments are typically structured as fixed-price swaps or collars at regional price indices. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma or oil price swaps that use Intercontinental Exchange, Inc. (ICE) Brent oil prices as the reference price. QEP also enters into crude oil and natural gas basis swaps to achieve a fixed-price swap for a portion of its oil and gas sales at prices that reference specific regional index prices.

QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. Commodity derivative contract counterparties are normally financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and avoids concentration of credit exposure by transacting with multiple counterparties. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

Derivative Contracts – Production

The following table sets forth QEP’s quantities and average prices for its commodity derivative swap contracts as of June 30, 2016:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2016	NYMEX HH	29.4	$	2.78
2016	IFNPCR	36.8	$	2.53
2017	NYMEX HH	73.0	$	2.75
2017	IFNPCR	32.9	$	2.51
2018	NYMEX HH	7.3	$	2.80
Oil sales		(bbls)	($/bbl)
2016	NYMEX WTI	6.1	$	51.24
2017	NYMEX WTI	9.1	$	50.76
2018	NYMEX WTI	1.1	$	53.72

The following table sets forth details of QEP's gas collars as of June 30, 2016:



Year	Index	Total Volume	Average Price Floor		Average Price Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	3.7	$	2.75	$	3.89
2017	NYMEX HH	11.0	$	2.50	$	3.50

QEP uses gas basis swaps, combined with NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table sets forth details of QEP's gas basis swaps as of June 30, 2016:



Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2016	NYMEX HH	IFNPCR	18.4	$	(0.16	)
2017	NYMEX HH	IFNPCR	51.1	$	(0.18	)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)

Derivative Contracts – Storage

QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table sets forth QEP’s quantities and average prices for its storage commodity derivative swap contracts as of June 30, 2016:



Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2016	SWAP	IFNPCR	2.3	$	2.57
2017	SWAP	IFNPCR	2.4	$	2.77
Gas purchases
2016	SWAP	IFNPCR	1.8	$	2.43

QEP Derivative Financial Statement Presentation

The following table identifies the Condensed Consolidated Balance Sheet location of QEP’s outstanding derivative contracts on a gross contract basis as opposed to the net contract basis presentation in the Condensed Consolidated Balance Sheets and the related fair values at the balance sheet dates:



		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	June 30, 2016		December 31, 2015		June 30, 2016		December 31, 2015
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	7.7	$	147.8	$	52.9	$	1.8
Long-term:
Commodity	Fair value of derivative contracts	0.6		23.2		33.7		4.0
Total derivative instruments		$	8.3	$	171.0	$	86.6	$	5.8

The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Condensed Consolidated Statements of Operations are summarized in the following table:



	Three Months Ended						Six Months Ended
Derivative instruments not designated as cash flow hedges	June 30,						June 30,
Derivative instruments not designated as cash flow hedges	2016			2015			2016			2015
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Gas derivative contracts	$	28.9		$	28.1		$	50.4		$	46.0
Oil derivative contracts	19.9			64.5			60.7			148.5
Storage
Gas derivative contracts	0.7			(0.3		)	2.8			2.2
Total realized gains (losses) on commodity derivative contracts	49.5			92.3			113.9			196.7
Unrealized gains (losses) on commodity derivative contracts
Production
Gas derivative contracts	(120.2		)	(34.5		)	(104.8		)	(23.1		)
Oil derivative contracts	(107.7		)	(123.7		)	(135.6		)	(156.8		)
Storage
Gas derivative contracts	(2.1		)	(0.1		)	(3.1		)	(1.9		)
Total unrealized gains (losses) on commodity derivative contracts	(230.0		)	(158.3		)	(243.5		)	(181.8		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(180.5	)	$	(66.0	)	$	(129.6	)	$	14.9

Note 8 – Restructuring Costs

In April 2016, the Company streamlined its organizational structure, resulting in a reduction of approximately 6% of its total workforce. The Company estimates that the total costs related to the 2016 restructuring will be approximately $1.9 million, all of which is related to one-time termination benefits. During the three and six months ended June 30, 2016, restructuring costs of $1.8 million were incurred and paid related to the 2016 restructuring. The Company estimates that the remaining $0.1 million of restructuring costs related to the 2016 restructuring will be incurred during the remainder of 2016.

During 2015, QEP had multiple restructuring events, including the closure of its Tulsa office, which occurred in the third quarter of 2015. The Company estimates that the total costs related to the 2015 restructuring events will be approximately $8.5 million, of which approximately $5.3 million is related to one-time termination benefits and approximately $3.2 million is related to relocation of certain employees. During the three and six months ended June 30, 2016, restructuring costs of $0.2 million and $0.5 million, respectively, were incurred and paid related to the Tulsa office closure, all of which were related to the relocation of certain employees. The Company estimates that the remaining $0.3 million of restructuring costs related to the 2015 restructuring events will be incurred during the remainder of 2016.

All restructuring costs were recorded within "General and administrative" expense on the Condensed Consolidated Statement of Operations.

Note 9 – Debt

As of the indicated dates, the principal amount of QEP’s debt consisted of the following:



	June 30, 2016			December 31, 2015
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
6.05% Senior Notes due 2016	176.8			176.8
6.80% Senior Notes due 2018	134.0			134.0
6.80% Senior Notes due 2020	136.0			136.0
6.875% Senior Notes due 2021	625.0			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
Less: unamortized discount and unamortized debt issuance costs	(27.2		)	(30.3		)
Total principal amount of debt (including current portion)	2,194.6			2,191.5
Less: current portion of long-term debt	(176.8		)	(176.8		)
Total long-term debt outstanding	$	2,017.8		$	2,014.7

Of the total debt outstanding on June 30, 2016, the 6.05% Senior Notes due September 1, 2016, the 6.80% Senior Notes due April 1, 2018, the 6.80% Senior Notes due March 1, 2020 and the 6.875% Senior Notes due March 1, 2021, will mature within the next five years. In addition, the revolving credit facility matures on December 2, 2019.

Credit Facility

QEP’s revolving credit facility, which matures in December 2019, provides for loan commitments of $1.8 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary provisions and restrictions. The credit agreement contains financial covenants (as defined in the credit agreement) that limit the amount of debt the Company may incur and may limit the amount available to be drawn under the credit facility, including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarters ending on and prior to December 31, 2017, and 3.75 times thereafter and (iii) a present value coverage ratio under which the present value of the Company’s proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2018, and 1.50 times at any time on or after January 1, 2018. At June 30, 2016, QEP was in compliance with the covenants under the credit agreement.

During the six months ended June 30, 2016 and 2015, QEP had no borrowings under the credit facility. Additionally, as of June 30, 2016 and December 31, 2015, QEP had no borrowings outstanding under the credit facility and had $2.8 million and $3.4 million, respectively, in letters of credit outstanding under the credit facility.

Senior Notes

At June 30, 2016, the Company had $2,221.8 million principal amount of senior notes outstanding with maturities ranging from September 2016 to May 2023 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP’s senior notes contain customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

Note 10 – Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Condensed Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable, and unfavorable resolutions can occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including

the potential defenses, procedural status of the matter in question, the presence of complex legal or factual issues, or the ongoing discovery and/or development of information important to the matter.

Litigation

Rocky Mountain Resources Lawsuit – Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint in March 2011, seeking determination of the existence of a 4% overriding royalty interest in an oil and gas lease. Rocky Mountain alleges that the defendants have failed to pay Rocky Mountain monies associated with the claimed 4% overriding royalty interest since the issuance of the lease by the State of Wyoming in 1980. In February 2015, a jury rendered a verdict against the Company and awarded Rocky Mountain damages in the amount of $16.7 million, including interest. The Company is appealing the verdict to the Wyoming Supreme Court, and, in connection with such appeal, has posted a bond for approximately $20.0 million (representing the amount of the verdict and two years of accrued interest at the statutory rate of 10%). In accordance with the Court’s order, the Company is depositing the future monthly revenues attributable to the 4% overriding royalty interest with the Court as it becomes due and payable. The overriding royalty payments will be subject to the direction of the Court following the conclusion of the appeal. QEP estimates that, notwithstanding the verdict, the range of reasonably possible losses in excess of current accruals, if any, is zero to approximately $20.0 million.

Claims of Former Limited Partners – The Company received a demand from certain former limited partners of terminated drilling partnerships of the Company (acting as the general partner). The former limited partners allege that distributions to which they were entitled from the drilling partnerships were not made or were calculated incorrectly. Other former limited partners may assert claims. No litigation has been filed, and the Company is in the process of evaluating the allegations and its defenses. The Company believes that it is not possible to reasonably estimate a range of possible losses at this time. The cost to settle legal proceedings (alleged or threatened), or satisfy any resulting judgment against the Company in such proceedings could result in a substantial liability, which could materially and adversely impact the Company’s cash flows and operating results for a particular period.

Arbitration Regarding Gas Purchase Agreement – An entity that purchases, gathers and processes natural gas produced from oil wells operated by the Company in the Williston Basin has claimed that the decline in commodity prices has rendered its gathering and processing operations "uneconomic" and demanded that, effective March 1, 2016, QEP pay additional fees for gathering and processing services. The midstream provider has been unwilling to connect new wells unless the Company agrees to pay the increased fees for production from the new wells. QEP initiated arbitration proceedings in May 2016 to enforce the terms of the existing agreement. The Company estimates that, notwithstanding the arbitration outcome, the range of reasonably possible losses in excess of current accruals, if any, is zero to approximately $2.5 million per month, effective March 1, 2016.

Note 11 – Share-Based Compensation

QEP issues stock options, restricted shares and restricted share units under its Long-Term Stock Incentive Plan (LTSIP) and awards performance share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes the expense over the vesting periods for the stock options, restricted shares, restricted share units and performance share units. There were 7.1 million shares available for future grants under the LTSIP at June 30, 2016.

Share-based compensation expense is recognized within "General and administrative" expense on the Condensed Consolidated Statements of Operations and is summarized in the table below:



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2016		2015			2016		2015
	(in millions)
Stock options	$	0.5	$	0.7		$	1.2	$	1.5
Restricted share awards	5.7		6.4			12.2		12.7
Performance share units	4.8		(0.6		)	5.6		1.4
Restricted share units	0.1		—			0.1		—
Total share-based compensation expense	$	11.1	$	6.5		$	19.1	$	15.6

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of the grant. Fair value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for measuring the value of options traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares.

The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below for the six months ended June 30, 2016:



	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	3.76
Weighted-average risk-free interest rate	1.15		%
Weighted-average expected price volatility	43.4		%
Expected dividend yield	—		%
Expected term in years at the date of grant	4.5

Stock option transactions under the terms of the LTSIP are summarized below:



	Options Outstanding		Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2015	2,200,776		$	27.94
Granted	436,726		10.12
Canceled	(486,999	)	23.77
Outstanding at June 30, 2016	2,150,503		$	25.27	4.17	$	3.3
Options Exercisable at June 30, 2016	1,348,779		$	30.52	3.03	$	—
Unvested Options at June 30, 2016	801,724		$	16.43	6.07	$	3.3

During the six months ended June 30, 2016, there were no exercises of stock options. During the six months ended June 30, 2015, the total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.1 million. As of June 30, 2016, $2.3 million of unrecognized compensation cost related to stock options granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average period of 2.22 years.

Restricted Share Awards

Restricted share grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The total fair value of restricted stock that vested during the six months ended June 30, 2016 and 2015, was $21.4 million and $18.1 million, respectively. The weighted-average grant date fair value of restricted stock was $10.25 per share and $21.66 per share for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016, $28.8 million of unrecognized compensation cost related to restricted shares granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average vesting period of 2.34 years.

Transactions involving restricted shares under the terms of the LTSIP are summarized below:



	Restricted Shares Outstanding		Weighted- Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	2,008,210		$	24.18
Granted	2,390,046		10.25
Vested	(829,128	)	25.79
Forfeited	(201,802	)	14.27
Unvested balance at June 30, 2016	3,367,326		$	14.49

Performance Share Units

The performance share units' cash payouts are dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units and have historically been delivered in cash. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of June 30, 2016, the Company expects to settle all awards in cash. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Condensed Consolidated Balance Sheet. As these awards are dependent upon the Company's total shareholder return and stock price, they are remeasured at fair value at the end of each reporting period. The weighted-average grant date fair value of the performance share units was $10.12 per share and $21.69 per share for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016, $16.7 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.15 years.

Transactions involving performance share units under the terms of the CIP are summarized below:



	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
Unvested balance at December 31, 2015	630,786		$	27.50
Granted	594,245		10.12
Vested and Paid	(178,169	)	30.07
Forfeited	(3,942	)	28.42
Unvested balance at June 30, 2016	1,042,920		$	17.15

Restricted Share Units

Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfunded deferred compensation plan at the time of vesting. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Condensed Consolidated Balance Sheet. As these awards are dependent upon the Company's stock price, they are remeasured at fair value at the end of each reporting period. The weighted-average grant date fair value of the restricted share units was $10.12 per share for the six months ended June 30, 2016. As of June 30, 2016, $0.3 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 2.86 years.

Transactions involving restricted share units under the terms of the LTSIP are summarized below:



	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
Unvested balance at December 31, 2015	—		$	—
Granted	21,493		10.12
Vested	(193	)	10.12
Forfeited	(3,266	)	10.12
Unvested balance at June 30, 2016	18,034		$	10.12

Note 12 – Employee Benefits

Pension and Other Postretirement Benefits

The Company provides pension and other postretirement benefits to certain employees through three retirement benefit plans: the QEP Resources, Inc. Retirement Plan (the Pension Plan), the Supplemental Executive Retirement Plan (SERP), and a postretirement medical plan (the Medical Plan).

As a result of the Company's divestitures in 2014 and retirements in 2015, the number of active participants in the Pension Plan fell to 50 employees during the year ended December 31, 2015, which is the minimum number of active participants for a plan to be qualified under the Internal Revenue Services' participation rules. In order to prevent disqualification, the Pension Plan was amended in June 2015 and was frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services.

The Pension Plan is a closed, qualified defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the six months ended June 30, 2016, the Company made contributions of $4.0 million to the Pension Plan and does not expect to make additional contributions to the Pension Plan during the remainder of 2016. Contributions to the Pension Plan increase plan assets.

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the six months ended June 30, 2016, the Company made contributions of $1.5 million to its SERP and expects to contribute an additional $2.1 million to its SERP during the remainder of 2016. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and was closed to new participants effective January 1, 2016.

The Medical Plan is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired employees. During the six months ended June 30, 2016, the Company made contributions of $0.1 million to its Medical Plan and expects to contribute an additional $0.2 million to its Medical Plan during the remainder of 2016. Contributions to the Medical Plan are used to fund current benefit payments.

The following table sets forth the Company’s net periodic benefit costs related to its Pension Plan, SERP and Medical Plan:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.4		$	0.4		$	0.6		$	1.0
Interest cost	1.4			1.1			2.6			2.4
Expected return on plan assets	(1.4		)	(1.4		)	(2.8		)	(2.8		)
Amortization of prior service costs ⁽¹⁾	0.3			0.1			0.4			0.9
Amortization of actuarial losses ⁽¹⁾	0.4			—			0.6			0.3
Curtailment loss ⁽²⁾	—			11.2			—			11.2
Periodic expense	$	1.1		$	11.4		$	1.4		$	13.0

Medical Plan benefits
Interest cost	$	—		$	—		$	0.1		$	0.1
Amortization of prior service costs ⁽¹⁾	0.1			0.1			0.1			0.1
Periodic expense	$	0.1		$	0.1		$	0.2		$	0.2

____________________________


⁽¹⁾	Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income are recognized in the Condensed Consolidated Statements of Operations within "General and administrative" expense.


⁽²⁾	A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses are included on the Condensed Consolidated Statements of Operations within "General and administrative" expense for the three and six months ended June 30, 2015.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

The following information updates the discussion of QEP's financial condition provided in its 2015 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three and six months ended June 30, 2016 and 2015. For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the "Glossary of Commonly Used Terms" provided in QEP's 2015 Annual Report on Form 10-K.

OVERVIEW

The Company has substantial acreage positions and operations in some of the most prolific hydrocarbon resource plays in the continental United States, including the Williston Basin, Permian Basin, Pinedale Anticline, Uinta Basin and Haynesville Shale. These resource plays are characterized by unconventional oil or gas accumulations in continuous tight sands or shales that underlie broad geographic areas. The lateral continuity of such resource plays means that aside from wells abandoned due to mechanical issues, the Company does not expect to drill many unsuccessful wells as it develops these resource plays. Resource plays allow the Company the opportunity to gain considerable operational efficiencies through high-density, repeatable drilling and completion operations. The Company believes it has a large inventory of lower-risk, predictable development drilling locations across its acreage holdings in the onshore U.S. that provide a solid base for growth in organic production and reserves.

Outlook

In response to the commodity price environment, we reduced drilling and completion activities, slowed production growth, reduced costs and preserved our liquidity in 2015 and in the first half of 2016, and plans to continue these strategies for the remainder of 2016. We are focused on driving improved operating performance by optimizing reservoir development, enhancing well completion designs, and aggressively pursuing cost reductions.

Based on current commodity prices, we expect to be able to fund our planned capital program with cash flow from operating activities, cash on hand and, if needed, availability under our credit facility. Our total capital expenditures for 2016, primarily related to development and recompletion activities, are expected to be approximately $525.0 million, which includes adding two rigs in the fourth quarter of 2016 associated with the expected closing of the 2016 Permian Acquisition (defined below), a decrease of approximately 50% from 2015 capital expenditures. With this capital program, we expect total equivalent production to be relatively flat compared to 2015, excluding any production from the 2016 Permian Acquisition. We plan to continuously evaluate our level of drilling and completion activity in light of both commodity prices and changes we are able to make to our costs of operations and adjust our capital spending program as appropriate. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures. We will also continue to pursue acquisitions and divest of non-core properties.

Equity Offerings

In June 2016, QEP issued 23.0 million additional shares of common stock through a public offering and received net proceeds of approximately $413.0 million. QEP intends to use the net proceeds from this offering to partially fund the acquisition of additional properties in the Permian Basin. If the acquisition is not consummated, QEP intends to use the net proceeds from this offering for general corporate purposes, which may include, among other things, reducing indebtedness, acquiring properties and funding a portion of our exploration and production activities and working capital.

Termination of Marketing Agreements and QEP Marketing Segment

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and the Haynesville gathering system. As a result, QEP Energy is directly marketing its own gas, oil and NGL production. While QEP will continue to act as an agent for the sale of gas, oil and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently is reporting lower resale revenue and expenses than it had in prior periods. In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP has one reportable segment effective January 1, 2016.

Acquisitions and Divestitures

primarily held by production from 96 vertical wells. The 2016 Permian Acquisition is expected to close in September 2016, and the Company plans to fund the transaction with proceeds from the June 2016 equity offering and cash on hand.

During the six months ended June 30, 2016, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for a total purchase price of $29.8 million, which primarily included additional interests in QEP's operated wells and additional undeveloped leasehold. As a part of the purchase price allocation, the Company recorded $3.7 million of goodwill.

While QEP believes its extensive inventory of identified drilling locations provide a solid base for growth in production and reserves, the Company continues to evaluate acquisition opportunities that it believes will create significant long-term value. QEP believes that its experience, expertise, and presence in its core operating areas, combined with a low-cost operating model and financial strength, enhances its ability to pursue acquisition opportunities.

Financial and Operating Results

During the three months ended June 30, 2016, QEP:


•	Achieved natural gas equivalent production of 83.3 Bcfe, a 3% increase over the same period in 2015;


•	Achieved record oil production of 5,209.5 Mbbls, a 7% increase over the second quarter of 2015, including higher production in both the Permian and Williston basins;


•	Reduced lease operating and transportation and other handling expense by $0.15/Mcfe to $1.46/Mcfe;


•	Generated a net loss of $197.0 million, or $0.90 per diluted share;


•	Achieved Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $168.3 million;


•	Issued 23.0 million additional shares of common stock through a public offering and received net proceeds of approximately $413.0 million; and


•	Maintained $1,038.3 million in cash and cash equivalents and had nothing drawn under our credit facility.

During the six months ended June 30, 2016, QEP:


•	Achieved natural gas equivalent production of 166.0 Bcfe, a 6% increase over the same period in 2015;


•	Increased oil production to 10,385.9 Mbbls, an 11% increase over the first half of 2015, including higher production in both the Permian and Williston basins;


•	Reduced lease operating and transportation and other handling expense by $0.10/Mcfe to $1.54/Mcfe;


•	Generated a net loss of $1,060.8 million, or $5.21 per diluted share;


•	Achieved Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $283.4 million;


•	Incurred impairment expense of $1,183.2 million due to lower future commodity prices; and


•	Issued 60.95 million additional shares of common stock through two public offerings and received net proceeds of approximately $781.6 million.

Factors Affecting Results of Operations

Supply, Demand, Market Risk and its Impact on Oil and Gas Prices

Oil and gas prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. In recent years, oil and gas prices have been affected by supply growth particularly in U.S. oil and natural gas production, driven by advances in drilling and completion technologies, and fluctuations in demand driven by a variety of factors.

Changes in the market prices for gas, oil and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling and completion activity and related capital expenditures, liquidity, rate of growth, costs of goods and services required to drill, complete and operate wells, and the carrying value of its oil and gas properties. Historically field-level prices received for QEP’s oil and gas production have been volatile. During the past five years, the posted price for WTI crude oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $113.39 per barrel in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March

2016 to a high of $8.15 per MMBtu in February 2014. If the prices of oil and natural gas continue at current levels or decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.

NGL Prices

NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient domestic demand and export capacity. Prices of heavier NGL components, typically correlated to crude oil prices, have declined in concert with weakening oil prices. Concurrently, the lighter NGL components, ethane and propane, have experienced declines as a result of growing North American oversupply. In addition to produced price movements, QEP's composite NGL prices are affected by ethane recovery or rejection. When ethane is recovered as a discrete NGL component instead of being sold as part of the natural gas stream, the average sales price of an NGL barrel decreases as the ethane price is generally lower than the prices of the remaining NGL components. As permitted in some of its processing agreements, QEP recovers ethane when gas processing economics support the recovery of ethane from the natural gas stream. When gas processing economics do not support ethane recovery, and processing agreements permit it to do so, QEP elects to reject ethane from the NGL stream. In instances where QEP can make an election, QEP rejected ethane during the six months ended June 30, 2016, and will likely continue to reject ethane for the remainder of 2016.

Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the global economy, including Europe's economic outlook and the United Kingdom’s vote to exit the European Union; the Organization of Petroleum Exporting Countries (OPEC) countries oil production; political unrest in Europe, the Middle East, and Africa; slowing growth in Asia, particularly in China; the outcome of U.S. federal, state and local elections and ballot initiatives; the U.S. federal budget deficit; changes in regulatory oversight policy; commodity price volatility; the impact of a potential increase in interest rates; volatility in various global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on natural gas, crude oil and NGL supply, demand, prices and the Company's ability to continue its planned drilling programs on federal and Native American lands and could materially impact the Company's financial position, results of operations and cash flow from operations.

In December 2015, the U.S. lifted a 40-year ban on the export of crude oil. U.S. producers now have access to a wider market, and the U.S. could become a significant exporter of oil if the necessary infrastructure is built to support oil exports. QEP anticipates global oil prices will improve in the coming years as supply growth moderates due to lower level of investment and modest demand increases. Disruption to the global oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oil prices.

Due to increased global economic uncertainty and the corresponding volatility of commodity prices, QEP has built a strong liquidity position to ensure financial flexibility and has reduced drilling and completion activity and planned capital expenditures. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. At June 30, 2016, assuming forecasted 2016 annual production of approximately 320 Bcfe, QEP had approximately 77% of its forecasted gas production and 48% of its forecasted oil production covered with fixed-price swaps and collars. The average swap prices for the derivative contracts settling in 2016, 2017 and 2018 are significantly lower than the average swap prices for the derivative contracts settled prior to 2016 and, therefore, QEP's derivative portfolio may not contribute as much to QEP's net realized prices for current and future production. See Part 1, Item 3 - "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk Management" for further details on QEP’s commodity derivatives transactions.

Government Regulatory Developments

New Clean Air Act regulations at 40 C.F.R Part 60, Subpart OOOO (Subpart OOOO) became effective in 2012, with further amendments effective in 2013 and 2014. Subpart OOOO imposes air quality controls and requirements upon QEP's operations. For example, in June 2016, the EPA finalized updates to Subpart OOOO to achieve additional methane and volatile organic compound reductions from certain activities in the oil and gas industry. The new rules include, among others, new requirements for finding and repairing leaks at new well sites and reduced emission completion requirements for oil wells. Additionally, many states are adopting air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that are more stringent than existing requirements under federal regulations.

In June 2016, the EPA published a rule under the Clean Air Act regarding source determination and permitting requirements for the onshore oil and gas industry. This rule defines adjacent sources as those within a quarter of a mile of each other that have

shared equipment. Under the new rule, emissions from those sources must be aggregated as a single source. The new rule specifically addresses programs administered by the EPA, such as lands situated in tribal lands. Most states and local agencies will have discretion on adopting similar rules. This ruling could lead to increased emission controls and potentially increased permitting costs and compliance requirements, particularly for operations located in areas where EPA has primary jurisdiction.

In June 2016, the EPA also issued a Federal Implementation Plan (FIP) to implement the Federal Minor New Source Review Program on tribal lands for oil and gas production. The FIP primarily impacts QEP’s operations on the Fort Berthold Reservation in the Williston Basin and on the Uintah and Ouray Indian Reservations in the Uinta Basin. The FIP creates a permit-by-rule process for minor sources that also incorporates emission limits and other requirements under various federal air quality standards, applying them to a range of equipment and processes used in oil and gas production. However, the FIP does not apply in areas of ozone non-attainment. As a result, the EPA may impose area-specific regulations in parts of the Uinta Basin in Utah identified as tribal lands that may require additional emissions controls on existing equipment. The proposals will likely result in increased operating and compliance costs.

In June 2016, the EPA also issued a proposed Information Collection Request (ICR) to support development of new regulations covering methane emissions at existing oil and gas sites. There will be both an "operator survey" and a "facility survey" with greater detail required in the "facility survey". This process could result in additional regulations on existing oil and gas sites potentially leading to increased operating and compliance costs.

Potential for Future Asset Impairments

The carrying value of the Company's properties is sensitive to declines in natural gas, crude oil and NGL prices. The value of these assets are at risk of impairment if future natural gas, crude oil and/or NGL prices decline and/or drilling and completion costs increase. The cash flow model that the Company uses to assess proved properties for impairment includes numerous assumptions, such as management's estimates of future gas, oil and NGL production, market outlook on forward commodity prices, operating and development costs, and discount rates. During the six months ended June 30, 2016, the Company recorded impairments of $1,183.2 million, of which $1,167.9 million was related to impairments of proved properties due to lower future prices, primarily in Pinedale, $11.6 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill. During the six months ended June 30, 2015, impairments were $20.5 million, of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. If commodity prices decline during 2016, there could be additional impairment charges to our oil and gas assets or other investments.

Multi-Well Pad Drilling

To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. In certain of our producing areas, wells drilled on a pad are not brought into production until all wells on the pad are drilled and cased and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP’s quarterly operating results.

Midstream Services

QEP's ability to produce its wells depends in substantial part on the availability and capacity of gathering, transportation and gas processing facilities owned and operated by third parties. Due to market conditions, many midstream companies are attempting to renegotiate their gathering, processing and transportation agreements with their upstream counterparties. For example, an entity that purchases, gathers and processes natural gas produced from oil wells operated by QEP in the Williston Basin has claimed that the decline in commodity prices has rendered its gathering and processing operations "uneconomic" and demanded that QEP pay additional fees for gathering and processing services. The midstream provider has been unwilling to connect recently drilled and completed wells on the Company's South Antelope acreage of the Williston Basin unless QEP agrees to pay the increased fees, which has negatively impacted completion activities and production volumes. Due to this dispute, the pace at which the Company is able to complete additional drilled and uncompleted wells during the third quarter 2016 at South Antelope may be impacted. QEP initiated arbitration proceedings in May 2016 to enforce the terms of the existing agreement. The Company anticipates the arbitration will likely be concluded in the fourth quarter of 2016.

Critical Accounting Estimates

QEP's significant accounting policies are described in Item 7 of Part II of its 2015 Annual Report on Form 10-K. The Company's Condensed Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of the Company's Condensed Consolidated Financial Statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP's accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, impairment of long-lived assets, asset retirement obligations, revenue recognition, litigation and other contingencies, environmental obligations, derivative contracts, pension and other postretirement benefits, share-based compensation, income taxes and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.

Drilling Activity

The following table presents operated and non-operated well completions for the three and six months ended June 30, 2016:



	Operated Completions				Non-operated Completions
	Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended
	June 30, 2016		June 30, 2016		June 30, 2016		June 30, 2016
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	4	3.4	4	3.4	—	—	—	—
Williston Basin	1	1.0	18	17.8	4	0.0	7	0.0
Uinta Basin	—	—	8	8.0	—	—	2	0.0
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	4	0.7	9	1.8
Permian Basin	6	6.0	13	12.7	—	—	—	—
Other Southern	—	—	—	—	—	—	—	—

The following table presents operated and non-operated wells drilling or waiting on completion at June 30, 2016:



	Operated				Non-operated
	Drilling		Waiting on completion		Drilling		Waiting on completion
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	8	3.9	32	17.1	—	—	—	—
Williston Basin	2	2.0	28	24.7	—	—	25	1.6
Uinta Basin	—	—	—	—	—	—	1	0.0
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	2	0.3	7	0.4
Permian Basin	1	1.0	2	2.0	—	—	—	—
Other Southern	—	—	—	—	—	—	—	—

The term "gross" refers to all wells or acreage in which QEP has at least a partial working interest and the term "net" refers to QEP's ownership represented by that working interest. Each gross well completed in more than one producing zone is counted as a single well. QEP typically utilizes multi-well pad drilling where practical. Wells drilled are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location. QEP sometimes suspends completion activities due to adverse weather conditions, operational factors or other macroeconomic circumstances, such as low commodity prices. As a result, QEP had 62 gross operated wells waiting on completion as of June 30, 2016.

RESULTS OF OPERATIONS

Net Income

QEP generated a net loss during the second quarter of 2016 of $197.0 million, or $0.90 per diluted share, compared to a net loss of $76.3 million, or $0.43 per diluted share, in the second quarter of 2015. QEP's increased net loss was primarily due to a 27% decrease in realized prices and a $71.7 million increase in unrealized derivative losses. These changes were partially offset by a 3% increase in natural gas equivalent production and lower operating expenses in the second quarter of 2016 compared to the second quarter of 2015.

QEP generated a net loss during the first half of 2016 of $1,060.8 million, or $5.21 per diluted share, compared to a net loss of $131.9 million, or $0.75 per diluted share, in the first half of 2015. QEP's increased net loss was primarily due to an increase in impairment expense of $1,162.7 million, a 31% decrease in realized prices, a $61.7 million increase in unrealized derivative losses and a $38.5 million increase in depreciation, depletion and amortization. These changes were partially offset by a 6% increase in natural gas equivalent production and lower production and property tax expense in the first half of 2016 compared to the first half of 2015.

Adjusted EBITDA

Management defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, and certain other non-cash and/or non-recurring items. Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company's financial and operating performance that allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources.



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
Net income (loss)	$	(197.0	)	$	(76.3	)	$	(1,060.8	)	$	(131.9	)
Interest expense	36.6			36.2			73.3			73.0
Interest and other (income) expense	0.3			(3.8		)	(2.0		)	(1.2		)
Income tax provision (benefit)	(113.3		)	(38.8		)	(612.2		)	(70.3		)
Depreciation, depletion and amortization	209.7			215.8			449.7			411.2
Unrealized (gains) losses on derivative contracts	230.0			158.3			243.5			181.8
Exploration expenses	0.4			0.8			0.7			1.9
Net (gain) loss from asset sales	0.8			(24.5		)	0.3			6.0
Impairment	0.8			0.5			1,183.2			20.5
Other ⁽¹⁾	—			11.2			7.7			11.2
Adjusted EBITDA	$	168.3		$	279.4		$	283.4		$	502.2

____________________________

⁽¹⁾

Reflects a non-cash pension curtailment loss that was incurred during the three and six months ended June 30, 2015, due to changes in the Company's pension plan (see Note 12 – Employee Benefits for additional information) and additional legal expenses incurred during the six months ended June 30, 2016. The Company believes that these costs do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded the losses from the calculation of Adjusted EBITDA.

Adjusted EBITDA decreased to $168.3 million in the second quarter of 2016 from $279.4 million in the second quarter of 2015, due to a 27% decrease in the average realized prices, partially offset by a 3% increase in natural gas equivalent production and lower operating expenses in the second quarter of 2016 compared to the second quarter of 2015.

Adjusted EBITDA decreased to $283.4 million in the first half of 2016 from $502.2 million in the first half of 2015, due to a 31% decrease in the average realized prices, partially offset by a 6% increase in natural gas equivalent production and lower production and property tax expense in the first half of 2016 compared to the first half of 2015.

Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP’s major revenue categories for the three and six months ended June 30, 2016, compared to the three and six months ended June 30, 2015:



	Gas			Oil			NGL			Total
	(in millions)
Production revenues
Three months ended June 30, 2015 revenues	$	111.9		$	250.4		$	26.1		$	388.4
Changes associated with volumes ⁽¹⁾	(4.0		)	17.1			7.0			20.1
Changes associated with prices ⁽²⁾	(28.7		)	(59.8		)	(10.3		)	(98.8		)
Three months ended June 30, 2016 revenues	$	79.2		$	207.7		$	22.8		$	309.7

Production revenues
Six months ended June 30, 2015 revenues	$	233.9		$	429.2		$	45.2		$	708.3
Changes associated with volumes ⁽¹⁾	(1.8		)	47.1			15.4			60.7
Changes associated with prices ⁽²⁾	(67.8		)	(124.8		)	(24.2		)	(216.8		)
Six months ended June 30, 2016 revenues	$	164.3		$	351.5		$	36.4		$	552.2

____________________________


⁽¹⁾	The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and six months ended June 30, 2016, as compared to the three and six months ended June 30, 2015, by the average field-level price for the three and six months ended June 30, 2015.

⁽²⁾

The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level prices from the three and six months ended June 30, 2016, as compared to the three and six months ended June 30, 2015, by volumes for the three and six months ended June 30, 2016. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

Total Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
Production volumes (Bcfe)
Northern Region
Pinedale	22.8		24.9		(2.1		)	48.0		46.7		1.3
Williston Basin	31.6		28.6		3.0			61.0		54.0		7.0
Uinta Basin	7.9		7.3		0.6			15.2		14.2		1.0
Other Northern	2.1		2.4		(0.3		)	4.4		5.1		(0.7		)
Southern Region
Haynesville/Cotton Valley	9.2		10.4		(1.2		)	18.3		22.1		(3.8		)
Permian Basin	9.5		6.2		3.3			18.6		11.1		7.5
Other Southern	0.2		1.1		(0.9		)	0.5		2.9		(2.4		)
Total production	83.3		80.9		2.4			166.0		156.1		9.9
Total equivalent prices (per Mcfe)
Average equivalent field-level price	$	3.72	$	4.80	$	(1.08	)	$	3.33	$	4.54	$	(1.21	)
Commodity derivative impact	0.59		1.14		(0.55		)	0.67		1.25		(0.58		)
Net realized equivalent price	$	4.31	$	5.94	$	(1.63	)	$	4.00	$	5.79	$	(1.79	)

Gas Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
Gas production volumes (Bcf)
Northern Region
Pinedale	19.9		21.5		(1.6		)	41.6		40.5		1.1
Williston Basin	4.0		3.0		1.0			7.2		5.7		1.5
Uinta Basin	6.4		5.7		0.7			12.2		10.6		1.6
Other Northern	2.0		2.1		(0.1		)	4.0		4.5		(0.5		)
Southern Region
Haynesville/Cotton Valley	9.0		10.3		(1.3		)	18.1		21.9		(3.8		)
Permian Basin	1.6		1.2		0.4			3.0		1.9		1.1
Other Southern	—		0.7		(0.7		)	0.2		2.0		(1.8		)
Total production	42.9		44.5		(1.6		)	86.3		87.1		(0.8		)
Gas prices (per Mcf)
Northern Region	$	1.80	$	2.49	$	(0.69	)	$	1.89	$	2.66	$	(0.77	)
Southern Region	1.97		2.59		(0.62		)	1.94		2.75		(0.81		)

Average field-level price	$	1.84	$	2.52	$	(0.68	)	$	1.90	$	2.69	$	(0.79	)
Commodity derivative impact	0.67		0.63		0.04			0.58		0.53		0.05
Net realized price	$	2.51	$	3.15	$	(0.64	)	$	2.48	$	3.22	$	(0.74	)

Gas revenues decreased $32.7 million, or 29%, in the second quarter of 2016 compared to the second quarter of 2015, due to lower field-level prices and lower gas production. Average field-level gas prices decreased 27% in the second quarter of 2016 compared to the second quarter of 2015 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The 4% decrease in production volumes was primarily driven by a production decrease in Pinedale due to the suspension of well completions until late in the second quarter of 2016, in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program and in Other Southern due to the continued divestitures of non-core properties. These decreases were partially offset by production increases in the Uinta, Permian and Williston basins due to continued development drilling.

Gas revenues decreased $69.6 million, or 30%, in the first half of 2016 compared to the first half of 2015, due to lower field-level prices and lower gas production. Average field-level gas prices decreased 29% in the first half of 2016 compared to the first half of 2015 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The 1% decrease in production volumes was primarily driven by a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program and in Other Southern due to the continued divestitures of non-core properties. These decreases were partially offset by production increases in Pinedale and the Uinta, Permian and Williston basins due to continued development drilling.

Oil Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
Oil production volumes (Mbbl)
Northern Region
Pinedale	149.5		176.0		(26.5		)	325.8		321.5		4.3
Williston Basin	3,799.3		3,769.2		30.1			7,517.3		7,200.7		316.6
Uinta Basin	198.3		202.0		(3.7		)	406.6		423.6		(17.0		)
Other Northern	34.1		44.3		(10.2		)	70.5		89.4		(18.9		)
Southern Region
Haynesville/Cotton Valley	7.3		8.9		(1.6		)	13.9		16.7		(2.8		)
Permian Basin	1,008.7		628.1		380.6			2,028.1		1,199.9		828.2
Other Southern	12.3		47.4		(35.1		)	23.7		105.5		(81.8		)
Total production	5,209.5		4,875.9		333.6			10,385.9		9,357.3		1,028.6
Oil prices (per bbl)
Northern Region	$	38.86	$	50.60	$	(11.74	)	$	32.82	$	44.93	$	(12.11	)
Southern Region	43.99		55.85		(11.86		)	37.96		51.47		(13.51		)

Average field-level price	$	39.88	$	51.34	$	(11.46	)	$	33.84	$	45.86	$	(12.02	)
Commodity derivative impact	3.81		13.24		(9.43		)	5.84		15.88		(10.04		)
Net realized price	$	43.69	$	64.58	$	(20.89	)	$	39.68	$	61.74	$	(22.06	)

Oil revenues decreased $42.7 million, or 17%, in the second quarter of 2016 compared to the second quarter of 2015, due to lower average field-level prices, partially offset by higher volumes. Average field-level oil prices decreased 22% in the second quarter of 2016 compared to the second quarter of 2015 driven by a decrease in average NYMEX-WTI and ICE Brent oil prices for the comparable periods. The 7% increase in production volumes was driven by increases in the Permian and Williston basins due to continued development drilling. These increases were partially offset by production decreases in Other Southern due to the continued divestitures of non-core properties and in Pinedale due to suspension of well completions until late in the second quarter of 2016.

Oil revenues decreased $77.7 million, or 18%, in the first half of 2016 compared to the first half of 2015, due to lower average field-level prices, partially offset by higher volumes. Average field-level oil prices decreased 26% in the first half of 2016 compared to the first half of 2015 driven by a decrease in average NYMEX-WTI and ICE Brent oil prices for the comparable periods. The 11% increase in production volumes was primarily driven by increases in the Permian and Williston basins due to continued development drilling. These production increases were partially offset by a production decrease in Other Southern due to the continued divestitures of non-core properties.

NGL Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
NGL production volumes (Mbbl)
Northern Region
Pinedale	334.1		403.8		(69.7		)	736.1		716.8		19.3
Williston Basin	802.4		482.8		319.6			1,441.9		841.6		600.3
Uinta Basin	57.3		70.3		(13.0		)	101.6		179.7		(78.1		)
Other Northern	6.0		6.5		(0.5		)	9.7		9.2		0.5
Southern Region
Haynesville/Cotton Valley	6.2		6.8		(0.6		)	14.6		13.9		0.7
Permian Basin	310.2		209.0		101.2			572.3		328.8		243.5
Other Southern	5.1		18.8		(13.7		)	10.1		55.4		(45.3		)
Total production	1,521.3		1,198.0		323.3			2,886.3		2,145.4		740.9
NGL prices (per bbl)
Northern Region	$	15.61	$	23.41	$	(7.80	)	$	13.11	$	22.44	$	(9.33	)
Southern Region	12.61		14.59		(1.98		)	10.67		14.57		(3.90		)

Average field-level price	$	14.97	$	21.68	$	(6.71	)	$	12.61	$	20.98	$	(8.37	)
Commodity derivative impact	—		—		—			—		—		—
Net realized price	$	14.97	$	21.68	$	(6.71	)	$	12.61	$	20.98	$	(8.37	)

NGL revenues decreased $3.3 million, or 13%, during the second quarter of 2016 compared to the second quarter of 2015, due to lower average field-level prices, partially offset by increased production volumes. NGL prices decreased 31% during the second quarter of 2016 compared to the second quarter of 2015, which was primarily driven by receiving an increased percentage of ethane from a midstream provider on our Williston Basin production during the second quarter of 2016 compared to the second quarter of 2015. The increased percentage of ethane is a result of a midstream provider electing to operate their gas processing plant in ethane recovery. The 27% increase in total NGL production volumes was driven by increases in the Williston and Permian basins. The increase in the Williston Basin is due to the additional ethane recovered combined with continued development drilling and the increase in the Permian Basin is due to continued development drilling. These increases were partially offset by a production decrease in Pinedale due to the suspension of well completions until late in the second quarter of 2016.

NGL revenues decreased $8.8 million, or 20%, during the first half of 2016 compared to the first half of 2015, due to lower average field-level prices, partially offset by increased production volumes. NGL prices decreased 40% during the first half of 2016 compared to the first half of 2015, which was primarily driven by receiving an increased percentage of ethane from a midstream provider on our Williston Basin production during the first half of 2016 compared to the first half of 2015. The increased percentage of ethane is a result of a midstream provider electing to operate their gas processing plant in ethane recovery. The 35% increase in total NGL production volumes was driven by increases in the Williston and Permian basins. The increase in the Williston Basin is due to the additional ethane recovered combined with continued development drilling and the increase in the Permian Basin is due to continued development drilling. These increases were partially offset by a production decrease in the Uinta Basin due to refrigeration processing of gas in the first half of 2016 compared to cryogenic processing during a portion of the first half of 2015.

Resale Margin and Storage Activity

QEP purchases and resells gas and oil primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. The difference between the price of products purchased and sold, net of transportation costs, creates a resale margin that represents a gain or loss for the Company. The following table is a summary of QEP's financial results from its resale activities.



	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
	(in millions)
Purchased gas and oil sales	$	24.5		$	181.0		$	(156.5	)	$	41.0		$	324.8		$	(283.8	)
Purchased gas and oil expense	(26.8		)	(183.2		)	156.4			(43.7		)	(329.1		)	285.4
Realized gains (losses) on storage derivative instruments	0.7			(0.3		)	1.0			2.8			2.2			0.6
Resale margin	$	(1.6	)	$	(2.5	)	$	0.9		$	0.1		$	(2.1	)	$	2.2

As a result of the termination of QEP Marketing agreements effective January 1, 2016, QEP is no longer the first purchaser of other working interest owner production. As such, QEP is reporting lower resale revenue and expenses in the first half of 2016 than it had in prior periods. For additional details, see Note 1 – Basis of Presentation, in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Operating Expenses

The following table presents QEP production costs on a per unit of production basis:



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
	(per Mcfe)
Lease operating expense	$	0.63	$	0.71	$	(0.08	)	$	0.68	$	0.76	$	(0.08	)
Gas, oil and NGL transportation and other handling costs	0.83		0.90		(0.07		)	0.86		0.88		(0.02		)
Production and property taxes	0.25		0.40		(0.15		)	0.23		0.39		(0.16		)
Total production costs	$	1.71	$	2.01	$	(0.30	)	$	1.77	$	2.03	$	(0.26	)

Lease operating expense (LOE). QEP’s LOE was $52.6 million, a decrease of $4.5 million, or $0.08 per Mcfe, during the second quarter of 2016 compared to the second quarter of 2015. The decrease was driven by a decrease in the Permian Basin as a result of lower chemical and compression expenses and a decrease in Other Southern as a result of continued divestitures of non-core properties. Partially offsetting the decrease was an increase in the Williston Basin due to increased maintenance, repairs, workover and produced water disposal expenses.

QEP’s LOE was $112.6 million, a decrease of $6.3 million, or $0.08 per Mcfe, during the first half of 2016 compared to the first half of 2015. The decrease was driven by a decrease in the Permian Basin as a result of lower chemical, maintenance, repairs and workover expenses and a decrease in Other Southern as a result of continued divestitures of non-core properties. Partially offsetting the decrease was an increase in the Williston Basin due to increased maintenance, repairs, workover and produced water disposal expenses.

Gas, oil and NGL transportation and other handling costs. Gas, oil and NGL transportation and other handling costs were $69.5 million, a decrease of $3.5 million, or $0.07 per Mcfe, during the second quarter of 2016 compared to the second quarter of 2015. The $3.5 million decrease in expense was primarily attributable to a decrease in Haynesville/Cotton Valley due to declining production volumes and a decrease in the Williston Basin due to lower rates. These decreases were partially offset by an increase in the Permian Basin, primarily due to an increase in production volumes and slightly higher rates.

Gas, oil and NGL transportation and other handling costs were $143.1 million, an increase of $5.0 million, during the first half of 2016 compared to the first half of 2015, primarily attributable to production increases in Pinedale and the Williston, Permian and Uinta basins. Gas, oil and NGL transportation and other handling costs, on a per Mcfe basis, was down $0.02, primarily driven by rate decreases in the Williston and Uinta basins.

Production and property taxes. In most states in which QEP operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production and property taxes were $20.7 million, a decrease of $12.0 million, or $0.15 per Mcfe, during the second quarter of 2016 compared to the second quarter of 2015 primarily as a result of decreased gas, oil and NGL revenues from lower field-level prices and production tax refunds.

Production and property taxes were $38.5 million, a decrease of $22.0 million, or $0.16 per Mcfe, during the first half of 2016 compared to the first half of 2015 primarily as a result of decreased gas, oil and NGL revenues from lower field-level prices and production tax refunds.

Depreciation, depletion and amortization (DD&A). DD&A expense was $209.7 million, a decrease of $6.1 million in the second quarter of 2016 compared to the second quarter of 2015, due to decreases in Pinedale and the Williston Basin, partially offset by an increase in the Permian Basin. The decrease in Pinedale is primarily due to a decrease in production and a rate decrease due to a first quarter 2016 impairment. The decrease in the Williston Basin is primarily due to a rate decrease from increased proved reserves, partially offset by an increase in production. The increase in the Permian Basin is primarily due to a rate increase from decreased proved reserves and an increase in production.

DD&A expense was $449.7 million, an increase of $38.5 million in the first half of 2016 compared to the first half of 2015, due to increases in the Permian and Uinta basins, partially offset by decreases in Pinedale and the Williston Basin. The increases in the Permian and Uinta basins were primarily due to increased rates due to a decrease in proved reserves, combined with increased production. The decrease in Pinedale is primarily the result of a rate decrease due to a first quarter 2016 impairment, while the decrease in the Williston Basin is the result of a rate decrease from increased proved reserves, partially offset by an increase in production.

Impairment expense. Impairment expense was $0.8 million for the second quarter of 2016, and $0.5 million for the second quarter of 2015, all of which was related to expiring leaseholds on unproved properties.

Impairment expense was $1,183.2 million for the first half of 2016, of which $1,167.9 million was related to proved properties due to lower future prices, $11.6 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill. Of the $1,167.9 million impairment on proved properties, $1,164.0 million related to Pinedale properties, $3.5 million related to Other Northern properties and $0.4 million related to Other Southern properties. Impairment expense was $20.5 million for the first half of 2015, of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. Of the $19.4 million impairment on proved properties, $14.5 million related to Other Southern properties and $4.9 million related to Other Northern properties.

General and administrative expense (G&A). During the second quarter of 2016, G&A expense was $43.7 million, a decrease of $7.6 million, or 15%, compared to the second quarter of 2015, primarily due to a pension curtailment expense of $11.2 million recognized in the second quarter of 2015 (see Note 12 – Employee Benefits, in Item 1 of Part I of this Quarterly Report on Form 10-Q), a $2.6 million decrease in legal, professional and outside services expenses, a $1.5 million decrease in bad debt expense and a $1.2 million decrease in labor, benefits and employee expenses. These decreases were partially offset by a $7.8 million increase in share-based compensation primarily due to an increase in the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan (CIP) and a $1.3 million increase in severance payments primarily related to the April 2016 restructuring (see Note 8 – Restructuring Costs, in Item 1 of Part I of this Quarterly Report on Form 10-Q).

During the first half of 2016, G&A expense was $92.4 million, a decrease of $6.3 million, or 6%, compared to the first half of 2015, primarily due to a pension curtailment expense of $11.2 million recognized in the second quarter of 2015 (see Note 12 – Employee Benefits, in Item 1 of Part I of this Quarterly Report on Form 10-Q), a $4.3 million decrease in labor, benefits and employee expenses and a $1.8 million decrease in bad debt expense. These decreases were partially offset by a $5.7 million increase in legal, professional and outside services expenses and a $7.6 million increase in share-based compensation primarily due to an increase in the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan (CIP).

Net gain (loss) from asset sales. QEP recognized a loss on the sale of assets of $0.8 million during the second quarter of 2016 compared to a gain on sale of $24.5 million in the second quarter of 2015. The loss on sale of assets in the second quarter of 2016 was primarily related to continued divestitures of non-core Other Southern properties. The gain on sale of assets recognized during the second quarter of 2015 was primarily due to a $26.6 million gain recognized on the sale of QEP's Other Southern non-core properties, partially offset by losses related to post-closing adjustments on the sale of QEP's interest in non-core Other Southern properties in 2014.

QEP recognized a loss on the sale of assets of $0.3 million during the first half of 2016 compared to a loss on the sale of assets of $6.0 million in the first half of 2015. The loss on sale of assets in the first half of 2016 was primarily related to continued divestitures of non-core Other Southern properties. The loss on sale of assets of $6.0 million recognized during the first half of 2015 was primarily due to post-closing adjustments related to sales of QEP's interest in non-core Other Southern properties.

Non-operating Expenses

Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative contracts are comprised of both realized and unrealized gains and losses on QEP’s commodity derivative contracts, which are marked-to-market each quarter. During the second quarter of 2016, losses on commodity derivative contracts were $180.5 million, of which $230.0 million were unrealized losses, partially offset by $49.5 million of realized gains. During the second quarter of 2015, losses on commodity derivative contracts were $66.0 million, of which $158.3 million were unrealized losses, partially offset by $92.3 million of realized gains.

During the first half of 2016, losses on commodity derivative contracts were $129.6 million, of which $243.5 million were unrealized losses, partially offset by $113.9 million of realized gains. During the first half of 2015, gains on commodity derivative contracts were $14.9 million, of which $196.7 million were realized gains, partially offset by $181.8 million of unrealized losses.

Interest expense. Interest expense was $36.6 million during the second quarter of 2016 compared to $36.2 million during the second quarter of 2015.

Interest expense was $73.3 million during the first half of 2016 compared to $73.0 million during the first half of 2015.

Income tax (provision) benefit. Income tax benefit was $113.3 million during the second quarter of 2016 compared to $38.8 million of benefit during the second quarter of 2015. The income tax rate was 36.5% during the second quarter of 2016 compared to a rate of 33.7% during the second quarter of 2015. The increase in income tax rate was primarily the result of a lower state tax rate in 2015 due to a change in the composition of income between subsidiaries.

Income tax benefit was $612.2 million during the first half of 2016 compared to $70.3 million of benefit during the first half of 2015. The income tax rate was 36.6% during the first half of 2016 compared to a rate of 34.8% during the first half of 2015. The increase in income tax rate was primarily the result of a lower state tax rate in 2015 due to a change in the composition of income between subsidiaries.

LIQUIDITY AND CAPITAL RESOURCES

QEP plans to fund its development projects by employing a capital structure and financing strategy that will provide sufficient liquidity to withstand commodity price volatility. As a part of this strategy, QEP maintains a commodity price derivative strategy to reduce the financial impact of commodity price volatility and to provide some certainty to QEP's cash flows. In response to the current commodity price environment, QEP reduced drilling and completion activity, slowed production growth and preserved liquidity in 2015 and in the first half of 2016 and plans to continue these strategies for the remainder of 2016. In February 2016, the Board of Directors indefinitely suspended the payment of quarterly dividends.

Generally, QEP funds its operations, capital expenditures and working capital requirements with cash flow from its operating activities, cash on hand and, if needed, borrowings under its credit facility. To provide additional liquidity, QEP also periodically accesses debt and equity markets and sells non-core assets. In 2016, QEP issued 60.95 million shares of common stock through two public offerings and received net proceeds of approximately $781.6 million, which the Company plans to use for general corporate purposes and to fund the 2016 Permian Acquisition, if consummated. The Company plans to repay its $176.8 million Senior Notes due in September 2016 with cash on hand. Further, the Company expects cash flow from operations, cash on hand and availability under its credit facility will be sufficient to fund the Company’s planned capital expenditures, operating expenses and any potential obligations related to loss contingencies (see Note 10 – Contingencies, in Item 1 of Part I of this Quarterly Report on Form 10-Q) during the next 12 months and the foreseeable future.

The Company estimates that, as of June 30, 2016, it could incur additional indebtedness of approximately $1.0 billion and continue to be in compliance with the covenants contained in its credit facility. The Company expects that its ability to incur additional indebtedness will decrease significantly throughout the remainder of 2016 as lower commodity prices continue to impact the financial results that are used to calculate the amount of indebtedness the Company can incur while remaining in compliance with the covenants contained in its credit facility (see Credit Facility discussion below). To the extent actual operating results, realized commodity prices or uses of cash differ from the Company’s assumptions, QEP's liquidity could be adversely affected.

Credit Facility

QEP’s revolving credit facility, which matures in December 2019, provides for loan commitments of $1.8 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit agreement contains financial covenants (as defined in the credit agreement) that limit the amount of debt the Company may incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarters ending on and prior to December 31, 2017, and 3.75 times thereafter and (iii) a present value coverage ratio under which the present value of the Company’s proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2018, and 1.50 times at any time on or after January 1, 2018.

As of June 30, 2016 and December 31, 2015, QEP had no borrowings outstanding under the credit facility, had $2.8 million and $3.4 million, respectively, in letters of credit outstanding under the credit facility, and was in compliance with the covenants under the credit agreement. As of July 22, 2016, QEP had no borrowings outstanding under the credit facility, had $2.8 million of letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.

Senior Notes

The Company’s senior notes outstanding as of June 30, 2016, totaled $2,221.8 million principal amount and are comprised of six issuances as follows:


•	$176.8 million 6.05% Senior Notes due September 2016;


•	$134.0 million 6.80% Senior Notes due April 2018;


•	$136.0 million 6.80% Senior Notes due March 2020;


•	$625.0 million 6.875% Senior Notes due March 2021;


•	$500.0 million 5.375% Senior Notes due October 2022; and


•	$650.0 million 5.25% Senior Notes due May 2023.

Cash Flow from Operating Activities

Cash flows from operations are primarily affected by gas, oil and NGL production volumes and commodity prices (including the effects of settlements of the Company’s derivative contracts) and by changes in working capital. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future gas, oil and NGL production for the next 12 to 36 months.

Net cash from operating activities is presented below:



	Six Months Ended June 30,
	2016			2015			Change
	(in millions)
Net income (loss)	$	(1,060.8	)	$	(131.9	)	$	(928.9	)
Non-cash adjustments to net income (loss)	1,338.6			620.2			718.4
Changes in operating assets and liabilities	(58.2		)	(490.9		)	432.7
Net cash provided by (used in) operating activities	$	219.6		$	(2.6	)	$	222.2

Net cash provided by operating activities was $219.6 million during the first half of 2016, which included a $1,060.8 million net loss, $1,338.6 million of non-cash adjustments to the net loss and a $58.2 million decrease in operating assets and liabilities. Non-cash adjustments to the net loss primarily included impairment expense of $1,183.2 million, DD&A expense of $449.7 million and unrealized losses on derivative contracts of $243.5 million, partially offset by a decrease in deferred income taxes of $559.9 million. The decrease in operating assets and liabilities primarily included a decrease in accounts payable and accrued expenses of $106.2 million and an increase in income taxes receivable of $83.2 million, partially offset by a decrease in accounts receivable of $118.5 million.

Net cash used in operating activities was $2.6 million during the first half of 2015, which included a $131.9 million net loss, $620.2 million of non-cash adjustments to the net loss and a $490.9 million decrease in operating assets and liabilities. Non-cash adjustments to the net loss primarily included DD&A expense of $411.2 million, unrealized losses on derivative contracts of $181.8 million and impairment expense of $20.5 million, partially offset by a decrease in deferred income taxes of $29.4 million. The decrease in operating assets and liabilities primarily included a decrease in accounts payable and accrued expenses of $25.1 million and a decrease in income taxes payable of $587.8 million, primarily related to income taxes payable from the gain on the sale of substantially all of QEP's midstream business, which was paid in the first half of 2015. These changes were partially offset by a decrease in accounts receivable of $103.1 million.

Cash Flow from Investing Activities

A comparison of capital expenditures for the first half of 2016 and 2015, are presented in the table below:



	Six Months Ended June 30,
	2016		2015		Change
	(in millions)
Property acquisitions and acquisition deposit held in escrow	$	59.8	$	—	$	59.8
Property, plant and equipment capital expenditures	242.7		559.7		(317.0		)
Total accrued capital expenditures	302.5		559.7		(257.2		)
Change in accruals and other non-cash adjustments	27.7		91.6		(63.9		)
Total cash capital expenditures	$	330.2	$	651.3	$	(321.1	)

In the first half of 2016, on an accrual basis, the Company invested $242.7 million on property, plant and equipment capital expenditures, a decrease of $317.0 million compared to the first half of 2015. In the first half of 2016, QEP's capital expenditures were $119.4 million in the Williston Basin, $72.0 million in the Permian Basin, $21.9 million in Haynesville/Cotton Valley, $15.9 million in Pinedale and $10.4 million in the Uinta Basin. In addition, in the first half of 2016, QEP acquired various oil and gas properties in the Williston and Permian basins, primarily additional interests in QEP's operated wells and additional undeveloped leasehold, for a total purchase price of $29.8 million, of which $23.6 million was cash and $6.2 million was non-cash related to the settlement of an accounts receivable balance. Lastly, QEP paid a deposit of $30.0 million that is held in escrow related to the 2016 Permian Acquisition that is expected to close in the third quarter of 2016.

In the first half of 2015, on an accrual basis, the Company invested $559.7 million on property, plant and equipment capital expenditures, which included $282.1 million in the Williston Basin, $122.3 million in the Permian Basin, $88.2 million in Pinedale, $34.1 million in the Uinta Basin and $26.0 million in Haynesville/Cotton Valley.

QEP has significantly reduced its planned capital expenditures for 2016 as compared to its capital expenditures in 2015. Due to efficiency gains, strong well performance, and ongoing cost-reduction initiatives, QEP expects total equivalent production to be relatively flat compared to 2015, excluding any production from the 2016 Permian Acquisition. The mid-point of our forecasted capital expenditures for 2016, primarily for development and recompletion activities, is $525.0 million, which includes adding two rigs in the fourth quarter of 2016 associated with the 2016 Permian Acquisition. QEP intends to fund capital expenditures with cash flow from operating activities, cash on hand and, if needed, borrowings under its credit facility. The aggregate levels of capital expenditures for 2016 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, gas, oil and NGL prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management’s business assessments as to where QEP’s capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

Cash Flow from Financing Activities

In the first half of 2016, net cash provided by financing activities was $749.1 million compared to net cash used in financing activities of $58.2 million in the first half of 2015. During the first half of 2016, QEP had net proceeds from the March and June 2016 equity offerings of approximately $781.6 million and had a decrease in checks outstanding in excess of cash balances of $29.8 million. During the first half of 2015, QEP had a decrease in checks outstanding in excess of cash balances of $47.3 million and paid $7.1 million of quarterly dividend payments.

As of June 30, 2016, the Company did not have any borrowings outstanding under the credit facility and had $2,221.8 million in senior notes outstanding (excluding $27.2 million of net original issue discount and unamortized debt issuance costs).

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market risks arise from changes in the market price for gas, oil and NGL and volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. QEP has long-term contracts for pipeline capacity, and is obligated to pay for transportation services with no guarantee that it also will be able to fully utilize the contractual capacity of these transportation commitments. In addition, additional non-cash impairment expense of the Company’s oil and gas properties may be required if future oil and gas commodity prices experience a significant decline. Furthermore, the Company’s credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. To partially manage the Company’s exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price and basis swaps and collars to manage commodity price risk and periodically enters into interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP uses commodity price derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price and basis swaps and collars. The volume of commodity derivative instruments utilized by the Company may vary from year to year based on QEP's forecasted production. The Company's current derivative instruments do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of June 30, 2016, QEP held commodity price derivative contracts totaling 277.4 million MMBtu of gas and 16.3 million barrels of oil.

The following table presents QEP's derivative positions as of July 22, 2016. See Note 7 – Derivative Contracts in Part 1, Item 1 of this Quarterly Report on Form 10-Q for open derivative positions as of June 30, 2016.



Production Commodity Derivative Swap Positions
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2016	NYMEX HH	24.5	$	2.78
2016	IFNPCR	30.6	$	2.53
2017	NYMEX HH	76.7	$	2.77
2017	IFNPCR	32.9	$	2.51
2018	NYMEX HH	11.0	$	2.87
Oil Sales		(bbls)	($/bbl)
2016	NYMEX WTI	6.1	$	51.24
2017	NYMEX WTI	9.9	$	50.74
2018	NYMEX WTI	1.8	$	53.41



Production Gas Collars
Year	Index	Total Volume	Average Price Floor		Average Price Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	3.1	$	2.75	$	3.89
2017	NYMEX HH	11.0	$	2.50	$	3.50



Production Gas Basis Swaps
Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2016	NYMEX HH	IFNPCR	15.3	$	(0.16	)
2017	NYMEX HH	IFNPCR	51.1	$	(0.18	)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)



Storage Commodity Derivative Positions
Year	Type of Contract	Index	Total Volumes	Average Swap Price per MMBtu
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2016	SWAP	IFNPCR	2.4	$	2.59
2017	SWAP	IFNPCR	2.8	$	2.80
Gas purchases
2016	SWAP	IFNPCR	2.4	$	2.46

Changes in the fair value of derivative contracts from December 31, 2015 to June 30, 2016, are presented below:



	Commodity derivative contracts
	(in millions)
Net fair value of gas and oil derivative contracts outstanding at December 31, 2015	$	165.2
Contracts settled	(113.9		)
Change in gas and oil prices on futures markets	(111.8		)
Contracts added	(17.8		)
Net fair value of gas and oil derivative contracts outstanding at June 30, 2016	$	(78.3	)

The following table shows the sensitivity of the fair value of gas and oil derivative contracts to changes in the market price of gas, oil and basis differentials:



	June 30, 2016
	(in millions)
Net fair value – asset (liability)	$	(78.3	)
Fair value if market prices of gas and oil and basis differentials decline by 10%	$	(86.1	)
Fair value if market prices of gas and oil and basis differentials increase by 10%	$	(70.5	)

Utilizing the actual derivative volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $7.8 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $7.8 million as of June 30, 2016. However, a gain or loss eventually would be offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company’s commodity derivative transactions, see Note 7 – Derivative Contracts in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Interest Rate Risk Management

The Company’s ability to borrow and the rates offered by lenders can be adversely affected by illiquid credit markets and the Company's credit rating, as described in the risk factors in Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015. The Company’s credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. At June 30, 2016, the Company did not have any borrowings outstanding under its credit facility.

The remaining $2,221.8 million of the Company’s debt is senior notes with fixed interest rates; therefore, it is not affected by interest rate movements. For additional information regarding the Company’s debt instruments, see Note 9 – Debt, in Item I of Part I of this Quarterly Report on Form 10-Q.

Forward-Looking Statements

The quarterly report contains information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. We use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:


•	our growth strategies;


•	strong liquidity position providing financial flexibility and plans to preserve liquidity;


•	our liquidity and sufficiency of cash flow from operations, cash on hand and availability under our credit facility to fund the 2016 Permian Acquisition, our planned capital expenditures, operating expenses and repayment of maturing debt;


•	plans and ability to pursue acquisition opportunities;


•	the funding and closing of the 2016 Permian Acquisition;


•	our inventory of drilling locations;


•	drilling and completion plans;


•	focus on improving operating performance by optimizing reservoir development, enhancing well completion designs and aggressively pursuing cost reductions;


•	results from planned drilling operations and production operations;


•	plans to reduce drilling and completion activities, slow production growth, reduce costs and preserve liquidity;


•	ability to incur additional indebtedness;


•	loss contingencies;


•	sufficiency of accruals;


•	impact of government regulations;


•	expectations regarding gas, oil and NGL prices;


•	plans to recover or reject ethane from produced natural gas;


•	impact of lower or higher commodity prices and interest rates;


•	volatility of gas, oil and NGL prices and factors impacting such prices;


•	impact of global geopolitical and macroeconomic events;


•	exports of oil from the U.S.;


•	plans to enter into derivative contracts and the anticipated benefits from our derivative contracts;


•	divestitures of non-core assets;


•	amount and allocation of forecasted capital expenditures and plans for funding capital expenditures, operating expenses, repayment of maturing debt and working capital requirements;


•	resale revenues and expenses;


•	assumptions regarding equity compensation;


•	settlement of performance share units in cash;


•	recognition of compensation costs related to equity compensation grants;


•	expected contributions to our employee benefit plans;


•	employee benefit plan gains or losses;


•	the importance of Adjusted EBITDA (a non-GAAP financial measure) as a measure of performance;


•	delays caused by transportation, processing, storage and refining capacity issues;


•	fair values and critical accounting estimates, including estimated asset retirement obligations;


•	implementation and impact of new accounting pronouncements;


•	impact of shutting in wells;


•	factors impacting our ability to transport oil and gas;


•	potential for asset impairments and impact of impairments on financial statements;


•	the timing and estimated costs of restructurings;


•	managing counterparty risk exposure;


•	ability to meet delivery and sales commitments;


•	value of pension plan assets and plans regarding additional contributions to the pension plan;


•	changes to production plans, operating costs and capital expenditures; and


•	use of proceeds from the March 2016 and June 2016 public offerings of common stock.

Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and

uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:


•	the risk factors discussed in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, and Part II, Item 1A of this Quarterly Reporting on Form 10-Q;


•	changes in gas, oil and NGL prices;


•	global geopolitical and macroeconomic factors;


•	general economic conditions, including the performance of financial markets and interest rates;


•	asset impairments;


•	liquidity constraints, including those resulting from the cost and availability of debt and equity financing;


•	drilling methods and results;


•	shortages of oilfield equipment, services and personnel;


•	lack of available pipeline, processing and refining capacity;


•	our ability to successfully integrate acquired assets;


•	the outcome of contingencies such as legal proceedings;


•	delays in obtaining permits and governmental approvals;


•	operating risks such as unexpected drilling conditions and risks inherent in the production of oil and gas;


•	weather conditions;


•	changes in laws or regulations;

•

changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning: the environment, climate change, greenhouse gas or other emissions, natural resources, fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;


•	derivative activities;


•	volatility in the commodity-futures market;


•	failure of internal controls and procedures;


•	failure of our information technology infrastructure or applications;


•	elimination of federal income tax deductions for oil and gas exploration and development costs;


•	production, severance and property taxation rates;


•	discount rates;


•	regulatory approvals and compliance with contractual obligations;


•	actions of, or inaction by federal, state, local or tribal governments, foreign countries and the Organization of Petroleum Exporting Countries;


•	lack of, or disruptions in, adequate and reliable transportation for our production;


•	competitive conditions;


•	production volumes;


•	oil and gas reserve quantities;


•	reservoir performance;


•	operating costs;


•	inflation;


•	capital costs;


•	creditworthiness and performance of the Company's counterparties, including financial institutions, operating partners and other parties;


•	volatility in the securities, capital and credit markets;


•	actions by credit rating agencies; and


•	other factors, most of which are beyond the Company’s control.

QEP undertakes no obligation to publicly correct or update the forward-looking statements in this Quarterly Report on Form 10-Q, in other documents, or on the Company's website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, the Exchange Act) as of June 30, 2016. Based on such evaluation, such officers have concluded that, as of June 30, 2016, the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in the Company’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information is accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating the Company’s disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company’s controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Controls.

There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended June 30, 2016, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

Risk factors relating to the Company are set forth in its Annual Report on Form 10-K for the year ended December 31, 2015. Below are material changes to such risk factors that have occurred during the six months ended June 30, 2016.

Renegotiation of gathering, processing and transportation agreements may result in higher costs and/or delays in selling production. Due to market conditions, many midstream companies are attempting to renegotiate their gathering, processing and transportation agreements with their upstream counterparties. If QEP agrees to renegotiate its midstream agreements, the costs QEP pays for midstream services may increase. If QEP and any of its midstream service providers cannot agree on revised terms to these agreements, the midstream service providers may assert that continued performance of their obligations under these contracts is uneconomic and attempt to terminate or alter the agreements, which could hinder QEP's access to gas, oil and NGL markets, increase costs and/or delay production from its wells. Disputes over termination or changes to the agreement could result in arbitration or litigation, causing uncertainty about the status of the agreements and further delays. For example, an entity that purchases, gathers and processes natural gas produced from oil wells operated by QEP in the Williston Basin has claimed that the decline in commodity prices has rendered its gathering and processing operations "uneconomic" and demanded that QEP pay additional fees for gathering and processing services. QEP initiated arbitration proceedings in May 2016 to enforce the terms of the existing agreement. If QEP is not successful and must pay these additional fees, QEP would incur higher transportation and handling costs which would result in reduced net income.

The Company is involved in legal proceedings that may result in substantial liabilities. Like many oil and gas companies, the Company is involved in various legal proceedings, including threatened claims, such as title, royalty, and contractual disputes. For example, the Company has received a demand from certain former limited partners of drilling partnerships, for which the Company acted as general partner. The former limited partners allege that the Company failed to make, or calculated incorrectly, distributions to which they were entitled. No litigation has been filed, and the Company has not fully evaluated the allegations or its defenses. Accordingly, the Company is unable to determine the extent of any potential liability or its impact on the Company’s business, financial condition or results of operations. The cost to settle legal proceedings (alleged or threatened), or satisfy any resulting judgment against the Company in such proceedings could result in a substantial liability, which could materially and adversely impact the Company’s cash flows and operating results for a particular period. Judgments and estimates to determine accruals or range of losses related to legal proceedings could change from one period to the next and such changes could be material. Current accruals may be insufficient.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following repurchases of QEP shares were made by QEP in association with vested restricted share awards withheld for

taxes.



Period	Total shares purchased ⁽¹⁾	Weighted- average price paid per share		Total shares purchased as part of publicly announced plans or programs	Remaining dollar amount that may be purchased under the plans or programs
April 1, 2016 - April 30, 2016	7,875	$	16.03	—	$	—
May 1, 2016 - May 31, 2016	3,567	$	17.38	—	$	—
June 1, 2016 - June 30, 2016	3,221	$	18.63	—	$	—

____________________________


⁽¹⁾	All of the 14,663 shares purchased during the three-month period ended June 30, 2016, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted share grants.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The following exhibits are being filed as part of this report:



Exhibit No.		Exhibits
1.1		Underwriting Agreement, dated as of June 21, 2016, by and among QEP Resources, Inc., J.P. Morgan Securities LLC and Deutsche Bank Securities Inc. (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 27, 2016.
3.1		Certificate of Incorporation, dated May 18, 2010 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 24, 2010)
3.2		Amended and Restated Bylaws, deemed effective October 27, 2014 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on October 29, 2014)
10.1		Purchase and Sale Agreement, dated June 21, 2016, by and among QEP Energy Company, as purchaser, and RK Petroleum Corp. and various other owners of certain oil and gas properties in the Permian Basin, as sellers.
31.1		Certification signed by Charles B. Stanley, QEP Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification signed by Richard J. Doleshek, QEP Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.LAB*		XBRL Label Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document

____________________________


*	These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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.



	QEP RESOURCES, INC.
	(Registrant)

July 27, 2016	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer

July 27, 2016	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

Exhibit

EXECUTION VERSION

PURCHASE AND SALE AGREEMENT

among

RK PETROLEUM CORP., ET AL
as Sellers

and

QEP ENERGY COMPANY

as Buyer

June 21, 2016

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Page

ARTICLE I DEFINITIONS; INTERPRETATION; FINAL DETERMINATION OF SELLERS AND NON-PARTICIPATING ASSOCIATED OWNERS AND RELATED MATTERS 1

1.1 Defined Terms 1

1.2 References and Rules of Construction 23

1.3 Final Determination of Sellers and Non-Participating Associated Owner 23

ARTICLE II PURCHASE AND SALE 25

2.1 Purchase and Sale 25

2.2 Excluded Assets 25

2.3 Revenues and Expenses 25

2.4 Allocation, Payment and Distribution of Adjusted Purchase Price 26

ARTICLE III PURCHASE PRICE 27

3.1 Preliminary Purchase Price and Participating Purchase Price 27

3.2 Deposit 27

3.3 Adjustments to Participating Purchase Price 27

3.4 Preliminary Settlement Statement 29

3.5 Final Settlement Statement 30

3.6 Disputes 32

3.7 Allocation of Participating Purchase Price / Allocated Values 33

3.8 Allocation of Consideration for Tax Purposes 33

ARTICLE IV BUYER’S CONDITIONS TO CLOSING 33

4.1 Individual Seller Conditions 33

4.2 Aggregate Seller Conditions 34

ARTICLE V SELLER’S CONDITIONS TO CLOSING 35

5.1 Representations 35

5.2 Performance 35

5.3 No Legal Proceedings 35

5.4 Title Defects, Hard Consents, Preferential Rights to Purchase, Environmental
Defects, and Casualty Losses 35

5.5 HSR Act 35

5.6 Replacement Bonds 35

5.7 Officer’s Certificates 36

5.8 Closing Deliverables 36

ARTICLE VI CLOSING 36

6.1 Date of Closing 36

6.2 Place of Closing 36

6.3 Closing Obligations 36

6.4 Records 37

ARTICLE VII TERMINATION; DEFAULT AND REMEDIES 37

7.1 Right of Termination 37

7.2 Partial or Complete Termination 38

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7.3 Effect of Termination 39

7.4 Return of Documentation and Confidentiality 40

ARTICLE VIII ASSUMPTION; INDEMNIFICATION; SURVIVAL 41

8.1 Assumption by Buyer 41

8.2 Indemnities of each Seller 41

8.3 Indemnities of Buyer 42

8.4 Limitation on Liability 43

8.5 Express Negligence 43

8.6 Exclusive Remedy 44

8.7 Indemnification Procedures 44

8.8 Survival 45

8.9 Waiver of Right to Rescission 46

8.10 Insurance 46

8.11 Waiver of Consequential Damages 46

8.12 Indemnity Escrow 47

ARTICLE IX REPRESENTATIONS AND WARRANTIES OF SELLER 48

9.1 Organization, Existence and Qualification 48

9.2 Authority, Approval and Enforceability 48

9.3 No Conflicts 48

9.4 Consents 49

9.5 Bankruptcy 49

9.6 Foreign Person 49

9.7 Litigation 49

9.8 Material Contracts 49

9.9 No Material Violation of Laws 50

9.10 Preferential Purchase Rights 51

9.11 Burdens 51

9.12 Imbalances 51

9.13 Current Commitments 51

9.14 Environmental 51

9.15 Taxes 52

9.16 Brokers’ Fees 52

9.17 Suspense Funds 52

9.18 Advance Payments 53

9.19 Properties 53

9.20 Non-Consent Operations. 53

9.21 Permits 53

9.22 Guarantees 53

9.23 Wells and Equipment 54

9.24 Operator 54

9.25 Condemnation. 54

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ARTICLE X REPRESENTATIONS AND WARRANTIES OF BUYER 54

10.1 Organization, Existence and Qualification 54

10.2 Authority, Approval and Enforceability 54

10.3 No Conflicts 55

10.4 Consents 55

10.5 Bankruptcy 55

10.6 Litigation 55

10.7 Financing 55

10.8 Regulatory 55

10.9 Independent Evaluation 55

10.10 Brokers’ Fees 56

10.11 Accredited Investor 56

ARTICLE XI CERTAIN AGREEMENTS 56

11.1 Conduct of Business 56

11.2 Operation of Assets After the Closing 59

11.3 HSR Act 60

11.4 Governmental Bonds 60

11.5 Exclusivity 60

11.6 Revenues 61

11.7 Financial Information 61

ARTICLE XII ACCESS; DISCLAIMERS 62

12.1 Access 62

12.2 Confidentiality 63

12.3 Disclaimers 63

ARTICLE XIII TITLE MATTERS; CASUALTY; TRANSFER RESTRICTIONS 65

13.1 Sellers’ Title 65

13.2 Notice of Title Defects; Defect Adjustments 66

13.3 Casualty Loss 73

13.4 Consents to Assign 73

ARTICLE XIV ENVIRONMENTAL MATTERS 75

14.1 Notice of Environmental Defects 75

ARTICLE XV MISCELLANEOUS 79

15.1 Exhibits, Schedules and Annexes 79

15.2 Expenses and Taxes 80

15.3 Assignment 81

15.4 Interpretation 82

15.5 Publicity 82

15.6 Notices 82

15.7 Seller Representatives. 84

15.8 Further Cooperation 88

iii

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15.9 Filings, Notices and Certain Governmental Approvals 88

15.10 Entire Agreement; Conflicts 88

15.11 Parties in Interest 88

15.12 Amendment 89

15.13 Waiver; Rights Cumulative 89

15.14 Conflict of Law Jurisdiction, Venue; Jury Waiver 89

15.15 Severability 90

15.16 Like-Kind Exchange 90

15.17 Counterparts 91

15.18 Waiver of Preferential Purchase Rights and Consents 91

15.19 Legal Representation 91

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LIST OF EXHIBITS, SCHEDULES, AND ANNEXES



EXHIBITS:
Exhibit A	―	Leases
Exhibit A-1	―	Wells (WI/NRI) and Allocated Values
Exhibit A-2	―	Tracts (WI/NRI/Net Acres); Hypothetical DSUs (WI/NRI/Net Acres); and Allocated Values
Exhibit A-3	―	Rights-of-Way
Exhibit A-4	―	Personal Property
Exhibit A-5	―	Aggregate Allocated Values by Seller
Exhibit A-6	―	Retained Fee Mineral Interests
Exhibit B	―	Contract Area
Exhibit C	―	Form of Assignment
Exhibit D	―	Form of Closing Certificate
Exhibit E	―	Target Formation Logs
Exhibit F	―	Form of Joinder Agreement
Exhibit G	―	Form of Transition Services Agreement
Exhibit H	―	Form of Seller Pooling Consent

SELLER SPECIFIC SCHEDULES:
Schedule 1.1	―	Seller Knowledge Persons
Schedule 9.1	―	Seller Organizational Information
Schedule 9.4	―	Consents
Schedule 9.7	―	Litigation
Schedule 9.8(a)	―	Material Contracts
Schedule 9.8(b)	―	Material Contract Matters
Schedule 9.9	―	Violation of Laws
Schedule 9.10	―	Preferential Purchase Rights
Schedule 9.11	―	Burdens
Schedule 9.12(a)	―	Imbalances
Schedule 9.12(b)	―	Payout Status
Schedule 9.13	―	Current Commitments
Schedule 9.14	―	Environmental
Schedule 9.15	―	Asset Taxes
Schedule 9.17	―	Suspense Funds
Schedule 9.18	―	Advance Payments
Schedule 9.19	―	Properties
Schedule 9.20	―	Non-Consent Operations
Schedule 9.21	―	Permits
Schedule 9.22	―	Guarantees
Schedule 9.23	―	Wells & Equipment
Schedule 11.1	―	Conduct of Business
Schedule 11.1(a)(iii)	―	Continuous Drilling Obligations
Schedule 11.4	―	Governmental Bonds

ANNEXES:
Annex A	―	Associated Owners
Annex B	―	BJH Represented Sellers as of Execution Date
Annex C	―	Schmidt Represented Sellers
Annex D	―	BJH Represented Sellers by Virtue of Joinder Agreement

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PURCHASE AND SALE AGREEMENT

This PURCHASE AND SALE AGREEMENT (this “Agreement”) is executed as of June 21, 2016 (the “Execution Date”), by and among each Person listed on Annex A, but only to the extent that such Person either (a) executes this Agreement as a Seller on the Execution Date or (b) executes a Joinder Agreement as contemplated by Section 1.3 prior to the Election Deadline (each individually, a “Seller” and collectively, the “Sellers” as the context requires), and QEP Energy Company, a Texas corporation (“Buyer”). Sellers and Buyer are referred to herein, individually as a “Party”, and collectively, as the “Parties”. Each of Blind Juniper Holdings, LLC, a Texas limited liability company (“BJH”), and Richard Schmidt REP, LLC, a Texas limited liability company (“Schmidt REP”), join in this Agreement solely in their respective capacities as Seller’s Representatives hereunder and solely for such purpose shall be deemed “Parties” to this Agreement.

RECITALS

Each Seller desires to sell and assign to Buyer, and Buyer desires to purchase and acquire from each Seller, the entirety of such Seller’s right, title and interest in and to the Assets (as hereinafter defined) on the terms and conditions set forth in this Agreement.

NOW, THEREFORE, for and in consideration of the mutual promises contained herein, the benefits to be derived by each Party hereunder, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Sellers and Buyer agree as follows:

Article I
DEFINITIONS; INTERPRETATION; FINAL DETERMINATION OF SELLERS AND NON-PARTICIPATING ASSOCIATED OWNERS AND RELATED MATTERS

1.1
Defined Terms. Capitalized terms used herein shall have the meanings set forth in this Section 1.1, unless the context otherwise requires.

“Accounting Arbitrator” shall have the meaning set forth in Section 3.6.

“Adjusted Purchase Price” shall have the meaning set forth in Section 3.3.

“Adjustment Escrow” shall have the meaning set forth in Section 3.5(c).

“Advisor” shall have the meaning given in the definition of “Excluded Assets”.

“AFE” shall have the meaning set forth in Section 9.13.

“Affiliate” shall mean any Person that, directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with, another Person. The term “control” and its derivatives with respect to any Person means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

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“Agreement” shall have the meaning set forth in the introductory paragraph herein and includes the Exhibits and Schedules attached hereto.

“Allocable Amount” shall have the meaning set forth in Section 3.8.

“Allocated Value” shall have the meaning set forth in Section 3.7.

“Allocation Schedule” shall have the meaning set forth in Section 3.8.

“Applicable Contracts” shall mean, as the context requires, as to (a) each Seller, or (b) all Sellers, collectively, all Contracts (i) to which any such Seller is a party (or is a successor or assign of a party), (ii) that pertain to any of the Assets and (iii) that will be binding on Buyer or any of the Assets after the Closing, but exclusive, in each case, of any master service agreements or similar Contracts.

“Assets” shall mean, with respect to each Seller, the entirety of such Seller’s right, title and interest in and to the following, in each case, less and except the Excluded Assets applicable to each such Seller:

(a) all of the oil, gas and/or mineral leases covering lands within the Contract Area, whether producing or non-producing, together with all leasehold interests, carried interests, reversionary interests, and other interests of a similar nature that are created thereby or attributable thereto, and the operating rights, Working Interests, Net Revenue Interests, and other rights to Hydrocarbons resulting therefrom, including all of the oil, gas and/or mineral leases described in Exhibit A (the “Leases”), together with any and all other rights, titles and interests of such Seller in and to the lands covered or burdened thereby (the “Lands”), and all other interests of such Seller of any kind or character in and to the Leases;

(b) all wells (including all oil and gas wells, water wells, disposal wells and injection wells) located on any of the Leases or on any other lease or lands with which any Lease has been unitized, whether such wells are producing, shut-in or abandoned (including the wells set forth in Exhibit A-1, the “Wells”);

(c) all rights and interests in, under or derived from all unitization or pooling agreements in effect with respect to any of the Leases or Wells and the units created thereby (the “Units”);

(d) all Applicable Contracts applicable to such Seller, insofar as covering or relating to such Seller’s Assets;

(e) all Rights-of-Way applicable to such Seller, insofar as covering or relating to such Seller’s Assets, including the Rights-of-Way owned by any such Seller and set forth in Exhibit A-3;

(f) all equipment, machinery, fixtures and other personal and mixed property, operational and nonoperational, known or unknown, located on any of the Leases, Wells, Units or other Assets, that are used or held for use in connection with the ownership, operation, production or development of such Leases, Well, Units or other Assets, including, pipelines, gathering systems,

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well equipment, casing, tubing, pumps, gauges, valves, motors, fixtures, machinery, compression equipment, flow lines, water lines, heaters, processing, treating and separation facilities, automation systems including meters and related telemetry on such Wells, power lines, telephone and communication lines, structures, materials and other items used in the ownership, operation or development of such Leases, Well, Units or other Assets (“Personal Property”), including the Personal Property set forth on Exhibit A-4;

(g) all Hydrocarbons attributable to any such Seller’s Leases, Wells and/or Units to the extent such Hydrocarbons were produced from and after the Effective Time;

(h) all Imbalances relating to any such Seller’s Assets;

(i) to the extent assignable or transferable by any such Seller, all Permits held by such Seller that are used or held in connection with the ownership or operation of such Seller’s other Assets;

(j) all non-proprietary geophysical, seismic and related technical data (in each case) that (i) are held by any such Seller or its respective Affiliates, (ii) are transferable without payment of a fee or other penalty to any Third Party under any Contract (unless Buyer has separately agreed in writing to pay such fee or other penalty), and (iii) primarily relate to the Leases, Wells, Units or other Assets;

(k) all original files, records and data (including electronic copies where available) that (i) primarily relate to the ownership, operation or development of any such Seller’s Assets described above, and (ii) that are in such Seller’s or its respective Affiliates’ possession, including: (A) land and title records (including abstracts of title, title opinions and title curative documents); (B) Applicable Contract files; (C) correspondence with a Third Party; (D) operations, environmental, health and safety, pipeline safety, production, accounting and Tax records (other than those relating to Income Taxes or that relate to such Seller’s businesses generally); and (E) facility and well records; provided, however, that those items referenced above in this sub-section (k) that are: (1) subject to a valid legal privilege or disclosure restrictions in favor of Third Parties (other than title opinions relating directly to the Assets); (2) not transferable without payment of additional consideration (and Buyer has not agreed in writing to pay such additional consideration); (3) internal correspondence or correspondence with such Seller’s Affiliates, including, without limitation, all emails on such Seller’s servers and networks; or (4) employee files, shall in each case, be excluded (the foregoing items, taking into account the exclusions listed above, collectively, the “Records”); and

(l) without limitation of the foregoing, all other rights, titles and interests of such Seller in and to the lands described on Exhibit B (the “Contract Area”), save and except the Excluded Assets of such Seller.

For the avoidance of doubt, and notwithstanding anything to the contrary herein, the Sellers’ collective “Assets” hereunder shall expressly exclude all right, title and interest in and to any of the foregoing described items in sub-sections (a) through (l) above to the extent the same are held by any Non-Participating Owner, regardless that the same were included on the Initial Exhibits and Schedules to this Agreement delivered as of the Execution Date, as the same shall be excluded in

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the Final Exhibits and Schedules to this Agreement delivered by the Seller’s Representatives pursuant to Section 1.3(b).

“Asset Taxes” shall mean ad valorem, property, sales, use, excise, severance, production or similar Taxes (including any interest, fine, penalty or additions to Tax imposed by a Governmental Authority in connection with such Taxes) based upon the operation or ownership of the Assets or the production of Hydrocarbons or receipt of proceeds therefrom but excluding, for the avoidance of doubt, (a) Income Taxes and (b) Transfer Taxes.

“Assigned Rights” shall have the meaning set forth in Section 15.16.

“Assignment” shall mean, with respect to each Seller, an Assignment and Bill of Sale from such Seller to Buyer pertaining to such Seller’s Assets and substantially in the form of Exhibit C.

“Associated Owners” shall mean those Persons listed on Schedule 9.1, whether or not such Person executes this Agreement as a Seller or delivers a Joinder Agreement pursuant to Section 1.3.

“Assumed Environmental Liabilities” shall mean all Liabilities and obligations (a) brought or assessed by any Persons relating to Environmental Conditions with respect to the Assets and (b) to properly plug and abandon any Wells and to restore the surface estate of applicable lands burdened by the Leases or pooled therewith, whether arising before, on or after the Effective Time.

“Assumed Obligations” shall have the meaning set forth in Section 8.1.

“BJH” shall have the meaning set forth in the introductory paragraph.

“BJH Represented Sellers” shall have the meaning set forth in Section 15.7(a).

“Burdens” shall mean royalties, non-participating royalty interests, overriding royalties, production payments, carried interests, net profits interests, reversionary interests, back-in interests and all other burdens upon, measured by or payable out of production.

“Business Day” shall mean a day (other than a Saturday or Sunday) on which commercial banks in Texas are generally open for business.

“Buyer” shall have the meaning set forth in the introductory paragraph of this Agreement.

“Buyer Indemnified Parties” shall have the meaning set forth in Section 8.2.

“Buyer’s Auditor” shall have the meaning set forth in Section 11.7.

“Buyer’s Representatives” shall have the meaning set forth in Section 12.1(a).

“Casualty Loss” shall have the meaning set forth in Section 13.3

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“Claim” shall have the meaning set forth in Section 8.7(b).

“Claim Notice” shall have the meaning set forth in Section 8.7(b).

“Closing” shall have the meaning set forth in Section 6.1.

“Closing Date” shall have the meaning set forth in Section 6.1.

“Code” shall mean the Internal Revenue Code of 1986, as amended.

“Confidentiality Agreement” shall mean that certain Confidentiality Agreement, dated as of April 19, 2016, between RK Petroleum Corp. and Buyer.

“Contract” shall mean any written or oral: contract; agreement; agreement regarding indebtedness; indenture; debenture; note, bond or loan; collective bargaining agreement; mortgage; license agreement; farmin and/or farmout agreement; participation, exploration or development agreement; crude oil, condensate or natural gas purchase and sale, gathering, processing, transportation or marketing agreement; operating agreement; balancing agreement; unitization agreement; facilities or equipment lease; production handling agreement; or other similar contract, but in each case specifically excluding, however, any Lease, Right-of-Way, Permit or other instrument creating or evidencing an interest in any Asset or any real property related to or used or held for use in connection with the operation of any Asset.

“Contract Area” shall have the meaning set forth in the definition of “Assets”.

“Cooperating Seller” shall have the meaning set forth in Section 11.7.

“Cure Period” shall have the meaning set forth in Section 13.2(c).

“Customary Post-Closing Consents” shall mean the consents and approvals from Governmental Authorities for the assignment of the Assets to Buyer that are customarily obtained after such assignment of properties similar to the Assets.

“Defensible Title” shall mean, with respect to each Seller, such title of such Seller to the Leases, the Lands and the Wells in which it owns an interest that, as of the Effective Time and as of the Closing Date, exclusive of the Excluded Assets, but subject to the Permitted Encumbrances:

(a) entitles such Seller to receive, during the entirety of the productive life of each Tract in which it owns an interest (as set forth in Exhibit A-2), and would entitle such Seller to receive, during the entirety of the productive life of each Hypothetical DSU in which it owns an interest (as set forth in Exhibit A-2), if such Hypothetical DSU could be and were formed in accordance with the Hypothetical DSU Assumptions, not less than the Net Revenue Interest for (i) each Target Formation in each Tract and Hypothetical DSU as set forth in Exhibit A-2, as applicable, and (ii) each Target Formation in each Well as set forth in Exhibit A-1, except (A) for decreases in connection with those operations in which such Seller or its successors or assigns may, from and after Closing, be a non-consenting co-owner, (B) for decreases resulting from the establishment or amendment, from and after the Execution Date, of actual pools or units to the extent such establishment or amendment is permitted under Section 11.1, (C) for decreases required

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to allow other Working Interest owners to make up past underproduction or pipelines to make up past under deliveries, in each case, only to the extent listed on such Seller’s Schedule 9.12(a), (D) for decreases occurring after the Execution Date as a result of the operation of continuous development and partial termination provisions in such Seller’s Leases, but only to the extent such decreases do not result from any breach by any Seller of the terms of this Agreement or of the applicable Lease, and (E) as otherwise expressly set forth in Exhibits A-1 or A-2, as applicable;

(b) obligates such Seller to bear, during the entirety of the productive life of each Tract in which it owns an interest (as set forth in Exhibit A-2), and would obligate such Seller to bear during the entire productive life of each Hypothetical DSU in which it owns an interest (as set forth in Exhibit A-2), if such Hypothetical DSU could be and were actually formed in accordance with the Hypothetical DSU Assumptions, not more than the Working Interest for (i) each Target Formation in each Tract and Hypothetical DSU as set forth in Exhibit A-2, as applicable, and (ii) each Target Formation in each Well as set forth in Exhibit A-1, except (A) for increases resulting from contribution requirements with respect to defaulting co-owners under applicable operating agreements, (B) for increases to the extent that they are accompanied by a proportionate increase in such Seller’s Net Revenue Interest in the relevant Target Formation for any such Tract, Hypothetical DSU or Well, (C) for increases resulting from the establishment or amendment, from and after the Execution Date, of actual pools or units to the extent such establishment or amendment is permitted under Section 11.1, and (D) as otherwise expressly set forth in Exhibits A-1 or A-2, as applicable;

(c) entitles such Seller to a number of Net Acres in each Target Formation for each Tract in which such Seller owns an interest (as set forth in Exhibit A-2), and would entitle such Seller to a number of Net Acres in each Target formation for each Hypothetical DSU in which such Seller owns an interest (as set forth in Exhibit A-2), if such Hypothetical DSU could be and were formed in accordance with the Hypothetical DSU Assumptions, that is not less than the “Seller Net Acres” set forth in Exhibit A-2 with respect to each Target Formation for each such Tract and Hypothetical DSU, as applicable, in each case, throughout the duration of the productive life of each such Tract and Hypothetical DSU in which such Seller owns an interest (as set forth in Exhibit A-2, as applicable) to the extent included in the applicable Target Formation; and

(d) is free and clear of Encumbrances.

“Deposit” shall have the meaning set forth in Section 3.2.

“Dispute Notice” shall have the meaning set forth in Section 3.5.

“DOJ” shall mean the Department of Justice.

“Election Deadline” shall have the meaning set forth in Section 1.3(a).

“Effective Time” shall mean 12:01 a.m. (Prevailing Central Time) on April 1, 2016.

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“Encumbrance” shall mean any lien, mortgage, security interest, pledge, charge, or similar encumbrance.

“Environmental Arbitrator” shall have the meaning set forth in Section 14.1(f).

“Environmental Claim Date” shall have the meaning set forth in Section 14.1(a).

“Environmental Condition” shall mean (a) a condition with respect to the air, soil, subsurface, surface waters, ground waters and/or sediments that causes Sellers or any Affiliate of Sellers not to be in material compliance with any Environmental Law or could reasonably be expected to result in any material Liability thereunder or (b) the existence, with respect to the Assets or the operation thereof, of any condition, environmental pollution, contamination or degradation where Remediation is presently required (or if known or confirmed, would be presently required) under Environmental Laws.

“Environmental Defect” shall mean any Environmental Condition with respect to an Asset that is not set forth on a Seller’s Schedule 9.14.

“Environmental Defect Deductible” shall mean 1.5% of the unadjusted Participating Purchase Price.

“Environmental Defect Notice” shall have the meaning set forth in Section 14.1(a).

“Environmental Defect Property” shall have the meaning set forth in Section 14.1(a).

“Environmental Laws” shall mean all applicable Laws in effect as of the Effective Time relating to the environment (including natural resources), health and safety, Hazardous Materials, industrial hygiene, the environmental conditions on, under, or about any of the Assets, including soil, groundwater, and indoor and ambient air conditions or the reporting or remediation of environmental contamination and includes, without limitation, any Law the purpose of which is to conserve or protect the environment, health and safety, wildlife or natural resources. The term “Environmental Laws” does not include good or desirable operating practices or standards that may be voluntarily employed or adopted by other oil and gas well operators or recommended, but not required, by a Governmental Authority.

“Escrow Agent” shall mean Amegy Bank.

“Escrow Agreement” shall mean the escrow agreement by and among Escrow Agent, Buyer, and Seller’s Representatives, entered into as of the Execution Date.

“Escrow Termination Date” shall have the meaning set forth in Section 8.12.

“Exchanging Party” shall have the meaning set forth in Section 15.16.

“Excluded Assets” shall mean, with respect to each Seller, the following listed items, and notwithstanding anything to the contrary herein, the Assets attributable to such Seller shall not include, and there is excepted, reserved and excluded from the sale contemplated by this Agreement, the following listed items:

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(a) any Burden and other like interests of such Seller in, to, or under the Leases, the Wells, the Lands and/or the lands included within the Contract Area; provided, however, that no Burden shall constitute an Excluded Asset that (i) is an overriding royalty interest, and (ii) was created solely from such Seller’s interest in the Leases (the foregoing retained Burdens, less and except any such overriding royalty interests, such Seller’s “Retained Burdens”);

(b) all fee surface interests in the Lands or the lands within the Contract Area or used or held in connection with the Assets;

(d) all trade credits and all accounts, accounts receivable, checks, funds, promissory notes, instruments and general intangibles (as those terms are defined in the Texas Uniform Commercial Code) attributable to the Assets with respect to any period of time prior to the Effective Time, in each case, except to the extent relating to any Assumed Obligation;

(e) all claims of such Seller for, and rights of such Seller to, refunds of or loss carryovers with respect to (i) any Asset Taxes paid by such Seller that are attributable to any taxable period, or portion thereof, ending on or before the Effective Time, (ii) any of such Seller’s Taxes with respect to the Excluded Assets, or (iii) amounts (other than Taxes) paid by such Seller in connection with such Seller’s Assets to the extent attributable to the period prior to the Effective Time, including refunds of amounts paid under any Hydrocarbon gathering or transportation agreement;

(f) all proceeds, income, royalties or revenues attributable to (i) such Seller’s Assets for any period prior to the Effective Time or (ii) any of such Seller’s other Excluded Assets;

(g) all Hydrocarbons produced from or attributable to the such Seller’s Assets with respect to all periods prior to the Effective Time, together with all proceeds from the sale of those Hydrocarbons, in each case, except to the extent the Participating Purchase Price is adjusted therefor pursuant to Section 3.3(a)(i);

(h) all of such Seller’s proprietary or licensed computer software, technology, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property;

(i) all documents and instruments of such Seller (other than title opinions) (i) that are subject to a valid attorney-client, work product or other privilege; (ii) prepared by or for counsel of such Seller; or (iii) received from any financial, commercial or legal advisor of such Seller (with respect to any Seller, each, an “Advisor”);

(j) all (i) agreements and correspondence between such Seller or any of such Seller’s Affiliates and any Advisor relating to the transactions contemplated in this Agreement; (ii) lists of prospective purchasers for those transactions compiled by such Seller or any of such Seller’s Affiliates or any Advisor; (iii) bids submitted by other prospective purchasers of such Seller’s Assets; (iv) analyses by such Seller or any of such Seller’s Affiliates or any Advisor of any bids submitted by any prospective purchaser; (v) correspondence between such Seller or any of such Seller’s

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Affiliates or any Advisor, or any of their respective representatives, and any prospective purchaser other than Buyer; and (vi) correspondence between such Seller or any of such Seller’s Affiliates or any Advisor or any of their respective representatives with respect to any of the bids, the prospective purchasers, the engagement or activities of any Advisor, or the transactions contemplated in this Agreement;

(k) all data and other information that may not be disclosed or assigned to Buyer by such Seller as a result of confidentiality or similar arrangements in favor of Third Parties under Contracts with Third Parties, even if such data or other information is inadvertently disclosed or provided to Buyer (in which case Buyer shall use its commercially reasonable efforts to promptly return such data or information to such Seller’s applicable Seller’s Representative);

(l) all audit rights arising under any of such Seller’s Applicable Contracts or otherwise with respect to any period prior to the Effective Time or to any of such Seller’s Excluded Assets, except to the extent that such audit rights relate to any Assumed Obligation;

(m) all corporate, partnership and limited liability company financial and Income Tax books, accounts, records and documents of such Seller or any of such Seller’s Affiliates that relate primarily to such Person’s business generally;

(n) all claims and causes of action of such Seller (i) arising from acts, omissions or events related to, or damage to or destruction of, the Assets, occurring prior to the Effective Time; (ii) arising under or with respect to any of the Applicable Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds); or (iii) with respect to any of the Excluded Assets, in each case, except to the extent relating to any Assumed Obligation;

(o) all rights and interests of such Seller (i) under any policy or agreement of insurance or indemnity; (ii) under any bond; or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events related to, or damage to or destruction of, the Assets occurring prior to the Effective Time;

(p) all amounts due or payable to such Seller as adjustments to insurance premiums related to such Seller’s Assets with respect to any period prior to the Effective Time;

(q) all Hedge Contracts held by such Seller and relating to such Seller’s Assets and all amounts resulting from derivative contracts or similar agreements used to manage oil, natural gas, products or other commodity prices whether deemed a hedge, non-hedge or ineffective hedge transaction;

(r) all security or other deposits made or attributable to such Seller’s (i) Assets for any period prior to the Effective Time; or (ii) Excluded Assets, in each case, except to the extent relating to any Assumed Obligation;

(s) all funds held in suspense accounts by any Third Party related to such Seller’s Assets for any period prior to the Effective Time;

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(t) all of such Seller’s vehicles, vessels, trailers, software, employees, computers and associated peripherals and all radio, telephone and other communication equipment;

(u) all rights of such Seller under this Agreement or under any instruments executed and delivered by such Seller (or on such Seller’s behalf by the Seller’s Representatives) in connection with Closing;

(v) any records properly retained by such Seller pursuant to the exclusions set forth in sub-section (k) in the definition of “Assets”, including all of such Seller’s internal correspondence and correspondence with such Seller’s Affiliates, including, without limitation, all emails on such Seller’s servers and networks;

(w) such Seller’s area-wide bonds, operator’s well bonds, permits and licenses or other permits, licenses or authorizations used in the conduct of such Seller’s business generally; and

(x) all items that would have constituted “Assets” as defined in Section 1.1 but for, and to the extent of, their being (i) used or held by such Seller solely in connection with such Seller’s Excluded Assets, or (ii) permanently excluded from the transactions contemplated by this Agreement pursuant to the provisions of Section 12.1(c), Section 13.2(d)(ii), Section 13.4 or Section 14.1(c)(iii).

“Execution Date” shall have the meaning set forth in the introductory paragraph of this Agreement.

“Failed Seller” shall have the meaning set forth in Section 7.2(a).

“Filings” shall have the meaning set forth in Section 11.7.

“Final Adjustment Amount” shall have the meaning set forth in Section 3.5(b).

“Final Exhibits and Schedules” shall have the meaning set forth in Section 1.3(b).

“Final Payment Date” shall have the meaning set forth in Section 3.5(b)(i).

“Final Price” shall have the meaning set forth in Section 3.5(a).

“Final Settlement Statement” shall have the meaning set forth in Section 3.5(a).

“FTC” shall mean the Federal Trade Commission.

“Fundamental Representations” shall mean the representations and warranties of Sellers set forth in Section 9.1, Section 9.2, Section 9.3, Section 9.5, Section 9.15 and Section 9.16.

“GAAP” shall mean generally accepted accounting principles in the United States, consistently applied.

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“Governmental Authority” shall mean any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, regulatory or taxing authority or power, and any court or governmental tribunal, including any tribal authority having or asserting jurisdiction.

“Guarantees” shall have the meaning set forth in Section 9.22.

“Hard Consent” shall mean a consent by a Third Party that if not obtained prior to the assignment of an Asset, would (a) automatically void or nullify the assignment with respect to such Asset, (b) automatically terminate an applicable Seller’s interest in the Asset subject to such consent, (c) give the Third Party holding such consent the right to terminate the Lease, Applicable Contract, Right-of-Way, Permit or other Asset subject to consent under the express terms thereof, or (d) require the payment of any liquidated amounts as a result of such failure.

“Hazardous Substances” shall mean any pollutants, contaminants, toxics or hazardous or extremely hazardous substances, materials, wastes, constituents, compounds or chemicals that are regulated by, or may form the basis of any Liability under, any Environmental Laws, including NORM and other substances referenced in Section 14.2.

“Hedge Contract” shall mean any swap, forward, future or derivatives transaction or option or other similar hedge contract.

“HSR Act” shall mean the Hart Scott Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations thereunder.

“Hydrocarbons” shall mean oil and gas and other hydrocarbons produced or processed in association therewith.

“Hypothetical DSU” shall mean the hypothetical drilling, spacing or pooled unit in each Target Formation formed by combining the Tracts (or portions thereof) included within each area of land designated as a unit on the plat included in Exhibit A-2, in each case, utilizing the Hypothetical DSU Assumptions.

“Hypothetical DSU Assumptions” shall mean the hypothetical formation, without regard to whether or not possible or permissible, of each Hypothetical DSU by combining the Tracts (or portions thereof) located within the area encompassed by the applicable Hypothetical DSU as set forth on the plat included in Exhibit A-2 in a manner that allocates the Working Interest and Net Revenue Interest of each applicable Seller in each of those Tracts (or portions thereof) on a surface acre basis to arrive at a hypothetical unit-wide Working Interest and Net Revenue Interest of such Seller for each Target Formation in each Hypothetical DSU through the following process:

(a) determining each applicable Seller’s hypothetical unit-wide Working Interest (on an 8/8ths basis) as to each Target Formation in such Hypothetical DSU by (i) multiplying (A) the Working Interest of such Seller with respect to such Target Formation in each Tract (or portion thereof) within the Hypothetical DSU, times (B) a fraction, the (1) numerator of which is the total number of surface acres within the applicable Tract (or portion thereof) within such Hypothetical

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DSU, and (2) denominator of which is the total number of surface acres covered by all Tracts (or portions thereof) within the applicable Hypothetical DSU, to arrive at a weighted Working Interest for such Seller with respect to such Target Formation in such Tract (or portion thereof) within such Hypothetical DSU, and (ii) adding together the amounts determined as to such Seller and Target Formation pursuant to subpart (a)(i) above with respect to each Tract (or portion thereof) within such Hypothetical DSU;

(b) determining each applicable Seller’s hypothetical unit-wide Net Revenue Interest (on an 8/8ths basis) as to each Target Formation in such Hypothetical DSU by (i) multiplying (A) the Net Revenue Interest of such Seller with respect to such Target Formation in each Tract (or portion thereof) within the Hypothetical DSU, times (B) a fraction, the (1) numerator of which is the total number of surface acres within the applicable Tract (or portion thereof) within such Hypothetical DSU, and (2) denominator of which is the total number of surface acres covered by all Tracts (or portions thereof) within the applicable Hypothetical DSU, to arrive at a weighted Net Revenue Interest for such Seller with respect to such Target Formation in each Tract (or portion thereof) within such Hypothetical DSU, and (ii) adding together the amounts determined as to such Seller and Target Formation pursuant to subpart (b)(i) above with respect to each Tract (or portion thereof) within such Hypothetical DSU; and

(c) determining the aggregate hypothetical unit-wide Working Interest and Net Revenue Interest of all applicable Sellers with respect to each Target Formation in such Hypothetical DSU by (i) adding the hypothetical unit-wide Working Interests of each individual applicable Seller with respect to such Target Formation in such Hypothetical DSU (as determined pursuant to subpart (a) above), and (ii) adding the hypothetical unit-wide Net Revenue Interests of each individual applicable Seller with respect to such Target Formation in such Hypothetical DSU (as determined pursuant to subpart (b) above), respectively.

For the avoidance of doubt, the foregoing assumptions and calculations shall be used separately as to each Target Formation within each Hypothetical DSU (as set forth on Exhibit A-2), such that each (x) applicable Seller may be assigned a hypothetical unit-wide Working Interest and Net Revenue Interest for each Target Formation with respect to each applicable Hypothetical DSU, and (y) each Hypothetical DSU shall be assigned an aggregate (of all applicable Sellers) hypothetical unit-wide Working Interest and Net Revenue Interest with respect to each applicable Target Formation within such Hypothetical DSU.

“Imbalances” shall mean, as the context requires, a Well Imbalance and/or a Pipeline Imbalance.

“Income Taxes” shall mean any income, capital gains, franchise, and similar Taxes.

“Indemnified Party” shall have the meaning set forth in Section 8.7(a).

“Indemnifying Party” shall have the meaning set forth in Section 8.7(a).

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“Indemnity Deductible” shall mean, with respect to each Seller, an amount equal to 1.5% of the aggregate Allocated Value of all Assets conveyed by such Seller to Buyer hereunder.

“Indemnity Escrow” shall have the meaning set forth in Section 3.2.

“Individual Environmental Defect Threshold” shall have the meaning set forth in Section 14.1(e).

“Individual Title Threshold” shall have the meaning set forth in Section 13.2(i).

“Initial Exhibits” shall have the meaning set forth in Section 1.3(b).

“Invasive Activities” shall have the meaning set forth in Section 12.1(c).

“Joinder Agreement” shall have the meaning set forth in Section 1.3(a).

“Kelly Bushing” shall have the meaning set forth in the definition of “Lower Spraberry Formation”.

“KHH” shall have the meaning set forth in Section 15.19.

“Knowledge” shall mean (a) with respect to a Seller that is an individual, the actual, present knowledge of such Seller, (b) with respect to a Seller that is an entity, the actual, present knowledge of the Persons set forth on such Seller’s Schedule 1.1 that such Persons have or would have obtained after making reasonable inquiry of the employees of such Seller (and, if applicable, its Affiliates) having management responsibility for the fact or matter in question, and (c) with respect to a Seller that is an entity that fails to deliver a Schedule 1.1 hereunder, the actual, present knowledge of any officer or director (or, in the case of unincorporated entities, individuals exercising similar functions) that such Persons have or would have obtained after making reasonable inquiry of the employees of such Seller (and, if applicable, its Affiliates) having management responsibility for the fact or matter in question.

“Lands” shall, as the context requires, have the meaning set forth in the definition of “Assets” as it applies to (a) each Seller, or (b) the collective right, title and interest of all Sellers.

“Law” shall mean any applicable statute, law (including common law), rule, regulation, ordinance, order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Authority.

“Leases” shall, as the context requires, have the meaning set forth in the definition of “Assets” as it applies to (a) each Seller, or (b) the collective right, title and interest of all Sellers.

“Liabilities” shall mean any and all claims, causes of action, payments, charges, judgments, assessments, liabilities, losses, damages, penalties, fines and costs and expenses, including any attorneys’ fees, legal or other expenses incurred in connection therewith and including liabilities, costs, losses and damages for personal injury or death or property damage or environmental damage or remediation.

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“Like-Kind Exchange” shall mean a simultaneous or deferred (forward or reverse) exchange allowed pursuant to Section 1031 of the Code and the Treasury Regulations promulgated thereunder or any applicable state or local tax Laws.

“Lower Spraberry Formation” shall mean the stratigraphic equivalent of the geologic formation as located on the electric log for the Dubose #1 well from a measured depth of 8,558 feet below the kelly bushing (at an elevation of 2,864 feet above sea level) (the “Kelly Bushing”) down to, but not below, the measured depth of 9,001 feet below the Kelly Bushing as shown on the type log attached hereto as Exhibit E, recognizing that the actual depth will vary across the Contract Area.

“Material Contract” shall have the meaning set forth in Section 9.8(a).

“Material Joinder Disclosure” shall have the meaning set forth in Section 1.3(e).

“Net Acre” shall mean, as computed separately with respect to each Seller’s interest in each Target Formation for each Tract and Hypothetical DSU, (a) the number of gross acres in the lands covered by such Tract and Hypothetical DSU insofar as they relate to such Target Formation, multiplied by (b) the interest in the Hydrocarbons covered by the Leases comprising such Tract and Hypothetical DSU insofar as they relate to such Target Formation, multiplied by (c) such Seller’s undivided Working Interest in such Tract and Hypothetical DSU insofar as it relates to such Target Formation.

“Net Revenue Interest” shall mean, with respect to any Tract, Hypothetical DSU or Well, the decimal interest in and to all Hydrocarbons produced, saved and sold from or allocated to such Tract, Hypothetical DSU or Well, after giving effect to all applicable Burdens.

“Non-Assets” shall have the meaning set forth in Section 1.3(b).

“Non-Participating Associated Owners” shall mean those Associated Owners, if any, that do not either execute this Agreement as a Seller on the Execution Date or thereafter execute a Joinder Agreement as contemplated by Section 1.3 prior to the Election Deadline. For the avoidance of doubt, no Non-Participating Associated Owner shall be deemed to be a “Seller” hereunder for any purpose of this Agreement.

“NORM” shall mean naturally occurring radioactive material.

“Operated Assets” shall mean all Assets operated by any Seller or any Affiliate of any Seller.

“Operating Expenses” shall mean the following types of direct expenses to the extent attributable to the Assets and incurred in the ordinary course of business consistent with past practices: operating expenses (including Asset Taxes, as allocated pursuant to Section 15.2(b) and all insurance premiums or any other costs of insurance attributable to Sellers’ and/or their Affiliates’ insurance and to coverage periods from and after the Effective Time but excluding in all cases, all costs and expenses of bonds, letters of credit or other surety instruments) and capital expenditures incurred in the ownership and operation of the Assets in the ordinary course of business and, where applicable, in accordance with the relevant operating or unit agreement, if any, and overhead costs

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charged to the Assets under the relevant operating agreement or unit agreement, if any, but excluding Liabilities attributable to (a) obligations to plug wells and dismantle or decommission facilities, (b) the Remediation of any Environmental Condition under applicable Environmental Laws, (c) obligations to pay Working Interest, Burden or other interest owners revenues or proceeds attributable to sales of Hydrocarbons relating to the Assets, including those held in suspense, (d) personal injury or death, property damage or violation of any Law, and (e) obligations with respect to Imbalances.

“Outside Date” shall mean noon (Prevailing Central Time) on October 14, 2016.

“Participating Purchase Price” shall have the meaning set forth in Section 3.1(b).

“Party” and “Parties” shall have the meaning set forth in the introductory paragraph of this Agreement.

“Permit” shall mean any permits, licenses, authorizations, registrations, consents or approvals granted or issued by any Governmental Authority.

“Permitted Encumbrances” shall mean:

(a) the terms and conditions of all Leases and all Burdens; provided that the net cumulative effect of such Leases and Burdens does not operate to (i) reduce the aggregate Net Revenue Interest of any Seller in any Target Formation for any Tract, Hypothetical DSU or Well to an amount less than the Net Revenue Interest set forth in Exhibit A-2 or Exhibit A-1, as applicable, with respect to such Target Formation and such Tract, Hypothetical DSU or Well, (ii) obligate any Seller to bear a Working Interest with respect to the Target Formation in any Tract, Hypothetical DSU or Well in any amount greater than the Working Interest set forth in Exhibit A-2 or Exhibit A-1, as applicable, with respect to such Target Formation and such Tract, Hypothetical DSU or Well (unless as a result of such same terms and conditions the Net Revenue Interest with respect to such Target Formation and such Tract, Hypothetical DSU or Well is greater than the Net Revenue Interest with respect to such Target Formation and such Tract, Hypothetical DSU or Well as set forth in Exhibit A-2 or Exhibit A-1, as applicable, in the same proportion as any increase in such Working Interest), (iii) reduce the aggregate number of Net Acres of any Seller in any Tract or Hypothetical DSU to an amount less than the “Seller Net Acres” set forth in Exhibit A-2, as applicable, with respect to such Target Formation and such Tract and Hypothetical DSU, (iv) reduce any Seller’s leasehold interest as to any Tract and Hypothetical DSU, except to the extent of any depth restriction or depth severance specifically described on Exhibit A-2, as applicable, or (v) materially impair the ownership, operation, development, production or use of any of the Assets as currently or reasonably anticipated to be owned, operated, developed, produced, or used;

(b) the terms and conditions of the Rights-of-Way included in the Assets, to the extent, individually or in the aggregate, such rights would not reasonably be expected to materially impair the ownership, operation, development, production or use of any of the Assets as currently owned, operated, developed, produced, or used;

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(d) liens for Taxes not yet due or delinquent;

(e) Customary Post-Closing Consents and any required notices to, or filings with, Governmental Authorities in connection with the consummation of the transactions contemplated by this Agreement;

(f) to the extent not yet triggered, conventional rights of reassignment upon final intention to abandon or release any of the Assets;

(g) easements, conditions, covenants, restrictions, servitudes, permits, rights-of-way, surface leases and other rights in the Assets for the purpose of operations, facilities, pipelines, transmission lines, transportation lines, distribution lines and other like purposes, or for the joint or common use of rights-of-way, facilities and equipment, to the extent, individually or in the aggregate, such rights would not reasonably be expected to materially impair the ownership, operation, development, production or use of any of the Assets as currently or reasonably anticipated to be owned, operated, developed, produced, or used;

(h) vendors, carriers, warehousemen’s, repairmen’s, mechanics’, workmen’s, materialmen’s, construction or other like liens arising by operation of Law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations which are not yet due or delinquent;

(i) liens created under Applicable Contracts that are operating agreements or by operation of Law in respect of obligations that are not yet due or delinquent, to the extent, individually or in the aggregate, such rights would not reasonably be expected to materially impair the ownership, operation, development, production or use of any of the Assets as currently owned, operated, developed, produced, or used;

(j) any Encumbrance affecting the Assets that is discharged to Buyer’s reasonable satisfaction at or prior to Closing;

(k) the terms and conditions of any Material Contracts listed on such Seller’s Schedule 9.8(a); provided that such Material Contracts do not (i) materially impair the use, ownership, development, production or operation of the Assets as currently or as reasonably anticipated to be used, owned, developed, produced or operated, (ii) reduce the aggregate Net Revenue Interest of any Seller in any Target Formation for any Tract, Hypothetical DSU or Well to an amount less than the Net Revenue Interest set forth in Exhibit A-2 or Exhibit A-1, as applicable, with respect to such Target Formation and such Tract, Hypothetical DSU or Well, (iii) obligate any Seller to bear a Working Interest with respect to the Target Formation in any Tract, Hypothetical DSU or Well in any amount greater than the Working Interest set forth in Exhibit A-2 or Exhibit A-1, as applicable, with respect to such Target Formation and such Tract, Hypothetical DSU or Well (unless the Net Revenue Interest with respect to such Target Formation and such Tract, Hypothetical DSU or Well is greater than the Net Revenue Interest with respect to such Target Formation and such Tract, Hypothetical DSU or Well as set forth in Exhibit A-2 or Exhibit A-1, as applicable, in the same proportion as any increase in such Working Interest), (iv) reduce the aggregate number of Net Acres of any Seller in any Tract or Hypothetical DSU to an amount less than the “Seller Net Acres” set forth in Exhibit A-2, as applicable, with respect to such Target Formation and such Tract

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and Hypothetical DSU, or (v) reduce any Seller’s leasehold interest as to any Tract and Hypothetical DSU, except to the extent of any depth restriction or depth severance specifically described on Exhibit A-2, as applicable;

(l) all other Encumbrances, defects and irregularities of title affecting any of the Assets that do not (i) materially impair the use, ownership, development, production or operation of the Assets as currently or as reasonably anticipated to be used, owned, developed, produced or operated, (ii) reduce the aggregate Net Revenue Interest of any Seller in any Target Formation for any Tract, Hypothetical DSU or Well to an amount less than the Net Revenue Interest set forth in Exhibit A-2 or Exhibit A-1, as applicable, with respect to such Target Formation and such Tract, Hypothetical DSU or Well, (iii) obligate any Seller to bear a Working Interest with respect to the Target Formation in any Tract, Hypothetical DSU or Well in any amount greater than the Working Interest set forth in Exhibit A-2 or Exhibit A-1, as applicable, with respect to such Target Formation and such Tract, Hypothetical DSU or Well (unless the Net Revenue Interest with respect to such Target Formation and such Tract, Hypothetical DSU or Well is greater than the Net Revenue Interest with respect to such Target Formation and such Tract, Hypothetical DSU or Well as set forth in Exhibit A-2 or Exhibit A-1, as applicable, in the same proportion as any increase in such Working Interest), (iv) reduce the aggregate number of Net Acres of any Seller in any Tract or Hypothetical DSU to an amount less than the “Seller Net Acres” set forth in Exhibit A-2, as applicable, with respect to such Target Formation and such Tract and Hypothetical DSU, or (v) reduce any Seller’s leasehold interest as to any Tract and Hypothetical DSU, except to the extent of any depth restriction or depth severance specifically described on Exhibit A-2, as applicable; and

(m) all other Encumbrances where a claim, or cause of action, for same would be barred or resolved by the applicable statute of limitations.

“Person” shall mean any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Authority or any other entity.

“Personal Property” shall, as the context requires, have the meaning set forth in the definition of “Assets” as it applies to (a) each Seller, or (b) the collective right, title and interest of all Sellers.

“Pipeline Imbalance” shall mean any marketing imbalance between the quantity of Hydrocarbons attributable to (a) any Seller’s Assets that are required to be delivered by such Seller under any Applicable Contract or applicable Law, in each case, relating to the purchase and sale, gathering, transportation, storage, processing or marketing of Hydrocarbons, and (b) such Seller’s Assets that are actually delivered by such Seller pursuant to the relevant Applicable Contract or applicable Law, together with any appurtenant rights and obligations concerning production balancing at the delivery point into the relevant sale, gathering, transportation, storage or processing facility.

“Post-Closing Tax Return” shall have the meaning set forth in Section 15.2(c).

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“Pre-Closing Tax Return” shall have the meaning set forth in Section 15.2(c).

“Preferential Purchase Right” shall mean each preferential purchase right, right of first refusal or similar right pertaining to any Seller’s interest in any Asset that is triggered by the transactions contemplated hereby.

“Preliminary Purchase Price” shall have the meaning set forth in Section 3.1(a).

“Preliminary Settlement Statement” shall have the meaning set forth in Section 3.4.

“Prevailing Central Time” shall mean central standard time or central daylight time in effect where the Assets are located.

“Proceeding” shall have the meaning set forth in Section 9.7.

“Records” shall, as the context requires, have the meaning set forth in the definition of “Assets” as it applies to (a) each Seller, or (b) the collective right, title and interest of all Sellers.

“Records Period” shall have the meaning set forth in Section 11.7.

“Remediation” shall mean, with respect to an Environmental Condition, the minimum commercially reasonable response required or allowed under Environmental Laws that addresses and resolves (for current and future use in the same manner as being currently used) the identified Environmental Condition.

“Remediation Amount” shall mean, with respect to an Environmental Condition, the cost net to Sellers’ interest of the Remediation of such Environmental Condition; provided, however, that “Remediation Amount” shall not include (a) expenses for matters that are ordinary costs of doing business regardless of the presence of an Environmental Condition (e.g., those costs that would ordinarily be incurred in the day-to-day operations of the Assets), or (b) overhead costs of Buyer and/or its Affiliates, or (c) costs and expenses that would not have been required under Environmental Laws as they exist on the Execution Date to remediate or otherwise cure such Environmental Defect in the most cost effective manner reasonably available and consistent with common industry practices.

“Retained Burdens” shall, as the context requires, have the meaning set forth in the definition of “Excluded Assets” as it applies to (a) each Seller, or (b) the collective right, title and interest of all Sellers.

“Retained Obligations” shall have the meaning set forth in Section 8.2.

“Rights-of-Way” shall mean, as the context requires, (a) a single Seller’s, or (b) all of Sellers’, collectively, permits, licenses, servitudes, easements, surface use agreements, fee surface, surface leases and rights-of-way used or held for use in connection with the ownership or operation of the Assets, other than Permits.

“RK Petroleum Schedules” shall have the meaning set forth in Section 1.3(a).

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“Scheduled Closing Date” shall have the meaning set forth in Section 6.1.

“Schmidt REP” shall have the meaning set forth in the introductory paragraph.

“Schmidt Represented Sellers” shall have the meaning set forth in Section 15.7(b).

“Securities Act” shall have the meaning set forth in Section 11.7.

“Seller” and “Sellers” shall have the meaning set forth in the introductory paragraph of this Agreement. For the avoidance of doubt, no Non-Participating Associated Owner shall be deemed to be a “Seller” hereunder for any purpose of this Agreement.

“Seller Indemnified Parties” shall have the meaning set forth in Section 8.3.

“Seller Pooling Consent” shall mean a consent to pooling, from each Seller holding an applicable Retained Burden to Buyer and substantially in the form of Exhibit H.

“Seller Taxes” shall mean (a) all Income Taxes imposed by any applicable laws on any Seller, any of its direct or indirect owners or Affiliates, or any combined, unitary, or consolidated group of which any of the foregoing is or was a member, (b) Asset Taxes allocable to the Sellers pursuant to Section 15.2(b) (taking into account, and without duplication of, (i) such Asset Taxes effectively borne by the Sellers as a result of the adjustments to the Participating Purchase Price made pursuant to Section 3.3, Section 3.4 or Section 3.5, as applicable, and (ii) any payments made from one Party to the other in respect of Asset Taxes pursuant to Section 15.2(b)), (c) any Taxes imposed on or with respect to the ownership or operation of the Excluded Assets or that are attributable to any asset or business of Sellers that is not part of the Assets and (d) any and all Taxes (other than the Taxes described in clauses (a), (b) or (c) of this definition) imposed on or with respect to the ownership or operation of the Assets for any Tax period (or portion thereof) ending on or before the Effective Time.

“Seller’s Representatives” shall have the meaning set forth in Section 15.7(d).

“Straddle Period” shall mean any Tax period beginning before and ending after the Effective Time.

“Suspense Funds” shall mean, as the context requires, as to (a) each Seller, or (b) all Sellers, collectively, all amounts held in suspense by any such Seller that are attributable to such Seller’s Assets.

“Target Formations” shall mean, collectively, the Upper Spraberry Formation, the Lower Spraberry Formation, the Wolfcamp A Formation, and the Wolfcamp B Formation, and each, individually, a “Target Formation”.

“Tax” or “Taxes” shall mean (a) all taxes, assessments, duties, levies, imposts or other similar charges imposed by a Governmental Authority, including all income, franchise, profits, capital gains, capital stock, transfer, gross receipts, sales, use, transfer, service, occupation, ad valorem, property, excise, severance, production, windfall profit, premium, stamp, license, payroll, employment, social security, unemployment, disability, environmental (including taxes under Code

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Section 59A), alternative minimum, add-on, value-added, withholding (including backup withholding) or other similar charges of any kind whatsoever (whether payable directly or by withholding and whether or not requiring the filing of a Tax Return), and all estimated taxes, deficiency assessments, additions to tax, additional amounts imposed by any Governmental Authority, penalties and interest, and (b) any liability in respect of any item described in clause (a) above that arises by reason of a contract, assumption, transferee or successor liability, operation of Law (including by reason of being a member of a consolidated, combined or unitary group) or otherwise.

“Tax Returns” shall mean any report, return, election, document, estimated Tax filing, declaration or other filing provided to any Taxing Authority, including any schedules and amendments thereto.

“Taxing Authority” shall mean, with respect to any Tax, the Governmental Authority that imposes such Tax, and the Governmental Authority (if any) charged with the collection of such Tax, including any Governmental Authority that imposes, or is charged with collecting, social security or similar charges or premiums.

“Third Party” shall mean any Person other than a Party to this Agreement or an Affiliate of a Party to this Agreement.

“Title Arbitrator” shall have the meaning set forth in Section 13.2(k).

“Title Benefit” shall mean any right, circumstance or condition existing as of the Effective Time or immediately prior to Closing that operates to increase the aggregate Net Revenue Interest of any Seller in any Target Formation in any Tract, Hypothetical DSU or Well above that shown for such Target Formation and such Tract, Hypothetical DSU or Well in Exhibit A-2 or Exhibit A-1, as applicable, to the extent the same does not cause a greater than proportionate increase in such Seller’s Working Interest in such Target Formation and such Tract, Hypothetical DSU or Well above that shown in Exhibit A-2 or Exhibit A-1, as applicable.

“Title Benefit Amount” shall have the meaning set forth in Section 13.2(e).

“Title Benefit Notice” shall have the meaning set forth in Section 13.2(b).

“Title Benefit Property” shall have the meaning set forth in Section 13.2(b).

“Title Claim Date” shall have the meaning set forth in Section 13.2(a).

“Title Defect” shall mean any Encumbrance or other matter, or series of related Encumbrances or other matters, in each case, that causes any Seller not to have Defensible Title with respect to such Seller’s Assets; provided that the following shall not be considered Title Defects:

(a) any absence or lack of, or any limitations or restrictions upon, the legal right, authority or ability, if any, of such Seller (i) to pool, unitize or otherwise combine the Lands, Leases, and Tracts to form any Hypothetical DSU or (ii) to drill a well across the boundary, or closer than permitted by applicable spacing regulations to the boundary, of any Tract included within any Hypothetical DSU;

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(b) defects based solely on lack of information in such Seller’s files unless such information is not available to Buyer from a source other than Seller;

(c) an Encumbrance created under a deed of trust, mortgage or similar instruments by the grantor under a Right-of-Way that would customarily be accepted by a reasonably prudent oil and gas operator or reasonably prudent pipeline owner in taking or purchasing such Rights-of-Way;

(d) defects or irregularities arising out of a lack of evidence of, or other defects with respect to, authorization, execution, delivery or acknowledgment of documents, or a variation in name, unless such matter should reasonably be expected to result in (or Buyer presents evidence of) another Person’s superior claim of title to the relevant Asset;

(e) defects or irregularities that have been cured or remedied by the applicable statutes of limitation and statutes for prescription;

(f) defects or irregularities in the chain of title consisting of the failure to recite marital status in documents or omissions of heirship proceedings, unless such matter should reasonably be expected to result in (or Buyer presents evidence of) another Person’s superior claim of title to the relevant Asset;

(g) lack of a survey, unless a survey is required by Law; or

(h) failure of the records of any Governmental Authority to reflect such Seller as the owner of an interest in a Lease; provided that (i) the instruments evidencing an assignment of such interest in such Lease to such Seller is recorded in the real property records of the applicable county, and (ii) such failure would not be a violation of any applicable Law.

“Title Defect Amount” shall have the meaning set forth in Section 13.2(g).

“Title Defect Deductible” shall mean, with respect to each Seller, an amount equal to 1.5% of the aggregate Allocated Value of all Assets to be conveyed by such Seller to Buyer hereunder.

“Title Defect Notice” shall have the meaning set forth in Section 13.2(a).

“Title Defect Property” shall have the meaning set forth in Section 13.2(a).

“Tract” shall mean each area of land designated as such on Exhibit A-2.

“Transaction Documents” shall mean this Agreement and all documents executed and delivered pursuant to or in connection with this Agreement.

“Transfer Taxes” shall have the meaning set forth in Section 15.2(b).

“Transition Services Agreement” shall mean a Transition Services Agreement, by and among Buyer and the Sellers that are party thereto, substantially in the form of Exhibit G.

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“Treasury Regulations” shall mean the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of succeeding, similar, substitute, proposed or final Treasury Regulations.

“Units” shall, as the context requires, have the meaning set forth in the definition of “Assets” as it applies to (a) each Seller, or (b) the collective right, title and interest of all Sellers.

“Upper Spraberry Formation” shall mean the stratigraphic equivalent of the geologic formation as located on the electric log for the Dubose #1 well from a measured depth of 7,948 feet below the Kelly Bushing down to, but not below, the measured depth of 8,186 feet below the Kelly Bushing as shown on the type log attached hereto as Exhibit E, recognizing that the actual depth will vary across the Contract Area.

“Wells” shall, as the context requires, have the meaning set forth in the definition of “Assets” as it applies to (a) each Seller, or (b) the collective right, title and interest of all Sellers.

“Well Imbalance” shall mean any imbalance at the wellhead between the (a) amount of Hydrocarbons produced from a Well and allocable to the interest of a Seller therein and (b) the shares of production from the relevant Well to which such Seller is entitled, together with any appurtenant rights and obligations concerning future in kind and/or cash balancing at the wellhead.

“Willful Breach” means, with respect to any Party, such Party knowingly and intentionally breaches in any material respect (by refusing to perform or taking an action prohibited) any material covenant applicable to such Party.

“Wolfcamp A Formation” shall mean the stratigraphic equivalent of the geologic formation as located on the electric log for the Dubose #1 well from a measured depth of 9,246 feet below the Kelly Bushing down to, but not below, the measured depth of 9,436 feet below the Kelly Bushing as shown on the type log attached hereto as Exhibit E, recognizing that the actual depth will vary across the Contract Area.

“Wolfcamp B Formation” shall mean the stratigraphic equivalent of the geologic formation as located on the electric log for the Dubose #1 well from a measured depth of 9,436 feet below the Kelly Bushing down to, but not below, the measured depth of 9,690 feet below the Kelly Bushing as shown on the type log attached hereto as Exhibit E, recognizing that the actual depth will vary across the Contract Area.

“Working Interest” shall mean, with respect to any Tract, Hypothetical DSU or Well, the decimal interest in and to such Tract, Hypothetical DSU or Well that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such Tract, Hypothetical DSU or Well, but without regard to the effect of any Burdens.

1.2 References and Rules of Construction. The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement. All references in this Agreement to Exhibits, Schedules, Annexes, Articles, Sections, subsections and other subdivisions refer to the corresponding Exhibits,

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Schedules, Annexes, Articles, Sections, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. All references in this Agreement to Schedules shall, as applicable, refer only to an individual Seller’s applicable Schedules. Titles appearing at the beginning of any Articles, Sections, subsections 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 or other subdivision unless expressly so limited. The words “this Article,” “this Section” and “this subsection,” and words of similar import, refer only to the Article, Section or subsection hereof in which such words occur. Wherever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limiting the foregoing in any respect.” Unless expressly provided to the contrary, the word “or” is not exclusive. All references to “$” or “dollars” shall be deemed references to United States dollars. Each accounting term not defined herein will have the meaning given to it under GAAP as interpreted as of the Execution Date. 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. The words “shall” and “will” are used interchangeably throughout this Agreement and shall accordingly be given the same meaning, regardless of which word is used.

1.3 Final Determination of Sellers and Non-Participating Associated Owners; Amended and Restated Exhibits; Additional Schedules; Purchase Price Adjustment; Termination Right.

(a) Final Determination of Sellers and Non-Participating Associated Owners. Each Associated Owner executing this Agreement on the Execution Date shall be deemed a “Seller” as of the Execution Date. Each Associated Owner that does not execute this Agreement on the Execution Date may, subject to Section 1.3(e), elect to become a “Seller” by executing a joinder to this Agreement in the form attached hereto as Exhibit F (each, a “Joinder Agreement”) and delivering such duly executed Joinder Agreement to both Buyer and the Seller’s Representatives on or prior to 5:00 p.m. (Prevailing Central Time) on July 13, 2016 (the “Election Deadline”) pursuant to Section 15.6, which shall evidence such Associated Owner’s agreement (i) to be bound by all of the terms of this Agreement as a “Seller” hereunder for all purposes of this Agreement as if such Associated Owner had executed this Agreement as a “Seller” on the Execution Date, (ii) to appoint BJH as the Seller’s Representative for such Seller pursuant to Section 15.7, and (iii) that any Schedules to this Agreement that may be delivered by and with respect to such Seller with such Joinder Agreement shall constitute the Schedules for such Seller for all purposes of this Agreement; provided, however, in the event such Associated Owner fails to deliver one or more of its Schedules pursuant to this clause (iii): (x) the validity and effectiveness of the Joinder Agreement shall not be affected, (y) the applicable Schedules that apply to RK Petroleum Corp. as a Seller (the “RK Petroleum Schedules”) shall be deemed such Associated Owner’s Schedules for all purposes under this Agreement, but for the avoidance of doubt, the RK Petroleum Schedules shall in every regard be deemed to be made by such Associated Owner, and not by RK Petroleum Corp., and (z) such Associated Owner releases RK Petroleum Corp., its Affiliates, Advisors and its and their respective representatives from any and all responsibility or Liability of any kind whatsoever in connection with the RK Petroleum Schedules and the contents thereof (including the accuracy and completeness of the information

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contained therein). Any Associated Owner that has not executed this Agreement as a “Seller” on the Execution Date and who (A) fails to execute a Joinder Agreement pursuant to this Section 1.3(a) prior to the Election Deadline, or (B) executes and delivers a Joinder Agreement pursuant to this Section 1.3(a) prior to the Election Deadline, but (1) which Seller’s Schedules contain a Material Joinder Disclosure and (2) Buyer elects, pursuant to Section 1.3(e), to exclude such Associated Owner from the transactions contemplated by this Agreement shall, in each case, be a Non-Participating Associated Owner for all purposes of this Agreement and shall not participate in any of the transactions contemplated by this Agreement. Should the Seller’s Representatives become aware that any such Associated Owner failed to copy Buyer on the delivery of its Joinder Agreement, such Seller’s Representative shall, promptly after so becoming aware (but in any event within one Business Day of becoming aware), forward such Joinder Agreement to Buyer (and such Associated Owner’s failure to deliver such Joinder Agreement directly to Buyer shall not constitute a failure to timely execute and deliver such Joinder Agreement).

(b) Initial and Final Exhibits and Schedules. Exhibits A through A-6 that were delivered as of the Execution Date (the “Initial Exhibits”) contemplate that all Associated Owners will be “Sellers” hereunder and such Initial Exhibits have been prepared accordingly. Each Seller executing this Agreement as of the Execution Date has delivered its Schedules to this Agreement as of the Execution Date. In the event that not all Associated Owners become “Sellers” hereunder by the Election Deadline, then within five Business Days of the Election Deadline (assuming, if applicable, that this Agreement is not terminated pursuant to Section 1.3(d) as of such time) the Seller’s Representatives shall deliver to Buyer appropriate amended and restated Exhibits A through A-6 and Annexes A through D (such Exhibits and Annexes, together with the Schedules to this Agreement delivered by each Seller pursuant to Section 1.3(a), the “Final Exhibits and Schedules”), which Final Exhibits and Schedules will, as applicable, (i) with respect to such Exhibits, only exclude from the Initial Exhibits information regarding each Non-Participating Associated Owner (thereby excluding the assets of the Non-Participating Associated Owners that would have been “Assets” if such Non-Participating Associated Owners were “Sellers” hereunder (the “Non-Assets”)), (ii) with respect to such Schedules, constitute such Seller’s Schedules to this Agreement, and (iii) with respect to such Annexes, shall be revised to, collectively, include each Seller and exclude each Non-Participating Associated Owner. From and after such time, for all purposes of this Agreement, references herein to a Seller’s Exhibits and/or Schedules shall be deemed a reference to the Final Exhibits and Schedules.

(c) Preliminary Purchase Price Reduction. The Preliminary Purchase Price will be reduced for all purposes of this Agreement by an aggregate amount equal to the aggregate Allocated Value of the Non-Assets as reflected in each Non-Participating Associated Owner’s Initial Exhibits that were delivered as of the Execution Date.

(d) Termination Right. In the event that the reductions to the Preliminary Purchase Price contemplated by Section 1.3(c) would exceed 10.0% of the Preliminary Purchase Price (i.e., would exceed $59,953,801.20), then Buyer may terminate this Agreement by providing written notice of such termination to the Seller’s Representatives within 10 Business Days of the Election Deadline. If this Agreement is not terminated pursuant to this Section 1.3(d) within such period, then no Party may thereafter terminate this Agreement except as expressly provided in Article VII (other than Section 7.1(b)).

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(e) Material Joinder Disclosure. Notwithstanding anything herein to the contrary, in the event the Schedules delivered by any Associated Owner under Section 1.3(a)(iii) disclose any material matter that is not listed on the RK Petroleum Schedules and such matter would, in Buyer’s good faith and reasonable opinion, be likely to (i) have a material adverse effect on such Associated Owner’s ability to consummate the transactions contemplated by this Agreement, or (ii) have a material adverse effect on the ownership, operation and use of either such Associated Owner’s Assets, viewed alone, or the Assets, taken as a whole, in each case, by Buyer following Closing (each, a “Material Joinder Disclosure”), then Buyer shall have the option, in its sole discretion and exercisable at any time on or prior to the date that is 10 Business Days after the Election Deadline, to exclude such Associated Owner and its interest in the Assets from the transactions contemplated under this Agreement (and, if applicable, reject any Joinder Agreement executed by such Associated Owner), in which case such Associated Owner shall be deemed a Non-Participating Associated Owner (and the assets of such Associated Owner shall be deemed Non-Assets) for all purposes under this Agreement, including, for the avoidance of doubt, determining whether Buyer’s termination right under Section 1.3(d) has been triggered. Buyer and Sellers further agree that should any Associated Owner who signs a Joinder Agreement disclose any material matter on such Seller’s Schedule 9.9, Schedule 9.11 or Schedule 9.14 that was not scheduled on any of the RK Petroleum Schedules, such disclosure shall be deemed to be a Material Joinder Disclosure for all purposes hereunder. If necessary, the Final Exhibits and Schedules shall be further revised to reflect any Non-Participating Owners and Non-Assets resulting from the exercise of Buyer’s option under this Section 1.3(e).

ARTICLE II

PURCHASE AND SALE

2.1 Purchase and Sale. Subject to the terms and conditions of this Agreement, each Seller agrees to sell and assign to Buyer, and Buyer agrees to purchase and acquire from each Seller, the entirety of such Seller’s right, title and interest in and to the Assets (save and except, for the avoidance of doubt, all of such Seller’s right, title and interest in and to the Excluded Assets).

2.2 Excluded Assets. Notwithstanding Section 2.1, each Seller reserves and retains all of such Seller’s right, title and interest in and to the Excluded Assets.

2.3 Revenues and Expenses. Each Seller shall be entitled to all of the rights of ownership attributable to such Seller’s interest in the Assets (including the right to all production, proceeds of production and other proceeds) and shall remain responsible for such Seller’s Operating Expenses, in each case, attributable to the period of time prior to the Effective Time. Subject to the occurrence of the Closing, Buyer shall be entitled to all of the rights of ownership attributable to the Assets (including the right to all production, proceeds of production and other proceeds), and shall be responsible for all Operating Expenses, in each case, from and after the Effective Time. Subject to Section 15.2(b), all Operating Expenses that are: (a) incurred with respect to operations conducted or production prior to the Effective Time shall be paid by or allocated to Sellers, and (b) incurred with respect to operations conducted or production from and after the Effective Time shall be paid by or allocated to Buyer. After Closing, Buyer and the Seller’s Representatives, on behalf of the applicable Sellers, shall be entitled to participate in all joint interest audits and other audits of

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Operating Expenses for which any applicable Party is entirely or in part responsible under the terms of this Section 2.3.

2.4 Allocation, Payment and Distribution of Adjusted Purchase Price. Each Seller shall be entitled to receive its pro rata portion of the Adjusted Purchase Price based on (x) the Allocated Value of such Seller’s interest in the Assets as set forth in Exhibits A-1, A-2 or A-6, as applicable, (y) such Seller’s relative interests in the Assets and (z) the extent to which Title Defects, Title Benefits, Environmental Defects or other matters (in respect of which adjustments are required to be made to the Participating Purchase Price) affect such Seller’s interests in the Assets. All such determinations shall be made in good faith by the applicable Seller’s Representative in its sole but reasonable discretion in accordance with the terms of this Agreement, including Section 15.7.

(a) Notwithstanding anything to the contrary herein, all payments payable hereunder to any of the BJH Represented Sellers shall be paid to the Seller’s Representative representing the BJH Represented Sellers, and all payments payable hereunder to the any of Schmidt Represented Sellers shall be paid to the Seller’s Representative representing the Schmidt Represented Sellers.

(b) The Seller’s Representative representing the BJH Represented Sellers shall represent the BJH Represented Sellers for all purposes of this Agreement and shall act as payment agent for the BJH Represented Sellers for purposes of this Agreement. The Seller’s Representative representing the BJH Represented Sellers shall be solely responsible for allocating and distributing to each BJH Represented Seller such Seller’s pro rata portion of the Adjusted Purchase Price net of all costs to be borne by such Sellers pursuant to this Agreement (as provided in this Agreement). Any payments made by or on behalf of Buyer to the Seller’s Representative representing the BJH Represented Sellers shall, for all purposes herein, satisfy Buyer’s obligations to pay such portion of the Adjusted Purchase Price to the BJH Represented Sellers or remit such amounts to the BJH Represented Sellers, as applicable.

(c) The Seller’s Representative representing the Schmidt Represented Sellers shall represent the Schmidt Represented Sellers for all purposes of this Agreement and shall act as payment agent for the Schmidt Represented Sellers for purposes of this Agreement. The Seller’s Representative representing the Schmidt Represented Sellers shall be solely responsible for allocating and distributing to each Schmidt Represented Seller such Seller’s pro rata portion of the Adjusted Purchase Price net of all costs to be borne by such Sellers pursuant to this Agreement (as provided in this Agreement). Any payments made by or on behalf of Buyer to the Seller’s Representative representing the Schmidt Represented Sellers shall, for all purposes herein, satisfy Buyer’s obligations to pay such portion of the Adjusted Purchase Price to the Schmidt Represented Sellers or remit such amounts to the Schmidt Represented Sellers, as applicable.

(d) Subject to the provisions of Section 15.7 (including Section 15.7(k)), promptly after its receipt of payment of any portion of the Adjusted Purchase Price hereunder (including the portion thereof (as determined pursuant to this Agreement) payable at Closing and any subsequent adjustments thereto), each Seller’s Representative shall remit to each Seller it represents such Seller’s pro rata portion thereof (pursuant to wire transfer instructions designated in advance by such Seller to such Seller’s Representative in writing). Buyer shall have no (i) duty to determine or confirm the correctness of any such allocation or to confirm that the Seller’s

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Representatives properly remit any amounts payable hereunder to the applicable Sellers pursuant to this Agreement, or (ii) Liability whatsoever with respect to the same; it being understood that the applicable Seller’s Representatives shall be solely responsible for such determinations and allocations among, and distributions to, such Sellers in accordance with this Agreement and that all such determinations, allocations and distributions shall be made in good faith by the applicable Seller’s Representative in its sole but reasonable discretion in accordance with the terms of this Agreement.

ARTICLE III
PURCHASE PRICE

3.1 Preliminary Purchase Price and Participating Purchase Price.

(a) The Parties agree that the aggregate preliminary purchase price for the entirety of the Assets and the Non-Assets, if any, shall be Five Hundred Ninety-Nine Million Five Hundred Thirty-Eight Thousand Twelve Dollars ($599,538,012) (the “Preliminary Purchase Price”).

(b) The aggregate purchase price for the Assets shall be the Preliminary Purchase Price, as the same may be reduced in accordance with Section 1.3(c) (such resulting amount, the “Participating Purchase Price”).

(c) The Participating Purchase Price shall be further adjusted in accordance with this Agreement and the Adjusted Purchase Price resulting therefrom shall be payable by Buyer to Seller’s Representatives on behalf of Sellers at Closing by wire transfer in same day funds to the bank accounts designated by Seller’s Representatives in the Preliminary Settlement Statement.

3.2 Deposit. Buyer shall deposit Thirty Million Dollars ($30,000,000) by wire transfer in same day funds with Escrow Agent on the Execution Date (such amount deposited with the Escrow Agent, together with any interest and earnings thereon, the “Deposit”). In the event the Closing occurs, the Deposit shall be credited against the Adjusted Purchase Price to be paid by Buyer at Closing, and the Deposit shall be retained in the escrow account established with Escrow Agent to satisfy amounts that may be owed by Sellers to Buyer after Closing with respect to the indemnities of Sellers under this Agreement as provided in Section 8.12. Such amount retained in the escrow account following the Closing, together with any interest and earnings thereon, shall be referred to as the “Indemnity Escrow”.

3.3 Adjustments to Participating Purchase Price. The Participating Purchase Price shall be adjusted as follows, and the resulting amount shall be herein called the “Adjusted Purchase Price”:

(a) The Participating Purchase Price shall be collectively adjusted upward by the aggregate of the following amounts as they relate to each Seller (without duplication):

(i) an amount equal to the value of all (A) Hydrocarbons attributable to such Seller’s interest in the Assets that are in pipelines or in tanks above the pipeline sales connection, in each case, as of the Effective Time, plus (B) the unsold inventory

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of salable gas products attributable to such Seller’s interest in the Assets as of the Effective Time, in each case such value to be based upon the contract price in effect for such Seller as of the Effective Time (or if no such contract is in effect, the market value in the area as of the Effective Time), less amounts payable by such Seller as royalties, overriding royalties and other burdens upon, measured by or payable out of such production;

(ii) an amount equal to all Operating Expenses (other than overhead costs which are covered in Section 3.3(a)(v) below and Asset Taxes) paid by such Seller or its respective Affiliates that are attributable to such Seller’s ownership or operation of the Assets from and after the Effective Time up to Closing, including to the extent actually paid by such Seller prior to the Closing (A) royalties or other burdens upon, measured by or payable out of proceeds of production, (B) rentals and other lease maintenance payments, and (C) costs of Lease renewals and/or extensions of the Leases;

(iii) the amount of all Asset Taxes prorated to Buyer in accordance with Section 15.2(b) but paid or otherwise economically borne by such Seller;

(iv) to the extent that such Seller’s interest in any of the Wells is underproduced with respect to any Hydrocarbons as of the Effective Time, in each case, as set forth on such Seller’s Schedule 9.12(a), the sum of: (A) with respect to gaseous Hydrocarbons, an amount equal to the product of (1) the underproduced volumes set forth on such Seller’s Schedule 9.12(a), multiplied by (2) $3.00/MMBtu; and (B) with respect to liquid Hydrocarbons, an amount equal to the product of (1) the underproduced volumes set forth on such Seller’s Schedule 9.12(a), multiplied by (2) $50.00/Bbl;

(v) an amount equal to all amounts attributable to overhead, and charged to such Seller’s interest pursuant to an applicable joint operating agreement or other operating arrangement covering such Seller’s interest in the Wells, in each case, only to the extent relating to the period of time between and including the Effective Time and the Closing Date, with such amount prorated to the extent of any partial months; and

(vi) any other amount provided for elsewhere in this Agreement or otherwise agreed upon by Seller’s Representatives and Buyer with respect to such Seller.

(b) The Participating Purchase Price shall be collectively adjusted downward by the aggregate of the following amounts as they relate to each Seller (without duplication):

(i) an amount equal to all gross proceeds received by such Seller or its respective Affiliates that are attributable to such Seller’s ownership or operation of the Assets from and after the Effective Time up to Closing, including the sale of Hydrocarbons produced from such Seller’s interest in the Assets or allocable thereto, net of any sales, excise or similar Taxes in connection therewith not reimbursed to such Seller or its respective Affiliates, as applicable, by a Third Party;

(ii) subject to Section 14.1(e), if Buyer make the election under (A) Section 14.1(c)(i) with respect to any uncured Environmental Defect, the Remediation Amount with respect to such Environmental Defect, or (B) Section 14.1(c)(iii) with respect

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to any uncured Environmental Defect, the Allocated Value attributable to the assets excluded from the transactions contemplated hereby with respect to such Environmental Defect;

(iii) subject to Section 13.2(i), if Buyer makes the election under (A) Section 13.2(d)(i) with respect to any uncured Title Defect, the Title Defect Amount with respect to such Title Defect, or (B) Section 13.2(d)(ii) with respect to any uncured Title Defect, the Allocated Value attributable to the assets excluded from the transactions contemplated hereby with respect to such Title Defect;

(iv) the Allocated Value of any Assets excluded from the Closing or the transactions contemplated hereby pursuant to Section 12.1(c), Section 13.2(c), Section 13.2(k), Section 13.4, Section 14.1(b) or Section 14.1(f);

(v) the amount of any adjustments pursuant to Section 13.3;

(vi) the amount of all Asset Taxes prorated to such Seller in accordance with Section 15.2(b) but paid or economically borne by Buyer;

(vii) to the extent that such Seller’s interest in any of the Wells is overproduced with respect to any Hydrocarbons as of the Effective Time, in each case, as set forth on such Seller’s Schedule 9.12(a), the sum of: (A) with respect to gaseous Hydrocarbons, an amount equal to the product of (1) the overproduced volumes set forth on such Seller’s Schedule 9.12(a), multiplied by (2) $3.00/MMBtu; and (B) with respect to liquid Hydrocarbons, an amount equal to the product of (1) the overproduced volumes set forth on such Seller’s Schedule 9.12(a), multiplied by (2) $50.00/Bbl; and

(viii) any other amount provided for elsewhere in this Agreement or otherwise agreed upon by Seller’s Representatives and Buyer.

For purposes of allocation and distribution of the Adjusted Purchase Price among Sellers, adjustments to the Participating Purchase Price shall be applied against or credited to, as the case may be, the affected individual Seller’s interests as determined by the Seller’s Representatives in their sole but reasonable good faith discretion in accordance with this Agreement. Except as specifically provided in Section 3.7, Buyer shall have no obligation to allocate the Participating Purchase Price (including any adjustments thereto) among the Sellers.

3.4 Preliminary Settlement Statement. Not less than five Business Days prior to the Closing, Seller’s Representatives shall prepare and submit to Buyer for review a draft settlement statement (the “Preliminary Settlement Statement”) that shall set forth the Adjusted Purchase Price, reflecting each adjustment made in accordance with this Agreement as of the date of preparation of such Preliminary Settlement Statement and the itemized calculation and reasonable supporting documentation of the adjustments used to determine such amount, together with the designation of Seller’s Representatives’ accounts for the wire transfers of funds and other applicable information set forth in Section 2.4. The Preliminary Settlement Statement shall also set forth the Seller’s Representatives’ good faith allocation of the portion of the Adjusted Purchase Price payable at the Closing among the BJH Represented Sellers and the Schmidt Represented Sellers, and shall provide wiring instructions for the Seller’s Representative representing the BJH Represented Sellers and

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the Seller’s Representative representing the Schmidt Represented Sellers. Within three Business Days of receipt of the Preliminary Settlement Statement, Buyer will deliver to Seller’s Representatives a written report containing all changes (including the explanations therefor) that Buyer proposes to be made to the Preliminary Settlement Statement, which report, for the avoidance of doubt, shall not challenge or address any allocation of the Adjusted Purchase Price among the Sellers that was proposed by the Seller’s Representatives. The Preliminary Settlement Statement, as agreed upon by the Parties, will be used to set the Adjusted Purchase Price at Closing; provided that if Buyer and Seller’s Representatives do not agree upon an adjustment set forth in the Preliminary Settlement Statement, then the amount of such adjustment used to adjust the Adjusted Purchase Price at Closing shall be the amount proposed by Seller’s Representatives in the Preliminary Settlement Statement originally delivered by the Seller’s Representatives to Buyer pursuant to this Section 3.4.

3.5 Final Settlement Statement.

(a) On or before 120 days after the Closing, a final settlement statement (the “Final Settlement Statement”) will be prepared by Seller’s Representatives based on actual income and expenses during the period from and after the Effective Time until Closing and which takes into account all final adjustments made to the Participating Purchase Price and shows the resulting final Adjusted Purchase Price. Buyer shall cooperate with Seller’s Representatives and use its commercially reasonable efforts to promptly furnish to Seller’s Representatives all information in Buyer’s possession relevant to preparation of the Final Settlement Statement upon written request. The Final Settlement Statement shall set forth the actual proration of amounts as may be required by this Agreement. The Final Settlement Statement shall also set forth the Seller’s Representatives’ allocation of the Final Adjusted Amount among the BJH Represented Sellers and the Schmidt Represented Sellers, and, if needed, shall provide wiring instructions for the Seller’s Representative representing BJH Represented Sellers and the Seller’s Representative representing the Schmidt Represented Sellers. As soon as practicable, and in any event within 45 days after receipt of the Final Settlement Statement, Buyer shall return to Seller’s Representatives a written report containing any proposed changes to the Final Settlement Statement and an explanation of any such changes and the reasons therefor (the “Dispute Notice”), which Dispute Notice, for the avoidance of doubt, shall not challenge or address any allocation of the Adjusted Purchase Price among the Sellers that was proposed by the Seller’s Representatives. Buyer’s failure to deliver to Seller’s Representatives a Dispute Notice detailing proposed changes to the Final Settlement Statement by such date shall be deemed to be an acceptance by Buyer of the Final Settlement Statement delivered by Seller’s Representatives and any changes to the Final Settlement Statement as initially prepared by Seller’s Representatives that are proposed or requested by Buyer and not included in the Dispute Notice shall be deemed waived, and Seller’s Representatives’ determinations with respect to all such adjustments in the Final Settlement Statement that are not addressed in the Dispute Notice shall prevail. Upon delivery of a Dispute Notice, Buyer and the Seller’s Representatives will promptly meet to discuss the contents thereof and attempt to come to agreement upon the disputed items contained therein (other than any allocation of the Adjusted Purchase Price among the Sellers, which allocation shall be the sole purview of the Seller’s Representatives). If the final Adjusted Purchase Price set forth in the Final Settlement Statement is mutually agreed upon by Seller’s Representatives and Buyer or deemed agreed pursuant to the foregoing (or determined by the Accounting Arbitrator pursuant to Section 3.6), the Final Settlement Statement (except, for the avoidance of doubt, as it

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relates to any adjustments for Asset Taxes), such final Adjusted Purchase Price as agreed by the Seller’s Representatives and the Buyer (or as determined by the Accounting Arbitrator) and such allocation among the BJH Represented Sellers and the Schmidt Represented Sellers (as agreed by the Seller’s Representatives) (collectively, the “Final Price”), shall be final and binding on the Parties.

(b) Any difference in the Adjusted Purchase Price as paid at Closing pursuant to the Preliminary Settlement Statement and the Final Price (such amount, the “Final Adjustment Amount”) shall be paid as follows:

(i) If the Final Adjustment Amount is owed by Buyer to Sellers, then, on or before the date that is 10 days following agreement or deemed agreement (or determination by the Accounting Arbitrator, as applicable) (such date, the “Final Payment Date”), the Buyer shall pay the applicable amount to (and Buyer and Seller’s Representatives shall deliver joint written instructions to the Escrow Agent directing the Escrow Agent to deliver the Adjustment Escrow to) the Seller’s Representative representing the BJH Represented Sellers and the Seller’s Representative representing the Schmidt Represented Sellers, as applicable, and in each case in accordance with the applicable allocation agreed to (or determined) as part of the Final Price. For the avoidance of doubt, all amounts owing to Sellers from Buyer pursuant to this Section 3.5 shall be payable to the Seller’s Representatives as payment agent for the Sellers represented by such Seller’s Representatives, to the accounts provided in writing by such Seller’s Representatives in the Final Settlement Statement, which shall in turn be distributed by the applicable Seller’s Representatives to the Sellers represented by such Seller’s Representatives as provided in Section 2.4.

(ii) If the Final Adjustment Amount is owed by Sellers to Buyer, then, on or before the Final Payment Date, the Seller’s Representative (for any such Seller that is required to pay Buyer pursuant to this Section 3.5(b)(ii)) shall pay Buyer the Final Adjustment Amount as provided in this Section 3.5(b)(ii). If the Final Adjustment Amount is less than or equal to the Adjustment Escrow, Seller’s Representatives and Buyer shall deliver joint written instructions to the Escrow Agent to deliver (A) the Final Adjustment Amount to Buyer and (B) any remaining amounts in the Adjustment Escrow to each of the Seller’s Representatives (in such proportions as directed by the Seller’s Representatives). If the Final Adjustment Amount is greater than the Adjustment Escrow, Seller’s Representatives and Buyer shall deliver joint written instructions to the Escrow Agent to (1) deliver the Adjustment Escrow to Buyer and (2) the portion of the Final Adjustment Amount not satisfied by the payment of the Adjustment Escrow shall be paid by Seller’s Representatives (on a joint and several basis). For the avoidance of doubt, no amounts owing under this Section 3.5 by Sellers to Buyer shall be paid from the Indemnity Escrow.

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(iii) If any such difference (i.e., the portion of the Final Adjustment Amount not satisfied by the payment of the Adjustment Escrow) is owed between the BJH Represented Sellers and the Schmidt Represented Sellers, then, on or before the Final Payment Date, the Sellers and the Seller’s Representatives representing the applicable Sellers shall make such allocations and disbursements as are appropriate based on the applicable allocation agreed to (or determined) as part of the Final Price.

(iv) In addition, on or before the Final Payment Date, each Seller shall transfer to Buyer all Suspense Funds held by such Seller.

(v) All amounts paid or transferred pursuant to this Section 3.5 shall be delivered in United States currency by wire transfer of immediately available funds to the account or accounts specified in writing by Buyer or the relevant Seller’s Representative(s), as applicable.

(c) At Closing, Buyer shall deposit Five Million Dollars ($5,000,000) by wire transfer in same day funds with Escrow Agent (such amount deposited with the Escrow Agent, together with any interest and earnings thereon, the “Adjustment Escrow”), such amount to be credited against the Adjusted Purchase Price to be paid by Buyer at Closing. The Adjustment Escrow shall be retained in the escrow account established with Escrow Agent to satisfy amounts that may be owed by Sellers upon determination of the Final Price as set forth in this Section 3.5.

3.6 Disputes. If Seller’s Representatives and Buyer are unable to resolve any matters addressed in the Dispute Notice within 25 Business Days after the delivery of such Dispute Notice, then any of Buyer or any Seller’s Representative shall have the right to invoke the dispute resolution provisions of this Section 3.6 with respect to such disputed matters by delivering written notice to the Buyer and/or other Seller’s Representatives, as applicable. Within 10 Business Days after any such Person has invoked the provisions of this Section 3.6, Buyer, on the one hand, and Seller’s Representatives, collectively, on the other hand, shall summarize its position with regard to such dispute in a written document of 20 pages or less and submit such summaries to the Houston, Texas office of Deloitte LLP or if Deloitte LLP refuses to serve, KPMG LLP, and if KPMG LLP refuses to serve, such other Person as Buyer and the Seller’s Representatives may mutually select (the “Accounting Arbitrator”), together with the Dispute Notice, the Final Settlement Statement and any other documentation such Party may desire to submit. Within 20 Business Days after receiving such Persons’ respective submissions, the Accounting Arbitrator shall render a decision choosing either the Seller’s Representatives’ position or Buyer’s position with respect to each matter addressed in any Dispute Notice, based on the materials described above. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Sellers and Buyer and will be enforceable against any of the Parties in any court of competent jurisdiction. The costs of such Accounting Arbitrators shall be borne one-half by Buyer and one-half by the Seller’s Representatives. In the event that both Deloitte LLP and KPMG LLP decline to serve as the Accounting Arbitrator and Buyer and Seller’s Representatives are unable to mutually agree on the replacement Accounting Arbitrator, then the Accounting Arbitrator shall be selected by the appointing authority of the Dallas, Texas office of the American Arbitration Association.

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3.7 Allocation of Participating Purchase Price / Allocated Values. Buyer and each Seller agree that the unadjusted Participating Purchase Price shall be allocated among each Seller and each Seller’s interest in the Assets as set forth in Exhibits A-1 or A-2, as applicable. The “Allocated Value” for (a) any Seller’s interest in any Asset equals the portion of the unadjusted Participating Purchase Price allocated to such Seller’s interest in Exhibits A-1 or A-2, as applicable, and (b) all Sellers’ interests in any Asset equals the aggregate portions of the unadjusted Participating Purchase Price allocated to such Asset in Exhibits A-1 or A-2, as applicable (all of such information contained on Exhibits A-1 and A-2 being compiled and listed on Exhibit A-5 as a single, transaction-wide, Allocated Value for each Seller). The Parties also agree that such Allocated Values shall be used in calculating adjustments to the Participating Purchase Price as provided herein. Buyer and Sellers also agree (i) that the Allocated Values, as so adjusted, shall be used by Sellers and Buyer as the basis for reporting asset values and other items for purposes of this Section 3.7, and (ii) that neither they nor their Affiliates will take positions inconsistent with such Allocated Values in notices to Governmental Authorities, in notices to Preferential Purchase Right holders or in other documents or notices relating to the transactions contemplated by this Agreement.

3.8 Allocation of Consideration for Tax Purposes. Sellers and Buyer agree that the Participating Purchase Price, as adjusted, and other amounts treated for U.S. federal income Tax purposes as consideration for a sale transaction (to the extent known at such time) (collectively, the “Allocable Amount”) shall be allocated among the various Assets in accordance with Section 1060 of the Code and the Treasury Regulations promulgated thereunder and, to the fullest extent allowed by applicable Laws, in a manner consistent with the Allocated Values. The initial draft of such allocations shall be prepared by Buyer and shall be provided to the Seller’s Representatives no later than 60 days after Closing for the Seller’s Representatives’ review and approval, such approval not to be unreasonably withheld (as adjusted, the “Allocation Schedule”). The Allocation Schedule shall be updated to reflect any adjustments to the Allocable Amount. The allocation of the Allocable Amount shall be reflected on a completed Internal Revenue Service Form 8594 (Asset Acquisition Statement under Section 1060), which Form will be timely filed separately by Sellers and Buyer with the Internal Revenue Service pursuant to the requirements of Section 1060(b) of the Code. Sellers and Buyer agree not to take any position inconsistent with the allocations set forth in the Allocation Schedule unless required by applicable Law or with the consent of the other Parties. The Parties further agree that the allocations set forth on the Allocation Schedule will represent reasonable estimates of the fair market values of the Assets described therein.

ARTICLE IV
BUYER’S CONDITIONS TO CLOSING

4.1 Individual Seller Conditions. The obligations of Buyer to consummate the transactions provided for herein with respect to each Seller are subject, at the option of Buyer, to the fulfillment by each Seller, or waiver by Buyer, on or prior to the Closing, of each of the following conditions:

(a) Representations. Each of the representations and warranties of such Seller set forth in Article IX (i) that are qualified by the term “material” or contain terms such as “material adverse change,” “material adverse effect” or other terms or Dollar amounts of similar import or effect (whether or not capitalized) shall be true and correct as of the Execution Date and the Closing

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Date as though such representations and warranties were made on and as of those dates, and (ii) that are not so qualified shall be true and correct in all material respects as of the Execution Date and the Closing Date as though such representations and warranties were made on and as of those dates.

(b) Performance. Such Seller shall have performed or complied in all material respects with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by such Seller is required prior to or at the Closing Date.

(c) Closing Certificates. Each Seller shall have executed and delivered a closing certificate to Buyer that (i) is dated as of the Closing Date, (ii) is substantially in the form of Exhibit D attached hereto, and (iii) certifies that the conditions set forth in Section 4.1(a) and Section 4.1(b) have been fulfilled with respect to such Seller.

(d) Closing Deliverables. Each Seller shall be ready, willing and able to deliver to Buyer at the Closing the documents and items required to be delivered by such Seller under Section 6.3.

4.2 Aggregate Seller Conditions. The obligations of Buyer to consummate the transactions provided for herein with respect to all Sellers, in the aggregate, are subject, to the fulfillment by each Seller, or, at the option of Buyer, waiver by Buyer, on or prior to the Closing, of each of the following conditions:

(a) Title Defects, Hard Consents, Preferential Rights to Purchase, Environmental Defects, Casualty Losses, and Failed Sellers. With respect to all Sellers, the sum of (i) all Title Defect Amounts for Title Defects for which Buyer has elected the remedy under Section 13.2(d)(i), plus (ii) all Title Defect Amounts that have been applied to reduce the Participating Purchase Price pursuant to Section 13.2(k), plus (iii) all Remediation Amounts for Environmental Defects for which Buyer has elected the remedy under Section 14.1(c)(i), plus (iv) the Allocated Values of all assets excluded from the transactions contemplated hereby pursuant to Section 12.1(c), Section 13.2(c), Section 13.2(d)(ii), Section 14.1(b), Section 14.1(c)(iii), Section 14.1(f) or Section 13.4, plus (v) the amount of any Participating Purchase Price adjustment that Buyer would be entitled to pursuant to Section 13.3, minus (vi) the sum of all Title Benefit Amounts that, individually, exceed the Individual Title Defect Threshold, plus (vii) the aggregate Allocated Values of the Assets attributable to the interests of any Failed Sellers, shall, in the aggregate of the items described in subparts (i) through (vii) above, be less than 10% of the unadjusted Participating Purchase Price. For the avoidance of doubt, the Allocated Value of any Non-Assets removed from the transactions contemplated hereby pursuant to Section 1.3 shall expressly not be included for purposes of the calculations set forth in this Section 4.2(a).

(b) No Legal Proceedings. No material suit, action or other proceeding by any Third Party shall be pending before any Governmental Authority (i) seeking to restrain, prohibit, enjoin or declare illegal the transactions contemplated by this Agreement, or (ii) seeking substantial damages in connection with, the transactions contemplated by this Agreement.

(c) HSR Act. If applicable, (i) the waiting period under the HSR Act applicable to the consummation of the transactions contemplated hereby shall have expired, (ii) notice of early

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termination shall have been received, or (iii) a consent order shall have been issued (in form and substance satisfactory to Buyer) by or from applicable Governmental Authorities.

ARTICLE V
SELLER’S CONDITIONS TO CLOSING

The obligations of Sellers to consummate the transactions provided for herein are subject to the fulfillment by Buyer or, at the option of Seller’s Representatives, waiver by Seller’s Representatives, on or prior to the Closing, of each of the following conditions:

5.1 Representations. Each of the representations and warranties of Buyer set forth in Article X shall be true and correct in all material respects as of the Execution Date and the Closing Date as though made on and as of those dates.

5.2 Performance. Buyer shall have materially performed or complied with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Buyer is required prior to or at the Closing Date.

5.3 No Legal Proceedings. No material suit, action or other proceeding by any Third Party shall be pending before any Governmental Authority (a) seeking to restrain, prohibit or declare illegal the transactions contemplated by this Agreement, or (b) seeking substantial damages in connection with, the transactions contemplated by this Agreement.

5.4 Title Defects, Hard Consents, Preferential Rights to Purchase, Environmental Defects, and Casualty Losses. The sum of (a) all Title Defect Amounts for Title Defects for which Buyer has elected the remedy under Section 13.2(d)(i), plus (b) all Title Defect Amounts that have been applied to reduce the Participating Purchase Price pursuant to Section 13.2(k), plus (c) all Remediation Amounts for Environmental Defects for which Buyer has elected the remedy under Section 14.1(c)(i), plus (d) the Allocated Values of all assets excluded from the transactions contemplated hereby pursuant to Section 12.1(c), Section 13.2(c), Section 13.2(d)(ii), Section 14.1(b), Section 14.1(c)(iii), Section 14.1(f) or Section 13.4, plus (e) the amount of any Participating Purchase Price adjustment that Buyer would be entitled to pursuant to Section 13.3, minus (f) the sum of all Title Benefit Amounts that, individually, exceed the Individual Title Defect Threshold, shall, in the aggregate of the items described in subparts (a) through (f) above, be less than 10% of the unadjusted Participating Purchase Price. For the avoidance of doubt, the Allocated Value of any Non-Assets removed from the transactions contemplated hereby pursuant to Section 1.3 shall expressly not be included for purposes of the calculations set forth in this Section 5.4.

5.5 HSR Act. If applicable, (a) the waiting period under the HSR Act applicable to the consummation of the transactions contemplated hereby shall have expired, (b) notice of early termination shall have been received, or (c) a consent order shall have been issued (in form and substance satisfactory to Seller’s Representatives) by or from applicable Governmental Authorities.

5.6 Replacement Bonds. Buyer shall have obtained, in the name of Buyer, replacements for Sellers’ and/or their Affiliates’ bonds, letters of credit and guarantees, and such other bonds, letters of credit and guarantees, if any, to the extent required to be obtained by Closing by Section 11.4.

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5.7 Officer’s Certificates. Buyer shall have executed and delivered an officer’s certificate to Seller’s Representatives that (a) is dated as of the Closing Date, (b) is substantially in the form of Exhibit D attached hereto, and (c) certifies that the conditions set forth in Section 5.1 and Section 5.2 have been fulfilled with respect to Buyer.

5.8 Closing Deliverables. Buyer shall be ready, willing and able to deliver to Sellers at the Closing the documents and items required to be delivered by Buyer under Section 6.3.

ARTICLE VI
CLOSING

6.1 Date of Closing. Subject to the conditions set forth in this Agreement, the sale by Sellers and the purchase by Buyer of the Assets pursuant to this Agreement (the “Closing”) shall occur on or before 9:00 a.m. (Prevailing Central Time) on September 14, 2016 (the “Scheduled Closing Date”). The Scheduled Closing Date may be changed to such other date and time as Buyer and Seller’s Representatives may agree upon in writing; provided that if the conditions to Closing in Article IV and Article V have not yet been satisfied or waived by the Scheduled Closing Date, then the Closing shall occur five Business Days after such conditions have been satisfied or waived. The date Closing actually occurs shall be the “Closing Date”.

6.2 Place of Closing. The Closing shall be held at the offices of Kelly Hart & Hallman LLP, located at 303 Colorado Street, Suite 2000, Austin, Texas 78701, or at such other place and in such other manner as Buyer and Seller’s Representatives may agree.

6.3 Closing Obligations. At the Closing, the following documents shall be delivered and the following events shall occur, the execution of each document and the occurrence of each event being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a) Each Seller and Buyer shall execute, acknowledge and deliver the Assignment of such Seller’s Assets, in sufficient counterparts to facilitate recording in the applicable counties where such Assets are located.

(b) If applicable, each Seller and Buyer shall execute and deliver assignments, on appropriate forms, of state and other Leases of Governmental Authorities included in such Seller’s Assets in sufficient counterparts to facilitate filing with the applicable Governmental Authorities.

(d) Each Seller shall, as applicable, deliver executed letters in lieu of transfer orders, as prepared by Seller’s Representatives and in form reasonably satisfactory to Buyer, directing all purchasers of production to make payment to Buyer of proceeds attributable to production from the Assets from and after the Effective Time, for delivery by Buyer to the purchasers of production.

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(e) Buyer shall deliver to Seller’s Representatives, to the accounts and in the amounts as designated in the Preliminary Settlement Statement, by direct bank or wire transfer in same day funds, an aggregate amount equal to (i) the Adjusted Purchase Price (as calculated by the Preliminary Settlement Statement) less (ii) the Deposit less (iii) the Adjustment Escrow.

(f) Buyer shall deliver to the Escrow Agent, by direct bank or wire transfer in same day funds, the Adjustment Escrow.

(g) Buyer and the applicable Sellers that are parties thereto shall execute and deliver the Transition Services Agreement.

(h) Each Seller that holds any Retained Burden that would give such Seller the right to consent to the formation of any Hypothetical DSU (or the formation of any other pooled unit incorporating the Lands) or the drilling of any allocation well shall, in each case, execute and deliver to Buyer a Seller Pooling Consent.

(i) Sellers and Buyer shall execute and deliver any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered at the Closing.

6.4 Records. In addition to the obligations set forth under Section 6.3 above, but notwithstanding anything herein to the contrary, no later than 10 Business Days following the Closing Date, each Seller shall make available to Buyer, at the offices of RK Petroleum Corp., located at 406 N. Main Street, Midland, Texas 79701, or at such other place as Buyer and Seller’s Representatives may agree, the Records for pickup during normal business hours.

ARTICLE VII
TERMINATION; DEFAULT AND REMEDIES

7.1 Right of Termination. This Agreement and the transactions contemplated herein may be terminated at any time prior to the Closing:

(a) by the mutual written agreement of the Buyer and Seller’s Representatives;

(b) by Buyer, upon written notice to Seller’s Representatives, pursuant to the termination right in Section 1.3(d) within 10 Business Days after the Election Deadline;

(c) by delivery of written notice from Buyer to Seller’s Representatives if any of the conditions set forth in Section 4.1 have not been satisfied (or waived by Buyer) by the Outside Date (but only as to the individual Seller or Sellers that have failed to meet such conditions);

(d) by delivery of written notice from Seller’s Representatives to Buyer if any of the conditions set forth in Article V (other than Section 5.3, Section 5.4 or Section 5.5) have not been satisfied (or waived by Seller’s Representatives) by the Outside Date;

(e) by delivery of written notice from Seller’s Representatives to Buyer, or from Buyer to Seller’s Representatives, as applicable, if any of the conditions set forth in Section 4.2(b),

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Section 4.2(c), Section 5.3 or Section 5.5 have not been satisfied (or waived by Seller’s Representatives or Buyer, as applicable) by the Outside Date;

(f) by delivery of written notice from Seller’s Representatives to Buyer, or from Buyer to Seller’s Representatives, as applicable, if any of the conditions set forth in Section 4.2(a) or Section 5.4 have not been satisfied (or waived by Seller’s Representatives or Buyer, as applicable) by the Outside Date; or

(g) by delivery of written notice from Seller’s Representatives to Buyer if any portion of the Deposit is not deposited with the Escrow Agent as provided in Section 3.2;

provided, however, that neither Buyer nor any Seller’s Representative on behalf of a Seller shall have the right to terminate this Agreement pursuant to Section 7.1(c) or Section 7.1(d) if Buyer or such Seller are at such time in material breach of any provision of this Agreement.

7.2 Partial or Complete Termination.

(a) Notwithstanding anything in this Agreement to the contrary, should Buyer be entitled to terminate this Agreement pursuant to Section 7.1(c) due to the failure of any of Buyer’s Closing conditions implicated by such Section to be met as of the Closing with respect to any individual Seller (each, a “Failed Seller”), then Buyer shall, without limiting its rights pursuant to Section 7.3 with respect to such Failed Seller or pursuant to Section 7.1(e) or Section 7.1(f) with respect to all Sellers, (i) proceed to Closing with respect to all those Sellers who have satisfied Buyer’s conditions to Closing set forth in Article IV (or with respect to whom Buyer has waived any such condition), and (ii) the Participating Purchase Price shall be reduced by the Allocated Value attributable to the Assets of such Failed Seller. After such Closing, and subject to Buyer’s rights under Section 7.3(c), Buyer may proceed to a standalone closing with such Failed Seller at such time as such Failed Seller has satisfied (or Buyer has waived) all of Buyer’s conditions to Closing set forth in Article IV with respect to such Failed Seller, at which closing Buyer shall purchase from such Failed Seller such Failed Seller’s Assets, on the terms and conditions otherwise set forth in this Agreement, for consideration equal to the Allocated Value by which the Participating Purchase Price was reduced with respect to such Failed Seller’s Assets pursuant this Section 7.2(a).

(b) For the avoidance of doubt, should Buyer be entitled to terminate this Agreement in its entirety pursuant to Section 7.1(e) or Section 7.1(f) due to the failure of any of Buyer’s Closing conditions implicated by such Sections to be met as of the Closing (regardless of whether such conditions were failed to be met by any individual Failed Seller or by the Sellers, taken as a whole), and assuming the Seller’s Representatives have not and do not terminate this Agreement pursuant to Section 7.1(d), Section 7.1(e) or Section 7.1(f), then Buyer shall have the option, exercisable in its sole discretion and without limiting its rights pursuant to Section 7.3, to (x) proceed to Closing with respect to all those Sellers who have satisfied Buyer’s conditions to Closing set forth in Article IV (or with respect to whom Buyer has waived any such condition), in which case the Participating Purchase Price shall be reduced by the Allocated Value attributable to the Assets of such Failed Seller(s), or (y) terminate this Agreement in its entirety pursuant to Section 7.1(e) or Section 7.1(f), as applicable.

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(i) Should such partial Closing occur (as a result of Section 7.2(b)), then after such Closing, Buyer shall have the right, exercisable in its sole discretion, to (A) seek specific performance against each such Failed Seller; provided, however, if (1) such Failed Seller shall be legally unable to provide specific performance, or Buyer shall be unable to obtain such specific performance, after using its commercially reasonable efforts to do so, and (2) Buyer would be entitled to additional remedies against such Failed Seller pursuant to Section 7.3(c) (due to the fact that, as of the Outside Date, (x) all of the conditions in Article V (excluding conditions that, by their terms, cannot be satisfied until the Closing) have been satisfied (or waived by Seller’s Representatives), (y) Buyer is ready, willing and able to perform their obligations under Section 6.3, and (z) such Failed Seller nevertheless elects not to close the transactions contemplated by this Agreement), then Buyer may (I) terminate this Agreement pursuant to Section 7.1(c) with respect to such Failed Seller, and (II) be entitled to recover Buyer’s actual damages from such Failed Seller that are attributable to such Failed Seller’s Willful Breach of this Agreement or such Failed Seller’s failure to close the transactions contemplated by this Agreement, (B) terminate this Agreement only with respect to each such Failed Seller, in which case neither Buyer (with respect to such Failed Seller only) nor such Failed Seller shall have any further liability or obligation hereunder, or (C) proceed to a standalone closing with each such Failed Seller at such time as such Failed Seller has satisfied (or Buyer has waived) all of Buyer’s conditions to Closing set forth in Article IV with respect to such Failed Seller, at which closing Buyer shall purchase from such Failed Seller such Failed Seller’s Assets, on the terms and conditions otherwise set forth in this Agreement, for consideration equal to the Allocated Value by which the Participating Purchase Price was reduced with respect to such Failed Seller’s Assets pursuant this Section 7.2(b).

7.3 Effect of Termination. If this Agreement is terminated pursuant to any provision of Section 7.1, then, except as provided in this Article VII and except for the provisions of Section 1.1, Section 1.2, Section 7.1, Section 7.2, this Section 7.3, Section 7.4, Section 8.11, Section 9.16, Section 10.10, Section 12.1(d), Section 12.2, Section 12.3 and Article XV (other than Sections 15.2(b), 15.2(c), 15.8 and 15.9), this Agreement shall forthwith become void and of no further force or effect and the Parties shall have no liability or obligation hereunder.

(a) If Buyer terminates this Agreement pursuant to Section 7.1(b), Buyer and Seller’s Representatives shall jointly instruct the Escrow Agent to return the Deposit to Buyer within five Business Days of the date this Agreement is terminated and no Party shall have any further liability or obligation hereunder.

(b) If the Seller’s Representatives have the right to terminate this Agreement pursuant to Section 7.1(d) because of (i) the Willful Breach by Buyer of this Agreement, or (ii) the failure of Buyer to close the transactions contemplated by this Agreement in the instance where, as of the Outside Date, (A) all of the conditions in Article IV (excluding conditions that, by their terms, cannot be satisfied until the Closing) have been satisfied (or waived by Buyer), (B) Sellers (other than Failed Sellers) are ready, willing and able to perform their obligations under Section 6.3, and (C) Buyer nevertheless elects not to close the transactions contemplated by this Agreement, then, in either such event, Sellers’ sole and exclusive remedy shall be (1) to obtain specific performance as against Buyer; or (2) to (x) terminate this Agreement pursuant to Section 7.1(d) and (y) receive the Deposit from Escrow Agent as liquidated damages, and not as a penalty, for such termination, free and clear of any claims thereon by Buyer, and, upon such termination, Seller’s Representatives

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and Buyer shall instruct Escrow Agent to transfer the Deposit to the Seller’s Representatives within five Business Days of the date this Agreement is terminated. The Parties agree that, the receipt of the Deposit shall be deemed to be liquidated damages and that such amount is reasonable considering all of the circumstances existing as of the Execution Date and constitute the Parties’ good faith estimate of the actual damages reasonably expected to result from such termination of this Agreement by Sellers and which remedy shall be the sole and exclusive remedy available to Sellers.

(c) If Buyer has the right to terminate this Agreement with respect to a Failed Seller pursuant to Section 7.1(c) (or in its entirety pursuant to Section 7.1(f) due to the existence of a Failed Seller) because of (i) the Willful Breach by such Failed Seller of this Agreement, or (ii) the failure of a Failed Seller to close the transactions contemplated by this Agreement in the instance where, as of the Outside Date, (A) all of the conditions in Article V (excluding conditions that, by their terms, cannot be satisfied until the Closing) have been satisfied (or waived by Seller’s Representatives), (B) Buyer is ready, willing and able to perform its obligations under Section 6.3, and (C) such Failed Seller nevertheless fails to close the transactions contemplated by this Agreement, then, in either such event of clauses (i) or (ii) above, Buyer shall have the right of specific performance as against such Failed Seller. In the event that (1) such Failed Seller shall be legally unable to provide specific performance, or (2) Buyer shall be unable to obtain such specific performance, after using its commercially reasonable efforts to do so, then in either such case Buyer may (x) terminate this Agreement pursuant to Section 7.1(c) with respect to such Failed Seller, and (y) be entitled to recover Buyer’s actual damages from such Failed Seller that are attributable to such Failed Seller’s Willful Breach of this Agreement or failure to close the transactions contemplated by this Agreement. Should Buyer also, due to the presence of such Failed Seller, be entitled to terminate this Agreement pursuant to Section 7.1(f), then, for the avoidance of doubt, Buyer shall also be entitled to (I) terminate this Agreement in its entirety pursuant to Section 7.1(f), and (II) receive a return of the Deposit from Escrow Agent, free and clear of any claims thereon by Sellers, and Seller’s Representatives and Buyer shall instruct Escrow Agent to return the Deposit to Buyer within five Business Days of the date this Agreement is terminated.

(d) If this Agreement is terminated for any reason other than as set forth in Section 7.3(b) or Section 7.3(c), then the Parties shall have no liability or obligation hereunder as a result of such termination, and Seller’s Representative and Buyer shall, within five Business Days of the date this Agreement is terminated, instruct Escrow Agent to return the Deposit to Buyer.

(e) Subject to the foregoing, upon the termination of this Agreement no Party shall have any other liability or obligation hereunder.

7.4 Return of Documentation and Confidentiality. Upon termination of this Agreement, Buyer shall return to Seller’s Representatives all title, engineering, geological and geophysical data, environmental assessments and/or reports, maps, documents and other information furnished by or on behalf of any Seller to Buyer or any of its Affiliates or representatives (without retaining any copy thereof) and an officer of Buyer shall certify same to Seller’s Representatives in writing.

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ARTICLE VIII
ASSUMPTION; INDEMNIFICATION; SURVIVAL

8.1 Assumption by Buyer and Retention by Sellers. Without limiting Buyer’s rights to indemnity under this Article VIII, from and after the Closing, Buyer assumes and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid and discharged) all obligations and Liabilities, known or unknown, with respect to the Assets (other than the Retained Obligations), whether arising before, on or after the Effective Time, including, without limitation: (a) the Assumed Environmental Liabilities; (b) the obligation to furnish makeup gas and/or settle Imbalances according to the terms of applicable gas sales, processing, gathering or transportation Applicable Contracts included in the Assets; and (c) all obligations and Liabilities to (i) pay Working Interests, royalties, overriding royalties and other interest owners revenues or proceeds attributable to sales of Hydrocarbons, to the extent attributable to the Assets, other than those held in suspense for which Suspense Funds are transferred to Buyer pursuant to Section 3.5(b)(iv), and (ii) perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases and the Applicable Contracts, or as required by Laws (all of said obligations and Liabilities herein being referred to as the “Assumed Obligations”). Sellers shall retain and agree to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid and discharged), and hereby release the Buyer Indemnified Parties with respect to, the Retained Obligations.

8.2 Indemnities of each Seller. Effective as of the Closing, subject to the limitations set forth herein (including those set forth in Sections 8.4, 8.6, 8.7 and 8.8), each Seller shall, severally and not jointly, be responsible for, shall pay on a current basis and hereby agrees to defend, indemnify, hold harmless and forever release Buyer and its Affiliates, and all of its and their respective partners, members, directors, officers, managers, employees, agents and representatives (collectively, “Buyer Indemnified Parties”) from and against any and all Liabilities, arising from, based upon, related to or associated with:

(a) any breach by such Seller of any of its representations or warranties contained in Article IX or in the certificate delivered to Buyer by such Seller pursuant to Section 4.1(c);

(b) any breach by such Seller of any of its covenants or agreements under this Agreement or in the certificate delivered to Buyer by such Seller pursuant to Section 4.1(c);

(d) such Seller’s share of any Liabilities resulting from any personal injury or death relating to the Assets and occurring prior to Closing, it being recognized and agreed that, as between Sellers, nothing herein shall expand or limit exculpations of the operations Liability of any Seller serving as the operator of Assets under applicable operating agreements;

(e) such Seller’s share of any Liabilities resulting from Claims for property damage relating to the Assets and occurring prior to Closing, it being recognized and agreed that, as between Sellers, nothing herein shall expand or limit exculpations of the operations Liability of any Seller serving as the operator of Assets under applicable operating agreements;

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(f) such Seller’s share of any Liabilities arising out of offsite disposal of Hazardous Substances generated on the Assets, or used on the Assets, in each case occurring prior to the Closing;

(g) any and all Seller Taxes of such Seller;

(h) such Seller’s failure to pay (or cause to be paid) all Burdens due by such Seller with respect to its interest in the Assets and attributable to periods prior to the Effective Time in accordance with applicable Law and the terms of the applicable Leases;

(i) any Contracts between such Seller and any Affiliate of such Seller that are attributable to periods of time prior to the Closing;

(j) the gross negligence or willful misconduct of such Seller or any of its Affiliates in connection with its operations, prior to Closing, of the Assets in its capacity as operator thereof, in each case, to the extent the same are related to a Claim;

(k) any Proceeding set forth on such Seller’s Schedule 9.7;

(l) such Seller’s Excluded Assets;

(m) such Seller’s failure to perform all obligations applicable to or imposed on such Seller under the Leases and the Applicable Contracts, or as required by Laws, in each case, (i) with respect to periods of time prior to the Effective Time, and (ii) excluding any Assumed Environmental Liabilities;

(n) such Seller’s failure to properly account for (or caused to be accounted for) any Imbalances or any Suspense Funds, in each case, attributable to periods of time prior to the Effective Time; and

(o) the formation, governance, termination or cancellation of any partnership related to, or holding any right, title or interest in and to, the Assets or any portion thereof, in which such Seller (or any predecessor in interest of such Seller) was a partner, general partner or limited partner, or was otherwise involved in any capacity, in each case, attributable to periods of time prior to the Closing.

The obligations described in subsections (d) through (o) of this Section 8.2 may be referred to herein collectively as such Seller’s “Retained Obligations.” For purposes of Section 8.2(c) through 8.2(f), a Seller’s “share” of any specified Liability shall be equal to (1) the aggregate amount of such specified Liability, multiplied by (2) a fraction, the (x) numerator of which shall be the portion of the Adjusted Purchase Price payable to such Seller pursuant to this Agreement (as determined by the Seller’s Representatives in their sole discretion) and (y) denominator of which shall be the aggregate Adjusted Purchase Price.

8.3 Indemnities of Buyer. Effective as of the Closing, subject to the limitations set forth herein (including those set forth in Sections 8.4, 8.6, 8.7 and 8.8), Buyer and its successors and assigns shall assume, be responsible for, shall pay on a current basis and defend, indemnify, hold harmless and forever release Sellers and their respective Affiliates, and all of their respective

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partners, members, directors, officers, managers, employees, agents and representatives (collectively, “Seller Indemnified Parties”) from and against any and all Liabilities arising from, based upon, related to or associated with:

(a) any breach by Buyer of any of its representations or warranties contained in Article X or in the certificate delivered to Seller’s Representative by Buyer pursuant to Section 5.7;

(b) any breach by Buyer of any of its covenants or agreements under this Agreement or in the certificate delivered to Seller’s Representative by Buyer pursuant to Section 5.7; and

8.4 Limitation on Liability.

(a) No Seller shall have any liability for any indemnification under Section 8.2(a) (other than liabilities with respect to the breach by such Seller of any of its Fundamental Representations) (i) for any individual Liability unless the amount of such Liability exceeds $37,500, and (ii) until and unless the aggregate amount of all Liabilities for which Claim Notices are delivered by Buyer with respect to such Seller exceeds the Indemnity Deductible applicable to such Seller, and then only to the extent such Liabilities exceed such Indemnity Deductible.

(b) Notwithstanding anything to the contrary contained in this Agreement, no Seller shall be required to indemnify the Buyer Indemnified Parties under Section 8.2(a) (other than liabilities with respect to the breach by such Seller of any of its Fundamental Representations) for aggregate Liabilities in excess of 10% of the aggregated Allocated Value of all Assets sold by such Seller hereunder. Without prejudice to the other limitations contained herein, under no circumstances shall a Seller’s maximum indemnification obligations hereunder ever exceed an amount equal to the portion of the Adjusted Purchase Price actually received by such Seller.

(c) For the avoidance of doubt and notwithstanding anything seemingly to the contrary herein, the Liabilities of Sellers in connection with this Agreement are several and not joint in all respects.

8.5 Express Negligence. THE DEFENSE, INDEMNIFICATION, HOLD HARMLESS, RELEASE AND ASSUMPTION OF THE ASSUMED OBLIGATIONS PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY, PROVIDED, HOWEVER, BUYER SHALL HAVE NO OBLIGATION UNDER THIS AGREEMENT TO INDEMNIFY OR HOLD HARMLESS ANY SELLER INDEMNIFIED PERSON FOR ANY DAMAGES THAT ARE ATTRIBUTABLE TO, ARISE FROM OR IN CONNECTION WITH, ARE BASED UPON, OR EXIST BY REASON OF THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY SELLER INDEMNIFIED PERSON. BUYER AND SELLER ACKNOWLEDGE THAT

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THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS CONSPICUOUS.

8.6 Exclusive Remedy. Notwithstanding anything to the contrary contained in this Agreement, from and after the Closing, Section 8.2, Section 8.3, Section 12.1(d), Section 13.1(b), Section 13.2(d), Section 13.2(e), Section 13.2(k), Section 14.1(c), Section 14.1(f), Section 15.7(g), Section 15.7(i) and each Seller’s special warranty of title in the Assignment contain the Parties’ sole and exclusive remedy against each other with respect to the transactions contemplated hereby and the sale of the Assets, including breaches of the representations, warranties, covenants and agreements of the Parties contained in this Agreement or in any document delivered pursuant to this Agreement. For the avoidance of doubt and notwithstanding anything to the contrary contained in this Agreement or in the Assignment, after Closing, if an applicable Seller or Seller’s Representative demonstrates that Buyer received, pursuant to the Assignments (i) an aggregate Net Revenue Interest equal to the aggregate Net Revenue Interests of all Sellers for each Target Formation in each Well or Tract as set forth in Exhibits A-1 and A-2, (ii) an aggregate Working Interest equal to the aggregate Working Interests of all Sellers for each Target Formation in each Well or Tract as set forth in Exhibits A-1 and A-2, and (iii) an aggregate number of Net Acres equal to the aggregate number of Net Acres of all Sellers in each Target Formation in each Tract as set forth in Exhibit A-2, then Buyer shall not have any remedy under the special warranty of title in the Assignment with respect to any claim related to a Net Revenue Interest, Working Interest or Net Acre deficiency.

8.7 Indemnification Procedures. All claims for indemnification under Section 8.2, Section 8.3, and Section 12.1(d) shall be asserted and resolved as follows:

(a) For purposes of this Article VIII, and Section 12.1(d), the term “Indemnifying Party” when used in connection with particular Liabilities shall mean the Party or Parties having an obligation to indemnify another Party or Parties with respect to such Liabilities pursuant to this Article VIII, or Section 12.1(d), and the term “Indemnified Party” when used in connection with particular Liabilities shall mean the Party or Parties having the right to be indemnified with respect to such Liabilities by another Party or Parties pursuant to Article VIII or Section 12.1(d).

(b) To make claim for indemnification under Section 8.2, Section 8.3, or Section 12.1(d), an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 8.7, 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 Party (a “Claim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Claim and shall enclose a copy of all papers (if any) served with respect to the Claim; provided that the failure of any Indemnified Party to give notice of a Claim as provided in this Section 8.7 shall not relieve the Indemnifying Party of its obligations under Section 8.2, Section 8.3 and Section 12.1(d) (as applicable) except to the extent (and then only to the extent) such failure prejudices the Indemnifying Party’s ability to defend against the 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.

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(c) In the case of a claim for indemnification based upon a Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such 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 Party and that is not prejudicial to the Indemnifying Party.

(d) If the Indemnifying Party admits its liability to defend the Claim, it shall have the right and obligation to diligently defend, at its sole cost and expense, the Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement of the Claim. If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in contesting any Claim which the Indemnifying Party elects to contest. The Indemnified Party may participate in, but not control, any defense or settlement of any Claim controlled by the Indemnifying Party pursuant to this Section 8.7(d). Without the written consent of the Indemnified Party, an Indemnifying Party shall not (i) settle any Claim or consent to the entry of any judgment with respect to any Claim which does not include an unconditional written release of the Indemnified Party from all liability in respect of such Claim or (ii) settle any Claim or consent to the entry of any judgment with respect any Claim in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(e) If the Indemnifying Party does not admit its liability to defend the Claim, fails to timely respond, or admits its liability but fails diligently to prosecute or settle the Claim, then the Indemnified Party shall have the right to defend against the Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing, subject to the right of the Indemnifying Party to admit its liability to defend the Claim and assume the defense of the Claim at any time prior to its settlement or final determination. If the Indemnifying Party has not yet admitted its liability for a Claim defense, the Indemnified Party shall notify the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option, on or before the 10th day following receipt of that notice (i) to admit in writing its liability for the Claim defense, and (ii) if liability is so admitted, to reject, in its reasonable judgment, the proposed settlement.

(f) In the case of a claim for indemnification not based upon a Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to (i) cure the Liabilities complained of, (ii) admit its liability for such Liability or (iii) dispute the claim for such Liabilities. If the Indemnifying Party does not notify the Indemnified Party within such 30 day period that it has cured the Liabilities or that it disputes the claim for such Liabilities, then the Indemnifying Party shall be deemed to be disputing the claim for such Liabilities.

8.8 Survival.

(a) The representations and warranties of the Parties set forth in this Agreement (other than the Fundamental Representations), shall, in each case, survive the Closing for a period of 12 months after the Closing Date. The Fundamental Representations shall survive the Closing indefinitely. The covenants and agreements of the Parties set forth in this Agreement that, by their terms, are to be performed prior to the Closing shall survive the Closing for a period of one year after the Closing Date. The obligation of each Seller to indemnify the Buyer Indemnified Parties

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for such Seller’s Retained Obligations shall (i) with respect to such Seller’s Retained Obligations set forth in Sections 8.2(d), (e), (j), (m), and (n), survive the Closing for a period of two years after the Closing Date, (ii) with respect to such Seller’s Retained Obligations set forth in Section 8.2(f), survive the Closing until the expiration of the applicable statute of limitations with respect to such environmental offsite disposal matters, (iii) with respect to such Seller’s Retained Obligations set forth in Section 8.2(g), survive the Closing until 60 days after the expiration of the applicable statute of limitations with respect to such Seller Taxes, and (iv) with respect to such Seller’s Retained Obligations set forth in Section 8.2(h), (i), (k), (l) and (o), survive the Closing without time limit.

(b) Subject to Section 8.8(a) and except as set forth in Section 8.8(c), the remainder of this Agreement shall survive the Closing without time limit. 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.

(c) The indemnities in Section 8.2(a), Section 8.2(b), Section 8.3(a) and Section 8.3(b) shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification, except, in each case, as to matters for which a specific written claim for indemnity has been delivered to the Indemnifying Party on or before such termination date.

8.9 Waiver of Right to Rescission. Sellers and Buyer acknowledge that, following the Closing, the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated by this Agreement. As the payment of money shall be adequate compensation, following the Closing, Buyer and Sellers waive any right to rescind this Agreement or any of the transactions contemplated hereby.

8.10 Insurance. The amount of any Liabilities for which any of the Buyer Indemnified Parties or Seller Indemnified Parties is entitled to indemnification under this Agreement or in connection with or with respect to the transactions contemplated by this Agreement shall be reduced by any corresponding insurance proceeds actually received by any such indemnified Party under any insurance arrangements.

8.11 Waiver of Consequential Damages. NONE OF THE BUYER INDEMNIFIED PARTIES NOR SELLER INDEMNIFIED PARTIES SHALL BE ENTITLED TO RECOVER FROM SELLERS OR BUYER, OR THEIR RESPECTIVE AFFILIATES, ANY SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE, EXEMPLARY, REMOTE OR SPECULATIVE DAMAGES, INCLUDING DAMAGES FOR LOST PROFITS (OTHER THAN LOST PROFITS THAT CONSTITUTE DIRECT DAMAGES AS A MATTER OF LAW) OF ANY KIND ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY, EXCEPT TO THE EXTENT ANY SUCH PARTY SUFFERS SUCH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEY’S FEES INCURRED IN CONNECTION WITH DEFENDING OF SUCH DAMAGES) TO A THIRD PARTY, WHICH DAMAGES (INCLUDING COSTS OF

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DEFENSE AND REASONABLE ATTORNEY’S FEES INCURRED IN CONNECTION WITH DEFENDING AGAINST SUCH DAMAGES) SHALL NOT BE EXCLUDED BY THIS PROVISION AS TO RECOVERY HEREUNDER. SUBJECT TO THE PRECEDING SENTENCE, BUYER, ON BEHALF OF EACH OF THE BUYER INDEMNIFIED PARTIES, AND SELLERS, ON BEHALF OF EACH OF THE SELLER INDEMNIFIED PARTIES, WAIVE ANY RIGHT TO RECOVER ANY SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE, EXEMPLARY, REMOTE OR SPECULATIVE DAMAGES, INCLUDING DAMAGES FOR LOST PROFITS (OTHER THAN LOST PROFITS THAT CONSTITUTE DIRECT DAMAGES AS A MATTER OF LAW) OF ANY KIND, ARISING IN CONNECTION WITH OR WITH RESPECT TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

8.12 Indemnity Escrow. In order to provide security for Sellers’ indemnification obligations under this Agreement, the Indemnity Escrow shall be held by Escrow Agent, and disbursed by Escrow Agent after the Closing in accordance with this Section 8.12 and the Escrow Agreement. With respect to each claim for indemnification asserted in good faith by Buyer against Sellers pursuant to Section 8.2 or special warranty claim pursuant to the Assignment during the period from and after the Closing Date up to the date that is two years following the Closing Date (the “Escrow Termination Date”), upon final resolution or determination of such an indemnity or warranty claim by the applicable Parties or in accordance with Section 8.7, as applicable, Buyer and Seller’s Representatives shall jointly instruct Escrow Agent to disburse to Buyer the amount set forth in such joint instruction, which will be that portion of the Indemnity Escrow being held in the Indemnity Escrow account as would satisfy such finally resolved or determined indemnity or warranty claim. On the date that is six months following the Closing Date, Buyer and Seller’s Representatives shall jointly instruct the Escrow Agent to disburse to Seller’s Representatives an amount equal to the positive difference, if any, between (a) Fifteen Million Dollars ($15,000,000), and (b) an amount equal to the sum of (i) all amounts disbursed to Buyer as of such date, and (ii) any amounts necessary to satisfy any unresolved Claim Notices made in good faith as of such time in the proportions requested by Seller’s Representatives within three Business Days of its receipt of such joint instruction. On the date that is 12 months following the Closing Date, Buyer and each Seller’s Representative shall jointly instruct the Escrow Agent to disburse to Seller’s Representatives an amount equal to the positive difference, if any, between (A) Twenty-Five Million Dollars ($25,000,000), and (B) an amount equal to the sum of (1) all amounts disbursed to Seller’s Representatives as of such date, (2) all amounts disbursed to Buyer as of such date, and (3) any amounts necessary to satisfy any unresolved Claim Notices made in good faith as of such time in the proportions requested by Seller’s Representatives within three Business Days of its receipt of such joint instruction. On the Escrow Termination Date, Seller’s Representatives shall, subject to the remainder of this sentence, be entitled to receive the Indemnity Escrow balance as of such time and such amount shall be automatically distributed to Seller’s Representatives in the proportions requested by Seller’s Representatives pursuant to the terms of the Escrow Agreement (and Buyer and Seller’s Representatives shall jointly instruct Escrow Agent to take any necessary actions in order to accomplish the foregoing); provided, however, that Sellers shall not be entitled to a distribution of, and Escrow Agent shall retain, any amounts necessary to satisfy any unresolved Claim Notices that have been timely delivered by Buyer in good faith in accordance with Section 8.7 (which amounts shall remain in the Indemnity Escrow until such Claim Notices are finally resolved). If there are remaining amounts due by any Seller to Buyer pursuant to its indemnity obligations under Section 8.2 after the Indemnity Escrow balance is exhausted, then such amounts

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shall be promptly paid to Buyer by such Seller as they are agreed by the applicable Parties or finally determined in accordance with the terms of this Agreement. If there are any funds remaining in the Indemnity Escrow account after the resolution of all previously outstanding Claim Notices, then Seller’s Representatives and Buyer shall promptly jointly instruct Escrow Agent to release the remaining account balance to Seller’s Representatives in the proportions requested by Seller’s Representatives within three Business Days of its receipt of such joint instruction.

ARTICLE IX
REPRESENTATIONS AND WARRANTIES OF SELLER

Each Seller, severally and not jointly, as to such Seller, represents and warrants to Buyer the following:

9.1 Organization, Existence and Qualification. If such Seller is not a natural person, such Seller is duly formed, validly existing and in good standing under the Laws governing its organization as set forth in such Seller’s Schedule 9.1 (or, if such Seller fails to deliver its Schedule 9.1, as set forth opposite such Seller’s name on Schedule 9.1 of the RK Petroleum Schedules). If such Seller is a natural person, such Seller has all requisite and legal capacity to enter into this Agreement and perform his or her obligations hereunder. Such Seller has all requisite power and authority to own its interest in the Assets (including its interests in the Assets) and to carry on its business as now conducted. If such Seller is not a natural person, such Seller is duly licensed or qualified to do business and is in good standing in each jurisdiction in which it carries on business or in which its Assets are located as such qualification is required by Law.

9.2 Authority, Approval and Enforceability. Such Seller has full power and authority to enter into and perform its obligations under this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. If such Seller is not a natural person, the execution, delivery and performance by such Seller of this Agreement have been duly and validly authorized and approved by all necessary actions of such Seller. This Agreement is, and the Transaction Documents to which such Seller is a party when executed and delivered by such Seller will be, the valid and binding obligation of such Seller and enforceable against such Seller in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

9.3 No Conflicts. The execution, delivery and performance by such Seller of this Agreement and the consummation of the transactions contemplated herein will not (a) conflict with or result in a breach of any provisions of the governing documents of such Seller, if applicable, (b) result in a default or the creation of any 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 other material agreement to which such Seller is a party or by which such Seller or such Seller’s Assets may be bound or (c) violate any Law applicable to such Seller or any of its interest in the Assets.

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9.4 Consents. Except (a) for compliance with the HSR Act, (b) as set forth in such Seller’s Schedule 9.4, (c) for Customary Post-Closing Consents, (d) under Contracts that are terminable upon 30 days or less notice without payment of any fee, and (e) for the Preferential Purchase Rights set forth in such Seller’s Schedule 9.10, there are no requirements for consents from any Governmental Authority or other Third Parties to any assignment that such Seller is required to obtain in connection with the transfer of its interest in the Assets by such Seller to Buyer or the consummation of the transactions contemplated by this Agreement by such Seller.

9.5 Bankruptcy. There are no bankruptcy or receivership proceedings pending, being contemplated by or, to such Seller’s Knowledge, threatened in writing against such Seller or any of its Affiliates.

9.6 Foreign Person. Such Seller is not a “foreign person” within the meaning of Section 1445 of the Code.

9.7 Litigation. Except as set forth in such Seller’s Schedule 9.7, as of the Execution Date, there is no suit, action, claim, demand, filing, charge, litigation, pending settlement, order or proceeding (each a “Proceeding”) by any Person by or before any Governmental Authority, and no arbitration proceedings, (in each case) pending, or threatened in writing, against such Seller or its Affiliates, or to which such Seller or its Affiliates is a party, with respect to such Seller’s interest in the Assets or that would affect the ability of such Seller to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

9.8 Material Contracts.

(a) Such Seller’s Schedule 9.8(a) sets forth all of such Seller’s Applicable Contracts of the type described below (collectively, the “Material Contracts”):

(i) any Applicable Contract that can reasonably be expected to result in aggregate payments of more than $25,000 by such Seller during the current or any subsequent fiscal year;

(ii) any Applicable Contract that can reasonably be expected to result in aggregate revenues of more than $25,000 by such Seller during the current or any subsequent fiscal year;

(iii) any Applicable Contract that is a Hydrocarbon purchase and sale, exchange, supply, transportation, gathering, processing, marketing or similar Applicable Contract related to such Seller’s interest in the Assets and that is not terminable without penalty upon 30 days or less notice;

(iv) any Applicable Contract that is a purchase and sale agreement (other than with respect to production of Hydrocarbons in the ordinary course), farmout agreement, participation agreement, exploration agreement, development agreement, joint operating agreement, partnership agreement (other than tax partnerships) unit, pooling or communitization agreements, joint venture agreement or similar Applicable Contract related to such Seller’s interest in the Assets;

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(v) any Applicable Contract that is a drilling contract;

(vi) any Applicable Contract of such Seller to sell, lease, farmout, exchange, transfer or otherwise dispose of all or any part of such Seller’s interest in the Assets from and after the Effective Time, but excluding rights or reassignment upon intent to abandon an Asset;

(vii) any Applicable Contract that provides for an irrevocable power of attorney related to such Seller that will be in effect after the Closing Date;

(viii) any Applicable Contract that provides for calls on production of Hydrocarbons from such Seller’s interest in the Assets or options to purchase Hydrocarbons produced from such Seller’s interest in the Assets;

(ix) any Applicable Contract that purports to contain a dedication covering any portion of such Seller’s interest in the Assets;

(x) any Applicable Contract between such Seller and any other Seller or an Affiliate of any Seller that will not be terminated prior to Closing;

(xi) any Applicable Contract that relate to such Seller’s interest in the Assets and (A) contains or constitutes an existing area of mutual interest agreement or an agreement to enter into an area of mutual interest agreement in the future, or (B) includes non-competition restrictions or other similar restrictions on doing business; and

(xii) any Applicable Contract that constitutes an amendment, supplement or modification in respect of any of the foregoing.

(b) Except as set forth in such Seller’s Schedule 9.8(b), there exists no default under any Applicable Contract by such Seller or by any other Person that is a party to any such Seller’s Material Contract. As of the Execution Date, such Seller (or the Seller’s Representatives) has made available to Buyer true and complete copies of all of such Seller’s Applicable Contracts (including all amendments, supplements and modifications in respect thereof).

(c) There are no Hedge Contracts binding on such Seller’s interest in the Assets pursuant to which any production of Hydrocarbons from such Seller’s interest in the Assets is dedicated or committed from and after the Effective Time.

9.9 No Material Violation of Laws. Except as set forth in such Seller’s Schedule 9.9, (a) for Assets operated by such Seller or its Affiliates, such Seller and its applicable Affiliate(s) have complied in all material respects with, and the ownership, operation, development, maintenance and use of the Assets operated by such Seller or its Affiliates, as applicable, have been in compliance in all material respects with, in each case, all applicable Laws, (b) for Assets not operated by such Seller or its Affiliates, to the Knowledge of such Seller the applicable operator has complied in all material respects with, and the ownership, operation, development, maintenance and use of such Assets have been in compliance in all material respects with, in each case, all applicable Laws, and (c) for all Assets in which such Seller owns an interest, neither such Seller nor its Affiliates have

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received any written notice of a material violation of or material default by it or its Affiliates with respect to any Law or any decision, ruling, order or award of any Governmental Authority, in each case, that is applicable to such Seller’s interest in the Assets. This Section 9.9 does not include any matters with respect to Environmental Laws, Environmental Conditions or any other environmental matter, such matters being addressed exclusively in Section 9.14.

9.10 Preferential Purchase Rights. Except as set forth in such Seller’s Schedule 9.10, there are no Preferential Purchase Rights that are applicable to the transfer of such Seller’s interest in the Assets to Buyer.

9.11 Burdens. Except as set forth in such Seller’s Schedule 9.11, if (a) such Seller or any of its Affiliates is the operator of such Assets, such Seller or its applicable Affiliates have paid or caused to be paid in accordance with applicable Law and the terms of the applicable Leases, in all material respects, all Burdens due by such Seller with respect to its interest in the Assets, and (b) neither such Seller nor any of its Affiliates is the operator of such Assets, then, to the Knowledge of such Seller, the applicable operator has paid or caused to be paid in accordance with applicable Law and the terms of the applicable Leases, in all material respects, all Burdens due with respect to such Seller’s interest in such Assets.

9.12 Imbalances/Payout Status. Except as set forth in such Seller’s Schedule 9.12(a), to such Seller’s Knowledge there are no Imbalances associated with such Seller’s interest in the Assets as of the Effective Time. To such Seller’s Knowledge, such Seller’s Schedule 9.12(b) sets forth the status of any “payout” balance, as of the date set forth on such schedule, for those Wells in which such Seller owns an interest that are subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

9.13 Current Commitments. Such Seller’s Schedule 9.13 sets forth, as of the Execution Date, to Seller’s Knowledge all outstanding authorities for expenditures or written commitments (“AFEs”) that (a) relate to such Seller’s interest in the Assets and to drilling, reworking or conducting other operations with respect to, in each case, a Well or other Asset in which such Seller owns an interest, (b) are in excess of $37,500, net to such Seller’s interest in the Assets, and (c) for which all of the activities anticipated in such AFEs have not been completed by the Execution Date.

9.14 Environmental. Except as set forth in such Seller’s Schedule 9.14:

(a) Such Seller has not entered into any agreements, consents, orders, decrees, judgments, license or permit conditions, or other directives of any Governmental Authorities based on any prior violations of Environmental Laws, or any material Liability thereunder, that relate to the future use of any of such Seller’s interest in the Assets and that require any Remediation. Except for the Hazardous Substances generated in the ordinary course of such Seller’s business and which could not be reasonably expected to result in a material violation of Environmental Law, such Seller has not disposed of (and in the case of Assets not operated by such Seller or any of its Affiliates but which such Seller owns an interest, to such Seller’s Knowledge, the operator has not disposed of) any Hazardous Substances generated on the Assets, or used on the Assets, at sites off of the Assets.

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(b) Such Seller has not received written notice from any Person of any release or disposal of any Hazardous Substance concerning any land, facility, asset or property included in the Assets that would reasonably be expected to: (i) prevent compliance by such Seller with any Environmental Law or the terms of any license or permit issued pursuant thereto or (ii) alleges any material violation of or non-compliance with or claim under any Environmental Law.

9.15 Taxes. Except as disclosed in such Seller’s Schedule 9.15:

(a) all Asset Taxes of such Seller that have become due and payable have been properly paid by such Seller;

(b) all Tax Returns for Asset Taxes that are required to be filed by such Seller in connection with its ownership or operation of the Assets have been duly and timely filed by such Seller, and all such Tax Returns for such Asset Taxes are correct and complete in all material respects;

(d) such Seller has not received any written notice of any pending claim (which remains outstanding) from any applicable Taxing Authority for assessment of Asset Taxes relating to such Seller and, to such Seller’s Knowledge, no such claim has been made or threatened except as it relates to pending severance tax refund claims made by such Seller described in such Seller’s Schedule 9.15;

(e) no audit, administrative, judicial or other proceeding with respect to Asset Taxes of such Seller has been commenced or is presently pending except as it relates to pending severance tax refund claims made by such Seller described in such Seller’s Schedule 9.15; and

(f) none of such Seller’s interest in the Assets is subject to any tax partnership agreement, or is otherwise treated, or required to be treated, as held in an arrangement requiring a partnership income Tax Return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute.

9.16 Brokers’ Fees. Such Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Buyer or any Affiliate of Buyer shall have any responsibility.

9.17 Suspense Funds. Such Seller’s Schedule 9.17 lists all Suspense Funds held in suspense by such Seller as of the Effective Time, and all such Suspense Funds are held by such Seller in accordance with applicable Law and the terms of any applicable Lease or Applicable Contract.

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9.18 Advance Payments. Except for the throughput deficiencies attributable to or arising out of any Applicable Contract included in such Seller’s Schedule 9.18 and any Imbalances, (a) with respect to any of the Assets operated by such Seller, such Seller is not obligated by virtue of any take or pay payment, advance payment or other similar payment (other than royalties, overriding royalties, free gas arrangements and similar arrangements, in each case, established by the terms of the Leases) or under any gathering, transmission or any other similar contract or agreement, or (b) with respect to any of the Assets not operated by such Seller, to such Seller’s Knowledge, such Seller is not obligated to gather, deliver, process or transport Hydrocarbons, or deliver proceeds from the sale thereof, attributable to such Seller’s interest in the Assets at some future time without receiving full payment therefor at or after the time of delivery.

9.19 Properties.

(a) To such Seller’s Knowledge, no default exists in the performance of any obligation of such Seller under the Leases in which such Seller owns an interest that would entitle the lessor thereunder to cancel or terminate any such Leases, and, except as set forth in such Seller’s Schedule 9.19, no party to any Lease in which such Seller owns an interest 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.

(b) Except as set forth in such Seller’s Schedule 9.19, to such Seller’s Knowledge, all shut-in royalty payments and all delay rental payments due under the terms of the Leases in which Seller owns an interest have been fully and timely paid.

(c) Except as set forth in such Seller’s Schedule 9.19, to such Seller’s Knowledge, for each Lease set forth on the Exhibit A in which Seller owns an interest, there has been no lapse in production of Hydrocarbons that would give rise to a claim that such Lease has terminated.

9.20 Non-Consent Operations. Except as disclosed in such Seller’s Schedule 9.20, no operations are being conducted or have been conducted on the Assets in which such Seller owns an interest with respect to which such Seller has elected to be a non-consenting party under the applicable operating agreement and with respect to which all of such Seller’s rights have not yet reverted to it.

9.21 Permits. Except as set forth in such Seller’s Schedule 9.21, with respect to Assets currently operated by such Seller or its Affiliates, (a) such Seller or its applicable Affiliate has acquired all Permits from appropriate Governmental Authorities to conduct operations on such Assets in material compliance with all applicable Laws, (b) all such Permits are in full force and effect and no Proceeding is pending, nor to such Seller’s Knowledge, threatened, to suspend, revoke or terminate any such Permit or declare any such Permit invalid, and (c) such Seller and its applicable Affiliates, if applicable, are in compliance in all material respects with all such Permits.

9.22 Guarantees. Such Seller’s Schedule 9.22 accurately sets forth a true and complete list of (a) all bonds, letters of credit, guarantees and other forms of credit support currently maintained, posted or otherwise provided by such Seller or its Affiliates that relate to such Seller’s interest in the Assets or the Assumed Obligations (collectively, the “Guarantees”) and (b) all pending claims and the claims history against such Guarantees.

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9.23 Wells and Equipment. To such Seller’s Knowledge and except as set forth in such Seller’s Schedule 9.23:

(a) all Wells in which such Seller owns an interest have been drilled and completed within the limits permitted by all applicable Leases, Contracts, or pooling or unit agreements and such Wells in which such Seller owns an interest are not on expired leases;

(b) no Well in which such Seller owns an interest is subject to penalties on allowables on or after the Effective Time because of any overproduction or any other violation of Laws;

(c) there are no Wells in which such Seller owns an interest located on the Assets (i) that such Seller is currently obligated by any Laws or Contract to currently plug, dismantle or abandon, (ii) that such Seller has plugged, dismantled or abandoned in a manner that does not comply in all material respects with applicable Law or (iii) with respect to which such Seller has received notice from any Governmental Authority that such Well must be plugged, dismantled or abandoned; and

(d) all easements, rights-of-way, licenses and authorizations from Governmental Authorities necessary to access, construct, operate, maintain, and repair the Personal Property in the ordinary course of business as currently conducted have been obtained.

9.24 Operator. Such Seller has not received any written notice of any vote (or other action) being taken to remove any Seller as the operator of any of the Assets.

9.25 Condemnation. There is no actual, or to Seller’s Knowledge, threatened taking (whether permanent, temporary, whole or partial) of such Seller’s interest in any of the Assets, or any part of such Seller’s interest in the Assets, by reason of condemnation or eminent domain or the threat of condemnation or eminent domain.

ARTICLE X
REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer represents and warrants to Sellers the following:

10.1 Organization, Existence and Qualification. Buyer is a Texas corporation duly formed and validly existing under the Laws of the jurisdiction of its formation, and Buyer has all requisite power and authority to own and operate its property and to carry on its business as now conducted. Buyer is duly licensed or qualified to do business as a foreign corporation in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law. Buyer is duly licensed or qualified to do business in Texas.

10.2 Authority, Approval and Enforceability. Buyer has full power and authority to enter into and perform its obligations under this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by Buyer of this Agreement have been duly and validly authorized and approved by all necessary corporate action on the part of Buyer. This Agreement is, and the Transaction

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Documents to which Buyer is a party when executed and delivered by Buyer will be, the valid and binding obligation of Buyer and enforceable against Buyer in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

10.3 No Conflicts. The execution, delivery and performance by Buyer of this Agreement and the consummation of the transactions contemplated herein will not (a) conflict with or result in a breach of any provisions of the organizational or other governing documents of Buyer, (b) result in a default or the creation of any 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 other agreement to which Buyer is a party or by which Buyer or any of its property may be bound or (c) violate any Law applicable to Buyer or any of its property.

10.4 Consents. Except for compliance with the HSR Act (if applicable), there are no consents or other restrictions on assignment, including requirements for consents from Third Parties to any assignment (in each case) that Buyer is required to obtain in connection with the transfer of the Assets from Sellers to Buyer or the consummation of the transactions contemplated by this Agreement by Buyer.

10.5 Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s knowledge, threatened in writing against Buyer.

10.6 Litigation. There is no suit, action or litigation by any Person by or before any Governmental Authority, and no arbitration proceedings, (in each case) pending, or threatened in writing, against Buyer, that would affect the ability of Buyer to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

10.7 Financing. As of Closing, Buyer will have sufficient cash in immediately available funds and available lines of credit with which to pay the Participating Purchase Price, consummate the transactions contemplated by this Agreement and perform its obligations under this Agreement and the Transaction Documents.

10.8 Regulatory. As of the Closing Date, Buyer or its designee operator shall be qualified to own and assume operatorship of oil, gas and mineral leases in all jurisdictions where the Assets are located, and the consummation of the transactions contemplated by this Agreement will not cause Buyer or such designee to be disqualified as such an owner or operator. To the extent required by any applicable Laws, Buyer or its designee operator shall, as of the Closing Date, (a) hold all lease bonds and any other surety or similar bonds as may be required by, and in accordance with, all applicable Laws governing the ownership and operation of the Assets and (b) have filed any and all required reports necessary for such ownership and operation with all Governmental Authorities having jurisdiction over such ownership and operation.

10.9 Independent Evaluation. Buyer is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, Buyer has relied

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on its own independent investigation and evaluation of the Assets and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and not on any comments, statements, projections or other material made or given by any representative, consultant or advisor of Sellers. Buyer acknowledges and affirms that on or prior to Closing, Buyer will have completed its independent investigation, verification, analysis, and evaluation of the Assets and made all such reviews and inspections of the Assets as it has deemed necessary or appropriate to consummate the transaction contemplated hereunder; provided, however, no such investigation, verification, analysis or evaluation (or absence thereof) shall reduce, modify, release or waive any of Sellers’ obligations or Liabilities hereunder or under any of the other Transaction Documents.

10.10 Brokers’ Fees. Buyer has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Sellers or Sellers’ Affiliates shall have any responsibility.

10.11 Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act, as amended, and will acquire the Assets for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws.

ARTICLE XI
CERTAIN AGREEMENTS

11.1 Conduct of Business.

(a) Except (1) as set forth in such Seller’s Schedule 11.1, (2) for the operations covered by the AFEs described in such Seller’s Schedule 9.13, (3) with respect to Section 11.1(a)(i) only, as required in the event of an emergency to protect life, property or the environment, and (4) as expressly contemplated by this Agreement or as expressly consented to in writing by Buyer (which consent shall not be unreasonably delayed, withheld or conditioned), each Seller shall, from and after the Execution Date until the Closing:

(i) subject to (A) such Seller’s right to comply with the terms of the Leases, Applicable Contracts, applicable Laws and requirements of Governmental Authorities and (B) interruptions resulting from force majeure, mechanical breakdown and planned maintenance, in each case, operate or, in the case of those Assets not operated by such Seller or its Affiliates, use its commercially reasonable efforts to cause to be operated, the Assets in the usual, regular and ordinary manner consistent with past practice;

(ii) maintain, or cause to be maintained, the books of account and Records of such Seller relating to the Assets in the usual, regular and ordinary manner and in accordance with the usual accounting practices of such Seller;

(iii) drill and complete, or in the case of those Assets not operated by such Seller or its Affiliates, use its commercially reasonable efforts to cause to be drilled or completed, according to the time schedule and specifications included on such Seller’s

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Schedule 11.1(a)(iii), future wells required under continuous drilling obligation provisions of the Leases;

(iv) pay, when due, all Taxes, Burdens, Operating Expenses and any other assessments with respect to such Seller’s interest in the Assets that become due and payable prior to Closing;

(v) (A) if such Seller has a contractual right to renew or extend the term of any Lease, maintain in full force and effect such Lease and timely and properly pay Lease Burdens and all Lease renewals and extensions in accordance with the terms of such Lease, and (B) with respect to any other applicable Lease, timely and properly pay Lease Burdens, use commercially reasonable efforts to maintain in full force and effect such Lease, and if there is the potential to renew or extend any such Lease, use commercially reasonable efforts to timely and properly pay any applicable Lease renewals and extensions;

(vi) comply in all material respects with all Laws that are applicable to the Assets in which such Seller owns an interest;

(vii) maintain insurance coverage on the Assets in which such Seller owns an interest presently furnished by nonaffiliated Third Parties in the amounts and of the types presently in force;

(viii) notify Buyer if any Lease in which such Seller owns an interest terminates promptly upon learning of such termination;

(ix) provide Buyer lease operating expense statements with respect to the Assets in which such Seller is the operator and, with respect to RK Petroleum Corp. only, with respect to any Assets in which it is not the operator, in each case, by the 10^th day of each month applicable to operations during the preceding month;

(x) maintain all material Permits, approvals, bonds and guarantees affecting the Assets in which such Seller owns an interest, and make all filings that Seller is required to make under applicable Law with respect to the Assets in which such Seller owns an interest;

(xi) give written notice to Buyer as soon as is practicable of any written notice received or given by such Seller with respect to any alleged breach by such Seller or any Third Party of any Lease or Material Contract or violation of law or Proceeding or similar claim; and

(xii) take any and all actions necessary to ensure that the Assets in which such Seller owns an interest are free and clear of all Encumbrances as of the Closing except for Permitted Encumbrances.

(b) Except (1) as set forth in Schedule 11.1, (2) for the operations covered by the AFEs described in Schedule 9.13, (3) as required in the event of an emergency to protect life, property or the environment, and (4) as expressly contemplated by this Agreement or as expressly

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consented to in writing by Buyer (which consent shall not be unreasonably delayed, withheld or conditioned), each Seller shall not, from and after the Execution Date until the Closing:

(i) (A) enter into an Applicable Contract that, if entered into on or prior to the Execution Date, would have been required to be listed on such Seller’s Schedule 9.8(a), or (B) terminate (unless the term thereof expires pursuant to the provisions existing therein) or materially amend the terms of any Material Contract;

(ii) enter into, terminate (unless the term thereof expires pursuant to the provisions existing therein), materially amend or surrender any rights under any Lease or Right-of-Way, provided that such Seller shall be permitted to amend any Lease to increase its pooling authority;

(iii) subject to Section 11.1(e), approve, propose or commit to any individual AFE or similar request which would reasonably be estimated to require expenditures in excess of $100,000 across all Sellers;

(iv) transfer, sell, mortgage, encumber, pledge or dispose of any of such Seller’s interest in the Assets other than the (A) sale and/or disposal of Hydrocarbons in the ordinary course of business and consistent with past practices and (B) sales of equipment that is no longer necessary in the operation of the Assets in which such Seller owns an interest or for which replacement equipment has been obtained;

(v) incur costs to secure or acquire Lease renewals or extensions and/or necessary Rights-of-Way that would exceed $100,000 in the aggregate across all Sellers;

(vi) resign as the operator of any of the Assets;

(vii) waive, compromise or settle any material right or claim if such waiver, compromise or settlement would adversely affect the future use, ownership or operation of any of the Assets in which such Seller owns an interest in any material respect;

(viii) incur Liabilities with respect to the Assets in which such Seller owns an interest for which Buyer would be responsible after Closing, other than transactions in the normal, usual and customary manner, of a nature and in an amount (not to exceed $37,500 net to such Seller’s interest) consistent with past practices employed by such Seller with respect to the Assets;

(ix) make a non-consent election;

(x) enter into or amend any contract or agreement with its Affiliates affecting such Seller’s interest in any of the Assets;

(xi) make any change to a division order, revenue deck or expense deck relating to such Seller’s interest in any of the Assets that causes the Net Revenue Interest or Working Interest of such Seller in any such Assets to differ from as set forth on Exhibit A-1 or Exhibit A-2, as applicable;

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(xii) abandon any Lease or Well capable of production in commercial quantities; or

(xiii) commit to do any of the foregoing.

(c) Without expanding any obligations which Sellers may have to Buyer, it is expressly agreed that Sellers shall never have any monetary liability to Buyer with respect to any breach or failure of Section 11.1(a)(i) or Section 11.1(a)(ii) greater than that which such Seller might have as the operator to a non-operator under the applicable operating agreement (or, in the absence of such an agreement, under the AAPL 610 (1989 Revision) form Operating Agreement), IT BEING RECOGNIZED THAT, UNDER SUCH AGREEMENTS AND SUCH FORM, THE OPERATOR (SOLELY IN ITS CAPACITY AS OPERATOR) IS NOT RESPONSIBLE FOR ITS OWN NEGLIGENCE, AND HAS NO RESPONSIBILITY OTHER THAN FOR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

(d) Buyer acknowledges Sellers own undivided interests in certain of the properties comprising the Assets that it is not the operator thereof, and Buyer agrees that the acts or omissions of the other Working Interest owners (including the operators) who are not Sellers or any Affiliates of Sellers shall not constitute a breach of the provisions of this Section 11.1, nor shall any action required by a vote of Working Interest owners constitute such a breach so long as such Seller has voted its interests in a manner that complies with the provisions of this Section 11.1.

(e) With respect to any AFE or similar request received by Sellers that is estimated to cost in excess of $100,000 in the aggregate across all the Sellers, each applicable Seller shall forward such AFE to Buyer as soon as is reasonably practicable and thereafter the Parties shall consult with each other regarding whether or not such Seller should elect to participate in such operation. Buyer agrees that it will (i) timely respond to any written request for consent pursuant to this Section 11.1(e) and Section 11.1(b)(iii), and (ii) consent to any written request for approval of any AFE or similar request that Buyer reasonably considers to be economically appropriate or is necessary to continue any Asset in force and effect beyond Closing and to which operator has consented. In the event the Parties are unable to agree within 10 days (unless a shorter time, not to be less than 48 hours, is reasonably required by the circumstances and the applicable joint operating agreement and such shorter time is specified in such Seller’s request for consent) of Buyer’s receipt of any consent request as to whether or not such Seller should elect to participate in such operation, Buyer’s decision shall control.

11.2 Operation of Assets After the Closing.

(a) Except as provided for in the Transition Services Agreement, it is expressly understood and agreed that Sellers shall not be obligated to continue operating any of the operated Assets following the Closing and Buyer assumes full responsibility for operating (or causing the operation of) all such Assets following the Closing. Seller does not warrant or guarantee that Buyer will become the operator of the operated Assets or any portion of the Assets, as such matter will be controlled by the applicable joint operating agreement(s).

(b) Each Seller, as applicable, shall (and shall cause its Affiliates to) use its reasonable efforts to support Buyer’s succession of any Seller currently serving as operator of the

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Operated Assets, including (i) seeking the written undertakings of the other co-owners of such Assets to Buyer’s succession as operator to such Seller with respect to such Operated Assets, (ii) confirming that such owners will vote for Buyer to succeed such Seller as operator of such Operated Assets under operating agreements applicable thereto, and (iii) taking any other action reasonably requested by Buyer with respect to the transfer of operatorship with respect to such Operated Assets. Buyer will file all appropriate forms and declarations or bonds with federal and state agencies relative to its assumption of operatorship promptly following Closing. For all Operated Assets, all applicable Sellers will execute and deliver to Buyer, and Buyer will promptly file all documents necessary for such applicable Sellers to resign as operator of such Assets and for Buyer or an Affiliate thereof to succeed such Seller as operator of such Assets, including appropriate change or transfer of operator forms to file with the applicable Governmental Authority.

11.3 HSR Act. If applicable, within 10 Business Days following the Election Deadline, Buyer and applicable Sellers will each prepare and simultaneously file with the DOJ and the FTC the notification and report form required for the transactions contemplated by this Agreement by the HSR Act and request early termination of the waiting period thereunder. Buyer and applicable Sellers agree to respond promptly to any inquiries from the DOJ or the FTC concerning such filings and to comply in all material respects with the filing requirements of the HSR Act. Buyer and applicable Sellers shall cooperate with each other and, subject to the terms of the Confidentiality Agreement, shall promptly furnish all information to the other Party that is necessary in connection with Buyer’s and applicable Sellers’ compliance with the HSR Act. Buyer and applicable Sellers shall keep each other fully advised with respect to any requests from or communications with the DOJ or FTC concerning such filings and shall consult with each other with respect to all responses thereto. Each applicable Seller and Buyer shall use its commercially reasonable efforts to take all actions reasonably necessary and appropriate in connection with any HSR Act filing to consummate the transactions consummated hereby. Notwithstanding anything in this Agreement to the contrary, in no event will Buyer be obligated to propose or agree to accept any undertaking or condition, to enter into any consent decree, to make any divestiture, to accept any operational restriction, or take any other action that, in the reasonable judgment of Buyer, could be expected to limit the right of Buyer to own or operate all or any portion of its businesses or the Assets. Buyer and the Seller’s Representatives shall each bear one-half of the filing fees of the HSR Act filings.

11.4 Governmental Bonds. Buyer acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by Sellers or their Affiliates with Governmental Authorities and relating to the Assets are transferable to Buyer. On or before the Closing Date, Buyer or its designee operator shall obtain replacements for those bonds, letters of credit and guarantees described on such Seller’s Schedule 11.4, to the extent such replacements are necessary for Buyer’s ownership of the Assets.

11.5 Exclusivity. Until the earlier of (a) the Closing or (b) the valid termination of this Agreement, Sellers shall not, and shall cause their Affiliates, agents and representatives not to, solicit offers, inquiries or proposals from or negotiate or participate in discussions with, or disclose information to, any Third Party in connection with the possible sale of or other disposition of all or any material portion of the Assets (other than replacement of equipment or sale of

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Hydrocarbons in the regular course of business), or any other transaction involving a change in the ownership of, or debt or equity financing of, the Assets.

11.6 Revenues.

(a) In the event either (i) Buyer receives revenues attributable to any of the Assets for any periods prior to the Effective Time or (ii) any Seller receives revenues attributable to any of the Assets for any periods after the Effective Time which revenues, in either case, are not accounted for in the Preliminary Settlement Statement or the Final Settlement Statement, the receiving Party will hold such revenues for the exclusive benefit of the Party entitled thereto pursuant to this Agreement and, if not taken into account for purposes of the Final Settlement Statement, shall promptly deliver such funds to the appropriate Party within thirty (30) days after receipt.

(b) In the event either (i) Buyer pays monies for Operating Expenses attributable to any of the Assets for any periods prior to the Effective Time, or (ii) any Seller pays monies for Operating Expenses attributable to any of the Assets for any periods after the Effective Time which payment, in either case, is not accounted for in the Preliminary Settlement Statement or the Final Settlement Statement, then (A) such paying Party shall deliver the owing Party (or the Seller’s Representatives, if Buyer is the paying Party) an invoice and proof of payment with respect to such Operating Expenses, and (B) within 30 days after receipt of the applicable invoice and proof of payment are received by Buyer or the Seller’s Representatives, as applicable, the owing Party (or the Seller’s Representatives, if a Seller is the owing Party) shall reimburse the Party that paid such Operating Expenses.

(c) In the event that any Party (i) receives an invoice of an expense or obligation which is owed by the other Party, then if such Party receiving the invoice is (A) a Seller, such Seller shall promptly forward such invoice to Buyer, and (B) Buyer, Buyer shall promptly forward such invoice to the Seller’s Representatives, and (ii) receives an invoice or other evidence of an obligation that is partially an obligation of both Buyer, on the one hand, and any Seller, on the other hand, then Buyer and the Seller’s Representatives shall consult with one another other, and following such consultation each owing Party shall promptly pay its portion of such obligation to the obligee.

11.7 Financial Information. From and after the date of this Agreement until December 31, 2021 (the “Records Period”), (a) each Seller who is, or whose Affiliate is, the operator of any of the Assets, and (b) even with respect to Assets that it does not operate, RK Petroleum Corp., shall, and shall cause their Affiliates and their respective officers, directors, managers, employees, agents and representatives to, provide reasonable cooperation to Buyer, its Affiliates and their agents and representatives in connection with Buyer’s or its Affiliates’ filings, if any, that are required by the Securities and Exchange Commission, under securities laws applicable to Buyer and its Affiliates (collectively, the “Filings”, and such afore described Sellers, each a “Cooperating Seller”). During the Records Period, each Cooperating Seller agrees to make available to Buyer and its Affiliates and their agents and representatives any and all books, records, information and documents to the extent that such are attributable to the Assets in such Cooperating Seller’s or its Affiliates’ possession or control and reasonable access to such Cooperating Seller’s and its Affiliates’ personnel, in each case as reasonably required by Buyer, 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 (“Securities Act”),

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along with any documentation attributable to the Assets required to complete any audit associated with such financial statements, which records and information shall include, for the avoidance of doubt, lease operating statements for the 24 month period prior to the Execution Date. During the Records Period, each Cooperating Seller shall, and shall cause its Affiliates to, provide reasonable cooperation to the independent auditors chosen by Buyer (“Buyer’s Auditor”) in connection with any audit by Buyer’s Auditor of any financial statements of such Cooperating Seller or its Affiliates with respect to the Assets that Buyer 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 Cooperating Seller and its Affiliates shall retain all books, records, information and documents relating to the Assets for the three fiscal years prior to January 1, 2016 and the period from January 1, 2016 through the Closing Date. Buyer will reimburse each Cooperating Seller and its Affiliates, within 10 Business Days after demand in writing therefor, for any and all reasonable out of pocket costs incurred by such Cooperating Seller and its Affiliates in complying with the provision of this Section 11.7.

ARTICLE XII
ACCESS; DISCLAIMERS

12.1 Access.

(a) From and after the Execution Date and up to and including the Closing Date (or earlier termination of this Agreement), but subject to the other provisions of this Section 12.1 and obtaining any required consents of Third Parties, including Third Party operators of the Assets (which consents Sellers shall use commercially reasonable efforts (which shall not require the payment of money) to obtain), (i) each Seller shall afford to Buyer and its officers, employees, agents, accountants, attorneys, investment bankers and other authorized representatives (“Buyer’s Representatives”) reasonable access, during normal business hours, to (x) such Seller’s employees (following prior notice to Clinton J. Kuzmich at RK Petroleum Corp.), (y) such Seller’s Assets, and (z) all Records in such Seller’s or its Affiliates’ possession, and (ii) each Seller shall permit Buyer’s Representatives to contact any purchaser of production from such Seller’s interest in the Assets that is directly remitting Burdens and Working Interest amounts on behalf of such Seller. All investigations and due diligence conducted by Buyer or any Buyer’s Representative shall be conducted at Buyer’s sole cost, risk and expense and any conclusions made from any examination done by Buyer or any Buyer’s Representative shall result from Buyer’s own independent review and judgment.

(b) Buyer shall be entitled to conduct a Phase I environmental property assessment with respect to the Assets. Seller’s Representatives or their designees shall have the right to accompany Buyer and Buyer’s Representatives whenever they are on site on the Assets and also to collect split test samples if any are collected. Notwithstanding anything herein to the contrary, Buyer shall not have access to, and shall not be permitted to conduct, any environmental due diligence (including any Phase I environmental property assessments) with respect to any Assets where Sellers do not have the authority to grant access for such due diligence (provided, however, Sellers shall use their commercially reasonable efforts (which shall not require the payment of money) to obtain permission from any Third Party to allow Buyer and Buyer’s Representatives such access).

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(c) Neither Buyer nor any Buyer’s Representative shall be entitled to conduct any sampling, boring, drilling or other invasive investigation activities (collectively, “Invasive Activities”) on or with respect to any of the Assets. If as a result of any Phase I environmental property assessment findings, Buyer’s Representative recommends to Buyer to conduct any Invasive Activities, Buyer shall notify the Seller’s Representatives of the affected Asset of such recommendation in writing. If any such Seller’s Representative does not consent to any such Invasive Activities proposed by Buyer with respect to a particular Asset or is unable to grant access to Buyer or its designee to conduct the recommended Invasive Activities requested by Buyer with respect to any Asset, Buyer shall have the right, in its sole and absolute discretion, to exclude such Asset affected thereby, and the Participating Purchase Price shall be reduced at Closing by the Allocated Value of such Asset so excluded.

(d) Buyer shall use its commercially reasonable efforts to coordinate its environmental property assessments and physical inspections of the Assets with Seller’s Representative and all Third Party operators to minimize any inconvenience to or interruption of the conduct of business by Sellers or such Third Party operators. Buyer shall abide by Seller’s Representative’s, and any Third Party operator’s, safety rules, regulations and operating policies of which Buyer has been made aware in writing while conducting its due diligence evaluation of the Assets, including any environmental or other inspection or assessment of the Assets. Except for those Liabilities that result from discovery of conditions or defects that already existed or with respect to the Assets prior to or at the time of such investigations, Buyer hereby agrees to defend, indemnify and hold harmless each of the operators of the Assets and the Seller Indemnified Parties from and against any and all Liabilities arising out of, resulting from or relating to any field visit, environmental property assessment, or other due diligence activity conducted by Buyer or any Buyer’s Representative 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 OF OR BY A MEMBER OF THE SELLER INDEMNIFIED PARTIES, EXCEPTING ONLY IN THE CASE OF THIS SECTION 12.1(d) (i) LIABILITIES ACTUALLY RESULTING ON THE ACCOUNT OF THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES AND (ii) LIABILITIES THAT WERE EXISTING PRIOR TO SUCH INSPECTIONS.

12.2 Confidentiality. Buyer acknowledges that, pursuant to its right of access to the Records and the Assets, Buyer will become privy to confidential and other information of Sellers and that such confidential information shall be held confidential by Buyer and Buyer’s Representatives in accordance with the terms of the Confidentiality Agreement. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including the Confidentiality Agreement, shall terminate (except as to (a) such portion of the Assets that are not conveyed to Buyer pursuant to the provisions of this Agreement, (b) the Excluded Assets and (c) information related to assets other than the Assets).

12.3 Disclaimers.

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(a) EXCEPT (i) AS EXPRESSLY SET FORTH IN ARTICLE IX OR IN ANY CERTIFICATE DELIVERED BY A SELLER AT CLOSING PURSUANT TO SECTION 4.1(c) OR (ii) WITH RESPECT TO THE SPECIAL WARRANTY CONTAINED IN EACH ASSIGNMENT (A) NO SELLER MAKES REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, (B) EACH SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO BUYER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING, ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF ANY SELLER OR ANY OF ITS AFFILIATES) AND (C) EACH SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY WITH REGARD TO OR ANY LIMITATIONS OR RESTRICTIONS UPON, THE LEGAL RIGHT, AUTHORITY OR ABILITY, IF ANY, OF SELLERS (OR BUYER) TO POOL, UNITIZE OR OTHERWISE COMBINE THE LANDS, LEASES, AND TRACTS TO FORM ANY HYPOTHETICAL DSU.

(b) EXCEPT (i) AS EXPRESSLY SET FORTH IN ARTICLE IX OR IN ANY CERTIFICATE DELIVERED BY A SELLER AT CLOSING PURSUANT TO SECTION 4.1(c) OR (ii) WITH RESPECT TO THE SPECIAL WARRANTY CONTAINED IN EACH ASSIGNMENT, EACH SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (A) TITLE TO ANY OF THE ASSETS, (B) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (C) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (D) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (E) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (F) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (G) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY ANY SELLER OR ANY OTHER PERSON (INCLUDING THIRD PARTIES) WITH RESPECT TO THE ASSETS, (H) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, (I) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT AND (J) THE ABILITY OR INABILITY TO CREATE OR FORM ANY HYPOTHETICAL DSU OR THE APPROPRIATENESS THEREOF.

(c) EXCEPT (i) AS EXPRESSLY SET FORTH IN ARTICLE IX OR IN ANY CERTIFICATE DELIVERED BY A SELLER AT CLOSING PURSUANT TO SECTION 4.1(c) OR (ii) WITH RESPECT TO THE SPECIAL WARRANTY CONTAINED IN EACH ASSIGNMENT, EACH SELLER FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM

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FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF THE ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT BUYER SHALL BE DEEMED TO BE OBTAINING THE PERSONAL PROPERTY IN ITS PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS OF THE PERSONAL PROPERTY AS BUYER DEEMS APPROPRIATE.

(d) EXCEPT AS EXPRESSLY SET FORTH IN SECTION 9.14 OR IN ANY CERTIFICATE DELIVERED BY A SELLER AT CLOSING PURSUANT TO SECTION 4.1(c), BUT WITHOUT PREJUDICE TO SELLERS’ INDEMNITY OBLIGATIONS UNDER SECTION 8.2 AND THE RIGHT OF BUYER INDEMNIFIED PARTIES TO BE INDEMNIFIED PURSUANT TO SECTION 8.2, NO SELLER HAS AND NO SELLER WILL MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF HAZARDOUS SUBSTANCES 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 SUBJECT TO BUYER’S LIMITED RIGHTS AS EXPRESSLY SPECIFIED IN THIS AGREEMENT FOR A BREACH OF ANY SELLER’S REPRESENTATIONS SET FORTH IN SECTION 9.14 OR IN ANY CERTIFICATE DELIVERED BY A SELLER AT CLOSING PURSUANT TO SECTION 4.1(c), BUT WITHOUT PREJUDICE TO SELLERS’ INDEMNITY OBLIGATIONS UNDER SECTION 8.2 AND THE RIGHT OF BUYER INDEMNIFIED PARTIES TO BE INDEMNIFIED PURSUANT TO SECTION 8.2, BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER WILL MAKE OR CAUSE TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS OF THE ASSETS AS BUYER DEEMS APPROPRIATE.

(e) SELLERS AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 12.3 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY APPLICABLE LAW.

ARTICLE XIII
TITLE MATTERS; CASUALTY; TRANSFER RESTRICTIONS

13.1 Sellers’ Title.

(a) General Disclaimer of Title Warranties and Representations. Without limiting Buyer’s remedies for Title Defects set forth in this Article XIII, except as set forth in Section 13.1(b), no Seller makes any warranty or representation, express, implied, statutory or otherwise, with respect to title to any of the Assets, Tracts and Hypothetical DSUs and, Buyer acknowledges

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and agrees that Buyer’s sole remedy for any defect of title, including any Title Defect, with respect to any of the Assets (i) before Closing, shall be as set forth in Section 13.2, and (ii) after Closing, shall be pursuant to (A) the special warranty of title to the Wells, Leases, Tracts, Rights-of-Way and Personal Property contained in the Assignment, and (B) Buyer’s rights under Section 8.2(b) with respect to a breach of Section 11.1(b)(iv) or Section 13.4. For the avoidance of doubt and notwithstanding anything to the contrary contained in this Agreement or in the Assignment, after Closing, if an applicable Seller or Seller’s Representative demonstrates that Buyer received, pursuant to the Assignments (1) an aggregate Net Revenue Interest equal to the aggregate Net Revenue Interests of all Sellers for each Target Formation in each Well or Tract as set forth in Exhibits A-1 and A-2, (2) an aggregate Working Interest equal to the aggregate Working Interests of all Sellers for each Target Formation in each Well or Tract as set forth in Exhibits A-1 and A-2, and (3) an aggregate number of Net Acres equal to the aggregate number of Net Acres of all Sellers in each Target Formation in each Tract as set forth in Exhibit A-2, then in no event shall Buyer have any remedy under clause (ii)(A) with respect to any claim related to a Net Revenue Interest, Working Interest or Net Acre deficiency.

(b) Special Warranty of Defensible Title. Each Assignment delivered at Closing will contain a special warranty of Defensible Title as to such Seller’s interest in the Wells, Leases, Tracts, Rights-of-Way and Personal Property by the applicable Seller, subject, however, to the Permitted Encumbrances; provided, however, no Seller makes, and the Assignments delivered at Closing will not contain, any warranty of Defensible Title as to the Hypothetical DSUs. For the avoidance of doubt, any claim by Buyer under each Seller’s special warranty of Defensible Title in the applicable Assignment shall not be subject to the Individual Title Threshold or the Title Defect Deductible but shall not exceed the Allocated Value of the affected Asset and any claims for such breach must be asserted within the applicable statute of limitations. Any such claims not asserted within the applicable statute of limitations shall be deemed to be Assumed Obligations.

13.2 Notice of Title Defects; Defect Adjustments.

(a) Title Defect Notices. Buyer must deliver (which delivery may be by email), on or before 5:00 p.m. (Prevailing Central Time) on August 29, 2016 (the “Title Claim Date”), claim notices to Seller’s Representatives meeting the requirements of this Section 13.2(a) (collectively the “Title Defect Notices” and individually a “Title Defect Notice”) setting forth any matters which, in Buyer’s reasonable opinion, constitute Title Defects and which Buyer intends to assert as a Title Defect pursuant to this Section 13.2. For all purposes of this Agreement and notwithstanding anything herein to the contrary (except for the remedies expressly discussed in Section 13.1), Buyer shall be deemed to have waived, and no Seller shall have any liability for, any Title Defect that Buyer fails to assert as a Title Defect by a Title Defect Notice received by Seller’s Representative on or before the Title Claim Date. To be effective, each Title Defect Notice shall be in writing and shall include (i) a description of the alleged Title Defect and a description of the Asset and/or associated Tract or Hypothetical DSU, or any portion thereof, affected by such Title Defect (each a “Title Defect Property”), (ii) the Allocated Value of each Title Defect Property, (iii) supporting documents (which may be furnished via access to a web link or ftp site), to the extent in Buyer’s, its Affiliate’s, or its Third Party contractor’s possession, reasonably necessary for Seller’s Representative to verify the existence of such Title Defect, (iv) the amount by which Buyer reasonably believes the Allocated Value of each Title Defect Property is reduced by such Title Defect

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and the computations upon which Buyer’s belief is based, and (v) if applicable, each Seller whose interest is affected by such Title Defect; provided, however, that an alleged failure to comply with subsections (i) through (v) above shall not cause any such Title Defect Notice to be invalid or any Title Defect to be waived if the defect notice is reasonably sufficient to provide notice to Seller’s Representative of the existence and nature of the alleged Title Defect.

(b) Title Benefit Notices. If Buyer discovers any Title Benefit, it shall promptly deliver notice to Seller’s Representatives prior to the Title Claim Date. Seller’s Representatives shall have the right, but not the obligation, to deliver to Buyer on or before a time that is at least 24 hours prior to the Title Claim Date with respect to each Title Benefit a notice (a “Title Benefit Notice”) including (i) a description of the alleged Title Benefit and a description of the Asset and/or associated Tract or Hypothetical DSU, or portion thereof, affected by such Title Benefit (each a “Title Benefit Property”), (ii) the Allocated Value of each such Title Benefit Property, (iii) supporting documents, to the extent in Sellers’, its Affiliate’s, or its Third Party contractor’s possession, reasonably necessary for Buyer to verify the existence of such Title Benefit, (iv) the amount by which Seller’s Representatives reasonably believe the Allocated Value of such Title Benefit Property is increased by the Title Benefit and the computations upon which Seller’s Representatives’ belief is based, and (v) if applicable, each Seller whose interest is affected by such Title Benefit.

(c) Sellers’ Right to Cure. Subject to the terms of Section 13.2(d), the Sellers shall have the right, but not the obligation, to attempt, at the sole cost of such Sellers, to cure at any time prior to the end of the 60 days following Closing (the “Cure Period”) any Title Defects of which the Sellers have been advised by Buyer or a Seller’s Representative. Should any such Seller wish to attempt to cure any such Title Defect following Closing during the Cure Period, Seller’s Representatives must deliver written notice to Buyer of such election on or before the date that is five Business Days prior to Closing. At Closing, the Participating Purchase Price will be reduced by the Allocated Value of each Title Defect Property for which Seller’s Representative has provided such notice to Buyer. Such Title Defect Properties will not be conveyed by any such Seller to Buyer on the Closing Date. Should such Sellers cure the applicable Title Defects to Buyer’s reasonable satisfaction during the Cure Period, then, within 10 Business Days after such Title Defects are cured to Buyer’s reasonable satisfaction, such Title Defect Properties will be purchased by Buyer and sold by such Seller(s) for a price equal to the Allocated Value of such Title Defect Properties that was removed from the Participating Purchase Price at Closing (as such Allocated Value may be adjusted as provided in this Agreement), with the conveyance of the applicable Title Defect Properties being made pursuant to an Assignment. Should the Parties dispute whether such Title Defect was, in fact, cured during the Cure Period, the provisions of Section 13.2(k) shall govern and control such dispute.

(d) Remedies for Title Defects. Subject to Seller’s Representatives’ right to dispute the existence of a Title Defect and/or the Title Defect Amount asserted with respect thereto prior to the Closing Date and subject to the rights of the Parties pursuant to Section 7.1(f), in the event that any Title Defect timely asserted by Buyer in accordance with Section 13.2(a) is not waived in writing by Buyer or cured on or before Closing, then, subject to the Individual Title Threshold and the Title Defect Deductible:

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(i) Buyer may reduce the Participating Purchase Price by the Title Defect Amount (as determined pursuant to Section 13.2(g) or Section 13.2(k)); or

(ii) solely in instances in which the Title Defect Amount exceeds 50% of the Allocated Value of the applicable Title Defect Property, Buyer or the Seller’s Representatives may cause the applicable Sellers to retain their respective interests in the entirety of such Title Defect Property and all associated Assets, in which event the Participating Purchase Price shall be reduced by an amount equal to the Allocated Value of such Title Defect Property, and such Title Defect Property and associated Assets will constitute “Excluded Assets” for all purposes of this Agreement;

(iii) in the event either remedy set forth above is implemented, then the Sellers acknowledge and agree that, only for purposes of allocation and distribution by the Seller’s Representatives of the Participating Purchase Price (as adjusted pursuant to this Agreement) among the Sellers, any reduction of the Participating Purchase Price shall be applied in the following manner: (A) first (1) if only one Seller’s interest resulted in the Title Defect, against the individual Seller’s interest in the Title Defect Property, or (2) if more than one Seller’s interest resulted in the Title Defect, against such Sellers’ interests in the Title Defect Property on a pro rata basis based on each such Seller’s respective Allocated Value in the Title Defect Property; (B) second, to the extent the reduction of the Participating Purchase Price (as adjusted pursuant to this Agreement) is not satisfied by the preceding clause (A) above, against such Seller’s (or Sellers’, as applicable) interest(s) in all other Assets, Tracts, or Hypothetical DSUs, including any Title Benefits that are applicable to such Seller(s) in any other Assets, Tracts, or Hypothetical DSUs; and (C) third, to the extent the reduction of the Participating Purchase Price (as adjusted pursuant to this Agreement) is not satisfied by the preceding clauses (A) and (B) above, against the other Sellers’ interests in the Title Defect Property, on a pro rata basis based on each such Seller’s respective Allocated Value in the Title Defect Property.

(e) Remedies for Title Benefits. With respect to each Title Benefit Property affected by Title Benefits reported under Section 13.2(b), as Sellers’ sole and exclusive remedies for any Title Benefits, the amount (the “Title Benefit Amount”) equal to the increase in the Allocated Value for such Asset caused by such Title Benefits, as determined pursuant to Section 13.2(h) or Section 13.2(k), shall, if and only if such Title Benefit Amount is greater than the Individual Title Threshold, be applied as to offset the aggregate Title Defect Amounts attributable to Title Defects pursuant to Section 13.2(i).

(f) Exclusive Remedy. Except for Buyer’s rights (i) under the special warranty of title to the Wells, Leases, Tracts, Rights-of-Way and Personal Property contained in each Assignment, (ii) to terminate this Agreement pursuant to Section 7.1(f), and (iii) under Section 8.2(b) with respect to a breach of Section 11.1(b)(iv) or Section 13.4, the provisions set forth in Section 13.2(d) and Section 13.2(k) shall be the sole and exclusive right and remedy of Buyer with respect to any Seller’s failure to have Defensible Title with respect to any Asset.

(g) Title Defect Amount. The amount by which the Allocated Value of the affected Title Defect Property is reduced as a result of the existence of a Title Defect shall be the

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“Title Defect Amount” and shall be determined in accordance with the following terms and conditions:

(i) if Buyer and Seller’s Representatives agree on the Title Defect Amount, then that amount shall be the Title Defect Amount;

(ii) if the Title Defect is an Encumbrance 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 Title Defect Property;

(iii) if (A) the Title Defect represents a discrepancy between (1) any Seller’s Net Revenue Interest with respect to any Target Formation for any Tract, Hypothetical DSU or Well and (2) such Seller’s Net Revenue Interest with respect to such Target Formation for such Tract, Hypothetical DSU or Well as set forth in Exhibits A-2 or A-1, as applicable, (B) such Seller’s Working Interest with respect to such Target Formation for such Tract, Hypothetical DSU or Well is less than such Seller’s Working Interest with respect to such Target Formation for such Tract, Hypothetical DSU or Well as set forth in Exhibits A-2 or A-1, as applicable, in the same proportion to such Net Revenue Interest decrease, and (C) such Title Defect does not have an adverse impact on the Allocated Value of such Tract or Hypothetical DSU, as addressed in Section 13.2(g)(x) below, then the Title Defect Amount shall be the product of (x) the Allocated Value of such Title Defect Property, multiplied by (y) a fraction, the (I) numerator of which is the Net Revenue Interest decrease with respect to such Target Formation for such Tract, Hypothetical DSU or Well, and (II) denominator of which is the Net Revenue Interest with respect to such Target Formation for such Tract, Hypothetical DSU or Well as set forth in Exhibits A-2 or A-1, as applicable;

(iv) if (A) the Title Defect for any Tract or Hypothetical DSU is the actual failure of a Seller to own the represented Net Acres with respect to any Target Formation for such Tract or Hypothetical DSU as shown under the column titled “Seller Net Acres” on Exhibit A-2, as applicable, throughout the duration of the productive life of such Tract or Hypothetical DSU, and (B) such Title Defect does not have an adverse impact on the Allocated Value of the remainder of such Tract or Hypothetical DSU, as addressed in Section 13.2(g)(x) below, then the Title Defect Amount will be the product of (x) the Allocated Value of such Title Defect Property, multiplied by (y) a fraction, the (I) numerator of which is the positive difference between the (a) Net Acres with respect to such Target Formation for such Tract or Hypothetical DSU as shown under the column titled “Seller Net Acres” on Exhibit A-2, as applicable, and (b) actual Net Acres held by such Seller with respect to such Target Formation for such Tract or Hypothetical DSU, and (II) denominator of which is the Net Acres with respect to such Target Formation for such Tract or Hypothetical DSU as shown under the column titled “Seller Net Acres” on Exhibit A-2, as applicable;

(v) if the Title Defect represents an obligation, Encumbrance upon or other defect in title to the Title Defect Property of a type not described above, then 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 affected by the Title Defect, the legal effect of the Title Defect, the reasonably anticipated economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by

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Buyer and Seller’s Representatives, any effect (whether an increase or decrease) on the value of the remainder of the affected Title Defect Property or the remainder of the Assets that may be occasioned as a result of any (A) impairment on the ability to form a Hypothetical DSU (or other pooled unit) or drill a horizontal well or wells across a particular Tract or Hypothetical DSU (or other pooled unit), or (B) economic impact with respect to forming a Hypothetical DSU (or other pooled unit) or drilling a horizontal well or wells across a particular Tract or Hypothetical DSU (or other pooled unit), and such other reasonable factors as are customarily utilized in the oil and gas industry to make a proper evaluation; provided, however, that if such Title Defect is reasonably capable of being cured, the Title Defect Amount shall not be greater than the reasonable cost and expense of curing such Title Defect;

(vi) the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder;

(vii) if a Title Defect does not affect a Title Defect Property throughout the entire remaining productive life of such Title Defect Property, such fact shall be taken into account in determining the Title Defect Amount;

(viii) for purposes of Section 13.2(i) only, all Title Defects with respect to any Well, Hypothetical DSU or Tract that are attributable to (A) the interests of more than one Seller hereunder, or (B) more than one Target Formation shall, in each case, all be aggregated together for purposes of determining the Title Defect Amount with respect to the applicable Title Defect Property;

(ix) notwithstanding anything to the contrary in this Article XIII, if a Title Defect results in a Seller not having Defensible Title to a Tract as well as any corresponding Hypothetical DSU, the Participating Purchase Price shall be reduced only one time with respect to either the Tract or the Hypothetical DSU and in no event shall Buyer be entitled to claim a Title Defect Amount with respect to both a Tract and a Hypothetical DSU for such Title Defect;

(x) notwithstanding anything to the contrary in this Agreement, a Title Defect related to the interest of a single Seller in a Title Defect Property may have an adverse impact on the remainder of the Allocated Value of such Title Defect Property, including if such Title Defect (A) impairs the ability to form a Hypothetical DSU (or other pooled unit) for the drilling of horizontal wells across a Tract or Hypothetical DSU (or other pooled unit), (B) impairs the drilling of horizontal wells across a Hypothetical DSU (or other pooled unit), or (C) has an adverse effect on the economics of drilling horizontal wells across a Tract or Hypothetical DSU (or other pooled unit), in which case the applicable Title Defect Amount with respect to such Title Defect shall be determined pursuant to Section 13.2(g)(v); and

(xi) notwithstanding anything to the contrary in this Article XIII, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any single Title Defect Property shall not exceed the Allocated Value of such Title Defect Property and no Title Defect Amount shall be asserted by Buyer with respect to any Well, Tract or

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Hypothetical DSU except as to (A) presently producing formations in any Well, or (B) the Target Formations in any Well, Tract or Hypothetical DSU.

(h) Title Benefit Amount. The Title Benefit Amount resulting from a Title Benefit shall be determined in accordance with the following methodology, terms and conditions:

(i) if Buyer and Seller’s Representatives agree on the Title Benefit Amount, then that amount shall be the Title Benefit Amount;

(ii) if (A) the Title Benefit represents a discrepancy between (1) any Seller’s Net Revenue Interest with respect to any Target Formation for any Tract, Hypothetical DSU or Well and (2) such Seller’s Net Revenue Interest with respect to such Target Formation for such Tract, Hypothetical DSU or Well as set forth in Exhibits A-2 or A-1, as applicable, and (B) such Seller’s Working Interest with respect to such Target Formation for such Tract, Hypothetical DSU or Well is greater than such Seller’s Working Interest with respect to such Target Formation for such Tract, Hypothetical DSU or Well as set forth in Exhibits A-2 or A-1, as applicable, in the same proportion to such Net Revenue Interest decrease, then the Title Benefit Amount shall be the product of (1) the Allocated Value of such Title Benefit Property, multiplied by (2) a fraction, the (x) numerator of which is the Net Revenue Interest decrease with respect to such Target Formation for such Tract, Hypothetical DSU or Well, and (y) denominator of which is the Net Revenue Interest with respect to such Target Formation for such Tract, Hypothetical DSU or Well as set forth in Exhibits A-2 or A-1, as applicable; and

(iii) if the Title Benefit is of a type not described above, then the Title Benefit Amounts shall be determined by taking into account the Allocated Value of the Title Benefit Property, the portion of the Title Benefit Property affected by such 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 Buyer and Seller’s Representatives and such other reasonable factors as are necessary to make a proper evaluation.

(i) Title Thresholds and Deductible. Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Participating Purchase Price or other remedies provided by any Seller for any individual Title Defect or any individual Title Benefit for which the Title Defect Amount or the Title Benefit Amount, as applicable, does not exceed $25,000 (such amount “Individual Title Threshold”); and (ii) in no event shall there be any adjustments to the Participating Purchase Price or other remedies provided by any Seller for any Title Defect that exceeds the Individual Title Threshold unless (A) the difference of (1) the total Title Defect Amounts of all such Title Defects that exceed the Individual Title Threshold (excluding any Title Defects cured by the applicable Seller to Buyer’s reasonable satisfaction prior to Closing), minus (2) the Title Benefit Amounts of all Title Benefits that exceed the Individual Title Threshold, exceeds (B) the Title Defect Deductible, whereupon Buyer shall be entitled to adjustments to the Participating Purchase Price or other remedies only with respect to the Title Defect Amounts in excess of the aggregate Title Defect Deductible.

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(j) Exceptions to Individual Title Threshold and Title Defect Deductible. Notwithstanding anything in this Agreement to the contrary, the Individual Title Threshold and Title Defect Deductible shall not apply to:

(i) any Title Defect that results from (whether in whole or in part) the existence of any Retained Burden; and

(ii) any Title Defects and Title Benefits that (A) affect the same Title Defect Property (whether one or more Sellers are affected by such Title Defects and/or Title Benefits), but only to the extent such Title Defects and Title Benefits affect the same Title Defect Property, and (B) the applicable Seller or Seller’s Representative demonstrates will not collectively cause Buyer to receive (1) an aggregate Net Revenue Interest less than the aggregate Net Revenue Interests of all Sellers for each Target Formation in the applicable Title Defect Property as set forth in Exhibits A-1 or A-2, as applicable, (2) an aggregate Working Interest greater than the aggregate Working Interests of all Sellers for each Target Formation in the applicable Title Defect Property as set forth in Exhibits A-1 or A-2, as applicable, and (3) an aggregate number of Net Acres less than the aggregate number of Net Acres of all Sellers in each Target Formation in the applicable Title Defect Property as set forth in Exhibit A-2.

(k) Title Dispute Resolution. Such Seller’s Representatives and Buyer shall attempt to agree on (i) all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts prior to Closing and (ii) the efficacy of any attempted cure of a Title Defect promptly upon the expiration of the Cure Period. If such Seller’s Representatives and Buyer are unable to so agree, the Title Defects, Title Benefits, Title Defect Amounts, Title Benefit Amounts or cure in dispute shall be exclusively and finally resolved pursuant to this Section 13.2(k). There shall be a single arbitrator, who shall be a title attorney licensed in the State of Texas with at least 10 years’ experience in oil and gas titles involving properties in the regional area in which the Title Defect Properties are located, as selected by mutual agreement of Buyer and such Seller’s Representatives within 15 days after the end of the Cure Period (the “Title Arbitrator”). In the event the Parties are unable to mutually agree upon the Title Arbitrator within such time period, then such Seller’s Representatives on the one hand and Buyer on the other hand shall each nominate a candidate to be the Title Arbitrator, and such candidates so nominated by the Parties shall together determine the Title Arbitrator. Such Seller’s Representatives and the Buyer shall each present to the Title Arbitrator, with a simultaneous copy to the other party, a single written statement of its position on the defect or benefit in question, together with a copy of this Agreement and any supporting material that such Party desires to furnish, not later than the 10^th Business Day after appointment of the Title Arbitrator. In making the determination, the Title Arbitrator, unless the Title Arbitrator requests additional information from either party, shall make a determination of the matter submitted based solely on the single written submission of such Seller’s Representative and Buyer and shall be bound by the terms of this Agreement. Provided, however, the Title Arbitrator may consider available legal and industry matters as in the Title Arbitrator’s opinion are necessary or appropriate to make a proper determination. The Title Arbitrator’s determination shall be made within 20 Business Days after submission of the matters in dispute and shall be final and binding upon all Parties, without right of appeal. The Title Arbitrator, however, may not award the Buyer a greater Title Defect Amount than the Title Defect Amount claimed by Buyer in its applicable Title Defect Notice or

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Sellers a greater Title Benefit Amount than the Title Benefit Amount claimed by such Seller’s Representative in its applicable Title Benefit Notice. The Title Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Title Defect, Title Benefit, Title Defect Amounts, Title Benefit Amounts and/or cure efforts submitted by either party and may not award damages, interest or penalties to either party with respect to any matter. The applicable Sellers and Buyer shall bear their own legal fees and other costs of presenting its case. The Seller’s Representatives, on the one hand, and Buyer, on the other hand, shall each bear one-half of the costs and expenses of the Title Arbitrator. To the extent that the award of the Title Arbitrator with respect to any Title Defect Amount or Title Benefit Amount is not taken into account as an adjustment to the Participating Purchase Price pursuant to Section 3.4 or Section 3.5, then within 10 days after the Title Arbitrator delivers written notice to Buyer and Seller’s Representatives of his award with respect to a Title Defect Amount or a Title Benefit Amount (and subject to Section 13.2(k)), (A) Buyer shall pay to such Seller’s Representative the amount, if any, so awarded by the Title Arbitrator to Sellers, and (B) such Sellers (severally and not jointly) shall pay to Buyer the amount, if any, so awarded by the Title Arbitrator to Buyer. For the avoidance of doubt, no amounts owing under this Section 13.2(k) by such Sellers to Buyer shall be paid from the Indemnity Escrow. Nothing herein shall operate to cause the Closing to be delayed on account of any arbitration hereunder and to the extent any adjustments are not agreed upon by the Parties as of the Closing, the Participating Purchase Price shall be adjusted therefor as of the Closing by an amount that is equal to the average of (1) the Title Defect Amount claimed in good faith by the Seller’s Representatives and (2) the Title Defect Amount claimed in good faith by Buyer, and subsequent adjustments thereto, if any, will be made pursuant to Section 3.5 or this Section 13.2(k).

13.3 Casualty Loss. If, after the Execution Date but prior to the Closing Date, any portion of the Assets is destroyed by fire or other casualty or is taken in condemnation or under right of eminent domain (each, a “Casualty Loss”), then (a) subject to the Parties’ rights pursuant to Section 7.1(f), Buyer shall nevertheless be required to close, (b) each Seller, at the Closing, shall (i) pay to Buyer all sums actually paid to such Seller by Third Parties by reason of such Casualty Loss insofar as with respect to such Assets and (ii) assign, transfer and set over to Buyer or subrogate Buyer to all of such Sellers’ right, title and interest (if any) in insurance claims, rights to compensation under condemnation or eminent domain, unpaid awards and other rights against Third Parties (excluding any Liabilities, other than insurance claims, of or against any such Seller’s Seller Indemnified Parties) arising out of such Casualty Loss insofar as with respect to the Assets, and (c) the Participating Purchase Price shall be adjusted downward to the extent, if any, that such sums and such rights are not sufficient to cover the entire amount of such Casualty Loss; provided, however, that each Seller shall reserve and retain (and Buyer shall assign to each Seller) all rights, title, interests and claims against Third Parties for the recovery of such Seller’s costs and expenses incurred prior to the Closing in pursuing or asserting any such insurance claims or other rights against Third Parties with respect to any such Casualty Loss.

13.4 Consents to Assign and Preferential Purchase Rights.

(a) Seller’s Representatives, within 10 days after the Election Deadline, shall send to each holder of a (i) right to consent to assignment pertaining to the Assets and the transactions contemplated hereby a notice seeking such holder’s consent to the transactions contemplated hereby,

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and (ii) Preferential Purchase Right notice in accordance with the agreement giving rise to such right informing such holder of the transactions contemplated hereby.

(b) If any Seller (or Seller’s Representatives on its behalf) fails to obtain a Hard Consent applicable to any of its Asset(s) prior to the Closing or any consent request is rejected in writing by the holder thereof, then, in each such case, the affected Asset(s) shall be excluded from the Assets to be acquired by Buyer at Closing hereunder and the Participating Purchase Price shall be reduced by the Allocated Value of the Asset(s) so excluded (which, for the avoidance of doubt, shall affect only the impacted Seller(s)). In the event that any such consent (with respect to any applicable Asset(s) excluded pursuant to this Section 13.4(b)) that was not obtained prior to Closing is obtained within 180 days following Closing, then, Buyer shall purchase from such affected Seller(s), within 10 days after such consent is obtained, such Asset(s) so excluded under the terms of this Agreement for the amount by which the Participating Purchase Price was reduced at Closing due to the exclusion of such Asset(s) (as such amount is appropriately adjusted in accordance to Section 3.3 with respect to such Asset(s)), and such Seller shall assign to Buyer such Asset(s) pursuant to an assignment in the form of the Assignment and shall be entitled to receipt of such payment.

(c) If any Seller (or Seller’s Representatives on its behalf) fails to obtain a consent prior to the Closing and (i) such consent is not a Hard Consent and (ii) such consent was not rejected in writing by the holder thereof, then the Asset(s) subject to such un-obtained consent shall be acquired by Buyer at Closing as part of the Assets.

(d) If any Preferential Purchase Right is exercised prior to the Closing Date, or if the time frame for the exercise of such Preferential Purchase Right has not expired as of the Closing Date and the applicable Seller (or Seller’s Representatives on its behalf) has not received a written waiver of the Preferential Purchase Right, then that portion of the Assets affected by such Preferential Purchase Right shall be excluded from the Assets at Closing and the Participating Purchase Price shall be adjusted downward by an amount equal to the Allocated Value of such affected Assets (which, for the avoidance of doubt, shall only impact the affected Seller(s)).

(e) If a Third Party exercises its Preferential Purchase Right, but does not consummate the applicable transaction within the time frame specified in the Preferential Purchase Right (provided that the reason therefor is not such Seller’s default), such Seller agrees to convey its interest in the affected Asset to Buyer as soon as possible after the expiration of the time for consummation of the applicable transaction by the holder of the Preferential Purchase Right (provided that the same occurs within 180 days following Closing), such conveyance to be effective as of the Effective Time, and Buyer agrees to pay the applicable Seller’s Representatives on behalf of such Seller(s) the Allocated Value of the affected Asset (as adjusted in accordance with Section 3.3 to reflect such conveyance being made as of the Effective Time).

(f) If a Preferential Purchase Right is not discovered prior to Closing, and the affected Asset is conveyed to Buyer at Closing, and the Preferential Purchase Right is exercised after Closing, Buyer agrees to convey such affected Asset to the Third Party exercising such right on the same terms and conditions under which such Seller(s) conveyed such Asset to Buyer (with the purchase price being the Allocated Value for the affected Asset as adjusted pursuant to Section 3.3 and such other adjustments as may be permitted to reflect any other post-Closing expenditures Buyer has made with respect to such Asset) and Buyer shall retain all amounts paid by the party

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exercising such Preferential Purchase Right. In the event of such exercise, Buyer shall prepare, execute and deliver a form of conveyance of such Asset to such exercising party, such conveyance to be in form and substance as provided in this Agreement.

ARTICLE XIV
ENVIRONMENTAL MATTERS

14.1 Notice of Environmental Defects.

(a) Environmental Defect Notices. If Buyer discovers any Environmental Condition which, in its reasonable opinion, Buyer determines constitutes an Environmental Defect, Buyer shall notify Seller’s Representatives on or before 5:00 p.m. (Prevailing Central Time) on August 29, 2016 (the “Environmental Claim Date”) of such Environmental Defect (an “Environmental Defect Notice”). An Environmental Defect Notice shall be in writing and shall include (i) a description of the Environmental Condition constituting the asserted Environmental Defect(s), (ii) the Asset(s) (or portions thereof) affected by the asserted Environmental Defect (each, an “Environmental Defect Property”), (iii) documentation, including any physical measurements or, to the extent permitted by Seller’s Representatives under Section 12.1, lab analyses or photographs, sufficient for Seller’s Representatives to verify the existence of the asserted Environmental Defect(s), in each case, to the extent in Buyer’s, its Affiliate’s, or its Third Party contractor’s possession, (iv) the Allocated Value of each Environmental Defect Property, (v) the Remediation Amount (itemized in reasonable detail) that Buyer asserts is attributable to such Environmental Defect and the computations and information upon which Buyer’s belief is based; provided, however, that an alleged failure to comply with subsections (i) through (v) above shall not cause any such Environmental Defect Notice to be invalid or any Environmental Defect to be waived if the defect notice is reasonably sufficient to provide notice to Seller’s Representatives of the existence and general nature of the alleged Environmental Defect. Buyer’s calculation of the Remediation Amount included in the Environmental Defect Notice must describe in reasonable detail the Remediation proposed for the Environmental Condition that gives rise to the asserted Environmental Defect and identify assumptions used by the Buyer in calculating the Remediation Amount. For all purposes of this Agreement but subject to Buyer’s remedy for a breach of Sellers’ representation contained in Section 9.14, Buyer shall be deemed to have waived, and Sellers shall have no liability for, any Environmental Defect which Buyer fails to assert as an Environmental Defect by an Environmental Defect Notice received by Seller’s Representatives on or before the Environmental Claim Date. Sellers shall have the right, but not the obligation, to cure any asserted Environmental Defect to Buyer’s reasonable satisfaction on or before Closing.

(b) Sellers’ Right to Cure. Subject to the terms of Section 14.1(c), the Sellers shall have the right, but not the obligation, to attempt, at the sole cost of such Sellers, to cure at any time prior to the end of the Cure Period any Environmental Defects of which the Sellers or a Seller’s Representative have been advised by Buyer in a timely Environmental Defect Notice. Should any such Seller wish to attempt to cure any such Environmental Defect following Closing during the Cure Period, Seller’s Representatives must deliver written notice to Buyer of such election on or before the date that is five Business Days prior to Closing. At Closing, the Participating Purchase Price will be reduced by the Allocated Value of each Environmental Defect Property for which Seller’s Representative has provided such notice to Buyer. Such Title Defect Properties will not

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be conveyed by any such Seller to Buyer on the Closing Date. Should such Sellers cure the applicable Environmental Defects to Buyer’s reasonable satisfaction during the Cure Period, then, within 10 Business Days after such Environmental Defects are cured to Buyer’s reasonable satisfaction, such Environmental Defect Properties will be purchased by Buyer and sold by such Seller(s) for a price equal to the Allocated Value of such Environmental Defect Properties that were removed from the Participating Purchase Price at Closing (as such Allocated Value may be adjusted as provided in this Agreement), with the conveyance of the applicable Environmental Defect Properties being made pursuant to an Assignment. Should the Parties dispute whether such Environmental Defect was, in fact, cured during the Cure Period, the provisions of Section 14.1(f) shall govern and control such dispute.

(c) Remedies for Environmental Defects. Subject to the Seller’s Representatives’ right to dispute the existence of an Environmental Defect and/or the Remediation Amount asserted with respect thereto prior to the Closing Date, and subject to the rights of the Parties pursuant to Section 7.1(f), in the event that any Environmental Defect timely asserted by Buyer in accordance with Section 14.1(a) is not waived in writing by Buyer or cured on or before Closing, then, subject to the Individual Environmental Defect Threshold and the Environmental Defect Deductible, Buyer shall, at its sole option, elect to:

(i) reduce the Participating Purchase Price by the Remediation Amount, which reduction, for purposes of allocation and distribution of the Participating Purchase Price among Sellers, shall be applied against the affected individual Seller’s interest if less than all Sellers are affected by such Environmental Defect;

(ii) cause the applicable Sellers to assume responsibility for the Remediation of such Environmental Defect and complete the Remediation with respect to the affected Assets to Buyer’s reasonable satisfaction; or

(iii) solely in instances in which the Remediation Amount exceeds 50% of the Allocated Value of the Environmental Defect Property, cause the applicable Sellers to retain their respective interests in the entirety of such Environmental Defect Property and all associated Assets, in which event the Participating Purchase Price shall be reduced by an amount equal to the Allocated Value of such Environmental Defect Property, which reduction, for purposes of allocation and distribution of the Participating Purchase Price among Sellers, shall be applied against the affected individual Seller’s interest if less than all Sellers are affected by such Environmental Defect, and such Environmental Defect Property and associated Assets will constitute “Excluded Assets” for all purposes of this Agreement.

If Buyer elects the option set forth in clause (i) above, Buyer shall be deemed to have assumed responsibility for all of the costs and expenses attributable to the Remediation of the Environmental Condition attributable to such Environmental Defect and such responsibility of Buyer shall be deemed to constitute part of the Assumed Obligations hereunder. If Buyer elects the option set forth in clause (ii) above, the affected Sellers shall use reasonable efforts to implement such Remediation in a manner which is consistent with the requirements of Environmental Laws in a timely fashion for the type of Remediation that Seller’s Representatives and Buyer agree that Sellers will undertake and Buyer, effective as of the Closing, grants to Seller’s Representatives, access to the to conduct such Remediation. Notwithstanding anything in this Agreement to the contrary, in those instances

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in which Buyer’s request to conduct invasive investigations of certain Assets made under Section 12.1(c) is denied by Seller’s Representatives and Buyer elects to withdraw the affected Assets from the purchase and sale under this Agreement and such Assets as a consequence are deemed Excluded Assets pursuant to Section 12.1(c), the Participating Purchase Price shall be reduced by the aggregate amount of the Allocated Values of such Assets (which, for the avoidance of doubt, shall only impact the affected Seller(s)) pursuant to Section 3.3(b)(iv) and such Sellers shall have no option to pursue any other remedy with respect to same.

(d) Exclusive Remedy. Except as provided in Section 8.2(a) for a breach of such Seller’s representations and warranties set forth in Section 9.14 and Buyer’s rights to terminate this Agreement pursuant to Section 7.1(f), the provisions set forth in Section 14.1(c) and Section 14.1(f) shall be the exclusive right and remedy of Buyer with respect to any Environmental Defect with respect to any Asset.

(e) Environmental Thresholds and Deductible. Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Participating Purchase Price or other remedies provided by any Sellers for any individual Environmental Defect for which the Remediation Amount does not exceed $50,000 (such amount “Individual Environmental Defect Threshold”); and (ii) in no event shall there be any adjustments to the Participating Purchase Price or other remedies provided by any Seller for any Environmental Defect for which the Remediation Amount exceeds the Individual Environmental Defect Threshold unless (A) the total Remediation Amounts of all such Environmental Defects that exceed the Individual Environmental Defect Threshold (excluding any Environmental Defects cured by Sellers to Buyer’s reasonable satisfaction prior to Closing) exceeds (B) the Environmental Defect Deductible, whereupon Buyer shall be entitled to adjustments to the Participating Purchase Price or other remedies only with respect to such Environmental Defects in excess of the Environmental Defect Deductible (which, for the avoidance of doubt, shall only impact the affected Seller(s)).

(f) Environmental Dispute Resolution. Such Seller’s Representatives and Buyer shall attempt to agree on (i) all Environmental Defects and Remediation Amounts prior to Closing, and (ii) the efficacy of any attempted cure of an Environmental Defect promptly upon the expiration of the Cure Period. If such Seller’s Representatives and Buyer are unable to so agree, the Environmental Defects, Remediation Amounts and/or cure in dispute shall be exclusively and finally resolved by arbitration pursuant to this Section 14.1(f). There shall be a single arbitrator, who shall be an environmental attorney with at least 10 years’ experience in environmental matters involving oil and gas producing properties in the regional area in which the affected Assets are located, as selected by mutual agreement of Buyer and such Seller’s Representatives within 15 days after the Closing Date (the “Environmental Arbitrator”). In the event the Parties are unable to mutually agree upon the Environmental Arbitrator within such time period, then such Seller’s Representatives on the one hand and Buyer on the other hand shall each nominate a candidate to be the Environmental Arbitrator, and such candidates so nominated by the parties shall together determine the Environmental Arbitrator. Such Seller’s Representative and the Buyer shall each present to the Environmental Arbitrator, with a simultaneous copy to the other party, a single written statement of its position on the defect or benefit in question, together with a copy of this Agreement and any supporting material that such party desires to furnish, not later than the 10^th Business Day after appointment of the Environmental Arbitrator. In making the determination, the Environmental

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Arbitrator, unless the Environmental Arbitrator requests additional information from either party, shall make a determination of the matter submitted based solely on the single written submission of the such Seller’s Representatives and Buyer and shall be bound by the terms of this Agreement. Provided, however, the Environmental Arbitrator may consider available legal and industry matters as in the Environmental Arbitrator’s opinion are necessary or appropriate to make a proper determination. The Environmental Arbitrator’s determination shall be made within 20 days after submission of the matters in dispute and shall be final and binding upon both Parties, without right of appeal. The Environmental Arbitrator, however, may not award Buyer any greater Remediation Amount than the Remediation Amount claimed by Buyer in its applicable Environmental Defect Notice. The Environmental Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Environmental Defects and/or Remediation Amounts submitted by either party and may not award damages, interest or penalties to either party with respect to any matter. Sellers and Buyer shall each bear its own legal fees and other costs of presenting its case. The Seller’s Representatives, on the one hand, and Buyer, on the other hand, shall each bear one-half of the costs and expenses of the Environmental Arbitrator. Nothing herein shall operate to cause the Closing to be delayed on account of any arbitration hereunder and to the extent any adjustments are not agreed upon by the Parties as of the Closing, then the applicable Environmental Defect Property and all associated Assets shall be excluded from the Assets to be conveyed to Buyer at Closing, in which event the Participating Purchase Price shall be reduced by an amount equal to the Allocated Value of such excluded Environmental Defect Property and associated Assets. Within 10 days after the Environmental Arbitrator delivers written notice to Buyer and Seller’s Representatives of his award with respect to a Remediation Amount (and subject to Section 14.1(c) and Section 14.1(e)), should the Remediation Amount of such Environmental Defect Property (A) not exceed the Allocated Value threshold set forth in Section 14.1(c)(iii), then such Asset(s) so excluded under the terms of this Section 14.1(f) shall be assigned to Buyer by the applicable Sellers pursuant to an assignment in the form of the Assignment for the amount by which the Participating Purchase Price was reduced at Closing due to the exclusion of such Asset(s) (as such amount is appropriately adjusted in accordance to Section 3.3 with respect to such Asset(s) and in accordance with Section 14.1(c) as a result of the Environmental Arbitrator’s decision), or (B) meet or exceed the Allocated Value threshold set forth in Section 14.1(c)(iii), the Buyer shall have the option to receive an assignment of such Assets in the manner described in subpart (A) above or choose to exclude such Assets permanently pursuant to its rights under Section 14.1(c)(iii).

14.2 NORM, Wastes and Other Substances. Buyer acknowledges that the Assets have been used for exploration, development, production, gathering and transportation of oil and gas and there may be petroleum, produced water, wastes or other substances or materials located in, on or under the Assets 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, pipelines, materials and equipment as scale, or in other forms. The wells, materials and equipment located on the Assets or included in the Assets may contain NORM and other wastes or Hazardous Substances. NORM containing material and/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. For the avoidance of doubt (a) NORM shall not, by itself, constitute the basis of a breach of Sellers’ representations and warranties set forth in Section 9.14,

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and (b) to the extent an Environmental Condition is based on NORM that is presently in compliance with applicable Environmental Laws, it shall not constitute the basis of an Environmental Defect.

ARTICLE XV
MISCELLANEOUS

15.1 Exhibits, Schedules and Annexes.

(a)All of the Exhibits, Schedules and Annexes referred to in this Agreement (including those Exhibits and Schedules that are specific to an individual Seller) constitute a part of this Agreement (it being understood that, with respect to those Schedules that are that are specific to an individual Seller, such Schedules shall constitute a part of this Agreement only as to such Seller). Sellers and Buyer and their respective counsel have received a complete set of Initial Exhibits and Sellers have provided Buyer and its counsel a complete set of Initial Exhibits and (and such Sellers’ Schedules to this Agreement) prior to and as of the execution of this Agreement (it being understood that such Initial Exhibits may be amended and restated by the Seller’s Representatives pursuant to Section 1.3(b) and that each Associated Owner that executes a Joinder Agreement shall deliver its Schedules to this Agreement contemporaneously with its delivery of its Joinder Agreement, or utilize the RK Petroleum Schedules as set forth in Section 1.3(a)).

(b)Unless the context requires otherwise or unless otherwise indicated in the Schedules, capitalized terms used but not defined in any Seller’s Schedules have their respective meanings set forth in this Agreement. Disclosure of any fact or item by a Seller in any of its Schedules shall be deemed to have been disclosed with respect to every other Section of Article XI that contains a reference to a Schedule, but only to the extent it is readily apparent on the face of such Schedule that such disclosure is applicable with respect to such other Section. The headings in each Seller’s Schedules are for convenience of reference only and shall not affect the disclosures contained therein. References in any Seller’s Schedules to any Contract shall be deemed to refer to any and all amendments, restatements, supplements, other modifications, exhibits and schedules thereto.

(c)No information contained in any Seller’s Schedules shall be deemed to be an admission by such Seller to any other Party or Third Party of any matter whatsoever (including any violation of Law or breach of Contract). In disclosing the information in its Schedules, each Seller expressly does not waive any attorney-client privilege associated with any such information or any protection afforded by the “work product doctrine” with respect to any of the matters disclosed or discussed therein. Neither the specification of any item or matter in any representation or warranty contained in this Agreement nor the inclusion of any specific item in any Seller’s Schedules is intended to imply that such item or matter, or other items or matters, are or are not in the ordinary course of business, and no Party shall use the fact of the setting forth or the inclusion of any such item or matter in any dispute or controversy between the Parties as to whether any obligation, item or matter not described in this Agreement or included in any Seller’s Schedules is or is not in the ordinary course of business for purposes of this Agreement. No disclosure of any matter contained in any Schedule of any Seller will create an implication that such matter meets any standard of materiality (it being further understood and agreed that (i) matters reflected in the Schedules of each Seller are not necessarily limited to matters required by this Agreement to be reflected in such Schedules, which additional matters are included for informational purposes only and do not

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necessarily include other matters of a similar nature, and (ii) the inclusion of any item in any Schedule of any Seller will not be construed as implying that any such item is “material” for any purpose). Nothing in any Schedule of any Seller is intended or shall be construed to broaden the scope of any representation or warranty made by such Seller in this Agreement.

15.2 Expenses and Taxes.

(a) RK Petroleum Corp. will pay the commission payable to Evercore Partners in connection with the transactions contemplated by this Agreement. Except as otherwise specifically provided, all fees, costs and expenses incurred by Sellers or Buyer in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Person incurring the same, including, legal and accounting fees, costs and expenses.

(b) All required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments (including the Assignment), conveyances or other instruments required to convey title to the Assets to Buyer shall be borne by Buyer. Each Seller shall remain responsible for, and shall bear and pay, all Income Taxes incurred by or imposed on such Seller, its direct or indirect owners or Affiliates, or any combined, unitary, or consolidated group of which any of the foregoing is or was a member, and no such Taxes shall be taken into account as adjustments to the Participating Purchase Price under Section 3.3. Buyer shall assume responsibility for, and shall bear and pay, all state sales, use, transfer and similar Taxes incurred or imposed with respect to the transactions described in this Agreement (the “Transfer Taxes”). Each Seller shall remain responsible for, and shall bear and pay, all Asset Taxes attributable for such Seller for (i) any period ending on or before the Effective Time, and (ii) the portion of any Straddle Period ending at the Effective Time. All Asset Taxes arising after the Effective Time (including all Straddle Period Asset Taxes not apportioned to Sellers) shall be allocated to and borne by Buyer. Upon determination of the actual amount of Asset Taxes, to the extent not taken into account under Section 3.3, payments will be made to cause the appropriate Party to bear the Asset Taxes allocable to such Person under this Section 15.2(b). For purposes of allocation among the Parties of Asset Taxes that are payable with respect to Straddle Periods, (A) Asset Taxes that are attributable to the severance or production of Hydrocarbons shall be allocated to the period in which the severance or production giving rise to such Asset Taxes occurred, (B) Asset Taxes that are based upon or related to income or receipts or imposed on a transactional basis (other than such Asset Taxes described in clause (A) or (C)), shall be allocated to the period in which the transaction giving rise to such Asset Taxes occurred, and (C) Asset Taxes that are ad valorem, property or other Asset Taxes imposed on a periodic basis pertaining to a Straddle Period shall be allocated between the portion of such Straddle Period ending at the Effective Time and the portion of such Straddle Period beginning immediately following the Effective Time by prorating each such Asset Tax based on the number of days in the applicable Straddle Period that occur on or before the day on which the Effective Time occurs, on the one hand, and the number of days in such Straddle Period that occur after the day on which the Effective Time occurs, on the other hand.

(c) Sellers shall timely file any Tax Return with respect to Asset Taxes due on or before the Closing Date or that otherwise relates solely to periods before the Closing Date (a “Pre-Closing Tax Return”) and shall pay any Asset Taxes shown due and owing on such Pre-Closing Tax Return. From and after the Closing Date, Buyer shall timely file any Tax Returns with respect to Asset Taxes required to be filed after the Closing Date, including for any Straddle Period

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(a “Post-Closing Tax Return”), and, subject to Buyer’s indemnification rights under Article VIII, shall be responsible for the payment to the applicable Taxing Authorities of all Asset Taxes that become due and payable after the Closing Date. Buyer shall file any Post-Closing Tax Return in a manner consistent with past practice except as otherwise required by Law. The Parties agree that (i) this Section 15.2(c) is intended to solely address the timing and manner in which certain Tax Returns relating to Asset Taxes are filed and the Asset Taxes shown thereon are paid to the applicable Taxing Authority, and (ii) nothing in this Section 15.2(c) shall be interpreted as altering the manner in which Asset Taxes are allocated to and economically borne by the Parties.

(d) Any payments made to any Party pursuant to Article VIII shall constitute an adjustment of the Participating Purchase Price for Tax purposes and shall be treated as such by Buyer and Sellers on their Tax Returns to the extent permitted by applicable Law.

(e) The Parties shall cooperate fully, as and to the extent reasonably requested in connection with the filing of any Tax Returns, the qualification for any exemption or reduction in Tax that may be available, any audit, litigation or other proceeding with respect to these matters for the Assets. Such cooperation shall include the retention of records and information which are reasonably relevant to any such audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder. Buyer agrees to allow access (upon request) to the Assets by Seller’s Representatives and their auditors and State or Federal representatives relevant to any such audit, litigation or other proceeding.

15.3 Assignment. Except in the case of assignment by Buyer to an Affiliate or as otherwise provided in Section 15.16, this Agreement may not be assigned by Buyer or Sellers without the prior written consent of (a) if Buyer is the Party desiring to make such assignment, the Seller’s Representatives, and (b) if a Seller is the Party desiring to make such assignment, Buyer. In the event Buyer or the Seller’s Representatives, as applicable, consent to any such assignment requiring consent, unless otherwise agreed by such Persons, such assignment shall not relieve the assigning Party of any obligations and responsibilities hereunder.

15.4 Interpretation. Buyer and its counsel and RK Petroleum Corp., the Seller’s Representatives and their respective counsel participated in the review and/or preparation of this Agreement. In the event of any ambiguity in this Agreement, all Parties acknowledge and agree that no presumption shall arise based on the identity of the draftsman of this Agreement.

15.5 Publicity.

(a) No Party shall make or issue any press release or other public announcements concerning the transactions contemplated by this Agreement without the prior consent of (i) if Buyer is the Party desiring to make any such release or announcement, the Seller’s Representatives, and (ii) if a Seller is the Party desiring to make any such release or announcement, Buyer, in each case, which consent shall not be unreasonably withheld or delayed. In no event may any Party make or issue any press release or other public announcements concerning the transactions contemplated by the Agreement until the Deposit has been deposited with the Escrow Agent pursuant to Section 3.2. If a Party desires to make a public announcement, it shall first give Buyer or the Seller’s Representatives, as applicable, 48 hours written notification of its desire to make such a public

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announcement. The written notification shall include (A) a request for consent to make the announcement, and (B) a written draft of the text of such public announcement. Buyer, on the one hand, and the Sellers and Seller’s Representatives, on the other hand, shall each use their reasonable efforts to consult with the other Parties regarding the contents of any such release or announcement.

(b) Nothing in this Section 15.5 shall prohibit any Party from issuing or making a public announcement or statement if such Party deems it, in its sole but reasonable and good faith discretion (i) necessary to do so in order to comply with any applicable Law or the rules of any stock exchange having jurisdiction of a Party or a Party’s Affiliates, or (ii) desirable with respect to the investment community at large; provided, however, that (A) no Seller will be identified by name (other than RK Petroleum Corp.), (B) no disparaging remarks shall be made regarding any Seller and (C) to the extent practical, prior written notification shall be given to the other Parties prior to any such announcement or statement.

(c) Nothing herein or in the Confidentiality Agreement shall restrict the ability of any Seller’s Representative or Buyer to disclose the terms of this Agreement (including by providing a full copy of this Agreement) to all Associated Owners and their respective representatives who reasonably require access to such information in order to determine whether such Associated Owner desires to execute and deliver a Joinder Agreement pursuant to Section 1.3(a).

15.6 Notices. All notices and communications required or permitted to be given hereunder shall be sufficient in all respects if given in writing and addressed as indicated below, and any communication or delivery hereunder shall be deemed to have been duly delivered upon the earliest of: (a) actual receipt by the Party or Seller’s Representative to be notified; (b) if sent by U.S. certified mail, postage prepaid, return receipt requested, the date shown as received on the return notice; (c) if by email, upon receipt, provided that if such email is received after 5:00 pm local time of such recipient, such email will be deemed to have been received on the following business day; and provided, further, however, that any notice delivered hereunder via email or other electronic transmission shall, in order to be effective, be followed by delivery of the same notice via one of the other methods authorized pursuant to this Section 15.6 (other than the notices to be delivered pursuant to Section 1.3, which notices shall not require such subsequent delivery in order to be effective); or (d) if by Federal Express overnight delivery (or other reputable overnight delivery service), the date shown on the notice of delivery. Addresses for all such notices and communication shall be as follows:

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If to any Seller or any Seller’s Representative:

Blind Juniper Holdings, LLC

c/o RK Petroleum Corp.

406 N. Main Street

Midland, Texas 79701

Attention: Clinton J. Kuzmich

Email: clintrk@aol.com

and

Richard Schmidt REP, LLC

PO Box 50187

Austin, TX 78763

Attention: Richard Schmidt

Email: dickschmidt@sbcglobal.net

In each case, with a copy (which shall not constitute notice) to:

Kelly Hart & Hallman LLP

303 Colorado Street, Suite 2000

Austin, TX 78701

Attention: William M. Kerr, Jr.

Email: william.kerr@kellyhart.com

Blind Juniper Holdings, LLC

c/o RK Petroleum Corp.

406 N. Main Street

Midland, Texas 79701

Attention: Gregory D. Smith

Email: gsmith@rkpetroleum.com

If to Buyer:

QEP Energy Company

1015 17th Street, Suite 800

Denver, CO 80265

Attention: Mike Watanabe

Email: mike.watanabe@qepres.com

With copies (which shall not constitute notice) to:

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QEP Energy Company

1015 17th Street, Suite 800

Denver, CO 80265

Attention: Chris Woosley

Email: chris.woosley@qepres.com

QEP Energy Company

1015 17th Street, Suite 800

Denver, CO 80265

Attention: Matt Myers

Email: matt.myers@qepres.com

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

Attention: Michael P. Darden

Email: michael.darden@lw.com

Seller’s Representatives or Buyer may change the address to which such communications are to be addressed by giving written notice to (i) in the case of Buyer, the Seller’s Representatives, and (ii) in the case of any Seller or Seller’s Representatives, Buyer and the other Seller’s Representatives, in each case, in the manner provided in this Section 15.6. If a date specified herein 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 which is a Business Day.

15.7 Seller Representatives.

(a) Each Seller listed on Annex B (collectively, the “BJH Represented Sellers”) exclusively and irrevocably appoints BJH as its representative with full authority and power without limitation to execute all instruments (other than any Assignment or any certificate required pursuant to Section 4.1(c)), to perform all covenants and obligations, to grant such waivers and consents on behalf of such Seller under this Agreement, to exercise all rights on such Seller’s behalf in connection with the performance of this Agreement and to amend this Agreement except to the extent such amendment would decrease the Participating Purchase Price or adversely and disproportionately affect such Seller (in each case, except as otherwise provided herein or contemplated hereby, including with respect to Section 1.3(b)) without such Seller’s consent, in each case, as such Seller’s Representative in its sole discretion shall deem advisable, both prior to and after Closing.

(b) Each Seller listed on Annex C (collectively, the “Schmidt Represented Sellers”) exclusively and irrevocably appoints Schmidt REP as its Seller’s Representative with full authority and power without limitation to execute all instruments (other than any Assignment or any certificate required pursuant to Section 4.1(c)), to perform all covenants and obligations, to grant such waivers and consents on behalf of such Seller under this Agreement, to exercise all rights on such Seller’s behalf in connection with the performance of this Agreement and to amend this Agreement except to the extent such amendment would decrease the Participating Purchase Price

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or adversely and disproportionately affect such Seller (in each case, except as otherwise provided herein or contemplated hereby, including with respect to Section 1.3(b)) without such Seller’s consent, in each case, as such Seller’s Representative in its sole discretion shall deem advisable, both prior to and after Closing.

(c) Each Seller listed on Annex D (which will include each Associated Owner that executes a Joinder Agreement in accordance with Section 1.3) shall become a BJH Represented Seller and by executing such Joinder Agreement such Seller exclusively and irrevocably appoints BJH as its Seller’s Representative with full authority and power without limitation to execute all instruments (other than any Assignment or any certificate required pursuant to Section 4.1(c)), to perform all covenants and obligations, to grant such waivers and consents on behalf of such Seller under this Agreement, to exercise all rights on such Seller’s behalf in connection with the performance of this Agreement and to amend this Agreement except to the extent such amendment would decrease the Participating Purchase Price or adversely and disproportionately affect such Seller (in each case, except as otherwise provided herein or contemplated hereby, including with respect to Section 1.3(b)) without such Seller’s consent, in each case, as such Seller’s Representative in its sole discretion shall deem advisable, both prior to and after Closing.

(d) BJH in its capacity as representative appointed under Section 15.7(a) and under Section 15.7(c) and Schmidt REP in its capacity as representative appointed under Section 15.7(b) are each a “Seller’s Representative” and collectively, “Seller’s Representatives.”

(e) Without in any way limiting the authority and power set forth in Sections 15.7(a), (b) and (c), each Seller irrevocably appoints the applicable Seller’s Representative (as outlined above) the agent and attorney-in-fact of such Seller for the purposes of acting in the name and stead of such Seller in: (i) giving and receiving all notices permitted or required by this Agreement and acting on behalf of such Sellers for all purposes under this Agreement; (ii) dealing with Buyer in connection with any and all adjustments to the Participating Purchase Price under this Agreement (including negotiating and settling any dispute regarding any such adjustments on behalf of such Sellers); (iii) acting on such Seller’s behalf under any covenant, agreement or provision of this Agreement; (iv) agreeing with Buyer as to any amendments to this Agreement or waivers of any terms of this Agreement which Seller’s Representatives may reasonably deem necessary or advisable, including the extension of time in which to consummate the transactions contemplated by this Agreement, and the waiver of any closing conditions; (v) employing legal counsel; (vi) paying any legal and any other fees, costs and expenses incurred in connection with the transactions contemplated by this Agreement; (vii) granting any consent or approval on behalf of such Seller under this Agreement; (viii) determining whether the conditions to Closing in Article V have been satisfied and supervising the Closing, including waiving any such condition if Seller’s Representatives, in their sole discretion, determine that such waiver is appropriate; (ix) taking any action that may be necessary or desirable, as determined by Seller’s Representatives in their sole discretion, in connection with the termination of this Agreement in accordance with Section 1.3(d) or Article VII; (x) serving as payment agent for Sellers and otherwise making the determinations referenced by Section 2.4 in accordance with Section 2.4, including directing the timing, making and manner of payment of the Participating Purchase Price (as adjusted pursuant to this Agreement) hereunder equitably among the Sellers in accordance with this Agreement as contemplated by Section 2.4; (xi) dealing with Buyer in connection with the determination, dispute, negotiation and

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settlement of any Title Defects or Environmental Defects; and (xii) making, executing, acknowledging, and delivering all such contracts, orders, receipts, notices, requests, instructions, certificates, letters, and other writings, and in general doing all things and taking all actions which Seller’s Representatives, in their sole discretion, may consider necessary or proper in connection with or to carry out the terms of this Agreement, as fully as if such Sellers were personally present and acting. This power of attorney and all authority conferred hereby is granted and conferred subject to the interests of the other parties to this Agreement, and in consideration of those interests and for the purpose of completing the transactions contemplated hereby, this power of attorney and all authority conferred hereby shall be irrevocable and shall not be terminated by the Sellers or by operation of Law, whether by the incapacity of any of the Sellers or by the occurrence of any other event. As the representative of the Sellers, Seller’s Representatives shall act as the agent for all such Persons, shall have authority to bind each such Person in accordance with this Agreement, and Buyer shall be fully protected in relying conclusively without any investigation upon any notices, instruction, dealings, and actions of Seller’s Representatives within the scope of this Section 15.7 and the power of attorney contained herein.

(f) Each Seller exclusively and irrevocably appoints the Seller’s Representatives, acting jointly, with full authority and power to execute the Escrow Agreement, to perform all covenants and obligations under the Escrow Agreement, to execute joint written instructions to the Escrow Agent under the Escrow Agreement, to grant waivers and consents under the Escrow Agreement, to exercise all rights in connection with the performance of the Escrow Agreement and to amend the Escrow Agreement, in each case, as the Seller’s Representatives in their sole discretion shall deem advisable, during the term of the Escrow Agreement. Each Seller agrees that Buyer and Escrow Agent shall be entitled to rely on this granting of power of attorney in all respects.

(g) Notwithstanding anything to the contrary herein, the Seller’s Representatives shall not owe any fiduciary duties to the Sellers and shall not have any Liability of any kind whatsoever to the Sellers arising hereunder or in any way related to any of the transactions contemplated hereby, including for any action taken, or omission made, by either of them while acting in good faith in the absence of bad faith or willful misconduct and each Seller hereby irrevocably and unconditionally forever releases each Seller’s Representative from any and all Liability of any kind whatsoever arising hereunder or in any way related to any of the transactions contemplated hereby, including for any action taken, or omission made, by either of the Seller’s Representatives while acting in good faith, except (and only to the extent) of bad faith or willful misconduct by such Seller’s Representative. The Seller’s Representatives may, in all matters arising in connection with this Agreement, rely on the advice of counsel and the Seller’s Representative(s) shall not be liable to the Sellers for anything done, omitted, or suffered in good faith based on such advice in the absence of bad faith or willful misconduct by the Seller’s Representative(s). The Seller’s Representatives undertake to perform such duties herein and only such duties as are specifically set forth in this Agreement and no implied covenants or obligations shall be read into this Agreement against the Seller’s Representatives.

(h) Notwithstanding anything herein to the contrary, (i) the Seller’s Representative representing the BJH Represented Sellers shall make all decisions hereunder on behalf of the BJH Represented Sellers that are permitted or required to be made hereunder by the

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Seller’s Representatives and no other Seller’s Representative shall make any such decisions on behalf of the BJH Represented Sellers and (ii) the Seller’s Representative representing the Schmidt Represented Sellers shall make all decisions hereunder on behalf of the Schmidt Represented Sellers that are permitted or required to be made hereunder by the Seller’s Representatives and no other Seller’s Representative shall make any such decisions on behalf of the Schmidt Represented Sellers; provided, however, that the Seller’s Representatives shall be required to act jointly hereunder solely with respect to (A) the matters described in Section 15.7(f), (B) the preparation of the Preliminary Settlement Statement, (C) the preparation of the Final Settlement Statement (including negotiating and settling any dispute regarding any adjustments resulting therefrom to the extent that such adjustments impact one or more of the BJH Represented Sellers and one or more of the Schmidt Represented Sellers), and (D) those matters that, pursuant to the express terms of this Agreement, require the agreement of both Seller’s Representatives.

(i) Buyer, the Escrow Agent and all other Persons shall have the right to rely upon all actions taken or omitted to be taken by Seller’s Representatives pursuant to this Agreement. Notwithstanding anything herein to the contrary, Sellers do hereby agree that Buyer Indemnified Parties shall have no Liability to any Seller or any Seller’s Representative as a result of any action or inaction by any Seller’s Representatives in the performance of this Agreement or any action or inaction of any Buyer Indemnified Party at the request or instruction of any Seller Representative related to this Agreement, and Sellers do hereby agree to defend, indemnify, hold harmless and forever release Buyer Indemnified Parties from any such Liability, including for the avoidance of doubt, any distribution of any portion of the Adjusted Purchase Price paid to the Seller’s Representatives.

(j) The authorizations of the Seller’s Representatives under this Section 15.7 shall be effective until its rights and obligations under this Agreement terminate by virtue of the termination of all obligations of each Seller under this Agreement.

(k) Without in any way limiting the authority and power granted to the Seller’s Representatives hereunder, the Seller’s Representatives are expressly authorized to withhold (and otherwise make provision for) any amounts that they determine in their sole discretion as being sufficient to (i) satisfy any anticipated or potential downward adjustments to the Participating Purchase Price in excess of the Adjustment Escrow, it being understood that any amounts so withheld for such purpose that are remaining after the Final Payment Date will be distributed to the Sellers in accordance with Section 2.4 promptly after the Final Payment Date, and (ii) to satisfy any anticipated or potential liabilities or other obligations potentially arising hereunder affecting any Sellers in the group of Sellers which it represents hereunder, if and to the extent that such Seller’s Representative determines in its sole discretion acting reasonably and in good faith that such is in the collective best interest of the group of Sellers it represents hereunder, it being understood that any such remaining amounts so withheld will be distributed to the Sellers that such Seller’s Representative represents hereunder in accordance with Section 2.4 promptly after such Seller’s Representative determines in its sole discretion acting reasonably and in good faith that such distribution is in the collective best interest of the group of Sellers it represents hereunder.

15.8 Further Cooperation. After the Closing, Sellers and Buyer shall execute and deliver, or shall cause to be executed and delivered, from time to time such further instruments

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of conveyance and transfer, and shall take such other actions as Seller’s Representatives or Buyer may reasonably request, to convey and deliver the Assets to Buyer, to perfect Buyer’s title thereto and to accomplish the orderly transfer of the Assets to Buyer in the manner contemplated by this Agreement.

15.9 Filings, Notices and Certain Governmental Approvals. Promptly after the Closing, Buyer shall (a) record all assignments of state Leases executed at the Closing in the records of the applicable Governmental Authority, and (b) actively pursue all Customary Post-Closing Consents, that, in each case, shall not have been obtained prior to the Closing. Buyer obligates itself to use its commercially reasonable efforts to obtain such consents, including the posting of any and all bonds or other security that may be required in excess of its existing lease, pipeline or area-wide bond.

15.10 Entire Agreement; Conflicts.

(a) THIS AGREEMENT, THE EXHIBITS, ANNEXES AND SCHEDULES HERETO, THE OTHER TRANSACTION DOCUMENTS AND THE CONFIDENTIALITY AGREEMENT COLLECTIVELY CONSTITUTE THE ENTIRE AGREEMENT AMONG SELLERS AND BUYER PERTAINING TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ALL PRIOR AGREEMENTS, UNDERSTANDINGS, NEGOTIATIONS AND DISCUSSIONS, WHETHER ORAL OR WRITTEN, OF SELLERS AND BUYER PERTAINING TO THE SUBJECT MATTER HEREOF.

(b) The Parties expressly acknowledge and agree that, in the event that the Closing occurs, except as and to the extent provided in Section 12.2, the Confidentiality Agreement shall be terminated automatically effective as of the Closing Date.

(c) IN THE EVENT OF A CONFLICT BETWEEN THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY EXHIBIT HERETO, THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL; PROVIDED, HOWEVER, THAT THE INCLUSION IN ANY OF THE EXHIBITS HERETO OF TERMS AND PROVISIONS NOT ADDRESSED IN THIS AGREEMENT SHALL NOT BE DEEMED A CONFLICT, AND ALL SUCH ADDITIONAL PROVISIONS SHALL BE GIVEN FULL FORCE AND EFFECT, SUBJECT TO THE PROVISIONS OF THIS SECTION 15.10.

15.11 Parties in Interest. The terms and provisions of this Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns. Notwithstanding anything contained in this Agreement to the contrary, nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Sellers and Buyer and their respective successors and permitted assigns, or the Parties’ respective related Indemnified Parties hereunder, any rights, remedies, obligations or liabilities under or by reason of this Agreement; provided that only Buyer and its respective successors and permitted assigns or Seller’s Representatives (on behalf of the Sellers and their respective successors and permitted assigns) will have the right to enforce the provisions of this Agreement on its own behalf or on behalf of any of its related Indemnified Parties (but shall not be obligated to do so). The rights and

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liabilities of Sellers in connection with this Agreement are, for the avoidance of doubt, several and not joint in all respects.

15.12 Amendment. This Agreement may be amended only by an instrument in writing executed by Buyer and, subject to the limitations on such authority set forth in Section 15.7, Seller’s Representatives on behalf of Sellers.

15.13 Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance. No course of dealing on the part of Sellers or Buyer, or their respective officers, employees, agents or representatives or any failure by Sellers or Buyer to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such Person at a later time to enforce the performance of such provision. No waiver by Sellers or Buyer of any condition or any breach of any term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation or warranty. The rights of Sellers and Buyer under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

15.14 Conflict of Law Jurisdiction, Venue; Jury Waiver.

(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 AND SELLER’S REPRESENTATIVES 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 OR THE TRANSACTIONS CONTEMPLATED HEREBY, AND EACH PARTY AND EACH SELLER’S REPRESENTATIVE HEREBY IRREVOCABLY AGREES THAT ALL ACTIONS, SUITS AND PROCEEDINGS IN RESPECT OF SUCH DISPUTE, CONTROVERSY OR CLAIM MAY BE HEARD AND DETERMINED IN SUCH COURTS. EACH PARTY AND EACH SELLER’S REPRESENTATIVE HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAWS, (i) ANY OBJECTION IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUCH ACTION, SUIT OR PROCEEDING IN ANY OF THE AFORESAID COURTS, (ii) ANY CLAIM IT MAY NOW OR HEREAFTER HAVE THAT ANY SUCH ACTION, SUIT OR PROCEEDING HAS BEEN BROUGHT IN AN INCONVENIENT FORUM, AND (iii) THE RIGHT TO OBJECT, IN CONNECTION WITH SUCH ACTION, SUIT OR PROCEEDING, THAT ANY SUCH COURT DOES NOT HAVE ANY JURISDICTION

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OVER SUCH PERSON. EACH PARTY AND EACH SELLER’S REPRESENTATIVE HEREBY IRREVOCABLY CONSENTS TO THE SERVICE OF ANY PAPERS, NOTICES OR PROCESS AT THE ADDRESS SET OUT IN SECTION 15.6 IN CONNECTION WITH ANY ACTION, SUIT OR PROCEEDING AND AGREES THAT NOTHING HEREIN WILL AFFECT THE RIGHT OF THE OTHER PARTIES TO SERVE ANY SUCH PAPERS, NOTICES OR PROCESS IN ANY OTHER MANNER PERMITTED BY APPLICABLE LAW. EACH PARTY AND EACH SELLER’S REPRESENTATIVE AGREES THAT A JUDGMENT IN ANY SUCH DISPUTE, CONTROVERSY OR CLAIM MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY APPLICABLE LAW.

(c)EACH PARTY AND EACH SELLER’S REPRESENTATIVE WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY TRANSACTION CONTEMPLATED HEREBY.

15.15 Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any of Sellers or Buyer. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, Buyer and the Seller’s Representatives shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

15.16 Like-Kind Exchange. Notwithstanding anything else in this Agreement, each Party shall have the right to structure the transactions contemplated under the terms of this Agreement as a Like-Kind Exchange. Notwithstanding any other provisions of this Agreement, in connection with effectuating a Like-Kind Exchange, each Party shall have the right, at or prior to the Closing Date or any subsequent closing, to assign all or a portion of its rights under this Agreement (the “Assigned Rights”) to a “qualified intermediary” (as that term is defined in Section 1.1031(k)-1(g)(4) of the Treasury Regulations) or to an “Exchange Accommodation Titleholder” (as that term is defined in U.S. Revenue Procedure 2000-37). In the event a Party (in its capacity as an exchanging party, referred to in this Section 15.16 as an “Exchanging Party”) assigns the Assigned Rights to a “qualified intermediary” pursuant to this Section 15.16, then such Exchanging Party agrees to notify the other Party in writing of such assignment reasonably in advance of the Closing Date. In addition, should a Party choose to effectuate a Like-Kind Exchange, the Parties agree to use reasonable best efforts to cooperate with one another in the completion of such an exchange, including the execution of all documents reasonably necessary to effectuate such a Like-Kind Exchange; provided, however, that (a) the Closing Date shall not be delayed or affected by reason of the Like-Kind Exchange, (b) the Exchanging Party shall effect its Exchange through an assignment of the Assigned Rights to a “qualified intermediary” or to an “Exchange Accommodation Titleholder,” but such assignment shall not release such Exchanging Party from any of its liabilities or obligations under this Agreement and (c) the non-Exchanging Party shall incur no additional unreimbursed costs, expenses, fees or liabilities as a result of or in connection with the exchange

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requested by the Exchanging Party. Sellers and Buyer each hereby acknowledge and agree that any assignment of this Agreement pursuant to this Section 15.16 shall not release a Party from, or modify, any of its respective liabilities and obligations (including indemnity obligations to each other) under this Agreement. Neither Sellers nor Buyer, by its consent to a Like-Kind Exchange, shall be responsible in any way for the Exchanging Party’s compliance with such Like-Kind Exchange.

15.17 Counterparts. This Agreement may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. The execution and delivery of this Agreement by any Party may be evidenced by facsimile or other electronic transmission (including scanned documents delivered by email), which shall be binding upon all Parties.

15.18 Waiver of Preferential Purchase Rights and Consents. Each Seller hereby irrevocably (a) waives any Preferential Purchase Rights it may have that are applicable to the Assets, the transactions contemplated hereunder, and (b) grants any applicable consents to assignment pertaining to the Assets or the transactions contemplated hereunder.

15.19 Legal Representation. Notwithstanding anything seemingly to the contrary herein, each Seller hereby acknowledges and agrees that Kelly Hart & Hallman LLP (“KHH”) (a) has represented RK Petroleum Corp. and certain of its Affiliates in connection with the negotiation, execution and delivery of this Agreement and the other transactions contemplated by this Agreement, (b) has not represented and does not represent any other Seller or any of their respective Affiliates in connection with the negotiation, execution and delivery of this Agreement or the other transactions contemplated by this Agreement, and (c) in no event shall an attorney-client relationship be deemed to exist between KHH, on the one hand, and any Seller (other than RK Petroleum Corp.) or any of their respective Affiliates (other than certain Affiliates of RK Petroleum Corp.), on the other hand, in respect of KHH’s representation as described in clauses (a) and (b) above. The fees and expenses of KHH in connection with the negotiation, execution and delivery of this Agreement or the other transactions contemplated by this Agreement shall be borne by RK Petroleum Corp.

[Signature page follows.]

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IN WITNESS WHEREOF, Sellers and Buyer have executed this Agreement as of the date first written above.

BUYER:



		QEP Energy Company


By:		/s/ Austin Murr
Name:		Austin Murr
Title:		Senior Vice President of Business Development

Attached to and for all purposes made a part of that certain Purchase and Sale Agreement, by and among RK Petroleum Corp., et al, as Sellers, and QEP Energy Company, as Buyer, dated effective April 1, 2016.

Seller's Representative for the BJH Represented Sellers:

Blind Juniper Holdings, LLC, a Texas Limited Liability Company

/s/ Gregory D. Smith

By: Gregory D. Smith, Member, signing on behalf of the LLC only

c/o RK Petroleum Corp.

406 N. Main

Midland, TX 79701

Seller's Representative for the Schmidt Represented Sellers:

Richard Schmidt REP, LLC, a Texas Limited Liability Company

/s/ Richard Schmidt

By: Richard Schmidt, Member, signing on behalf of the LLC only

PO Box 50187

Austin, TX 78763

Attn: Richard Schmidt

Estate of R.W. Kuzmich, Deceased

/s/ Clinton J. Kuzmich

Clinton J. Kuzmich

Independent Co-Executor of the Estate of R.W. Kuzmich, Deceased

P.O. Box 8528

Midland, TX 79708

(432)683-4319 (w)

clintrk@aol.com

/s/ Berkley A. Kuzmich

Berkley A. Kuzmich

Independent Co-Executor of the Estate of R.W. Kuzmich, Deceased

P.O. Box 8528

Midland, TX 79708

(432)683-4319 (w)

bak7778@gmail.com

The Justin Chance Waller Special Needs Trust

/s/ Clinton J. Kuzmich

Clinton J. Kuzmich, as Trustee for

The Justin Chance Waller Special Needs Trust

P.O. Box 8528

Midland, TX 79708

clintrk@aol.com

(432)683-4319 (w)

/s/ Richard L. Glantz

Richard L. Glantz

217 Cedar Street, #283

Sandpoint, ID 83864-1410

dg4helo@televar.com

/s/ Joan Gaye Glantz

Joan Gaye Glantz

217 Cedar Street, #283

Sandpoint, ID 83864-1410

dg4helo@televar.com

GT Partners, a Texas General Partnership

/s/ Clinton J. Kuzmich

By: Clinton J. Kuzmich, its Manager, signing for the General Partnership only

P.O. Box 8528

Midland, TX 79708

clintrk@aol.com

(432)683-4319 (w)

/s/ Tanya Kreuz

Tanya Kreuz

29242 Enchanted Glen

Boerne, TX 78015

tanya@rkpetroleum.com

/s/ Berkley A. Kuzmich

Berkley A. Kuzmich

6215 Via La Cantera

Apartment 257

San Antonio, TX 78256

bak7778@gmail.com

(512) 571-2111 (h)

(210) 827-1680 (c)

/s/ Clinton J. Kuzmich

Clinton J. Kuzmich

P.O. Box 8528

Midland, TX 79708

clintrk@aol.com

(432)683-4319 (w)

(432)559-4634 (c)

/s/ Stephen W. Kuzmich

Stephen W. Kuzmich

P.O. Box 9728

Midland, TX 79708

kuz007@aol.com

(432)683-4319 (w)

(432) 699-0222 (h)

(432) 528-3477 (c)

/s/ Thomas M. Kuzmich

Thomas M. Kuzmich

P.O. Box 8528

Midland, TX 79708

tomkuz@aol.com

/s/ Kaye M. Kuzmich

Kaye M. Kuzmich

5009 Mt. Vernon Court

Midland, TX 79705

kmurphy0110@aol.com

/s/ John T. Kuzmich II

John T. Kuzmich II

1700 Maberry

Midland, TX 79705

clarissa.kuzmich@gmail.com

Lanterra Resources, Inc., a Texas Corporation

/s/ Clinton J. Kuzmich

By: Clinton J. Kuzmich, President/Director, signing on behalf of the Corporation only

P.O. Box 8528

Midland, TX 79708

clintrk@aol.com

(432) 683-4319 (w)

/s/ Glenn Prescott

Glenn Prescott

1409 Lanham

Midland, TX 79701

glenn@rkpetroleum.com

(432) 683-4319 (w)

RK Petroleum Corp., an Illinois Corporation

/s/ Stephen W. Kuzmich

By: Stephen W. Kuzmich, President/Director, signing on behalf of the Corporation only

P.O. Box 8528

Midland, TX 79708

(432) 683-4319 (w)

kuz007@aol.com

/s/ Gregory D. Smith

Gregory D. Smith

2000 Shell Ave.

Midland, TX 79705

gsmith@rkpetroleum.com

(432) 683-4319 (w)

(432) 664-2698 (c)

Topsy J. Glantz Living Trust

/s/ Topsy J. Glantz Living Trust

Topsy J. Glantz Trustor and Trustee of the

Topsy J. Glantz Living Trust

2186 Stage Stop Drive

Henderson, NV 89052-5825

drgoudge@cox.net

I have received cover letter and reviewed all schedules and I have no problems.

/s/ Michael Waller

Michael Waller

57 Neron Place

New Orleans, LA 70118

mwalter5555@gmail.com

The John Kuzmich Children's Trust

Wells Fargo Bank, as Trustee of

The John Kuzmich Children's Trust

By: /s/ Scott S. Tomlinson

Name: Scott S. Tomlinson, CPL

Title: Vice President and Sr. Regional Manager, Oil, Gas and Mineral Management

Wells Fargo Private Bank

500 W. Texas Ave., Suite 760

Midland, TX 79702

Scott.Tomlinson@wellsfargo.com

432-685-5131 (w)

/s/ J B Young

J B Young

4400 Cherrywood Drive

Midland, TX 79707

jbatrk@yahoo.com

(432) 683-4319 (w)

Augustus May Energy, Inc., a Texas Corporation

/s/ Kevin W. Harrison

By: Kevin W. Harrison, Director, signing on behalf of the Corporation only

5410 Bee Caves Road

Austin, TX 78746

graymarland@yahoo.com

(512) 329-8700

/s/ Daniel J. Bates, Sr.

Daniel J. Bates, Sr.

P.O. Box 162213

Austin, TX 78716-2213

(512) 732-7321

djbcpa18@earthlink.net

The Charles O. Newell Revocable Trust Agreement Dated 7/14/1995 as Amended and Restated

/s/ Charles O. Newell, Jr.

Charles O. Newell, Jr., as Trustee of

The Charles O. Newell Revocable Trust Agreement Dated 7/14/1995 as Amended and Restated

3300 Bee Caves Road

Suite 650-122

Austin, TX 78746

chadnewell@aol.com

(512) 633-5490 (cell)

Diamond Head Properties, L.P., a Texas Limited Partnership

By: Redfern Enterprises, Inc., a Texas Corporation, its General Partner

/s/ Rosalind Grover

By: Rosalind Grover, President/Director, signing on behalf of the Corporation only

P.O. Box 2127

Midland, TX 79702

rei@redferngrover.com

(432) 683-9137 (w)

(432) 682-5639 (f)

Dugan Production Corp., a New Mexico corporation

/s/ Thomas Dugan

By: Thomas Dugan, President, signing on behalf of the Corporation only

P.O. Box 420

Farmington, NM 87499-0420

(505) 325-1821 (w)

duganprod@duganproduction.com

crystal.gates@duganproduction.com

Emperor Partners, a Texas General Partnership

By: TX Nine Iron Oil & Gas, Ltd., a Texas Limited Partnership, its Partner

By: Sure Putt, Inc., a Texas Corporation, its General Partner

/s/ Gary Little

By: Gary Little, Secretary, signing on behalf of the Corporation only

P.O. Box 162810

Austin, TX 78716-2807

garylittle22@gmail.com

(512) 330-9380 (w)

/s/ John Fontenot

John Fontenot

5410 Bee Caves Road

Austin, TX 78746

j.fontenot@sbcglobal.net

Grover Family L.P., a Texas Limited Partnership

By: Grover Management, LLC, a Texas Limited Liability Company, its General Partner

/s/ David B. Grover

By: David B. Grover, Manager/Director, signing on behalf of the LLC only

P.O. Box 3666

Midland, TX 79702

david@groverenergy.com

/s/ Doug Laufer

Doug Laufer

1603 Enfield, Suite 101

Austin, TX 78703

douglaufer@sbcglobal.net

(512) 899-2414 (w)

(512) 784-8873 (c)

/s/ Kyle McDonnold

Kyle McDonnold

505 N. Big Spring St., #204

Midland, TX 79701

kyle@mcdonnold.net

/s/ Elisabeth M. Newell

Elisabeth M. Newell

3300 Bee Caves Road

Suite #650-1193

Austin, TX 78746

liz@liznewell.com

Otis Energy, LLC, a Texas Limited Liability Company

/s/ Charles O. Newell, Jr.

By: Charles O. Newell, Jr., Manager, signing on behalf of the LLC only

3300 Bee Caves Road

Suite #650-122

Austin, TX 78746

chadnewell@aol.com

(512) 633-5490 (h)

/s/ James Reichle

James Reichle

5410 Bee Caves Road

Austin, TX 78746

(737) 701-4262

jamespreichle@yahoo.com

/s/ Amy Reichle

Amy Reichle

5410 Bee Caves Road

Austin, TX 78746

(737) 701-4262

jamespreichle@yahoo.com

SBN 2006 Energy Fund, Ltd., a Texas Limited Partnership

By: SBN Holdings, LLC, a Texas Limited Liability Company, its General Partner

/s/ Richard W. Schmidt

By: Richard W. Schmidt, Manager, signing on behalf of the LLC only

5410 Bee Caves Road

Austin, TX 78746

dschmidt@viejoenergy.com

(512) 329-8700 (w)

SBN Holdings, LLC, a Texas Limited Liability Company

/s/ Richard W. Schmidt

By: Richard W. Schmidt, Manager, signing on behalf of the LLC only

5410 Bee Caves Road

Austin, TX 78746

dickschmidt@viejoenergy.com

(512) 329-8700 (w)

/s/ Richard W. Schmidt

Richard W. Schmidt

5410 Bee Caves Road

Austin, TX 78746

dschmidt@viejoenergy.com

(512) 329-8700 (w)

SIAN Properties, a Texas General Partnership

/s/ Richard W. Schmidt

By: Richard W. Schmidt, its Partner

P.O. Box 50187

Austin, TX 78763-0187

dschmidt@viejoenergy.com

(512) 329-8700 (w)

SIAN12, LP, a Texas Limited Partnership

By: ARTANNE HOLDINGS, LLC, a Texas Limited Liability Company, its General Partner

/s/ Arthur W. Schmidt

By: Arthur W. Schmidt, Managing Member/Director, signing on behalf of the LLC only

5410 Bee Caves Road

Austin, TX 78746

arrtintx@aol.com

The Ninety-Six Corporation, a Texas Corporation

/s/ William D. Kennedy, Jr.

By: William D. Kennedy, Jr., President, signing on behalf of the Corporation only

500 West Texas Ave.

Suite 655

Midland, TX 79701

reports@kennedyoil.biz

Viejo Energy I, LLC, a Texas Limited Liability Company

/s/ Richard W. Schmidt

By: Richard W. Schmidt, President, signing on behalf of the LLC only

5410 Bee Caves Road

Austin, TX 78746-5227

dschmidt@viejoenergy.com

(512) 329-8700 (w)

Exhibit

Exhibit 31.1

CERTIFICATION

I, Charles B. Stanley, certify that:


1.	I have reviewed this Form 10-Q of QEP Resources, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

July 27, 2016

/s/ Charles B. Stanley

Charles B. Stanley

Chairman, President and Chief Executive Officer

Exhibit

Exhibit 31.2

CERTIFICATION

I, Richard J. Doleshek, certify that:


1.	I have reviewed this Form 10-Q of QEP Resources, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

July 27, 2016

/s/ Richard J. Doleshek

Richard J. Doleshek

Executive Vice President and Chief Financial Officer

Exhibit

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of QEP Resources, Inc. (the Company) on Form 10-Q for the period ended June 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, Chairman, President and Chief Executive Officer of the Company, and Richard J. Doleshek, Executive Vice President and Chief Financial Officer, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



	QEP RESOURCES, INC.

July 27, 2016

	/s/ Charles B. Stanley
	Charles B. Stanley
	Chairman, President and Chief Executive Officer

July 27, 2016

	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer