10-Q

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 March 31, 2014

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 500, 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  o    No  ý

At March 31, 2014, there were 180,070,357 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended March 31, 2014

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION			2
	ITEM 1.	FINANCIAL STATEMENTS	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013	3
		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT MARCH 31, 2014 AND DECEMBER 31, 2013	4
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013	5
		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	27
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	47
	ITEM 4.	CONTROLS AND PROCEDURES	51
PART II. OTHER INFORMATION			51
	ITEM 1.	LEGAL PROCEEDINGS	51
	ITEM 1A.	RISK FACTORS	51
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	52
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	52
	ITEM 4.	MINE SAFETY DISCLOSURES	52
	ITEM 5.	OTHER INFORMATION	52
	ITEM 6.	EXHIBITS	52
SIGNATURES			53

1

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended
	March 31,
	2014			2013
REVENUES	(in millions, except per share amounts)
Gas sales	$	222.5		$	197.6
Oil sales	288.7			194.2
NGL sales	101.1			68.4
Gathering, processing and other	44.4			45.6
Purchased gas, oil and NGL sales	227.2			190.7
Total Revenues	883.9			696.5
OPERATING EXPENSES
Purchased gas, oil and NGL expense	224.3			196.8
Lease operating expense	55.3			40.1
Gas, oil and NGL transportation and other handling costs	43.4			32.8
Gathering, processing and other	25.8			20.6
General and administrative	56.6			46.0
Production and property taxes	49.3			35.9
Depreciation, depletion and amortization	240.2			254.2
Exploration expenses	2.2			5.1
Impairment	2.0			—
Total Operating Expenses	699.1			631.5
Net gain (loss) from asset sales	2.4			(0.2		)
OPERATING INCOME	187.2			64.8
Realized and unrealized losses on derivative contracts (See Note 8)	(80.9		)	(34.6		)
Interest and other income	2.9			2.0
Income from unconsolidated affiliates	2.2			1.3
Interest expense	(42.5		)	(39.4		)
INCOME (LOSS) BEFORE INCOME TAXES	68.9			(5.9		)
Income tax (provision) benefit	(23.4		)	2.2
NET INCOME (LOSS)	45.5			(3.7		)
Net income attributable to noncontrolling interest	(5.8		)	(0.6		)
NET INCOME (LOSS) ATTRIBUTABLE TO QEP	$	39.7		$	(4.3	)
Earnings Per Common Share Attributable to QEP
Basic total	$	0.22		$	(0.02	)
Diluted total	$	0.22		$	(0.02	)
Weighted-average common shares outstanding
Used in basic calculation	179.7			177.0
Used in diluted calculation	180.0			177.0
Dividends per common share	$	0.02		$	0.02

See notes accompanying the condensed consolidated financial statements.

2

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended
	March 31,
	2014			2013
	(in millions)
Net income (loss)	$	45.5		$	(3.7	)
Other comprehensive income (loss), net of tax:
Reclassification of previously deferred derivative gains(1)	—			(20.1		)
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss (2)	0.1			0.4
Amortization of prior service cost (3)	0.9			0.8
Total pension and other postretirement plans adjustments	1.0			1.2
Other comprehensive income (loss)	1.0			(18.9		)
Comprehensive income (loss)	46.5			(22.6		)
Comprehensive income attributable to noncontrolling interests	(5.8		)	(0.6		)
Comprehensive income (loss) attributable to QEP	$	40.7		$	(23.2	)

____________________________

⁽¹⁾  Presented net of income tax benefit of $11.9 millionduring the three months ended March 31, 2013.

⁽²⁾  Presented net of income tax expense of $0.1 million during the three months endedMarch 31, 2014 and $0.2 million during the three months endedMarch 31, 2013, respectively.

⁽³⁾  Presented net of income tax expense of $0.4 million during the three months endedMarch 31, 2014 and $0.5 million during the three months endedMarch 31, 2013, respectively.

See notes accompanying the condensed consolidated financial statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2014			December 31, 2013
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	3.9		$	11.9
Accounts receivable, net	586.5			408.5
Fair value of derivative contracts	—			0.2
Gas, oil and NGL inventories, at lower of average cost or market	7.8			13.4
Deferred income taxes - current	50.4			30.6
Prepaid expenses and other	61.8			54.4
Total Current Assets	710.4			519.0
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	12,401.4			11,571.4
Unproved properties	1,102.5			665.1
Midstream field services	1,719.2			1,698.1
Marketing and resources	89.4			85.5
Material and supplies	64.8			59.0
Total Property, Plant and Equipment	15,377.3			14,079.1
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,146.5			4,930.9
Midstream field services	425.0			409.7
Marketing and resources	24.2			22.1
Total Accumulated Depreciation, Depletion and Amortization	5,595.7			5,362.7
Net Property, Plant and Equipment	9,781.6			8,716.4
Investment in unconsolidated affiliates	38.5			39.0
Fair value of derivative contracts	3.9			1.0
Restricted Cash	—			50.0
Other noncurrent assets	45.2			51.4
TOTAL ASSETS	$	10,579.6		$	9,376.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	78.4		$	90.9
Accounts payable and accrued expenses	581.0			434.9
Production and property taxes	62.3			51.8
Interest payable	34.2			37.2
Fair value of derivative contracts	71.8			26.7
Total Current Liabilities	827.7			641.5
Long-term debt	3,919.2			2,997.5
Deferred income taxes	1,601.7			1,560.6
Asset retirement obligations	204.3			191.8
Fair value of derivative contracts	2.9			—
Other long-term liabilities	108.1			108.6
Commitments and contingencies (see Note 11)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized;  180.7 million and 179.7 million shares issued, respectively	1.8			1.8
Treasury stock - 0.6 million and 0.4 million shares, respectively	(20.9		)	(14.9		)
Additional paid-in capital	508.1			498.4
Retained earnings	2,953.8			2,917.8
Accumulated other comprehensive loss	(25.5		)	(26.5		)
Total Common Shareholders' Equity	3,417.3			3,376.6
Noncontrolling interest	498.4			500.2
Total Equity	3,915.7			3,876.8
TOTAL LIABILITIES AND EQUITY	$	10,579.6		$	9,376.8

See notes accompanying the condensed consolidated financial statements.

4

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
	2014			2013
	(in millions)
OPERATING ACTIVITIES
Net income (loss)	$	45.5		$	(3.7	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	240.2			254.2
Deferred income taxes	20.7			(9.3		)
Impairment	2.0			—
Equity-based compensation	6.8			6.1
Amortization of debt issuance costs and discounts	1.7			1.5
Net (gain) loss from asset sales	(2.4		)	0.2
Income from unconsolidated affiliates	(2.2		)	(1.3		)
Distributions from unconsolidated affiliates and other	2.7			1.5
Unrealized loss on derivative contracts	45.5			85.3
Changes in operating assets and liabilities	(38.1		)	(162.4		)
Net Cash Provided by Operating Activities	322.4			172.1
INVESTING ACTIVITIES
Property acquisitions	(946.6		)	(23.6		)
Property, plant and equipment, including dry exploratory well expense	(330.2		)	(361.0		)
Proceeds from disposition of assets	2.9			1.5
Acquisition deposit held in escrow	50.0			—
Net Cash Used in Investing Activities	(1,223.9		)	(383.1		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(12.5		)	60.0
Long-term debt issued	300.0			—
Long-term debt issuance costs paid	(1.1		)	—
Proceeds from credit facility	1,643.0			1,027.0
Repayments of credit facility	(1,021.5		)	(866.5		)
Treasury stock repurchases	(5.5		)	(7.5		)
Other capital contributions	2.9			2.1
Dividends paid	(3.6		)	(3.6		)
Excess tax benefit on equity-based compensation	(0.6		)	1.0
Distribution to noncontrolling interest	(7.6		)	(1.5		)
Net Cash Provided by Financing Activities	893.5			211.0
Change in cash and cash equivalents	(8.0		)	—
Beginning cash and cash equivalents	11.9			—
Ending cash and cash equivalents	$	3.9		$	—
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	43.8		$	40.7
Cash paid for income taxes	$	—		4.9
Non-cash investing activities:
Change in capital expenditure accrual balance	$	(11.6	)	$	42.6

See notes accompanying the condensed consolidated financial statements.

5

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Nature of Business

QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business: oil and gas exploration and production; midstream field services; and energy marketing. These businesses are conducted through the Company’s three principal subsidiaries:

• QEP Energy Company (QEP Energy) acquires, explores for, develops and produces gas, oil, and NGL;

• QEP Field Services Company (QEP Field Services), which includes the ownership and operations of QEP Midstream Partners, LP (QEP Midstream), provides midstream field services, including gathering of natural gas, oil and water, natural gas processing, compression, and treating services, as well as NGL marketing services for affiliates and third parties; and

• QEP Marketing Company (QEP Marketing) markets affiliate and third-party oil and gas, and owns and operates an underground gas storage reservoir.

QEP's operations are focused in two major regions: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Oklahoma, Louisiana, and Texas) of the United States. QEP's corporate headquarters are located in Denver, Colorado.

Shares of QEP’s common stock trade on the New York Stock Exchange under the ticker symbol “QEP.”

Note 2 – Basis of Presentation of Interim Consolidated Financial Statements

The interim condensed consolidated financial statements contain the accounts of QEP and its majority-owned or controlled subsidiaries, including QEP Midstream (see Note 4 - QEP Midstream). The condensed consolidated financial statements also include the accounts of a variable interest entity where the Company is the primary beneficiary of the arrangements. 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, 2013.

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 months endedMarch 31, 2014, are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

Reclassifications

In the first quarter of 2013, QEP presented certain credit facility payments and borrowings on a net basis on the Condensed Consolidated Statements of Cash Flow. These borrowings and payments were reclassified to be presented on a gross basis on the Condensed Consolidated Statement of Cash Flow in order to conform with the current period presentation. This reclassification is entirely within "Financing Activities" and has no effect on other categories or total cash on the Condensed Consolidated Statements of Cash Flows or net income or earnings per share on the Condensed Consolidated Statements of Operations.

New accounting pronouncements

During the three months ended March 31, 2014, there were no new accounting pronouncements that were applicable to QEP.

6

Note 3 - Acquisition

Permian Basin Acquisition

On February 25, 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $945.0 million, subject to customary post-closing adjustments (the Permian Basin Acquisition). The acquired properties consist of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which creates a new core area of operation for QEP Energy. The acquisition was funded with $50.0 million of restricted cash, $300.0 million from the Company's expanded term loan and approximately $595.0 million from its revolving credit facility.

Concurrent with the Permian Basin Acquisition, QEP entered into a transaction structured as a reverse like-kind exchange in accordance with Section 1031 of the Internal Revenue Code. In connection with this reverse like-kind exchange, QEP assigned the ownership of the Permian Basin oil and gas properties acquired to a variable interest entity. QEP operates the properties pursuant to lease and management agreements with that entity, and has a call option which allows the Company to terminate the exchange transaction at any time up and until the expiration date of the exchange. Because the Company is the primary beneficiary of these arrangements, the properties acquired are included in its Condensed Consolidated Balance Sheet as of March 31, 2014, and all revenues earned, expenses incurred, and cash flows related to the properties will be included in the Company’s Condensed Consolidated Statements of Operations and Condensed Consolidated Statements of Cash Flows during the term of the agreement. The agreements will terminate upon the transfer of the acquired properties from the exchange accommodation titleholder to QEP following the exercise of the call option but in no event later than August 24, 2014, the expiration date for this exchange.

The Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included significant proved properties. QEP allocated the cost of the Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $14.9 million and net income of $3.7 million were generated from the acquired properties from February 25, 2014, to March 31, 2014, and are included in QEP's Condensed Consolidated Statements of Operations. During the quarter ended March 31, 2014, QEP Energy's acquisition-related costs of $0.5 million which are included in "General and administrative" on the Condensed Consolidated Statements of Operations. QEP incurred $1.1 million of debt issuance costs associated with increasing the size of term loan borrowings to fund a portion of the acquisition, which are included in "Other noncurrent assets" on the Condensed Consolidated Balance Sheet.

QEP Energy recorded the Permian Basin Acquisition on its Condensed Consolidated Balance Sheets; however, the final purchase price is subject to post-closing adjustments. The following table presents a summary of the Company's preliminary purchase accounting entries:

	As of March 31, 2014
	(in millions)
Consideration given:
Cash consideration	$	945.0
Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
Proved properties	$	516.1
Unproved properties	439.7
Asset retirement obligations	(9.7		)
Liabilities assumed	(1.1		)
Total fair value	$	945.0

The following unaudited, pro forma results of operations are provided for the three months endedMarch 31, 2014 and 2013. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the period presented or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the three months endedMarch 31, 2014 and 2013, the acquired properties' historical results of operations, and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the preliminary purchase price allocation. The pro forma results of

7

operations do not include any cost savings or other synergies that may result from the Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.

	Three Months Ended				Three Months Ended
	March 31, 2014				March 31, 2013
	Actual		Pro forma		Actual			Pro forma
	(in millions, except per share data)
Revenues	$	883.9	$	910.0	$	696.5		$	731.0
Net income attributable to QEP	39.7		46.7		(4.3		)	3.6
Earnings per common share attributable to QEP
Basic	$	0.22	$	0.26	$	(0.02	)	$	0.02
Diluted	0.22		0.26		(0.02		)	0.02

Note 4 - QEP Midstream

QEP Midstream is a publicly traded master limited partnership formed by QEP to own, operate, acquire and develop midstream energy assets. QEP Midstream's assets currently consist of ownership interests in four gathering systems and two FERC regulated pipelines, which provide oil and gas gathering and transportation services. These assets are located in, or within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota.

Initial Public Offering

On August 14, 2013, QEP Midstream completed its initial public offering (the IPO) of 20,000,000 common units, representing limited partner interests in QEP Midstream, at a price to the public of $21.00 per common unit. QEP Midstream received net proceeds of $390.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of $29.3 million. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit, providing additional net proceeds of $58.9 million, after deducting $4.1 million of underwriters' discounts and commissions and structuring fees, to QEP Midstream.

QEP Midstream used the net proceeds to repay its outstanding debt balance with QEP, which was assumed with the assets contributed to QEP Midstream, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to QEP Midstream. The following table is a reconciliation of proceeds from the IPO (in millions):

Total proceeds from the IPO	$	483.0
IPO Costs	(33.4		)
Net proceeds from the IPO	449.6
QEPM Revolving credit facility origination fees	(3.0		)
QEPM Repayment of outstanding debt with QEP	(95.5		)
Net proceeds distributed to QEP from the IPO	$	351.1

QEP Midstream Partners GP, LLC (the General Partner), a wholly owned subsidiary of QEP Field Services, serves as the general partner of QEP Midstream. QEP Field Services owns a 57.8% interest in QEP Midstream and consolidates QEP Midstream for financial reporting purposes with the portion not owned by QEP Field Services reflected as a reduction to net income and equity as a noncontrolling interest.

8

Note 5 – Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income attributable to QEP 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 receive dividends.

Unvested equity-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. There were no anti-dilutive shares during the three months endedMarch 31, 2014. During the three months ended March 31, 2013, 0.3 million shares were not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss.

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

	Three Months Ended
	March 31,
	2014	2013
	(in millions)
Weighted-average basic common shares outstanding	179.7	177.0
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.3	—
Average diluted common shares outstanding	180.0	177.0

Note 6 – 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, production facilities, midstream assets, 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 $205.4 million and $193.6 million ARO liability for the periods ended March 31, 2014 and December 31, 2013, $1.1 million and $1.8 million was included, respectively, as a current liability in "Accounts payable and accrued expenses" on the Condensed Consolidated Balance Sheets.

9

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

	Asset Retirement Obligations
	2014
	(in millions)
ARO liability at January 1,	$	193.6
Accretion	2.0
Additions(1)	10.9
Revisions	(0.3		)
Liabilities settled	(0.8		)
ARO liability at March 31,	$	205.4

____________________________

⁽¹⁾ Additions includes $9.7 million related to the Permian Basin Acquisition.

Note 7 – 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, but does not change existing guidance as to whether or not an instrument is carried at fair value. 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 8 - 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.

In addition, QEP has interest rate swaps that it has determined are Level 2 financial instruments. The fair values of the interest rate swaps are determined using the market standard methodology of discounting the future expected cash flows that would occur under the contractual terms of the swap. The variable interest rates used in the calculation of projected cash flows are based on an expectation of future interest rates derived from observable market interest rate curves. QEP incorporates credit valuation adjustments to reflect both its nonperformance risk and the respective counterparty's nonperformance risk in the fair value measurements. While the credit valuation adjustments are not observable inputs, they are not significant to the overall valuation and the other inputs used to value the interest rate swaps are observable Level 2 inputs.

10

The fair value of financial assets and liabilities at March 31, 2014, is shown in the table below:

	Fair Value Measurements
	March 31, 2014
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.9	$	—	$	(5.9	)	$	—
Commodity derivative instruments - long-term	—		0.5		—		0.6			1.1
Interest rate swaps - long-term	—		2.8		—		—			2.8
Total financial assets	$	—	$	9.2	$	—	$	(5.3	)	$	3.9
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	73.0	$	—	$	(5.9	)	$	67.1
Interest rate swaps - short-term	—		4.7		—		—			4.7
Commodity derivative instruments - long-term	—		2.3		—		0.6			2.9
Total financial liabilities	$	—	$	80.0	$	—	$	(5.3	)	$	74.7

____________________________

⁽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 8 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

The fair value of financial assets and liabilities at December 31, 2013, is shown in the table below:

	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.5	$	—	$	(5.3	)	$	0.2
Commodity derivative instruments - long-term	—		0.4		—		—			0.4
Interest rate swaps - long-term	—		0.6		—		—			0.6
Total financial assets	$	—	$	6.5	$	—	$	(5.3	)	$	1.2
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	29.4	$	—	$	(5.3	)	$	24.1
Interest rate swaps - short-term	—		2.6		—		—			2.6
Total financial liabilities	$	—	$	32.0	$	—	$	(5.3	)	$	26.7

_______________________

⁽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 8 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

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The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to 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
	March 31, 2014				December 31, 2013
	(in millions)
Financial assets
Cash and cash equivalents	$	3.9	$	3.9	$	11.9	$	11.9
Financial liabilities
Checks outstanding in excess of cash balances	$	78.4	$	78.4	$	90.9	$	90.9
Long-term debt	$	3,919.2	$	4,018.0	$	2,997.5	$	3,034.9

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 asset retirement obligations 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 remaining reserve lives. A reconciliation of the Company’s asset retirement obligations is presented in Note 6 – Asset Retirement Obligations.

Note 8 – 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 100.0% of forecasted production from proved reserves. In addition, QEP may enter into commodity derivative contracts on a portion of its extracted NGL volumes in its midstream business and a portion of its gas sales and purchases for marketing transactions. QEP does not enter into commodity derivative instruments for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps to realize a known price 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, oil, or NGL between the parties at settlement. Swap 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 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 IntercontinentalExchange, Inc. (ICE), Brent oil prices as the reference price. QEP also enters into crude oil basis swaps to achieve a fixed price swap for a portion of its oil that it sells at prices that reference ICE Brent and Light Louisiana Sweet (LLS).

QEP enters into commodity derivative transactions that do not 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.

Effective January 1, 2012, QEP elected to de-designate all of its gas, oil and NGL derivative contracts that were previously designated as cash flow hedges and discontinue hedge accounting prospectively. As a result of discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were fixed in Accumulated Other Comprehensive Income (AOCI) as of the de-designation date and are being reclassified into the Condensed Consolidated Statements of Operations as the transactions settle and affect earnings. As of December 31, 2013, all mark-to-market value was reclassified from AOCI. During the three months ended March 31, 2013, $20.1 million of unrealized gains, after tax, were reclassified from AOCI into the Condensed Consolidated Statements of Operations in "Realized and unrealized losses on derivative contracts" as the transactions settled.

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All realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012, are presented in the Condensed Consolidated Statements of Operations in "Realized and unrealized losses on derivative contracts" below operating income.

QEP also uses interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk associated with its $600.0 million term loan. For the $300.0 million term loan issued during 2012, QEP locked in a fixed interest rate of 1.07% in exchange for a variable interest rate indexed to the one-month LIBOR. For the incremental $300.0 million borrowed under the term loan during 2014, QEP locked in a fixed interest rate of 0.86%. The average effective interest rate on the $600.0 million term loan is 2.96%. The interest rate swaps settle monthly and will mature in March 2017.

QEP Energy Derivative Contracts

The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative contracts as of March 31, 2014: 

Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	NYMEX	22.0	$	4.22
2014	SWAP	IFNPCR	60.5	$	4.08
2015	SWAP	NYMEX	25.6	$	4.14
2015	SWAP	IFNPCR	7.3	$	3.97
Oil sales			(Bbls)
2014	SWAP	NYMEX WTI	8.1	$	92.61
2015	SWAP	NYMEX WTI	4.0	$	87.64

The following table sets forth QEP Energy's oil basis swaps as of March 31, 2014:

Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
Oil basis swaps			(Bbls)
2014	NYMEX WTI	ICE Brent	0.6	$	13.78
2014	NYMEX WTI	LLS	0.5	$	4.00
2015	NYMEX WTI	LLS	0.1	$	4.00

QEP Marketing Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage and for marketing transactions in which QEP Marketing sells gas volumes at a fixed price. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of March 31, 2014:

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	IFNPCR	2.9	$	3.75
Gas purchases			(MMBtu)
2014	SWAP	IFNPCR	0.9	$	3.82

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QEP's Derivative Contracts

The following table sets forth QEP’s notional amount and interest rate for its interest rate swaps outstanding as of March 31, 2014:

Notional amount	Type of Contract	Maturity	Fixed Rate Paid	Variable Rate Received
(in millions)
$300.0	Swap	March 2017	1.07%	One-month LIBOR
$300.0	Swap	March 2017	0.86%	One-month LIBOR
$600.0			0.96%

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	March 31, 2014		December 31, 2013		March 31, 2014		December 31, 2013
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	5.9	$	5.5	$	73.0	$	29.4
Interest rate swaps	Fair value of derivative contracts	—		—		4.7		2.6
Long-term:
Commodity	Fair value of derivative contracts	0.5		0.4		2.3		—
Interest rate swaps	Fair value of derivative contracts	2.8		0.6		—		—
Total derivative instruments		$	9.2	$	6.5	$	80.0	$	32.0

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

	Three Months Ended
Derivative instruments not designated as cash flow hedges	March 31,
	2014			2013
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	(20.4	)	$	44.6
Oil derivative contracts	(12.9		)	5.2
QEP Marketing
Gas derivative contracts	(1.4		)	1.5
Total realized (losses) gains on commodity derivative contracts	(34.7		)	51.3
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	(24.3		)	(64.3		)
Oil derivative contracts	(20.9		)	(19.7		)
QEP Marketing
Gas derivative contracts	(0.3		)	(1.7		)
Total unrealized losses on commodity derivative contracts	(45.5		)	(85.7		)
Total realized and unrealized losses on commodity derivative contracts	$	(80.2	)	$	(34.4	)
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(0.7	)	$	(0.6	)
Unrealized gains (losses) on interest rate swaps
Unrealized (losses) gains on interest rate swaps	—			0.4
Total realized and unrealized losses on interest rate swaps	$	(0.7	)	$	(0.2	)
Total net realized (losses) gains on derivative contracts	$	(35.4	)	$	50.7
Total net unrealized losses on derivative contracts	(45.5		)	(85.3		)
Grand Total	$	(80.9	)	$	(34.6	)

Note 9 – Restructuring Costs

In December 2013, QEP announced its plan to pursue a separation of its midstream business, QEP Field Services. In connection with this announcement, the Board of Directors approved an employee retention plan to provide substantially all QEP Field Services' employees as of December 1, 2013, with a one-time lump-sum cash payment on December 31, 2014, or whenever the separation of QEP Field Services occurs, whichever is earlier, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated prior to such date.

During the first quarter of 2012, QEP began incurring costs related to the closure of its Oklahoma City office and the subsequent consolidation of its Southern Region operations into a single regional office located in Tulsa. During the second half of 2012, QEP incurred additional restructuring and reorganization costs related to consolidating various corporate and accounting functions to the Denver corporate headquarters. The creation of one office for QEP’s Southern Region as well as the consolidation of corporate and accounting functions increased efficiency, team-based collaboration and organizational productivity. As part of the reorganization, QEP incurred costs associated with the severance, retention and relocation of employees, additional pension expenses, exit costs associated with the termination of operating leases arising from office space that will no longer be utilized by the Company and other expenses. All remaining restructuring costs related to the office consolidations were incurred during 2013.

15

The following table summarizes, by line of business, each major type of restructuring cost expected to be incurred and the total amounts recorded in "General and administrative" expense on the Condensed Consolidated Statements of Operations for the respective periods indicated:

	Total Restructuring Costs
	Total Expected to be Incurred		Recognized in Income
			Period from Inception to March 31, 2014		Three Months Ended March 31,
					2014		2013
QEP Energy	(in millions)
One-time termination benefits	$	3.3	$	3.3	$	—	$	0.2
Retention & relocation expense	3.7		3.7		—		0.1
Lease termination costs	0.6		0.6		—		—
Total restructuring costs	$	7.6	$	7.6	$	—	$	0.3
QEP Field Services
One-time termination benefits	$	—	$	—	$	—	$	—
Retention & relocation expense	10.1		3.2		2.3		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	10.1	$	3.2	$	2.3	$	—
QEP Marketing
One-time termination benefits	$	0.3	$	0.3	$	—	$	0.1
Retention & relocation expense	—		—		—		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	0.3	$	0.3	$	—	$	0.1
Total QEP
One-time termination benefits	$	3.6	$	3.6	$	—	$	0.3
Retention & relocation expense	13.8		6.9		2.3		0.1
Lease termination costs	0.6		0.6		—		—
Total restructuring costs	$	18.0	$	11.1	$	2.3	$	0.4

The following is a reconciliation of the restructuring liability, by line of business, which is included within “Accounts payable and accrued expenses” on the Condensed Consolidated Balance Sheets:

	QEP Energy		QEP Field Services		QEP Marketing		Total
	(in millions)
Balance at December 31, 2013	$	—	$	0.8	$	—	$	0.8
Costs incurred and charged to expense	—		2.3		—		2.3
Costs paid or otherwise settled	—		—		—		—
Balance at March 31, 2014	$	—	3.1		—		$	3.1

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Note 10 – Debt

As of the indicated dates, the principal amount of QEP’s debt, including amounts outstanding under its and QEP Midstream's revolving credit facilities, QEP's term loan and QEP's senior notes consisted of the following:

	March 31, 2014			December 31, 2013
	(in millions)
QEP's revolving credit facility due 2016	$	1,101.5		$	480.0
QEP Midstream's revolving credit facility due 2018	—			—
Term loan due 2017	600.0			300.0
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
Total principal amount of debt	3,923.3			3,001.8
Less unamortized discount	(4.1		)	(4.3		)
Total long-term debt outstanding	$	3,919.2		$	2,997.5

Of the total debt outstanding on March 31, 2014, amounts outstanding under QEP's revolving credit facility due August 25, 2016, QEP Midstream's revolving credit facility due August 14, 2018, QEP's term loan due April 18, 2017, the 6.05% Senior Notes due September 1, 2016, and the 6.80% Senior Notes due April 1, 2018, will mature within the next five years.

Credit Facilities

QEP's Credit Facility

QEP’s unsecured revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a syndicate of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit facility also contains an accordion provision that would allow for the amount of the facility to be increased to $2.0 billion and a provision whereby the maturity can be extended for up to two additional one-year periods, with the agreement of the lenders.

During the three months endedMarch 31, 2014 and 2013, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.19% and 2.35%, respectively. At March 31, 2014 and December 31, 2013, QEP was in compliance with the covenants under the credit agreement. At March 31, 2014, there was $1,101.5 million outstanding and $3.8 million of letters of credit issued under the credit facility.

QEP Midstream's Credit Facility

On August 14, 2013, QEP Midstream entered into a $500.0 million senior secured revolving credit facility with a group of financial institutions, which matures on August 14, 2018. QEP Midstream's credit facility contains an accordion provision that allows for the amount of the facility to be increased to $750.0 million with the agreement of the lenders. QEP Midstream's credit facility is available for QEP Midstream's working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of QEP Midstream's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries, are pledged as collateral under the credit facility. In addition, the credit agreement contains restrictions and events of default customary for agreements of this nature.

There have been no borrowings under QEP Midstream's credit facility, and at March 31, 2014, and December 31, 2013, QEP Midstream was in compliance with the covenants under the QEP Midstream credit agreement.

QEP is not a borrower or guarantor of QEP Midstream's credit facility. In addition, QEP is not subject to any of the restrictions or covenants contained in QEP Midstream's credit agreement. Outstanding indebtedness under QEP Midstream's credit facility is not included in the definition of indebtedness under QEP's credit agreement.

17

Term Loan

QEP's $600.0 million unsecured term loan facility provides for borrowings at short-term interest rates and contains covenants, restrictions, and interest rates that are substantially the same as QEP’s revolving credit facility. The term loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. In conjunction with the Permian Basin Acquisition, QEP borrowed the incremental $300.0 million available under the facility and increased total borrowings under the term loan to $600.0 million. There were no changes to the maturity date, pricing or covenants in the credit agreement. QEP incurred $1.1 million of debt issuance costs associated with the new term loan issuance.

During the three months endedMarch 31, 2014 and 2013, QEP’s weighted-average interest rate on borrowings from the term loan was 1.59% and 2.26%, respectively. At March 31, 2014 and December 31, 2013, QEP was in compliance with the covenants under the term loan credit agreement.

Senior Notes

At March 31, 2014, 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 some or 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 11 - Contingencies

QEP is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. QEP assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated 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 could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, QEP may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matter. QEP's litigation loss contingencies are discussed below. QEP is unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. QEP believes, however, that the resolution of pending proceedings (after accruals and insurance coverage) will not be material to QEP's financial position, but could be material to results of operations in a particular quarter or year.

Environmental Claims

In October 2009, QEP received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from unpermitted work resulting in the discharge of dredged and/or fill material into waters of the United States at three sites located in Caddo and Red River Parishes, Louisiana. Region 6 of the U.S. Environmental Protection Agency (EPA) has assumed lead responsibility for enforcement of the cease and desist order and any possible future orders for the removal of unauthorized fills and/or civil penalties under the Clean Water Act. On June 28, 2013, the EPA issued to QEP an Administrative Complaint for the alleged violations. QEP and the EPA reached an agreement to settle the alleged violations through an Administrative Order, under the terms of which QEP paid an administrative penalty of $0.2 million. The Administrative Order is final. In 2012, QEP completed a field audit, which identified 112 additional instances affecting approximately 90 acres where work may have been conducted in violation of the Clean Water Act. QEP has disclosed each of these instances to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. QEP is working with the EPA and the COE to resolve these matters, which will require the Company to undertake certain mitigation and permitting activities, and may require QEP to pay a monetary penalty.

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In July 2010, QEP received a Notice of Potential Penalty (NOPP) from the Louisiana Department of Environmental Quality (LDEQ) regarding the assumption of ownership and operatorship of a single facility in Louisiana prior to transferring the facility's air quality permit. In 2011, QEP completed an internal audit, which identified 424 facilities in Louisiana for which QEP both failed to submit a complete permit application and to receive approval from the department prior to construction, modification, or operation. QEP has corrected and disclosed all instances of non-compliance to the LDEQ and is working with the department to resolve the NOPP. The LDEQ has assumed lead responsibility for enforcement of the NOPP, and may require the Company to pay a monetary penalty. 

Litigation

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services' former affiliate, Questar Gas Company (QGC), filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the 1993 Agreement) executed when the parties were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of QEP Field Services' systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of the Offering, the assets and agreement discussed above were assigned to QEP Midstream. QGC netted the disputed amount from its monthly payments of the gathering fees to QEP Field Services and has continued to net such amounts from its monthly payment to QEP Midstream. As of March 31, 2014, QEP Midstream has deferred revenue of $9.9 million related to the QGC disputed amount. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add QEP Midstream as a defendant in the litigation. QEP Midstream has been indemnified by QEP for costs, expenses and other losses incurred by QEP Midstream in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement entered into between QEP Midstream and QEP in connection with the IPO.

Rocky Mountain Resources, LLC v. QEP Energy Company, Wexpro Company, Ultra Resources, Inc. and Lance Oil & Gas Company, Inc., Civil No. 2011-7816, District Court of Sublette County, Wyoming. Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint on March 30, 2011, seeking determination of the existence of a 4% overriding royalty interest in State of Wyoming oil and gas Lease No. 79-0645 covering Section 16, T32-N R-109-W, Sublette County, Wyoming. QEP and the other defendants are current lessees of Lease 79-0645. Rocky Mountain alleges that the defendants have received benefits from Lease 79-0645 and 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. Rocky Mountain asserts claims for quiet title, declaratory judgment, breach of contract, breach of duty of good faith, conversion, constructive trust and prejudgment interest. The plaintiffs seek damages, but specific monetary damages are not asserted.

Gatti et al v. State of Louisiana et al, 589,350, 19th JDC, Parish of East Baton Rouge, Louisiana. In this putative class action arising out of the unitization practices and orders of the Louisiana Commissioner of Conservation (Commissioner), plaintiffs seek to represent a class of all Haynesville Shale mineral owners (alleged to be over 50,000 in number) against the Commissioner and all Haynesville Shale unit operators. Plaintiffs filed their complaint on April 8, 2010, and claim that the Commissioner exceeded his statutory authority in creating and perpetuating units larger than the area that can be efficiently and economically drained by a single well. They seek declaratory relief that would nullify all such improper orders, along with an unspecified amount of monetary damages from the unit operators sufficient to compensate the putative class members for the alleged dilution of their true interest in unit production as a result of "oversized" units and the "cloud on title" caused by having excessive and improperly sized units purport to hold their mineral leases via unit operations. All defendants filed exceptions to the plaintiffs' petition on the primary ground that plaintiffs had failed to comply with the exclusive statutory judicial review procedure (Louisiana Revised Statutes 30:12), which the trial court granted, dismissing the action in its entirety. On January 15, 2014, the Louisiana First Circuit Court of Appeal reversed and reinstated plaintiffs' claims. Defendants intend to seek review of the Louisiana Supreme Court, which review is discretionary.

Yannick Gagné and others similarly situated v. QEP Resources, Inc., No. 480-06-1-132, Superior Court, Province of Quebec, Canada. Plaintiffs seek to represent a class of all persons who sustained damages as a result of the July 6, 2013 train derailment in Lac-Mégantic, Quebec, which resulted in substantial loss of life and property. The fourth amended motion to authorize the bringing of a class action was filed on February 19, 2014, and names numerous defendants. The plaintiffs contend that QEP, and other producer defendants, sold Bakken crude oil to third-party purchasers in North Dakota, who resold the oil and transported it on the derailed train. The allegations are that QEP and the producer defendants, among other things, failed to ensure that the oil was adequately processed to remove volatile gases and vapors, knowingly added volatile light end petroleum liquids and/or vapors or blended the crude with condensate, failed to conduct adequate well site testing to determine the proper h

19

azard classification of the oil, failed to properly classify the shipping requirements for the oil, failed to take reasonable care to ensure that the oil was properly labeled and shipped, failed to identify the risk of the train derailment and take action to prevent it, and failed to adopt, implement and enforce rules and procedures pertaining to the safe shipment of the oil. The plaintiffs seek damages, but specific monetary damages are not asserted.

XTO Energy Inc. v. QEP Field Services Company, Civil No. 140900709, Third Judicial District Court, State of Utah. XTO Energy Inc. (XTO), filed this complaint in Utah state court on January 30, 2014, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, unjust enrichment and an accounting related to a 2010 gas processing agreement (the Agreement). QEP Field Services processes XTO’s natural gas on a firm basis under the Agreement. The Agreement requires QEP Field Services to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is disputing QEP Field Services allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes. The plaintiffs seek damages, but specific monetary damages are not asserted.

Note 12 – Equity-Based Compensation

QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance-based share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over time as the stock options, restricted shares, and performance-based share units vest. Deferred equity-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 10.9 million shares available for future grants under the LTSIP at March 31, 2014. Equity-based compensation expense is recognized in “General and administrative” on the Condensed Consolidated Statements of Operations. During the three months endedMarch 31, 2014, QEP recognized $6.8 million in total compensation expense related to equity-based compensation compared to $6.1 million during the three months endedMarch 31, 2013.

QEP Midstream maintains a unit-based compensation plan for officers, directors and employees of the general partner of QEP Midstream and its affiliates and any consultants, affiliates of the general partner, or other individuals who perform services for QEP Midstream. The QEP Midstream 2013 Long-Term Incentive Plan (the QEP Midstream LTIP) permits various types of awards, including awards of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Awards granted during 2013 under the QEP Midstream LTIP will be settled with QEP Midstream units. During the three months endedMarch 31, 2014, QEP recognized $0.4 million in compensation expense related to QEP Midstream LTIP.

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:

	Stock Option Assumptions
	Three Months Ended
	March 31, 2014
Weighted-average grant-date fair value of awards granted during the period	$	10.12
Weighted-average risk-free interest rate	1.31		%
Weighted-average expected price volatility	37.2		%
Expected dividend yield	0.25		%
Expected term in years at the date of grant	4.5

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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, 2013	1,794,187		$	27.90
Granted	279,458		31.67
Exercised	(29,479	)	23.01
Outstanding at March 31, 2014	2,044,166		$	28.49	3.91	$	5.2
Options Exercisable at March 31, 2014	1,480,337		$	27.56	3.02	$	5.1
Unvested Options at March 31, 2014	563,829		$	30.93	6.24	$	0.1

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.2 million and $4.2 million during the three months endedMarch 31, 2014 and 2013, respectively. The Company realized $0.1 million and $1.4 million of income tax benefit for the three months endedMarch 31, 2014 and 2013, respectively, which had no significant impact on Additional Paid-in-Capital (APIC) pool as of March 31, 2014. As of March 31, 2014, $4.7 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.43 years. During the three months endedMarch 31, 2014, QEP received $0.7 million in cash in relation to the exercise of stock options during 2014.

Restricted Shares

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 three months endedMarch 31, 2014 and 2013, was $15.1 million and $14.8 million, respectively. The Company realized $1.5 million and $0.3 million of income tax expense for the three months endedMarch 31, 2014 and 2013, respectively, with a $0.6 million impact to the Company's APIC pool as of March 31, 2014. The weighted average grant-date fair value of restricted stock was $31.69 per share and $30.12 per share for the three months endedMarch 31, 2014 and 2013, respectively. As of March 31, 2014, $35.5 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.53 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, 2013	1,388,953		$	30.96
Granted	844,552		31.69
Vested	(524,672	)	31.89
Forfeited	(18,170	)	31.28
Unvested balance at March 31, 2014	1,690,663		$	31.03

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 but delivered in cash at the end of the performance period. The weighted average grant-date fair value of the performance share units was $31.69 per share and $30.12 per share for the three months endedMarch 31, 2014 and 2013, respectively. As of March 31, 2014, $12.8 million of unrecognized compensation cost, representing the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.40 years.

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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, 2013	480,660		$	32.33
Granted	241,321		31.69
Vested and paid out	(55,659	)	39.07
Vested and canceled (1)	(51,361	)	39.07
Unvested balance at March 31, 2014	614,961		$	30.90

____________________________

⁽¹⁾  Represents units that vested but were not paid out. Payout of the performance share units are dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period.

Note 13 – Employee Benefits

The Company maintains closed, defined-benefit pension and postretirement medical plans. QEP's pension plans include a qualified and a nonqualified retirement plan. The Company's postretirement medical plan is unfunded and provides certain health care and life insurance benefits for certain retired employees. During the three months endedMarch 31, 2014, the Company made contributions of $2.7 million to its funded qualified pension plan, and $0.9 million to its unfunded nonqualified retirement plan. Contributions to funded qualified plans increase plan assets while contributions to unfunded nonqualified plans are used to fund current benefit payments. During the remainder of 2014, the Company expects to contribute approximately $5.4 million to its funded qualified pension plan, $4.0 million to its unfunded nonqualified pension plans and approximately $0.2 million for retiree health care and life insurance benefits.

The following table sets forth the Company’s pension and postretirement benefits net periodic benefit costs:

	Pension
	Three Months Ended
	March 31,
	2014			2013
	(in millions)
Service cost	$	0.7		$	1.0
Interest cost	1.4			1.2
Expected return on plan assets	(1.2		)	(1.0		)
Amortization of prior service costs (1)	1.2			1.2
Amortization of actuarial losses (1)	0.2			0.6
Periodic expense	$	2.3		$	3.0

____________________________

⁽¹⁾  Amortization of prior service costs and actuarial losses out of AOCI are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."

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	Postretirement Benefits
	Three Months Ended
	March 31,
	2014		2013
	(in millions)
Service cost	$	—	$	—
Interest cost	0.1		0.1
Amortization of prior service costs (1)	0.1		0.1
Periodic expense	$	0.2	$	0.2

____________________________

⁽¹⁾  Amortization of prior service costs out of AOCI are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."

Note 14 – Operations by Line of Business

QEP’s lines of business include gas and oil exploration and production (QEP Energy), midstream field services (QEP Field Services), which includes the ownership and operation of QEP Midstream, and marketing and corporate (QEP Marketing & Resources). The lines of business are managed separately and therefore the financial information is presented separately due to the distinct differences in the nature of operations of each line of business, among other factors. QEP Field Services owns a 57.8% ownership interest in QEP Midstream and it is consolidated under the voting interest model in QEP Field Services' operating results. The outside ownership interest in QEP Midstream is presented separately as a noncontrolling interest.

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The following table is a summary of operating results for the three months endedMarch 31, 2014, by line of business:

	QEP Energy			QEP Field Services			QEP Marketing  & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	613.2		$	79.8		$	190.9		$	—		$	883.9
From affiliated customers	—			26.4			312.1			(338.5		)	—
Total revenues	613.2			106.2			503.0			(338.5		)	883.9
Operating expenses
Purchased gas, oil and NGL expense	38.0			—			497.9			(311.6		)	224.3
Lease operating expense	56.4			—			—			(1.1		)	55.3
Gas, oil and NGL transportation and other handling costs	64.5			3.6			—			(24.7		)	43.4
Gathering, processing and other	—			25.7			0.4			(0.3		)	25.8
General and administrative	41.8			14.4			1.2			(0.8		)	56.6
Production and property taxes	47.4			1.8			0.1			—			49.3
Depreciation, depletion and amortization	223.4			16.5			0.3			—			240.2
Other operating expenses	4.2			—			—			—			4.2
Total operating expenses	475.7			62.0			499.9			(338.5		)	699.1
Net gain from asset sales	2.4			—			—						2.4
Operating income	139.9			44.2			3.1			—			187.2
Realized and unrealized losses on derivative contracts	(78.5		)	—			(2.4		)	—			(80.9		)
Interest and other income	2.9			—			48.8			(48.8		)	2.9
Income from unconsolidated affiliates	—			2.2			—			—			2.2
Interest expense	(48.9		)	(0.6		)	(41.8		)	48.8			(42.5		)
Income before income taxes	15.4			45.8			7.7			—			68.9
Income tax provision	(5.9		)	(14.6		)	(2.9		)	—			(23.4		)
Net income	9.5			31.2			4.8			—			45.5
Net income attributable to noncontrolling interest	—			(5.8		)	—			—			(5.8		)
Net income attributable to QEP	$	9.5		$	25.4		$	4.8		$	—		$	39.7
Identifiable total assets	$	9,004.1		$	1,515.5		$	314.6		$	(254.6	)	$	10,579.6

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The following table is a summary of operating results for the three months endedMarch 31, 2013, by line of business:

	QEP Energy			QEP Field Services			QEP Marketing  & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	508.2		$	64.4		$	123.9		$	—		$	696.5
From affiliated customers	—			27.6			217.2			(244.8		)	—
Total revenues	508.2			92.0			341.1			(244.8		)	696.5
Operating expenses
Purchased gas, oil and NGL expense	65.7			5.1			342.5			(216.5		)	196.8
Lease operating expense	41.0			—			—			(0.9		)	40.1
Gas, oil and NGL transportation and other handling costs	56.2			2.8			—			(26.2		)	32.8
Gathering, processing and other	—			20.3			0.3			—			20.6
General and administrative	36.7			9.5			1.0			(1.2		)	46.0
Production and property taxes	34.7			1.1			0.1			—			35.9
Depreciation, depletion and amortization	238.1			15.8			0.3			—			254.2
Other operating expenses	5.1			—			—			—			5.1
Total operating expenses	477.5			54.6			344.2			(244.8		)	631.5
Net gain (loss) from assets sales	0.1			(0.3		)	—			—			(0.2		)
Operating income (loss)	30.8			37.1			(3.1		)	—			64.8
Realized and unrealized losses on derivative contracts	(34.2		)	—			(0.4		)	—			(34.6		)
Interest and other income	1.7			0.3			51.2			(51.2		)	2.0
Income from unconsolidated affiliates	—			1.3			—			—			1.3
Interest expense	(45.3		)	(4.0		)	(41.3		)	51.2			(39.4		)
(Loss) income before income taxes	(47.0		)	34.7			6.4			—			(5.9		)
Income tax benefit (provision)	17.2			(12.5		)	(2.5		)	—			2.2
Net (loss) income	(29.8		)	22.2			3.9			—			(3.7		)
Net income attributable to noncontrolling interest	—			(0.6		)	—			—			(0.6		)
Net (loss) income attributable to QEP	$	(29.8	)	$	21.6		$	3.9		$	—		$	(4.3	)
Identifiable total assets	$	7,756.8		$	1,660.6		$	294.9		$	(568.4	)	$	9,143.9

Note 15 - Subsequent Events

QEP Energy Divestitures

In May 2014, QEP Energy entered into three separate purchase and sale agreements related to the disposition of certain of its non-core properties in the Midcontinent Region and other non-core assets in the Northern Region for an aggregate sales price of approximately $807.5 million, subject to customary purchase price adjustments. The aggregate net book value of the properties being sold is approximately $886.0 million as of the effective date of the sale, January 1, 2014. Any gain or loss on the sale recorded by the Company will be determined based upon the final purchase price, which is subject to customary purchase price adjustments. The Company expects to close these transactions in the second quarter of 2014 and will use proceeds to repay indebtedness under our revolving credit facility.

QEP Field Services Divestiture

In May 2014, QEP Field Services entered into a purchase and sale agreement to sell 40% of the membership interests in Green River Processing, LLC (Green River Processing) for approximately $230.0 million, subject to customary purchase price adjustments, to QEP Midstream. The transaction is expected to close in July 2014 and will be accounted for as a transaction

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between entities under common control with the difference between the carrying amount and the purchase price recorded to equity.

Green River Processing is a wholly owned subsidiary of QEP Field Services and will own the Blacks Fork processing complex and the Emigrant Trail processing plant, both of which are located in southwest Wyoming. The combined processing capacity of Green River Processing is 890 MMcf per day, of which 560 MMcf per day is cryogenic capacity and 330 MMcf per day is Joule-Thomson processing capacity. In addition, there is 15,000 bbl per day of NGL fractionation capacity at the Blacks Fork processing complex.

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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 2013 Annual Report on Form 10-K filing and analyzes the changes in the results of operations between the three months endedMarch 31, 2014 and 2013. For definitions of commonly used gas and oil terms found in this Quarterly Report on Form 10-Q, please refer to the “Glossary of Commonly Used Terms” provided in QEP’s 2013 Annual Report on Form 10-K.

OVERVIEW

QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business: oil and gas exploration and production; midstream field services; and energy marketing. These businesses are conducted through the Company’s three principal subsidiaries:

• QEP Energy Company (QEP Energy) acquires, explores for, develops and produces gas, oil, and NGL;

• QEP Field Services Company (QEP Field Services), which includes the ownership and operations of QEP Midstream Partners, LP (QEP Midstream), provides midstream field services, including gathering of natural gas, oil and water, natural gas processing, compression, and treating services, as well as NGL marketing services for affiliates and third parties, and;

• QEP Marketing Company (QEP Marketing) markets affiliate and third-party oil and gas, and owns and operates an underground gas storage reservoir.

QEP's operations are focused in two major regions: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Oklahoma, Louisiana, and Texas) of the United States. QEP's corporate headquarters are located in Denver, Colorado. QEP owns and operates, directly or through its ownership in QEP Midstream, gathering, natural gas processing and treating facilities in the majority of its core producing areas outside of Louisiana, Oklahoma and Texas.

On August 14, 2013, QEP Midstream completed its IPO of 20,000,000 common units, representing limited partner interests in QEP Midstream, at a price to the public of $21.00 per common unit. QEP Midstream received net proceeds of $390.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of approximately $29.3 million. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit, providing additional net proceeds of $58.9 million, after deducting $4.1 million of underwriters' discounts and commissions and structuring fees, to QEP Midstream. QEP Midstream used the net proceeds to repay its outstanding debt balance with QEP, which was assumed with the assets contributed to QEP Midstream, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to QEP Midstream.

QEP contributed gathering assets to QEP Midstream which are located in, or within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota. QEP utilized the proceeds of the cash distribution it received from QEP Midstream in connection with the IPO to fund ongoing operations, to repay debt under the Company's revolving credit facility and for general corporate purposes. QEP owns a 57.8% ownership interest in QEP Midstream and consolidates QEP Midstream for financial reporting purposes.

Strategies

We create value for our shareholders through returns-focused growth, superior execution and a low-cost structure. To achieve these objectives we strive to:

• operate in a safe and environmentally responsible manner;

• allocate capital to those projects that generate the highest returns;

• acquire businesses and assets that complement or expand our current business;

• divest of non-core assets;

• maintain a sustainable, diverse inventory of low-cost, high-margin resource plays;

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• be in the highest-potential areas of the resource plays in which we operate;

• build contiguous acreage positions that drive operating efficiencies;

• be the operator of our assets, whenever possible;

• be the low-cost driller and producer in each area where we operate;

• maximize the value of our midstream assets;

• actively market our QEP Energy production to maximize value;

• utilize derivative contracts to mitigate the impact of gas, oil or NGL price volatility and fluctuating interest rates, while locking in acceptable cash flows required to support future capital expenditures;

• attract and retain the best people; and

• maintain a capital structure that allows us the necessary financial flexibility with which to invest in organic growth and potential acquisition opportunities, as they may arise.

Acquisitions

As part of the Company's strategy to increase its crude oil reserves and drilling inventory, on February 25, 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $945.0 million, subject to customary post-closing adjustments (the Permian Basin Acquisition). The acquired properties consist of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which creates a new core area of operation for QEP Energy. The acquisition was funded with $50.0 million of restricted cash, $300.0 million from the Company's expanded term loan and approximately $595.0 million from its revolving credit facility.

While QEP believes that it can grow production and reserves from its extensive inventory of identified drilling locations, 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 its low-cost operating model and financial strength, enhance its ability to pursue acquisition opportunities.

Divestitures

The Company will periodically divest select non-core portfolio assets to redirect capital towards higher-return projects. In addition to the divestitures of non-core properties in 2013, which resulted in total cash proceeds of $205.8 million, in May 2014, QEP entered into entered into three separate purchase and sale agreements related to the disposition of certain of its non-core exploration and production (E&P) properties in the Midcontinent Region and other non-core assets in the Northern Region for an aggregate sales price of approximately $807.5 million, subject to customary purchase price adjustments. The Company expects to close these transactions in the second quarter of 2014 and will use the proceeds to repay debt incurred to fund the Permian Basin Acquisition and to focus future investment on QEP’s operations in its core areas in the Williston, Permian, Pinedale, and Uinta basins.

In January 2014, QEP's Board of Directors authorized the Company to develop a plan to separate the business of QEP Field Services, including the Company's interest in QEP Midstream, from QEP.

In May 2014, QEP Field Services entered into a purchase and sale agreement to sell 40% of the membership interests in Green River Processing, LLC for approximately $230.0 million, subject to customary purchase price adjustments, to QEP Midstream. The transaction is expected to close in July 2014.

Outlook

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, Woodford "Cana" shale 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 has a large inventory of lower-risk, predictable development drilling locations across its acreage holdings in the onshore United States that provide a solid base for consistent growth in organic production and reserves. QEP believes that it has one of the lowest cash operating structures among its E&P company peers. However, in certain of its resource plays, QEP, along with its peers, has experienced increased drilling and completion costs which could impact near term drilling plans.

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While historically a natural gas producer, the Company has increased its focus on growing the relative proportion of oil and NGL production in its E&P business. During the first quarter of 2014, which includes one month of results from the Permian Basin Acquisition, QEP Energy increased its oil and NGL production by 50% compared to the first quarter of 2013. Additionally, oil and NGL revenue represented 61% of QEP Energy's field-level revenue during the first quarter of 2014, up from 55% during the first quarter of 2013.

In January 2014, QEP's Board of Directors authorized the repurchase of up to $500.0 million of the Company's outstanding shares of common stock. This authorization is effective until January 2015. The timing and amount of any QEP share repurchases will depend upon a number of factors, including general market conditions, the Company’s financial position and the estimated intrinsic value of the Company’s shares. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time. During the quarter ended March 31, 2014, no shares were repurchased.

Financial and Operating Results

QEP Energy reported total equivalent production of 73.7 Bcfe during the first quarter of 2014, a decrease of 6% compared to the first quarter of 2013. Gas production decreased to 44.5 Bcfe in the first quarter of 2014, a decrease of 24% compared to the first quarter of 2013, which was partially offset by an increase to oil and NGL production. In the first quarter of 2014 oil and NGL production increased to 4,880.3 Mbbls, a combined increase of 50% from the first quarter of 2013. The Company's 2012 Williston Basin acquisition contributed 1,582 Mbbls oil and NGL production in the first quarter of 2014. Additionally, QEP Energy completed the Permian Basin Acquisition on February 25, 2014, which contributed 173.0 Mbbls oil and NGL production, $14.9 million of revenue and $3.7 million of net income during the period from February 25, 2014 to March 31, 2014, which are included in QEP's Condensed Consolidated Statements of Operations. QEP Energy also benefited from higher average realized prices (including the impact of settled commodity derivatives) which increased 16% to $7.34 per Mcfe for the first quarter of 2014 compared to the first quarter of 2013.

During the first quarter of 2014, QEP Field Services' NGL sales volumes increased 96% and fee-based processing volumes were 2% higher than the first quarter of 2013, while gathering throughput volumes decreased 13%. QEP Field Services also experienced an increase in the average net realized NGL sales price of 9%, whereas the fee-based processing rates and gas gathering rates both decreased by 6% during the first quarter of 2014.

Factors Affecting Results of Operations

Oil, Gas, and NGL Prices

Historically, field-level prices received for QEP's gas, oil and NGL production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than natural gas demand, driven by advances in drilling and completion technologies, including horizontal drilling and multi-stage hydraulic fracturing. These changes have allowed producers to extract increased quantities of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supplies have resulted in downward pressure on natural gas prices, while concern about the global economy and other factors has created volatility in the price of oil. Additionally, QEP's NGL prices are affected by ethane recovery. When ethane is recovered as an NGL instead of being sold, the average NGL barrel sales price decreases as the ethane price is lower than the remaining NGL components. 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 activity and related capital expenditures, liquidity, rate of growth, and costs of goods and services required to drill and complete wells, and may impact the carrying value of its oil and natural gas properties.

QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to 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% of its forecasted annual production by the end of the first quarter of each fiscal year. At March 31, 2014, assuming forecasted 2014 annual production of 286 Bcfe, QEP Energy had approximately 63% of its forecasted gas equivalent production covered with fixed-price swaps, including 61% of its forecasted gas production and 82% of its forecasted oil production covered with fixed-price swaps. See Part 1, Item 3 “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk Management” for further details concerning QEP’s commodity derivatives transactions. In addition, as a result of the continued spread between oil and gas prices, QEP Energy has allocated approximately 98% of its forecasted 2014 drilling and completion capital expenditure budget to oil and liquids-rich gas projects in its portfolio.

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Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the outlook of the global economy, including political unrest in Eastern Europe, the Middle East, and Africa; a slowing of growth in Asia; the United States federal budget deficit; the potential for future shut-downs of federal government offices including the Department of Interior (including the Bureau of Land Management (BLM) and Bureau of Indian Affairs (BIA), which process permits to drill and rights-of-way for construction of gathering lines and other midstream infrastructure on federal (BLM) and Native American (BIA and BLM) minerals and surface); changes in regulatory oversight policy; and commodity price volatility. 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 gas, oil and NGL supply, demand and prices, 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.

Supply, Demand and Other Market Risk Factors

U.S. natural gas directed drilling rig count decreased in 2012 and 2013 and has continued to decline in 2014 as producers reduced drilling activity for dry natural gas in response to current natural gas prices and have continued to direct investment toward oil and liquid-rich activities. A reduction in natural gas production has lagged the downturn in the natural gas rig count, because natural gas producers had a significant inventory of drilled wells waiting on completion, continued efficiency gains have allowed more wells to be drilled and completed per operating rig, and higher per-well natural gas production from horizontal wells now dominates U.S. completions. As a result, U.S. natural gas production continued to increase throughout 2013 despite the decreased rig-count. However, strong natural gas demand from electric power generation, cold winter weather during the 2013-2014 heating season, and other demand sources have caused a general firming of natural gas prices during the last half of 2013 and into 2014. Despite recent increases in natural gas prices, QEP expects U.S. natural gas prices to remain range-bound over the near term. Relatively low natural gas prices have caused U.S. E&P companies, including QEP, to shift capital investments away from predominantly dry gas areas toward plays that are known to have liquids-rich gas and oil. This shift in focus has caused domestic NGL production to increase dramatically. Increased NGL production and price dislocations from infrastructure bottlenecks in certain regions have all contributed to a weakening of domestic NGL prices, particularly ethane. QEP expects that ethane prices will continue to be range-bound until new ethylene crackers are built; however, the prices of heavier components of the NGL barrel have strengthened as a result of recent weather conditions combined with newly commissioned export facilities. QEP anticipates global oil prices will remain near current levels, assuming the global economy and socio-political backdrops remain relatively stable. Disruption to the global oil supply system, political and/or economic instability, and/or other factors could trigger additional volatility in oil prices. In addition, transportation, refining, or other infrastructure constraints could introduce significant price differentials between regional markets where QEP sells its oil production and national (NYMEX or Cushing) and global (Brent or U.S. Gulf Coast) markets. Because of the global and regional price volatility and the uncertainty around the natural gas, oil and NGL price environments, QEP continues to manage its capital spending program and liquidity accordingly.

Potential for Future Asset Impairments

The carrying value of the Company's properties is sensitive to declines in gas, oil and NGL prices. These assets are at risk of impairment if future prices for gas, oil 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 oil, gas and NGL production, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward gas, oil or NGL prices alone could result in an impairment of properties. The Company recorded a $2.0 million impairment of unproved properties and no impairment of proved properties during the first quarter of 2014.

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. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in QEP’s quarterly operating results. 

Critical Accounting Estimates

QEP’s significant accounting policies are described in Item 7 of Part II of its 2013 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 gas and oil reserves, successful efforts accounting for gas and oil operations, impairment of gas and oil properties, asset retirement obligations, accounting for derivative contracts, revenue recognition, environmental obligations, litigation and other contingencies, benefit plan

30

obligations, equity-based compensation, income taxes, and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.

RESULTS OF OPERATIONS

Net Income (Loss)

QEP’s net income for the first quarter of 2014 was $39.7 million, or $0.22 per diluted share, compared to a net loss of $4.3 million, or $0.02 per diluted share, in the first quarter of 2013. The increase in the first quarter of 2014 was due to a $39.3 million increase in QEP Energy’s net income, a $3.8 million increase in QEP Field Services' net income and a $0.9 million increase in QEP Marketing and Resources' net income. QEP Energy's net income increase was primarily related to higher oil and NGL production and higher realized gas prices partially offset by a realized loss on derivative instruments in the first quarter of 2014 compared to a realized gain in the comparable 2013 period as well as higher lease operating and production tax expenses and lower oil and NGL realized prices and gas production when compared to the first quarter of 2013. The increase in QEP Field Services’ net income during the first quarter of 2014 was driven by a $14.0 million increase in the keep-whole processing margin partially offset by a $3.8 million lower gathering margin and higher net income attributable to noncontrolling interest due to QEP Midstream's formation in the third quarter of 2013.

The following table provides a summary of net income (loss) attributable to QEP by line of business:

	Three Months Ended March 31,
	2014		2013			Change
	(in millions)
QEP Energy	$	9.5	$	(29.8	)	$	39.3
QEP Field Services	25.4		21.6			3.8
QEP Marketing and Resources	4.8		3.9			0.9
Net income (loss) attributable to QEP	$	39.7	$	(4.3	)	$	44.0
Earnings (loss) per diluted share	$	0.22	$	(0.02	)	$	0.24
Average diluted shares	180.0		177.0			3.0

Adjusted EBITDA

Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company’s cash flow, liquidity, and ability to incur and service debt, fund capital expenditures and make distributions to shareholders. The use of this measure allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. It is also an important measure for comparing the Company’s financial performance to other gas and oil producing companies. 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.

The following table provides a summary of Adjusted EBITDA by line of business:

	Three Months Ended March 31,
	2014		2013			Change
	(in millions)
QEP Energy	$	331.8	323.7			$	8.1
QEP Field Services	53.2		53.2			—
QEP Marketing and Resources	1.3		(1.9		)	3.2
Adjusted EBITDA	$	386.3	$	375.0		$	11.3

Adjusted EBITDA increased to $386.3 million in the first quarter of 2014 from $375.0 million in the first quarter of 2013, due to a 55% increase in oil production, a 41% increase in NGL production, and a 10% increase in average net realized equivalent gas prices at QEP Energy partially offset by a 24% decrease in gas production and an 11% and 12% decrease in average net realized equivalent oil and NGL prices, respectively.

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The following tables are reconciliations of Adjusted EBITDA to net income (loss) attributable to QEP, the most comparable GAAP financial measure:

	QEP Energy			QEP Field Services			QEP Marketing & Resources			QEP
Three Months Ended March 31, 2014	(in millions)
Net income attributable to QEP	$	9.5		$	25.4		$	4.8		$	39.7
Unrealized losses on derivative contracts	45.2			—			0.3			45.5
Net gain from asset sales	(2.4		)	—			—			(2.4		)
Interest and other income	(2.9		)	—			—			(2.9		)
Income tax provision	5.9			14.6			2.9			23.4
Interest expense (income)(1)	48.9			0.4			(7.0		)	42.3
Depreciation, depletion and amortization(2)	223.4			12.8			0.3			236.5
Impairment	2.0			—			—			2.0
Exploration expenses	2.2			—			—			2.2
Adjusted EBITDA	$	331.8		$	53.2		$	1.3		$	386.3
Three Months Ended March 31, 2013
Net (loss) income attributable to QEP	$	(29.8	)	$	21.6		$	3.9		$	(4.3	)
Unrealized losses on derivative contracts	84.0			—			1.3			85.3
Net (gain) loss from asset sales	(0.1		)	0.3			—			0.2
Interest and other income	(1.7		)	(0.3		)	—			(2.0		)
Income tax (benefit) provision	(17.2		)	12.5			2.5			(2.2		)
Interest expense	45.3			4.0			(9.9		)	39.4
Depreciation, depletion and amortization(2)	238.1			15.1			0.3			253.5
Exploration expenses	5.1			—			—			5.1
Adjusted EBITDA	$	323.7		$	53.2		$	(1.9	)	$	375.0

__________________________

⁽¹⁾ Excludes noncontrolling interest's share of $0.2 million during the three months endedMarch 31,2014, of interest expense attributable to QEP Midstream.

⁽²⁾ Excludes noncontrolling interest's share of $3.7 million and $0.7 million during the three months endedMarch 31,2014 and 2013, respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C and QEP Midstream.

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QEP ENERGY

The following table provides a summary of QEP Energy’s financial and operating results:

	Three Months Ended March 31,
	2014			2013			Change
Revenues	(in millions)
Gas sales	$	222.5		$	197.6		$	24.9
Oil sales	288.7			194.2			94.5
NGL sales	63.1			50.6			12.5
Purchased gas, oil and NGL sales	37.1			62.8			(25.7		)
Other	1.8			3.0			(1.2		)
Total revenues	613.2			508.2			105.0
Operating expenses
Purchased gas, oil and NGL expense	38.0			65.7			(27.7		)
Lease operating expense	56.4			41.0			15.4
Gas, oil and NGL transportation and other handling costs	64.5			56.2			8.3
General and administrative	41.8			36.7			5.1
Production and property taxes	47.4			34.7			12.7
Depreciation, depletion and amortization	223.4			238.1			(14.7		)
Exploration expenses	2.2			5.1			(2.9		)
Impairment	2.0			—			2.0
Total operating expenses	475.7			477.5			(1.8		)
Net gain from asset sales	2.4			0.1			2.3
Operating income	139.9			30.8			109.1
Realized (loss) gain on derivative instruments	(33.3		)	49.8			(83.1		)
Unrealized losses on derivative instruments	(45.2		)	(84.0		)	38.8
Interest and other income	2.9			1.7			1.2
Interest expense	(48.9		)	(45.3		)	(3.6		)
Income (loss) before income taxes	15.4			(47.0		)	62.4
Income tax (provision) benefit	(5.9		)	17.2			(23.1		)
Net income (loss) attributable to QEP Energy	$	9.5		$	(29.8	)	$	39.3
Production volumes (Bcfe)
Northern Region
Pinedale	20.9			21.7			(0.8		)
Williston Basin	16.8			9.0			7.8
Uinta Basin	6.2			5.8			0.4
Other Northern	2.5			3.5			(1.0		)
Southern Region
Haynesville/Cotton Valley	14.4			22.3			(7.9		)
Permian Basin	1.2			—			1.2
Midcontinent	11.7			15.7			(4.0		)
Total production	73.7			78.0			(4.3		)
Total equivalent prices (per Mcfe)
Average equivalent field-level price	$	7.79		$	5.67		$	2.12
Commodity derivative impact	(0.45		)	0.64			(1.09		)
Net realized equivalent price	$	7.34		$	6.31		$	1.03

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Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP Energy’s major revenue categories for the three months endedMarch 31, 2014, compared to the three months endedMarch 31, 2013:

	Gas			Oil			NGL			Total
	(in millions)
QEP Energy Production Revenues
Three months ended March 31, 2013 Revenues	$	197.6		$	194.2		$	50.6		$	442.4
Changes associated with volumes (1)	(47.3		)	106.6			20.9			80.2
Changes associated with prices (2)	72.2			(12.1		)	(8.4		)	51.7
Three months ended March 31, 2014 Revenues	$	222.5		$	288.7		$	63.1		$	574.3

____________________________

⁽¹⁾  The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three months endedMarch 31, 2014, as compared to the three months endedMarch 31, 2013, by the average field-level price for the three months endedMarch 31, 2013.

⁽²⁾  The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level prices from the three months endedMarch 31, 2014, as compared to the three months endedMarch 31, 2013, by volumes for the three months endedMarch 31, 2014.

Gas Volumes and Prices

	Three Months Ended March 31,
	2014			2013		Change
Gas production volumes (Bcf)
Northern Region
Pinedale	15.9			19.0		(3.1		)
Williston Basin	0.7			0.7		—
Uinta Basin	4.1			4.1		—
Other Northern	2.2			2.8		(0.6		)
Southern Region
Haynesville/Cotton Valley	14.3			22.2		(7.9		)
Permian Basin	0.2			—		0.2
Midcontinent	7.1			9.7		(2.6		)
Total production	44.5			58.5		(14.0		)
Gas prices (per Mcf)
Northern Region	$	5.12		$	3.37	$	1.75
Southern Region	4.89			3.38		1.51
Average field-level price	$	5.00		$	3.38	$	1.62
Commodity derivative impact	(0.46		)	0.76		(1.22		)
Net realized price	$	4.54		$	4.14	$	0.40

Gas revenues increased$24.9 million, or 13%, in the first quarter of 2014 when compared to the first quarter of 2013, due to higher field-level prices partially offset by lower volumes. The decrease in production volumes was primarily driven by the continued suspension of QEP's Haynesville/Cotton Valley operated drilling program. Additionally, production decreased in QEP's Pinedale field due to partial ethane recovery in the first quarter of 2014, in which ethane is extracted from the gas stream and sold as an NGL, compared to ethane rejection in 2013, as well as completions of wells in late 2013 in which QEP had no working interest. Production also decreased for the Midcontinent properties as a result of fewer net well completions throughout the second half of 2013 and the first quarter of 2014 compared to the prior year period and divestitures of non-core properties in the Midcontinent in the third quarter of 2013. Gas field-level prices increased 48% during the first quarter of 2014 as a result of higher index prices.

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Oil Volumes and Prices

	Three Months Ended March 31,
	2014			2013		Change
Oil production volumes (Mbbl)
Northern Region
Pinedale	133.1			148.8		(15.7		)
Williston Basin	2,520.2			1,269.0		1,251.2
Uinta Basin	212.4			216.3		(3.9		)
Other Northern	49.1			84.3		(35.2		)
Southern Region
Haynesville/Cotton Valley	9.2			11.6		(2.4		)
Permian Basin	140.0			—		140.0
Midcontinent	248.0			408.9		(160.9		)
Total production	3,312.0			2,138.9		1,173.1
Oil prices (per bbl)
Northern Region	$	86.53		$	91.50	$	(4.97	)
Southern Region	91.80			87.99		3.81
Average field-level price	$	87.16		$	90.81	$	(3.65	)
Commodity derivative impact	(3.91		)	2.43		(6.34		)
Net realized price	$	83.25		$	93.24	$	(9.99	)

Oil revenues increased$94.5 million, or 49%, in the first quarter of 2014 when compared to the first quarter of 2013, due to higher volumes partially offset by lower average field-level prices. The increase in production volumes was primarily driven by increases in the Williston Basin due to the continued development of the properties acquired in the 2012 acquisition and continued development drilling on QEP's existing pre-acquisition acreage. The Company also had an additional 140.0 Mbbls of production in the first quarter of 2014 from its Permian Basin Acquisition, which closed February 25, 2014. These increases were partially offset by a decrease in the Midcontinent due to decreased well completions and divestitures of non-core properties in the third quarter of 2013 and a decrease in the other Northern Region due to divestitures of non-core properties in the second quarter of 2013.

Field-level oil prices decreased 4% in the first quarter of 2014, primarily due to lower oil prices in the Williston Basin, a portion of which are referenced against Brent prices, which decreased in first quarter of 2014 compared to 2013.

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NGL Volumes and Prices

	Three Months Ended March 31,
	2014		2013		Change
NGL production volumes (Mbbl)
Northern Region
Pinedale	714.8		311.9		402.9
Williston Basin	160.9		112.1		48.8
Uinta Basin	139.4		77.4		62.0
Other Northern	2.0		10.7		(8.7		)
Southern Region
Haynesville/Cotton Valley	7.8		5.3		2.5
Permian Basin	33.0		—		33.0
Midcontinent	510.4		591.1		(80.7		)
Total production	1,568.3		1,108.5		459.8
NGL prices (per bbl)
Northern Region	$	39.74	$	60.20	$	(20.46	)
Southern Region	41.24		33.14		8.10
Average field-level price	$	40.26	$	45.64	$	(5.38	)
Commodity derivative impact	—		—		—
Net realized price	$	40.26	$	45.64	$	(5.38	)

NGL revenues increased$12.5 million, or 25%, during the first quarter of 2014, when compared to the first quarter of 2013, due to increased production volumes partially offset by a decreased average price per barrel. Pinedale and Uinta NGL volumes increased due to partial ethane recovery in the first quarter of 2014 compared to ethane rejection in the entire first quarter of 2013, while the Williston Basin NGL volumes grew as a result of increased development drilling. These increases were partially offset by a decrease in the Midcontinent due to decreased well completions and divestitures of non-core properties in the third quarter of 2013.

NGL prices decreased 12% during the first quarter of 2014 primarily as a result of partially recovering ethane from the wet gas production stream in Pinedale and Uinta during the first quarter of 2014, compared to no recovery in the first quarter of 2013. When ethane is recovered as an NGL instead of being sold as part of the gas stream, the average NGL barrel sales price decreases as the ethane price is lower than the remaining NGL components.

QEP Energy Resale Margin

QEP Energy purchases and resells gas, oil and NGL products in order to fulfill firm transportation contract commitments and mitigate potential losses. The difference between the price of the products purchased and sold creates a resale margin that represents a gain or loss for the Company. The following table is a summary of QEP Energy's financial results from its gas, oil and NGL resale activities:

	Three Months Ended March 31,
	2014			2013			Change
Resale Margin	(in millions)
Purchased gas, oil and NGL sales	$	37.1		$	62.8		$	(25.7	)
Purchased gas, oil and NGL expense	(38.0		)	(65.7		)	27.7
Resale margin loss	$	(0.9	)	$	(2.9	)	$	2.0

During the first quarter of 2014, QEP Energy recorded a loss on resale margin of $0.9 million compared to a loss of $2.9 million in the first quarter of 2013 as a result of its activities to utilize pipeline transportation commitments in Louisiana. The Company has transportation commitments in excess of its current production as a result of the continued suspension of its Haynesville drilling program.

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QEP Energy Drilling Activity

The following table presents operated and non-operated well completions for the three months endedMarch 31, 2014:

	Operated Completions		Non-operated Completions
	Three Months Ended		Three Months Ended
	March 31, 2014		March 31, 2014
	Gross	Net	Gross	Net
Northern Region
Pinedale	22	16.2	—	—
Williston Basin	14	12.9	20	1.3
Uinta Basin	—	—	—	—
Other Northern	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	14	0.4
Permian Basin	5	4.6	—	—
Midcontinent	1	0.9	40	3.3

The following table presents operated and non-operated wells being drilled or waiting on completion at March 31, 2014:

	Operated				Non-operated
	Being drilled		Waiting on completion		Being drilled		Waiting on completion
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	17	11.8	58	45.6	—	—	—	—
Williston Basin	17	15.1	24	19.1	33	2.2	10	1.0
Uinta Basin	1	1.0	1	1.0	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	7	0.6	5	0.1
Permian Basin	3	2.7	3	2.8	—	—	—	—
Midcontinent	—	—	4	3.8	5	0.3	20	0.6

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 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. As a result, QEP had 90 gross operated wells waiting on completion as of March 31, 2014.

Operating expenses

The following table presents certain QEP Energy operating expenses on a per unit of production basis.

	Three Months Ended March 31,
	2014		2013		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	3.03	$	3.05	$	(0.02	)
Lease operating expense	0.76		0.53		0.23
Gas, oil and NGL transportation and other handling costs	0.88		0.72		0.16
Production taxes	0.65		0.44		0.21
Operating Expenses	$	5.32	$	4.74	$	0.58

37

Depreciation, depletion and amortization. DD&A expense decreased $14.7 million, or $0.02 per Mcfe, in the first quarter of 2014 compared to the first quarter of 2013 due to expense decreases in Haynesville/Cotton Valley and the Midcontinent partially offset by an increase in the Williston Basin expense and additional expenses related to the Permian Basin Acquisition. The decrease in expense at Haynesville relates to decreased production whereas the decrease in the Midcontinent relates to divestitures of non-core properties in the second half of 2013. The increase in the Williston Basin expense relates to increased production partially offset by a lower rate due to additional proved reserves added at the end of the 2013.

Lease operating expense. The following table presents lease operating expenses (LOE) for QEP Energy by region on a unit of production basis:

	Three Months Ended March 31,
	2014		2013		Change
	(per Mcfe)
Northern Region	$	0.77	$	0.64	$	0.13
Southern Region	0.75		0.41		0.34
Average lease operating expense	0.76		0.53		0.23

QEP Energy’s LOE increased $15.4 million, or $0.23 per Mcfe, during the first quarter of 2014 compared to the first quarter of 2013. The Southern Region's LOE per Mcfe increase during the first quarter of 2014 was driven primarily by the Permian Basin Acquisition in the first quarter of 2014 as well as a per Mcfe increase in Haynesville/Cotton Valley properties due to declining production volume but relatively flat labor and pumper costs, fixed operating expenses due to the consistent well count and increased workover costs. The Northern Region increase was driven primarily by a per Mcfe increase in the Williston Basin due to increased water injection and disposal costs, overhead and utility costs in the current year attributable to increased well count and higher operating costs in the area.

Gas, oil and NGL transportation and other handling costs. Gas, oil and NGL transportation and other handling costs increased $8.3 million, or $0.16 per Mcfe, in the first quarter of 2014 when compared to the first quarter of 2013, due to cost increases in the Williston Basin, and declining production volumes in the Haynesville/Cotton Valley area.

Production and property taxes. In most states in which QEP Energy operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production taxes increased $12.7 million, or $0.21 per Mcfe, during the first quarter of 2014 as a result of increased gas, oil and NGL revenues due to higher field-level gas prices and higher oil and NGL production, which in recent years have generated more revenue per Mcfe than gas.

Exploration expense. Exploration expenses decreased $2.9 million during the first quarter of 2014 when compared with the first quarter of 2013. The decrease primarily related to decreases in exploration-related labor.

Impairment expense. During the first quarter of 2014, impairment expense was $2.0 million due to unproved property impairments due to changes in drilling plans.

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QEP FIELD SERVICES

The following table provides a summary of QEP Field Services’ financial and operating results:

	Three Months Ended March 31,
	2014			2013			Change
	(in millions)
Revenues
NGL sales	$	38.0		$	17.8		$	20.2
Processing (fee based) revenues	16.0			16.4			(0.4		)
Other processing fees	8.1			4.9			3.2
Gathering revenues	32.6			37.6			(5.0		)
Other gathering revenues	11.1			10.2			0.9
Purchased gas, oil and NGL sales	0.4			5.1			(4.7		)
Total revenues	106.2			92.0			14.2
Operating expenses
Purchased gas, oil and NGL expense	—			5.1			(5.1		)
Processing expense	4.4			4.1			0.3
Processing plant fuel and shrinkage	11.3			5.9			5.4
Gathering expense	10.0			10.3			(0.3		)
Gas, oil and NGL transportation and other handling costs	3.6			2.8			0.8
General and administrative	14.4			9.5			4.9
Taxes other than income taxes	1.8			1.1			0.7
Depreciation, depletion and amortization	16.5			15.8			0.7
Total operating expenses	62.0			54.6			7.4
Net loss from asset sales	—			(0.3		)	0.3
Operating income	44.2			37.1			7.1
Interest and other income	—			0.3			(0.3		)
Income from unconsolidated affiliates	2.2			1.3			0.9
Interest expense	(0.6		)	(4.0		)	3.4
Income before income taxes	45.8			34.7			11.1
Income tax provision	(14.6		)	(12.5		)	(2.1		)
Net income	31.2			22.2			9.0
Net income attributable to noncontrolling interest	(5.8		)	(0.6		)	(5.2		)
Net income attributable to QEP Field Services	$	25.4		$	21.6		$	3.8

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GatheringMargin

The following tables present a summary of QEP Field Services’ financial and operating results from gathering activities:

	Three Months Ended March 31,
	2014			2013			Change
Gathering Margin	(in millions)
Gathering revenues	$	32.6		$	37.6		$	(5.0	)
Other gathering revenues	11.1			10.2			0.9
Gathering expense	(10.0		)	(10.3		)	0.3
Gathering margin	$	33.7		$	37.5		$	(3.8	)
Operating Statistics
Gas gathering volumes (in millions of MMBtu)
For unaffiliated customers	51.8			54.1			(2.3		)
For affiliated customers	45.5			57.2			(11.7		)
Total Gas Gathering Volumes	97.3			111.3			(14.0		)
Average gas gathering revenue (per MMBtu)	$	0.34		$	0.34		$	—

During the first quarter of 2014, gathering margin declined10% when compared to the first quarter of 2013 due to a 13% decrease in gathering system throughput. Gathering system throughput decreased primarily as a result of a 42% decline at QEP Field Services' Northwest Louisiana Hub primarily due to lower QEP Energy production resulting from the continued suspension of drilling in Haynesville as well as lower gathering volumes on the Uinta gathering system and QEP Midstream's Vermillion gathering system.

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Processing Margin

The following table presents a summary of QEP Field Services’ gas processing financial and operating results:

	Three Months Ended March 31,
	2014			2013			Change
Processing Margin	(in millions)
NGL sales	$	38.0		$	17.8		$	20.2
Processing (fee-based) revenues	16.0			16.4			(0.4		)
Other processing fees	8.1			4.9			3.2
Processing expense	(4.4		)	(4.1		)	(0.3		)
Processing plant fuel and shrink expense	(11.3		)	(5.9		)	(5.4		)
Gas, oil and NGL transportation and other handling costs	(3.6		)	(2.8		)	(0.8		)
Processing margin	$	42.8		$	26.3		$	16.5
Keep-whole margin(1)	$	23.1		$	9.1		$	14.0
Operating Statistics
NGL sales (Mbbl)	669.2			341.1			328.1
Average net realized NGL sales price (per bbl)(2)	$	56.78		$	52.32		$	4.46
Fee-based processing volumes (in millions of MMBtu)
For unaffiliated customers	23.2			20.5			2.7
For affiliated customers	31.5			33.2			(1.7		)
Total fee-based processing volumes	54.7			53.7			1.0
Average fee-based processing revenue (per MMBtu)	$	0.29		$	0.31		$	(0.02	)

____________________________

⁽¹⁾  Keep-whole processing margin is calculated as NGL sales less processing plant fuel and shrink, gas, oil and NGL transportation and other handling costs.

⁽²⁾  Average net realized NGL sales price per gallon is calculated as NGL sales including realized gains from commodity derivative contracts settlements divided by NGL sales volumes.

QEP Field Services provides gas processing services under fee-based and keep-whole agreements. Approximately 69% and 83% of QEP Field Services' total margin was derived from fee-based gathering and processing agreements in the first quarter of 2014 and 2013, respectively. The decrease in the fee-based contribution to the total margin was due to the increase in the keep-whole margin.

Under keep-whole arrangements, QEP Field Services processes natural gas, sells the resulting NGL at market prices, and remits the energy equivalent value to its customers. Because the extraction of NGL from the natural gas during processing reduces the Btu content of the natural gas, QEP Field Services must acquire natural gas at market prices for return to its customers. Accordingly, under these arrangements the Company’s revenues and margins increase as the price of NGL increases relative to the price of natural gas and decrease as the price of NGL decreases relative to the price of natural gas.

QEP Field Services' keep-whole margin increased154% during the first quarter of 2014, compared to the first quarter of 2013, due to a 96%increase in NGL sales volumes. The increase in NGL sales volumes is the result of the Iron Horse II cryogenic processing plant operating during the entire first quarter of 2014 (start-up in late first quarter of 2013) and linefill cash-outs due to a contractual change in the first quarter of 2014. Also contributing to the higher NGL sales was an increase in the average net realized NGL sales price due to the higher propane prices and completion of the Blacks Fork fractionation and loading facility expansion which gives QEP Field Services the ability to sell products into local and regional markets. Average net realized NGL prices increased9% in the first quarter of 2014, primarily the result of rejection of ethane, which is normally the lower-value component of the composite NGL barrel. Partially offsetting the increase in keep-whole margins was an increase in processing and shrink expense primarily due to higher natural gas prices.

Fee-based processing revenues decreased slightly during the first quarter of 2014 compared to the first quarter of 2013 due to a 6% decrease in average fee-based processing rate partially offset by a 2%increase in fee-based processing volumes. During the first quarter of 2014, the increase in fee-based processing volumes was the result of additional gas processed at the Vermillion

41

and Iron Horse plants. The decrease in the average fee-based processing rate was due to increased processing volumes from producers with lower processing fees.

QEP MARKETING AND RESOURCES

The following table provides a summary of QEP Marketing and Resources' financial and operating results:

	Three Months Ended March 31,
	2014			2013			Change
	(in millions)
Revenues
Purchased gas, oil and NGL sales	$	501.5		$	339.3		$	162.2
Other	1.5			1.8			(0.3		)
Total revenues	503.0			341.1			161.9
Operating expenses
Purchased gas, oil and NGL expense	497.9			342.5			155.4
Gathering, processing and other	0.4			0.3			0.1
General and administrative	1.2			1.0			0.2
Production and property taxes	0.1			0.1			—
Depreciation, depletion and amortization	0.3			0.3			—
Total operating expenses	499.9			344.2			155.7
Operating income (loss)	3.1			(3.1		)	6.2
Realized (loss) gain on derivative instruments	(2.1		)	0.9			(3.0		)
Unrealized losses on derivative instruments	(0.3		)	(1.3		)	1.0
Interest and other income	48.8			51.2			(2.4		)
Interest expense	(41.8		)	(41.3		)	(0.5		)
Income before income taxes	7.7			6.4			1.3
Income tax provision	(2.9		)	(2.5		)	(0.4		)
Net income attributable to QEP Marketing	$	4.8		$	3.9		$	0.9

Resale Margin

The following table is a summary of QEP Marketing’s financial results from resale activities:

	Three Months Ended March 31,
	2014			2013			Change
Resale Margin	(in millions)
Purchased gas, oil and NGL sales	$	501.5		$	339.3		$	162.2
Purchased gas, oil and NGL expense	(497.9		)	(342.5		)	(155.4		)
Realized (loss) gain on derivative instruments	(2.1		)	0.9			(3.0		)
Resale margin gain (loss)	$	1.5		$	(2.3	)	$	3.8

Purchased gas, oil and NGL sales increased by $162.2 million, or 48%, during the first quarter of 2014, compared to the first quarter of 2013, due to a $37.4 million increase in resale gas sales, and a $124.8 million increase in resale oil and NGL sales. Resale gas sales increased due to a 53% increase in the resale price partially offset by a 17% decrease in resale gas volumes. Resale oil and NGL sales increased due to an 80% increase in resale volumes, partially offset by a 9% decrease in resale price.

Purchased gas, oil and NGL expense, which includes transportation expense, increased 45% in the first quarter of 2014, compared to the first quarter of 2013, due to a $31.8 million increase in resale gas purchases and a $123.6 million increase in resale oil and NGL purchases. Resale gas purchased increased due to a 50% increase in the resale price, partially offset by a 15% decrease in resale purchase volumes. Resale oil and NGL sales increased due to a 73% increase in resale purchase volumes, partially offset by a 9% decrease in resale purchase price.

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OTHER CONSOLIDATED EXPENSES AND INCOME

General and administrative expense. During the first quarter of 2014, general and administrative (G&A) expense increased $10.6 million, or 23% compared to the first quarter of 2013. The increase in G&A in 2014 was primarily due to a $2.6 million increase in labor costs due to the increased number of employees, a $2.3 million increase for retention bonuses related to the QEP Field Services separation to be paid in December 2014 or whenever the separation of QEP Field Services occurs, whichever is earlier (see Note 9 – Restructuring Costs, for additional information), and a $5.4 million increase in professional and outside services mainly related to the ongoing implementation of a new Enterprise Resource Planning (ERP) system, feasibility studies and current transactions, including the QEP Field Services separation, QEP Midstream operating as a public company, Permian Basin Acquisition and various divestitures of non-core properties.

Net gain from asset sales. In the first quarter of 2014, QEP Energy sold its interest in non-core unproved oil and gas properties resulting in a pre-tax gain on sale of $2.4 million.

Realized and unrealized (loss) gain on derivative contracts. Gains and losses on derivative instruments are comprised of both realized and unrealized gains and losses on QEP’s commodity derivative contracts and interest rate swaps, which are marked-to-market each quarter. During the first quarter of 2014, losses on commodity derivative instruments were $80.2 million, of which $34.7 million were realized and $45.5 million were unrealized. During the first quarter of 2013, losses on commodity derivative instruments were $34.4 million, of which $51.3 million were realized gains and $85.7 million were unrealized losses. Additionally, during the first quarter of 2014, losses from interest rate swaps were $0.7 million, all of which were realized, compared to a loss of $0.2 million during the first quarter of 2013, of which $0.6 million were realized losses offset by an unrealized gain of $0.4 million.

Interest expense. Interest expense increased $3.1 million, or 8% during the first quarter of 2014, compared to the first quarter of 2013. The increase was attributable to average debt levels in 2014 that were approximately $171.2 million, or 5%, higher than average debt levels in the first quarter of 2013. The increase in average debt levels is primarily related to additional borrowing on the credit facility and the increase in QEP's term loan to $600.0 million in the first quarter of 2014, both of which were used to fund the Permian Basin Acquisition.

Income taxes. Income tax provision was $23.4 million during the first quarter of 2014 compared to an income tax benefit of $2.2 million during the first quarter of 2013. The increased provision was primarily the result of higher income before income taxes for the first quarter of 2014, compared to a loss before income taxes for the first quarter of 2013.

LIQUIDITY AND CAPITAL RESOURCES

QEP seeks to fund its development projects by employing a capital structure and financing strategy to provide sufficient liquidity to withstand commodity price swings. QEP maintains a commodity price derivative strategy to reduce commodity price volatility and to provide certainty to cash flows. QEP funds its operations, capital expenditures and working capital requirements with cash flow from its operating activities and borrowings under its credit facilities. Periodically, QEP accesses debt and equity capital markets and sells properties to provide additional liquidity. The Company believes cash flow from operations, cash-on-hand and availability under its credit facility will be sufficient to fund the Company’s planned capital expenditures and operating expenses during the next 12 months and the foreseeable future. To the extent actual operating results differ from the Company’s estimates, QEP's liquidity could be adversely affected.

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The following table provides QEP’s available liquidity and debt to equity ratio compared to the previous period:

	March 31, 2014			December 31, 2013
	(in millions, except %)
Cash and cash equivalents	$	3.9		$	11.9
Amount available under the QEP credit facility (1)	394.7			1,016.2
Total liquidity	$	398.6		$	1,028.1
Total debt	$	3,919.2		$	2,997.5
Total common shareholders' equity	3,417.3			3,376.6
Ratio of debt to total capital (2)	53		%	47		%

____________________________

⁽¹⁾  See discussion of revolving credit facility below. Availability under QEP's credit facility is reduced by outstanding letters of credit of $3.8 million as of March 31, 2014, and December 31, 2013, and does not include the $500.0 million available under QEP Midstream's credit facility.

⁽²⁾  Defined as total debt divided by the sum of total debt plus common shareholders’ equity.

QEP's Credit Facility

QEP’s unsecured revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a syndicate of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit facility also contains an accordion provision that would allow for the amount of the facility to be increased to $2.0 billion and a provision whereby the maturity can be extended for up to two additional one-year periods, with the agreement of the lenders. QEP’s weighted-average interest rate on borrowings from its credit facility was 2.19% during the first quarter of 2014. At March 31, 2014, QEP was in compliance with the debt covenants under the credit agreement. At April 30, 2014, QEP had $1,138.5 million of borrowings and $3.8 million of letters of credit outstanding under its credit facility.

QEP Midstream's Credit Facility

On August 14, 2013, QEP Midstream entered into a $500.0 million senior secured revolving credit facility with a group of financial institutions, which matures on August 14, 2018. QEP Midstream's credit facility contains an accordion provision that allows for the amount of the facility to be increased to $750.0 million with the agreement of the lenders. QEP Midstream's credit facility is available for QEP Midstream's working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. In addition, QEP Midstream's credit facility includes a sublimit of up to $50.0 million for letters of credit and a sublimit of up to $25.0 million for swing line loans. Substantially all of QEP Midstream's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries, are pledged as collateral under the credit facility. In addition, the credit agreement contains restrictions and events of default customary for agreements of this nature.

There have been no borrowings under QEP Midstream's credit facility, and at March 31, 2014, QEP Midstream was in compliance with the covenants under the QEP Midstream credit agreement.

QEP is not a borrower or guarantor of QEP Midstream's credit facility. In addition, QEP is not subject to any of the restrictions or covenants contained in QEP Midstream's credit agreement. Outstanding indebtedness under QEP Midstream's credit facility is not included in the definition of indebtedness under QEP's credit agreement.

Term Loan

QEP's $600.0 million unsecured term loan facility provides for borrowings at short-term interest rates and contains covenants, restrictions and interest rates that are substantially the same as QEP’s revolving credit facility. The term loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. In conjunction with the Permian Basin Acquisition, QEP borrowed the incremental $300.0 million available under the facility and increased total borrowings under the term loan to $600.0 million. There were no changes to the maturity date, pricing or covenants in the credit agreement. QEP incurred $1.1 million of debt issuance costs associated with the new term loan issuance.

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During the first quarter of 2014, QEP’s weighted-average interest rate on borrowings under the term loan was 1.59%. In conjunction with the term loan, QEP entered into interest rate swap contracts with a combined notional principal amount of $600.0 million which will mature in March 2017. Under the aggregated swap contracts, QEP pays 0.96% for the life of the swaps and receives one-month LIBOR. The interest rate at March 31, 2014, under the term loan is one-month LIBOR, plus 2.00% (the Applicable Margin) which, when combined with the fixed interest rate swaps, results in an effective rate of 2.96% for borrowings under the term loan. To the extent that the Applicable Margin under the term loan changes, the effective fixed rate paid for borrowings under the term loan will change.

Senior Notes

The Company’s senior notes outstanding as of March 31, 2014, 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

• $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 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 24 months.

Net cash provided by operating activities during the first quarter of 2014 increased $150.3 million compared to the first quarter of 2013, due to increased net income and a decrease in the use of cash from operating assets and liabilities, partially offset by lower noncash net income adjustments. Changes in operating assets and liabilities used $38.1 million of cash in the first quarter of 2014, mainly due to an increase of accounts receivable related to increased revenue offset by increased accounts payable and accrued expenses. Changes in operating assets and liabilities used $162.4 million of cash in the first quarter of 2013 primarily due to a $115.0 million settlement payment in the first quarter of 2013 and an increase in deferred income taxes. Net cash provided by operating activities is presented below:

	Three Months Ended March 31,
	2014			2013			Change
	(in millions)
Net income	$	45.5		$	(3.7	)	$	49.2
Noncash adjustments to net income	315.0			338.2			(23.2		)
Changes in operating assets and liabilities	(38.1		)	(162.4		)	124.3
Net cash provided by operating activities	$	322.4		$	172.1		$	150.3

Cash Flow from Investing Activities

In the first quarter of 2014, net cash used in investing activities was $1,223.9 million, compared to $383.1 million in the first quarter of 2013. This increase in investing activities was largely due to the Permian Basin Acquisition, which closed in the first quarter of 2014 for a total purchase price of $945.0 million, subject to post-closing adjustments. A comparison of capital expenditures for the first quarter of 2014 and 2013 and a forecast for calendar year 2014 are presented in the table below:

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	Three Months Ended								Current Forecast Twelve Months Ended (1)		Prior Forecast Twelve Months Ended (2)
	March 31,
	2014			2013		Change			December 31, 2014		December 31, 2014
	(in millions)
QEP Energy	$	1,263.2		$	325.4	$	937.8		$	1,650.0	$	1,700.0
QEP Field Services	21.5			12.0		9.5			80.0		80.0
QEP Marketing	0.3			0.4		(0.1		)	0.5		0.5
QEP	3.4			4.2		(0.8		)	24.5		24.5
Total accrued capital expenditures	1,288.4			342.0		946.4			1,755.0		1,805.0
Change in accruals and purchase adjustments	(11.6		)	42.6		(54.2		)	—		—
Total cash capital expenditures	$	1,276.8		$	384.6	$	892.2		$	1,755.0	$	1,805.0

____________________________

⁽¹⁾  Represents the mid-point of the most recent guidance and excludes approximately $945.0 million for the Permian Basin Acquisition.

⁽²⁾  Forecast as reported in the 2013 Annual Report on Form 10-K, filed on February 25, 2014.

During the first quarter of 2014, capital expenditures on a cash basis increased 232% to $1,276.8 million, compared to $384.6 million during the first quarter of 2013. The increase of $892.2 million in cash capital expenditures during the first quarter of 2014 was primarily the result of QEP Energy's increased capital expenditures related to the Permian Basin Acquisition.

In the first quarter of 2014, QEP Energy's capital investment, on an accrual basis, increased $937.8 million over the first quarter of 2013 to a total of $1,263.2 million. This increase was primarily due to the Permian Basin Acquisition, which closed in the first quarter of 2014 for a total purchase price of $945.0 million, subject to post-closing adjustments. In addition, capital expenditures increased $48.1 million in the Williston Basin, and $11.6 million in Pinedale due to additional drilling activity and operations in these areas. These increases were partially offset by decreases of $32.3 million in the Midcontinent, $20.1 million in the other Northern Region and $19.1 million in the Uinta Basin due to divestitures of non-core properties in 2013, and decreased drilling activity in the areas, as well as a $6.9 million decrease in the Haynesville/Cotton Valley area due to the suspended drilling program.

In the first quarter of 2014, compared to the first quarter of 2013, QEP Field Services' capital investment increased $9.5 million, on an accrual basis. Capital expenditures during the first quarter of 2014 primarily related to $7.4 million for expansion of the Uinta Basin Gathering system and $2.7 million for expansion of the Vermillion Processing Plant, with the remaining expenditures relating to maintenance capital expenditures and other minor projects on the various plants and gathering systems.

At March 31, 2014, forecasted capital investments for 2014, excluding acquisitions, are expected to be approximately $1,755.0 million, comprised of $1,650.0 million for QEP Energy, $80.0 million for QEP Field Services, and $25.0 million for QEP Marketing and Resources. For the remainder of 2014, QEP intends to fund capital expenditures with cash flow from operating activities, and, if needed, borrowings under its revolving credit facility. QEP plans minimal capital expenditures for the Haynesville Shale and other dry-gas development areas and plans to increase capital expenditures for higher return projects, including oil-directed horizontal drilling in the Williston Basin and the Permian Basin, the latter of which was acquired in the first quarter of 2014. QEP Energy has allocated approximately 98% of its forecasted 2014 drilling and completion capital expenditure budget to oil and liquids-rich gas plays. QEP plans to invest a total of approximately $80.0 million in capital expenditures during 2014 to maintain and grow its midstream business (including QEP Midstream), including an expansion of the Vermillion processing plant as well as additional gathering facilities in the Uinta Basin. The remaining QEP Field Services' capital expenditures will be related to compressor projects, new well connections and gathering line expansion. QEP plans to invest approximately $25.0 million in capital expenditures related to corporate activities, primarily the implementation of a new ERP system and building improvements. The aggregate levels of capital expenditures for 2014, 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 investment can generate the best return. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

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Cash Flow from Financing Activities

In the first quarter of 2014, net cash proceeds from financing activities were $893.5 million compared to $211.0 million in the first quarter of 2013. During the first quarter of 2014, QEP had borrowings from the credit facility of $1,643.0 million and repayments on the credit facility of $1,021.5 million. QEP also issued an additional $300.0 million under its term loan. These increased borrowings were offset by decreased checks outstanding in excess of cash balances of $12.5 million during the first quarter of 2014. In the three months ended March 31, 2014, QEP paid $3.6 million of regular quarterly dividends.

At March 31, 2014, long-term debt consisted of $1,101.5 million outstanding under the credit facility, $600.0 million under the term loan and $2,221.8 million in senior notes (including $4.1 million of net original issue discount). The $621.5 million increase in borrowings under the credit facility and $300.0 million increase in the term loan during the first three months of 2014 were primarily used to fund the Permian Basin Acquisition.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market risk exposures 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 Energy, QEP Field Services, and QEP Marketing also have long-term contracts for pipeline capacity, and are obligated to pay for transportation services with no guarantee that QEP will be able to fully utilize the contractual capacity of these transportation commitments. In addition, a non-cash write-down of the Company’s oil and gas properties may be required if future oil and gas commodity prices experience a sustained, significant decline. Furthermore, the Company’s credit facility and term loan agreement have floating interest rates which expose QEP to interest rate risk. To manage the Company’s exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price swaps to manage commodity price risk and 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 same arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price swaps. The volume of commodity derivative instruments utilized by the Company may vary from year-to-year based on QEP's forecasted production. The derivative instruments utilized by the Company do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of March 31, 2014, QEP held commodity price derivative contracts totaling 119.2 million MMBtu of gas and 12.8 million barrels of oil. At December 31, 2013, the QEP derivative contracts covered 139.4 million MMBtu of gas and 6.9 million barrels of oil.

The following table presents open 2014 derivative positions, which includes what was in effect as of March 31, 2014 (see Note 8 - Derivative Contracts, under Part 1, Item 1 of this Quarter Report on Form 10-Q for table as of March 31, 2014) and what is known to be in effect as of April 30, 2014:

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QEP Energy Commodity Derivative Positions
Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	NYMEX	19.6	$	4.22
2014	SWAP	IFNPCR	53.9	$	4.08
2015	SWAP	NYMEX	25.6	$	4.14
2015	SWAP	IFNPCR	7.3	$	3.97
Oil Sales			(Bbls)
2014	SWAP	NYMEX WTI	7.2	$	92.59
2015	SWAP	NYMEX WTI	4.7	$	88.17

QEP Energy Oil Basis Swaps
Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
Oil basis swaps			(Bbls)
2014	NYMEX WTI	ICE Brent	0.5	$	13.78
2014	NYMEX WTI	LLS	0.5	$	4.00
2015	NYMEX WTI	LLS	0.1	$	4.00

QEP Marketing Commodity Derivative Positions
Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	IFNPCR	2.6	$	3.77
Gas purchases			(MMBtu)
2014	SWAP	IFNPCR	0.8	$	3.82

Changes in the fair value of derivative contracts from December 31, 2013 to March 31, 2014, are presented below:

	Commodity derivative contracts
	(in millions)
Net fair value of gas and oil derivative contracts outstanding at December 31, 2013	$	(23.5	)
Contracts settled	34.8
Change in gas and oil prices on futures markets	(70.8		)
Contracts added	(9.4		)
Net fair value of gas and oil derivative contracts outstanding at March 31, 2014	$	(68.9	)

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

	March 31, 2014
	(in millions)
Net fair value - asset (liability)	$	(68.9	)
Fair value if market prices of gas and oil and basis differentials decline by 10%	106.2
Fair value if market prices of gas and oil and basis differentials increase by 10%	(244.0		)

Utilizing the actual derivative volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $175.1 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $175.1 million as of March 31, 2014. 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 8 – Derivative Contracts under 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 as described in the risk factors in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013. The Company’s credit facility has a floating interest rate, which exposes QEP to interest rate risk. At March 31, 2014, the Company had $1,101.5 million outstanding under its revolving credit facility. If interest rates were to increase or decrease 10% over the three months ended March 31, 2014, at our average level of borrowing for those same periods, our interest expense would increase or decrease by $0.4 million for the three months endedMarch 31, 2014.

The Company’s term loan has a floating interest rate, which also exposes QEP to interest rate risk. QEP uses interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk associated with its $600.0 million term loan. For the $300.0 million term loan issued during 2012, QEP locked in a fixed interest rate of 1.07% in exchange for a variable interest rate indexed to the one-month LIBOR. For the $300.0 million term loan issued during 2014, QEP locked in a fixed interest rate of 0.86%. The interest rate swaps settle monthly and will mature in March 2017. At March 31, 2014, the fair value of the interest rate swaps was a derivative liability balance of $1.9 million. A 50 basis point decrease would cause the fair value of the interest rate swaps to decrease by $8.1 million while a 50 basis point increase would cause the fair value of the interest rate swaps to increase by $8.6 million.

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 10 – Debt under Part I, Item 1 of this Quarterly Report on Form 10-Q.

Forward-Looking Statements

This 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, 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. They 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:

• QEP’s growth strategies;

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

• plans to drill or participate in wells and to defer completion of wells;

• results from planned drilling operations and production operations;

• pro forma results for acquired properties;

• expected restructuring costs;

• the Company's liquidity;

• plans to divest of non-core assets and use of proceeds from such divestitures;

• plans to separate the midstream business;

• impact of refinery and pipeline and other infrastructure constraints on oil prices;

49

• assumptions regarding equity-based compensation;

• recognition of compensation costs related to equity compensation grants;

• amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;

• estimated accrual for loss contingencies and other items;

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

• effect of a recession;

• plans to enter into derivative contracts for a portion of forecasted production;

• the outcome of contingencies such as legal proceedings;

• expected contributions to the Company’s pension plans and returns from plan assets;

• the significance of Adjusted EBITDA as a measure of cash flow and liquidity;

• potential for future asset impairments;

• estimated future purchase accounting adjustments; and

• timing of closing and recognition of any gain or loss on dispositions.

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, 2013;

• changes in gas, oil and NGL prices;

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

• drilling results;

• shortages of oilfield equipment, services and personnel;

• lack of available pipeline capacity;

• QEP's ability to successfully integrate acquired assets or divest of non-core assets;

• the outcome of contingencies such as legal proceedings;

• permitting delays;

• operating risks such as unexpected drilling conditions;

• weather conditions;

• changes in maintenance and construction costs, including possible inflationary pressures;

• the availability and cost of debt and equity financing;

• changes in laws or regulations;

• legislation regarding climate change and other initiatives related to drilling and completion techniques, including hydraulic fracturing;

• derivative activities;

• substantial liabilities from legal proceedings and environmental claims;

• failure of internal controls and procedures;

• failure of QEP's information technology infrastructure or applications;

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

• future opportunities that QEP's Board of Directors may determine present greater potential value to stockholders than planned divestiture of assets;

• regulatory approvals and compliance with contractual obligations;

• actions, or inaction, by federal, state, local or tribal governments;

• fluctuations in processing margins;

• unexpected changes in costs for constructing, modifying or operating midstream facilities;

• lack of, or disruptions in, adequate and reliable transportation for QEP's products; 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 website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

50

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 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 March 31, 2014. Based on such evaluation, such officers have concluded that, as of March 31, 2014, 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 during the quarter ended March 31, 2014, that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control - Integrated Framework (the 2013 Framework). Originally issued in 1992 (the 1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of March 31, 2014, QEP has initiated the process to ensure we are in compliance with the 2013 Framework and we anticipate we will be in compliance by the required due date of December 15, 2014.

PART II. OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Information regarding legal proceedings is set forth in Note 11 - Contingencies to the Company's condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

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, 2013. No material changes to such risk factors have occurred during the three months endedMarch 31, 2014.

51

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 stock 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	Maximum number of shares that may yet be purchased under the plans or programs
January 1, 2014 - January 31, 2014	265	$	31.30	—	—
February 1, 2014 - February 28, 2014	—	—		—	—
March 1, 2014 - March 31, 2014	188,927	28.82		—	—

____________________________

⁽¹⁾  All of the 189,192 shares purchased during the three-month period ended March 31, 2014 were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock. Stock options that are net settled do not involve the acquisition of any shares.

In January 2014, QEP's Board of Directors authorized the repurchase of up to $500.0 million of the Company's outstanding shares of common stock. This authorization is effective until January 2015. The timing and amount of any QEP share repurchases will depend upon a number of factors, including general market conditions, the Company’s financial position and the estimated intrinsic value of the Company’s shares. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time. During the quarter ended March 31, 2014, no shares were repurchased.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.    MINE SAFETY DISCLOSURES

None.

ITEM 5.    OTHER INFORMATION

None.

ITEM 6.    EXHIBITS

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

Exhibit No.	Exhibits
10.1	Purchase and Sale Agreement, dated December 6, 2013, by and among QEP Energy Company, as purchaser, and Enervest Holding, L.P., Enervest Energy Institutional Fund XII-A, L.P., Enervest Energy Institutional Fund XII-WIB, L.P., and Enervest Energy Institutional Fund XII-WIC, L.P., as sellers, as amended by First Amendment to Purchase and Sale Agreement, date January 31, 2014, by and between EnerVest Holding, L.P. and QEP Energy Company, and Second Amendment to Purchase and Sale Agreement, date February 14, 2014, by and between EnerVest Holding, L.P. and QEP Energy Company.
10.2	Second Amendment to Term Loan Agreement, dated as of February 25, 2014, by and among QEP Resources, Inc., the lenders party thereto and Wells Fargo Bank, National Association, in its capacity as administrative agent for the lenders.
10.3	Third Amendment to Credit Agreement, dated as of January 31, 2014, by and among QEP Resources, Inc., the lenders party thereto and Wells Fargo Bank, National Association, in its capacity as administrative agent for the lenders.
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

52

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)
May 7, 2014	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer
May 7, 2014	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President,
	Chief Financial Officer and Treasurer

53

EX-10.1

Exhibit 10.1

Execution Version

PURCHASE AND SALE AGREEMENT

between

ENERVEST HOLDING, L.P.,

ENERVEST ENERGY INSTITUTIONAL FUND XII-A, L.P.,

ENERVEST ENERGY INSTITUTIONAL FUND XII-WIB, L.P.

and

ENERVEST ENERGY INSTITUTIONAL FUND XII-WIC, L.P.,

as Sellers,

and

QEP Energy company,

as Buyer,

dated

December 6, 2013

Exhibit 10.1

TABLE OF CONTENTS

		Page
ARTICLE I DEFINITIONS AND INTERPRETATION		1
1.1	Defined Terms	1
1.2	References and Rules of Construction	1
ARTICLE II PURCHASE AND SALE		1
2.1	Purchase and Sale	1
2.2	Excluded Assets	2
2.3	Revenues and Expenses	3
ARTICLE III PURCHASE PRICE		3
3.1	Purchase Price	3
3.2	Deposit	3
3.3	Adjustments to Purchase Price	4
3.4	Adjustment Methodology	5
3.5	Preliminary Settlement Statement	6
3.6	Final Settlement Statement	6
3.7	Disputes	7
3.8	Allocation of Purchase Price; Allocated Values	7
3.9	Allocation for Imbalances at Closing	7
3.10	Holdback Amount	7
ARTICLE IV REPRESENTATIONS AND WARRANTIES OF SELLERS		8
4.1	Organization, Existence and Qualification	8
4.2	Authority, Approval and Enforceability	8
4.3	No Conflicts	8
4.4	Consents	9

Exhibit 10.1

4.5	Bankruptcy	9
4.6	Litigation	9
4.7	Material Contracts	9
4.8	Gathering and Transportation	10
4.9	Compliance with Law	10
4.10	Preferential Purchase Rights	10
4.11	Royalties, Etc	10
4.12	Imbalances	10
4.13	Current Commitments	10
4.14	Operating Expenses for New Wells	10
4.15	Environmental Representation and Warranty	10
4.16	Taxes	11
4.17	Well Status	11
4.18	Calls on Production	11
4.19	Tax Partnerships	11
4.20	Wells	11
4.21	Brokers’ Fees	11
4.22	EnerVest Assets	11
ARTICLE V REPRESENTATIONS AND WARRANTIES OF BUYER		12
5.1	Organization, Existence and Qualification	12
5.2	Authority, Approval and Enforceability	12
5.3	No Conflicts	12
5.4	Consents	12
5.5	Bankruptcy	12
5.6	Litigation	12
5.7	Financing	13
5.8	Regulatory	13
5.9	Independent Evaluation	13
5.10	Brokers’ Fees	13
5.11	Accredited Investor	13
ARTICLE VI CERTAIN AGREEMENTS		13
6.1	Conduct of Business	13
6.2	Successor Operator	14
6.3	Governmental Bonds	14
6.4	Record Retention	15
6.5	Knowledge of Breach	15

Exhibit 10.1

6.6	Amendment of Schedules	15
6.7	Non-Solicitation of Employees	15
6.8	Sellers’ Existence	16
6.9	Financial Statements	16
ARTICLE VII BUYER’S CONDITIONS TO CLOSING		16
7.1	Representations	16
7.2	Performance	16
7.3	No Legal Proceedings	16
7.4	Title Defects and Environmental Defects	17
7.5	Closing Deliverables	17
ARTICLE VIII SELLERS’ CONDITIONS TO CLOSING		17
8.1	Representations	17
8.2	Performance	17
8.3	No Legal Proceedings	17
8.4	Title Defects and Environmental Defects	17
8.5	Replacement Bonds and Guarantees	17
8.6	Closing Deliverables	17
ARTICLE IX CLOSING		17
9.1	Date of Closing	17
9.2	Place of Closing	18
9.3	Closing Obligations	18
9.4	Records	18
ARTICLE X ACCESS; DISCLAIMERS		18
10.1	Access	19
10.2	Confidentiality	20
10.3	Disclaimers	20

Exhibit 10.1

ARTICLE XI TITLE MATTERS; CASUALTY; TRANSFER RESTRICTIONS		20
11.1	Sellers’ Title	21
11.2	Notice of Title Defects; Defect Adjustments	22
11.3	Casualty Loss	26
11.4	Consents to Assign	26
ARTICLE XII ENVIRONMENTAL MATTERS		27
12.1	Notice of Environmental Defects	27
12.2	NORM, Asbestos, Wastes and Other Substances	29
ARTICLE XIII ASSUMPTION; INDEMNIFICATION; SURVIVAL		30
13.1	Assumed Obligations; Specified Obligations	30
13.2	Indemnities of Sellers	30
13.3	Indemnities of Buyer	31
13.4	Limitation on Liability	31
13.5	Express Negligence	32
13.6	Exclusive Remedy	32
13.7	Indemnification Procedures	32
13.8	Survival	33
13.9	Waiver of Right to Rescission	34
13.10	Insurance, Taxes	34
13.11	Non-Compensatory Damages	34
13.12	Disclaimer of Application of Anti-Indemnity Statutes	35
13.13	Specified Obligation Disputes	35
ARTICLE XIV TERMINATION, DEFAULT AND REMEDIES		36
14.1	Right of Termination	36
14.2	Effect of Termination	37
14.3	Return of Documentation and Confidentiality	37

Exhibit 10.1

ARTICLE XV MISCELLANEOUS		37
15.1	Appendices, Exhibits and Schedules	37
15.2	Expenses and Taxes	37
15.3	Assignment	38
15.4	Preparation of Agreement	39
15.5	Publicity	39
15.6	Notices	39
15.7	Further Cooperation	40
15.8	Filings, Notices and Certain Governmental Approvals	40
15.9	Entire Agreement; Conflicts	41
15.10	Parties in Interest	41
15.11	Amendment	41
15.12	Waiver; Rights Cumulative	41
15.13	Governing Law; Jurisdiction	41
15.14	Severability	42
15.15	Removal of Name	42
15.16	Counterparts	42
15.17	Seller Representative	42
15.18	Like-Kind Exchange	43

Exhibit 10.1

LIST OF EXHIBITS AND SCHEDULES

Annex I	Defined Terms
Exhibit A	Leases
Exhibit B	Existing Wells
Exhibit C	Applicable Contracts
Exhibit D	Easements and Surface Contracts
Exhibit E	Personal Property
Exhibit F	Excluded Assets
Exhibit G	Form of Assignment and Bill of Sale
Exhibit H	Form of Transition Services Agreement
Schedule 2.3	New Wells
Schedule 3.8	Allocated Values
Schedule 4.4	Consents
Schedule 4.6	Litigation
Schedule 4.7	Material Contracts
Schedule 4.8	Gathering and Transportation Agreements
Schedule 4.9	Violation of Laws
Schedule 4.11	Royalties
Schedule 4.12	Imbalances
Schedule 4.13	Current Commitments
Schedule 4.14	Pre-Effective Time New Well Costs
Schedule 4.15	Environmental Compliance
Schedule 4.16	Taxes
Schedule 4.21	Asset Taxes
Schedule 6.1	Conduct of Business

Exhibit 10.1

PURCHASE AND SALE AGREEMENT

This PURCHASE AND SALE AGREEMENT (this “Agreement”) is executed as of this 6th day of December, 2013 (the “Execution Date”), and is between EnerVest Holding, L.P., a Texas limited partnership (“EnerVest Holding”), EnerVest Energy Institutional Fund XII-A, L.P., a Delaware limited partnership (“EnerVest XII-A”), EnerVest Energy Institutional Fund XII-WIB, L.P., a Delaware limited partnership (“EnerVest XII-WIB”) and EnerVest Energy Institutional Fund XII-WIC, L.P., a Delaware limited partnership (“EnerVest XII-WIC”) (collectively “Sellers” and each individually a “Seller,”) and QEP Energy Company, a Texas corporation (“Buyer”). Sellers and Buyer are each referred to as a “Party” and collectively referred to as the “Parties.”

RECITALS

Each Seller desires to sell and assign, and Buyer desires to purchase and pay for, all of each Seller’s right, title and interest in and to the Assets (as defined hereinafter) effective as of the Effective Time (as defined hereinafter).

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 AND INTERPRETATION

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

1.2References and Rules of Construction. All references in this Agreement to Annexes, Exhibits, Schedules, Articles, Sections, subsections and other subdivisions refer to the corresponding Annexes, Exhibits, Schedules, Articles, Sections, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. 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 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.” All references to “$”, “dollars” 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 date of this Agreement. 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. Reference to any agreement (including this Agreement), document or instrument shall include such agreement, document or instrument as amended or modified (including any waiver or consent) and in effect from time to time.

ARTICLE II

PURCHASE AND SALE

2.1Purchase and Sale. Subject to the terms and conditions of this Agreement, each Seller agrees to sell, and Buyer agrees to purchase and pay for, as of the Effective Time, all of such Seller’s right, title and

1

Exhibit 10.1

interest, whether present, contingent or reversionary, in and to the assets described in Section 2.1(a) through Section 2.1(g) (such assets, less and except the Excluded Assets, collectively, the “Assets”):

(a)the oil and gas leases covering lands in Andrews, Crockett and Martin Counties, Texas described on Exhibit A, subject to any reservations, limitations or depth restrictions included in the descriptions of such oil and gas leases set forth on Exhibit A, and the lands covered by such leases (whether or not the lands subject to such leaseholds are correctly or sufficiently described on Exhibit A), including working interests, mineral interests, royalty interests, overriding royalty interests, production payments and net profit interests therein subject to the terms, conditions, covenants and obligations set forth in such leases and on Exhibit A (such interest in such leases, the “Leases”);

(b)all wells located on the Leases or on any other lease with which any such property or Lease has been unitized (including the oil, gas, water and disposal wells specifically described on Exhibit B), (collectively, the “Wells”), and all Hydrocarbons produced therefrom or allocated thereto;

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

(d)to the extent that they may be assigned, all Applicable Contracts and all rights thereunder;

(e)to the extent that they may be assigned, all permits, licenses, servitudes, easements, rights-of-way, surface leases, other surface interests and surface rights to the extent appurtenant to or used primarily in connection with the ownership, operation, production, gathering, treatment, processing, storing, sale or disposal of Hydrocarbons or produced water from the Leases, Wells or Units or any of the Assets, including those described on Exhibit D;

(f)all equipment, machinery, tanks, pipe, fixtures, SCADA systems and associated communication equipment, vehicles and other personal, moveable and mixed property, injection facilities, saltwater disposal facilities, compression facilities, pumping units and engines, gas and oil treating facilities, power lines and other appurtenances, inventory, improvements, doghouses, storage facilities and similar structures, flowlines, pipelines, gathering systems and appurtenances thereto, located on any of the Assets that is primarily used in connection therewith as of the Effective Time, including those described on Exhibit E (collectively, the “Personal Property”);

(g)all of the files, records, maps, information and data, whether written or electronically stored, primarily relating to the Assets in Sellers’ or its Affiliates’ possession, including: (i) land, division order and title records (including abstracts of title, title opinions and title curative documents); (ii) Applicable Contract files; (iii) correspondence; (iv) operations, engineering, environmental (including all environmental reports, files, audits, assessments, environmental notices of violation from Governmental Authorities (if any) and written notice from landowners regarding any environmental or operating issues (if any)), regulatory, production and accounting records; (v) production, facility and well records; and (vi) geological and geophysical data (including seismic data), interpretive data, electric logs, core data, pressure data, decline curves and production curves (collectively, “Records”).

2.2    Excluded Assets. Sellers shall reserve and retain all of the Excluded Assets.

2

Exhibit 10.1

2.3    Revenues and Expenses. Subject to the provisions hereof, Sellers shall remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and all other income, proceeds, receipts and credits) and shall remain responsible (by payment, through the adjustments to the Purchase Price hereunder or otherwise) for all Operating Expenses, in each case, attributable to the Assets for the period of time prior to the Effective Time. Subject to the provisions hereof, and subject to the occurrence of Closing, Buyer shall be entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds), and shall be responsible (by payment, through the adjustments to the Purchase Price hereunder or otherwise) for all Operating Expenses, in each case, attributable to the Assets for the period of time from and after the Effective Time. Notwithstanding the foregoing, with respect to any well located on the Leases or on any other lease with which any such property or Lease has been unitized and spudded but not completed prior to the Effective Time described on Schedule 2.3 (the “New Wells”), Buyer shall be responsible (by payment, through the adjustments to the Purchase Price hereunder or otherwise, for all Operating Expenses attributable to such New Well (net to Sellers’ interest) whether before, on or after the Effective Time. “Operating Expenses” means all operating expenses and all 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 charged or chargeable to the Assets under the relevant operating agreement or unit agreement, if any, but excluding, for the avoidance of doubt, any Income Taxes and Asset Taxes. After the Closing, each Party shall be entitled to participate in all joint interest audits and other audits of Operating Expenses for which such Party is entirely or in part responsible under the terms of this Section 2.3.

ARTICLE III

PURCHASE PRICE

3.1    Purchase Price. The purchase price for the Assets shall be Nine Hundred Fifty Million Dollars ($950,000,000) (the “Purchase Price”), adjusted in accordance with this Agreement and payable by Buyer to Sellers at the Closing by wire transfer in immediately available funds to a bank account designated by Sellers in the Preliminary Settlement Statement.

3.2    Deposit.

(a)     No later than the third Business Day after the execution of this Agreement, Buyer shall deposit by wire transfer in same day funds with the Escrow Agent the sum of Fifty Million Dollars ($50,000,000) (such amount, excluding any interest earned thereon, the “Deposit”). If Closing occurs, the Deposit shall be applied toward the Adjusted Purchase Price at Closing, but shall be retained under the Escrow Agreement as the Holdback Amount pursuant to Section 3.10. The fees and expenses of the Escrow Agent shall be borne 50% by Buyer and 50% by Sellers.

(b)    If the transactions contemplated by this Agreement are not consummated because of (i) the failure of Buyer to materially perform any of its obligations hereunder or (ii) the failure of any of Buyer’s representations or warranties hereunder to be true and correct in all material respects as of the date of this Agreement and Closing, then, in such event, Sellers shall have the right to (A) terminate this Agreement and receive from the Escrow Agent the Deposit together with any interest or income thereon, free of any claims by Buyer with respect thereto (and Buyer shall execute joint instructions to the Escrow Agent to that effect), and (B), at its option, seek all additional remedies available at law, and with respect to Buyer’s obligations under Section 6.3 or instructions to the Escrow Agent required under this Agreement, specific performance.

(c)    If this Agreement is terminated by the mutual written agreement of Buyer and Sellers, or if Closing does not occur for any reason other than as set forth in Section 3.2(b), then Buyer shall be entitled to receive the Deposit together with any interest or income thereon from the Escrow Agent, free of

3

Exhibit 10.1

any claims by Sellers with respect thereto and Sellers shall execute joint instructions to the Escrow Agent to that effect.

(d)    In the event of a termination of this Agreement pursuant to Section 3.2(b) or Section 3.2(c), Buyer and Sellers shall, in each case, also have the rights and obligations set forth in Section 14.2.

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

(a)    The Purchase Price shall be adjusted upward by the following amounts (without duplication):

(i)an amount equal to, to the extent that such amount has been received by Buyer and not remitted or paid to Sellers, the value of all Hydrocarbons from or attributable to the Assets in storage or existing in pipelines, plants and tanks (including inventory) and upstream of the sales meter as of the Effective Time, the value to be based upon the contract price in effect as of the Effective Time (or the sales price, if there is no contract price, in effect as of the Effective Time), less Burdens on such production;

(ii)an amount equal to all Operating Expenses and all other costs and expenses (including drilling and completion costs and other capital expenditures but excluding, for the avoidance of doubt, any Income Taxes and Asset Taxes) paid by Sellers that are attributable to the Assets during the period following the Effective Time, whether paid before or after the Effective Time, including (A) Burdens and (B) rentals and other lease maintenance payments;

(iii)an amount equal to all Operating Expenses and all other costs and expenses (excluding, for the avoidance of doubt, any Income Taxes and Asset Taxes) paid by Sellers that are attributable to the New Wells whether before, on or after the Effective Time;

(iv)the amount of all Asset Taxes allocated to Buyer in accordance with Section 15.2 but that are paid or otherwise economically borne by Sellers;

(v)subject to Section 3.9, to the extent that Sellers are underproduced as shown with respect to the net Well Imbalances set forth on Schedule 4.12, as complete and final settlement of all Well Imbalances attributable to the Assets, an amount equal to the product of the underproduced volumes times (A) $3.50/Mcf for gaseous Hydrocarbons or (B) $90.00/Bbl for liquid Hydrocarbons, as applicable;

(vi)subject to Section 3.9, to the extent that Sellers have overdelivered any Hydrocarbons (that is, Sellers have delivered more product to the pipeline than the pipeline has purchased or redelivered for Sellers) as of the Effective Time as shown with respect to the net Pipeline Imbalances set forth on Schedule 4.12, as complete and final settlement of all Pipeline Imbalances attributable to the Assets, an amount equal to the product of the overdelivered volumes times (A) $3.50/Mcf for gaseous Hydrocarbons or (B) $90.00/Bbl for liquid Hydrocarbons, as applicable;

(vii)to the extent not included as an Operating Expense for which an adjustment was made pursuant to Section 3.3(a)(ii), any bond or insurance premiums paid by or on behalf of Sellers in connection with ownership or operation of the Assets and prorated to the period from and after the Effective Time;

(viii)the portion of the Overhead Costs, if any, attributable to the Assets from and after the Effective Time up to the Closing Date; and

4

Exhibit 10.1

(ix)any other amount provided for elsewhere in this Agreement or otherwise agreed upon by Sellers and Buyer.

(b)    The Purchase Price shall be adjusted downward by the following amounts (without duplication):

(i)    an amount equal to, to the extent that such amount has been received by Sellers and not remitted or paid to Buyer, all proceeds actually received by Sellers attributable to the ownership or operation of the Assets, including the sale of Hydrocarbons produced therefrom or allocable thereto during the period following the Effective Time, net of expenses (other than Operating Expenses and other expenses taken into account pursuant to Section 3.3(a), Income Taxes and Asset Taxes) directly incurred in earning or receiving such proceeds;

(ii)    if Sellers make the election under Section 11.2(d)(i) with respect to a Title Defect, an amount equal to all Title Defect Amounts determined pursuant to Sections 11.2(g), 11.2(i) or 11.2(j), as applicable, less an amount equal to all Title Benefit Amounts determined pursuant to Sections 11.2(h) or 11.2(j), as applicable;

(iii)    if Sellers make the election under Section 12.1(b)(i) with respect to an Environmental Defect, the Remediation Amount with respect to such Environmental Defect if the Remediation Amount has been determined prior to Closing;

(iv)    the Allocated Value of the Assets excluded from the transactions contemplated hereby pursuant to Section 11.2(d)(ii), Section 11.4(a), or Section 12.1(b)(ii);

(v)    the amount of all Asset Taxes allocated to Sellers in accordance with Section 15.2 but that are paid or otherwise economically borne by Buyer;

(vi)    subject to Section 3.9, to the extent that Sellers are overproduced as shown with respect to the net Well Imbalances set forth on Schedule 4.12, as complete and final settlement of all Well Imbalances attributable to the Assets, the sum of $21,434.00 which is an amount equal to the product of the overproduced volumes times (A) $3.50/Mcf for gaseous Hydrocarbons or (B) $90.00/Bbl for liquid Hydrocarbons, as applicable;

(vii)    subject to Section 3.9, to the extent that Sellers have underdelivered (that is, Sellers have delivered less product to the pipeline than the pipeline purchased or redelivered for the Sellers) any Hydrocarbons as of the Effective Time as shown with respect to the net Pipeline Imbalances set forth on Schedule 4.12, as complete and final settlement of all Pipeline Imbalances attributable to the Assets, an amount equal to the product of the underdelivered volumes times (A) $3.50/Mcf for gaseous Hydrocarbons or (B) $90.00/Bbl for liquid Hydrocarbons, as applicable;

(viii)    an amount equal to all proceeds from sales of Hydrocarbons relating to the Assets and payable to owners of Working Interests, royalties, overriding royalties and other similar interests (in each case) that are held by Sellers in suspense as of the Closing Date; and

(ix)    any other amount provided for elsewhere in this Agreement or otherwise agreed upon by Sellers and Buyer.

3.4    Adjustment Methodology. When available, actual figures will be used for the adjustments to the Purchase Price at Closing. To the extent actual figures are not available, estimates will be used subject to final adjustments in accordance with Section 3.6 and Section 3.7.

5

Exhibit 10.1

3.5    Preliminary Settlement Statement. Not less than five Business Days prior to Closing, Sellers 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 calculation of the adjustments used to determine such amount, together with the designation of Sellers’ account for the wire transfer of funds as required by Section 3.1 and Section 9.3(d). Within two Business Days after receipt of the Preliminary Settlement Statement, Buyer shall deliver to Sellers a written report containing all changes that Buyer proposes to be made to the Preliminary Settlement Statement together with the explanation therefor and the supporting documents thereof. The Parties shall in good faith attempt to agree on the Preliminary Settlement Statement as soon as possible after Sellers’ receipt of Buyer’s written report. The Preliminary Settlement Statement, as agreed upon by the Parties, will be used to adjust the Purchase Price at Closing; provided that if the Parties do not agree upon an adjustment set forth in the Preliminary Settlement Statement, then the amount of such adjustment used to adjust the Purchase Price at Closing shall be that amount set forth in the draft Preliminary Settlement Statement delivered by Sellers to Buyer pursuant to this Section 3.5.

3.6    Final Settlement Statement.

(a)    On or before 120 days after Closing, a final settlement statement (the “Final Settlement Statement”) will be prepared by Sellers, based on actual income and expenses during the Interim Period and which takes into account all final adjustments made to the Purchase Price and shows the resulting final Purchase Price (the “Final Price”). The Final Settlement Statement shall set forth the actual proration of the amounts required by this Agreement. As soon as practicable, and in any event within 30 days, after receipt of the Final Settlement Statement, Buyer shall return to Sellers 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”). Any changes not so specified in the Dispute Notice shall be deemed waived, and Sellers’ determinations with respect to all such elements of the Final Settlement Statement that are not addressed specifically in the Dispute Notice shall prevail. If Buyer fails to timely deliver a Dispute Notice to Sellers containing changes Buyer proposes to be made to the Final Settlement Statement, the Final Settlement Statement as delivered by Sellers will be deemed to be correct and will be final and binding on the Parties and not subject to further audit or arbitration. Subject to Section 3.6(b), if the Final Price set forth in the Final Settlement Statement is mutually agreed upon by Sellers and Buyer, the Final Settlement Statement and the Final Price, shall be final and binding on the Parties. Any difference in the Adjusted Purchase Price as paid at Closing pursuant to the Preliminary Settlement Statement and the Final Price shall be paid by the owing Party within ten days of final determination of such owed amounts in accordance herewith to the owed Party. All amounts paid pursuant to this Section 3.6 shall be delivered in United States currency by wire transfer of immediately available funds to the account specified in writing by the relevant Party.

(b)    If after the delivery of the Final Settlement Statement pursuant to the provisions of Section 3.6(a) (i) either Party receives monies (including proceeds of production) belonging to the other Party pursuant to Section 2.3 or otherwise, then such monies shall, within five Business Days after the end of the month in which they were received, be paid over by the receiving Party to the owed Party, (ii) either Party pays monies for Operating Expenses that are the obligation of the other Party pursuant to Section 2.3 or otherwise, then the obligated Party shall, within five Business Days after the end of the month in which the applicable invoice and proof of payment of such invoice are received by it, reimburse the paying Party therefor, (iii) either Party receives an invoice of an expense or obligation that is owed by the other Party pursuant to Section 2.3 or otherwise, then the receiving Party shall promptly forward such invoice to the obligated Party and (iv) if an invoice of an expense or other obligation is received by either Party and is the obligation of both Parties, then the Parties shall consult with each other and shall each promptly pay its portion of such invoice to the obligee. Each Party shall be permitted to offset any monies owed by it to the

6

Exhibit 10.1

other Party pursuant to this Section 3.6 against amounts owing by it to such other Party pursuant to this Section 3.6.

3.7    Disputes. If Sellers and Buyer are unable to resolve the matters addressed in the Dispute Notice, each of Buyer and Sellers shall within ten Business Days after the delivery of such Dispute Notice, summarize its position with regard to such dispute in a written document of 20 pages or less and submit such summaries to such Person as the Parties 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 ten Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision choosing either Sellers’ 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 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 Sellers.

3.8    Allocation of Purchase Price; Allocated Values. Solely for the purposes of Article XI and Article XII, Buyer and Sellers agree that the Purchase Price shall be allocated among the Assets as set forth on Schedule 3.8 (the “Allocated Values”).

3.9    Allocation for Imbalances at Closing. If, prior to Closing, any Party discovers an error in the Imbalances set forth on Schedule 4.12, then the Purchase Price shall be further adjusted at Closing pursuant to Section 3.3(a)(v), Section 3.3(a)(vi), Section 3.3(b)(vi) or Section 3.3(b)(vii), as applicable, and Schedule 4.12 will be deemed amended immediately prior to Closing to reflect the Imbalances for which the Purchase Price is so adjusted.

3.10    Holdback Amount.

(a)    At Closing, in partial satisfaction of Buyer’s payment obligations under Section 3.1, the Deposit, but specifically excluding any interest or income earned thereon to the Closing, shall be retained by the Escrow Agent pursuant to the Escrow Agreement and from and after the Closing the Deposit and all interest or other amounts earned thereon after the Closing shall be the “Holdback Amount” for the purposes of this Agreement and the Escrow Agreement. The Holdback Amount shall be paid out in accordance with the provisions of this Section 3.10 and the Escrow Agreement by way of security against all obligations of Sellers to defend and indemnify or otherwise pay any amounts owed by Sellers to Buyer and Buyer Indemnified Parties pursuant to Sellers’ payment, defense and indemnity obligations under Section 13.2 and Sellers’ special warranty of title under Sections 11.1(b) and (c).

(b)    To the extent that Sellers do not promptly (and in any event within 10 Business Days after receipt of written notice from Buyer) reimburse or pay Buyer for any Liabilities for which Buyer is entitled to be indemnified or paid by Sellers pursuant to Sections 11.1(b) and (c) or Section 13.2, then Buyer shall be entitled, at any time and from time to time, to deliver to the Escrow Agent and Sellers one or more written notices (an “Escrow Claim Notice”) which notice shall specify with particularity the nature and Buyer’s good faith estimate of the amount of the claim (the “Escrow Claim”), including the provision of this Agreement entitling Buyer to such Escrow Claim. Upon Sellers’ and Buyer’s agreement on the amount and validity of such Escrow Claim, Sellers and Buyer shall jointly instruct the Escrow Agent to disburse to Buyer the amount set forth in such joint instructions, which will be that portion of the Holdback Amount being held in the Escrow Account as would satisfy such Escrow Claim. If Sellers and Buyer are unable to agree on the amount or validity of any such Escrow Claim, it shall be resolved in accordance with Section 15.13 (except that with respect to Sellers’ indemnity obligations for Specified Obligations, in accordance with Section 13.13) and if upon the resolution or determination of any such Escrow Claim, the Parties fail to deliver a joint written instruction to the Escrow Agent in accordance with the foregoing sentence, then the Escrow

7

Exhibit 10.1

Agent shall pay the Escrow Claim to Buyer upon delivery by any Party to the Escrow Agent of a final and non-appealable written court order resolving such dispute and directing the payment of a specified amount to Buyer with respect to such Escrow Claim (except that with respect to Sellers’ indemnity obligations for Specified Obligations, a final and binding arbitral award issued by arbitrators in accordance with Section 13.13). The Escrow Agent shall release to Sellers any portion of the Holdback Amount remaining in the Escrow Account on the first Business Day that is 273 days after the Closing Date, except for the aggregate amount of all outstanding Escrow Claims for which Buyer has, in good faith, provided an Escrow Claim Notice to Sellers and Escrow Agent in accordance with Section 3.10(b) that has not been previously satisfied (which monies shall remain part of the Holdback Amount until final resolution of such outstanding Escrow Claims). Upon the final resolution and payment of all Escrow Claim Notices delivered by Buyer during the Survival Period, Buyer and Sellers shall execute and deliver to the Escrow Agent written instruction to release any remaining Holdback Amount to Sellers.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF SELLERS

Subject to the matters specifically listed or disclosed in the Schedules (as added, supplemented or amended pursuant to Section 6.6), each Seller jointly and severally with each other Seller represents and warrants to Buyer, as of the Execution Date and as of the Closing Date, the following:

4.1    Organization, Existence and Qualification. Each Seller is a limited partnership duly formed and validly existing under the Laws of the state of its formation. Each Seller has all requisite power and authority to own and operate its property (including its interests in the Assets) and to carry on its business as now conducted. Each Seller is duly licensed or qualified to do business as a foreign limited partnership in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law, except where the failure to be so qualified would not have a material adverse effect.

4.2    Authority, Approval and Enforceability. Each Seller has full power and authority to enter into and perform this Agreement, the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by each Seller of this Agreement have been duly and validly authorized and approved by all necessary limited partnership action on the part of each Seller. Assuming the due authorization, execution and delivery by the other parties to such documents, this Agreement is, and the Transaction Documents to which each Seller is a party when executed and delivered by such Seller will be, the valid and binding obligations 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).

4.3    No Conflicts. Assuming the receipt of all Consents, the execution, delivery and performance by each 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 organizational documents of such Seller, (b) except for Permitted Encumbrances, 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 Applicable Contract to which such Seller is a party or by which such Seller or the Assets may be bound or (c) violate any Law applicable to such Seller or any of the Assets, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a material effect upon the ability of such Seller to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

8

Exhibit 10.1

4.4    Consents. Except (a) as set forth on Schedule 4.4, (b) for Customary Post-Closing Consents and (c) under Contracts that are terminable upon not greater than 60 days’ notice without payment of any fee, there are no restrictions on assignment, including requirements for consents from Third Parties to any assignment (in each case), that a Seller is required to obtain in connection with the transfer of its Assets to Buyer or the consummation of the transactions contemplated by this Agreement by such Seller (each, a “Consent”).

4.5    Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to such Seller’s Knowledge, threatened in writing against such Seller.

4.6    Litigation. Except as set forth on Schedule 4.6, as of the date of this Agreement, there is no suit, action or litigation by any Third Party before any Governmental Authority, and no legal, administrative or arbitration proceeding, in each case, pending or, to Sellers’ Knowledge, threatened in writing against Sellers or the Assets. Sellers are not in material default under any order, writ, injunction or decree of any Governmental Authority

4.7    Material Contracts.

(a)    Except for Contracts entered into in accordance with Section 6.1, Schedule 4.7 sets forth all 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 by such Seller of more than $100,000 during the current or any subsequent calendar year (based solely on the terms thereof and current volumes, without regard to any expected increase in volumes or revenues);

(ii)    any Applicable Contract that can reasonably be expected to result in aggregate revenues to such Seller of more than $100,000 during the current or any subsequent calendar year (based solely on the terms thereof and current volumes, without regard to any expected increase in volumes or revenues);

(iii)    any Hydrocarbon purchase and sale, transportation, processing or similar Applicable Contract that is not terminable without penalty upon 60 days’ or less notice;

(iv)    any indenture, mortgage, loan, or similar Applicable Contract, a Seller’s obligations under which are secured by a lien or mortgage on any of the Assets;

(v)    any Applicable Contract that constitutes a lease under which a Seller is the lessor or the lessee of real property (other than any Lease) or Personal Property which lease (A) cannot be terminated by such Seller without penalty upon 60 days’ or less notice and (B) involves an annual base rental of more than $100,000;

(vi)    any farmout agreement, farmin agreement, area of mutual interest agreement, exploration agreement, development agreement, participation agreement, joint operating agreement, pooling agreement, pooling declaration, unit agreement or similar Applicable Contract; and

(vii)    any Applicable Contract between any Seller and any Affiliate of Sellers that will not be terminated prior to Closing.

9

Exhibit 10.1

(b)    Except as set forth on Schedule 4.7, there exists no default under any Material Contract by any Seller or, to any Seller’s Knowledge, by any other Person that is a party to such Material Contract, and no event has occurred that with notice or lapse of time or both would constitute any default under any such Contract by Seller or, to such Seller’s Knowledge, any other Person who is a party to such Material Contract.

4.8    Gathering and Transportation. Except as set forth on Schedule 4.8, all Contracts and arrangements for the gathering or transportation of Hydrocarbons produced from the Assets are terminable upon 30 days’ or less notice.

4.9Compliance with Law. Except as described on Schedule 4.9, the Assets are and have been operated by Sellers and, to Sellers’ Knowledge, by such Seller’s predecessor in interest in compliance in all material respects with all Laws (excluding Environmental Laws). Except as described on Schedule 4.9, no Seller has received any written notice of a violation of any statute, law, ordinance, regulation, rule, order, writ, injunction or decree of any foreign, federal, state or local government or any other governmental department or agency, or any judgment, decree, order, writ or injunction of any court, applicable to the Assets. For the avoidance of doubt, this Section 4.9 does not include any matters with respect to Environmental Laws, which shall be exclusively addressed in Section 4.15 and Article XII.

4.10Preferential Purchase Rights. There are no preferential purchase rights, rights of first refusal or other similar rights that are applicable to the transfer of the Assets in connection with the transactions contemplated hereby (each a “Preferential Purchase Right”).

4.11Royalties, Etc. Except for those items that are being held in suspense for which the Purchase Price is adjusted pursuant to Section 3.3(b)(viii), each Seller has properly, timely and legally paid, in accordance with the terms of each Lease and applicable Laws, all Burdens with respect to the Assets due by that Seller, or if not paid, is contesting such Burdens in good faith in the normal course of business and described on Schedule 4.11. All rentals, shut-in payments, and operating expenses payable by any Seller with respect to the Assets prior to the Effective Time, have been duly and properly paid in all material respects. No Seller has received any written requests or demands for payments, adjustments of payments or performance pursuant to obligations under the Leases.

4.12Imbalances. To Sellers’ Knowledge, Schedule 4.12 sets forth all Imbalances associated with the Assets as of the Effective Time.

4.13Current Commitments. Schedule 4.13 sets forth, as of the date of this Agreement, all authorities for expenditures (the “AFEs”) that have been delivered to Sellers, relating to the Assets to drill, rework or conduct any other operations on or in connection with a well or for other capital expenditures in connection with the Assets for which all of the activities anticipated in such AFEs or commitments have not been completed by the date of this Agreement.

4.14Operating Expenses for New Wells. Except as set forth on Schedule 4.14, there are no Operating Expenses attributable to the period prior to the Effective Time for or related to New Wells.

4.15Environmental Representation and Warranty.

(a)    Except as described on Schedule 4.15, (i) with respect to the Assets operated by any Seller or any of Sellers’ Affiliates, those Assets are being operated in material compliance with all Environmental Laws, (ii) with respect to the Assets not operated by any Seller or any of Sellers’ Affiliates,

10

Exhibit 10.1

to Sellers’ Knowledge, those Assets are being operated in compliance with all Environmental Laws, (iii) Seller has not received a written notice of a violation of an Environmental Law from a Governmental Authority with respect to the Assets, (iv) with respect to the Assets operated by any Seller or any of Sellers’ Affiliates, no notice of action alleging a material violation of an Environmental Law is pending or, to such Seller’s Knowledge, threatened against such Assets, and (v) with respect to the Assets not operated by any Seller or any of Sellers’ Affiliates, to such Seller’s Knowledge, no notice of action alleging a violation of an Environmental Law is pending or threatened against such Assets.

(b)    Except as described on Schedule 4.15, there are no civil, criminal, or administrative actions, lawsuits, litigation, hearings, or proceedings pending against such Seller with respect to the Assets or the Assets as a result of the violation or breach of any Environmental Law.

4.16Taxes. All Asset Taxes based on a Seller’s ownership of its Assets for all taxable periods prior to the taxable period in which this Agreement is executed that were required to be paid prior to the Effective Time have been paid. Except as set forth on Schedule 4.16, no Seller has received written notice nor, to any Seller’s Knowledge, is there any pending or threatened claim against or audit of such Seller from or by any applicable Taxing Authority for the assessment of Asset Taxes. All income taxes that could result in a lien or other claim against any of the Assets that have become due and payable have been properly paid, unless contested in good faith by appropriate proceeding.

4.17Well Status. During the period of a Seller’s ownership of its Assets, and to such Seller’s Knowledge prior to such Seller’s ownership, there are no wells located on the Assets that: (a) such Seller is obligated by Law or contract to currently plug and abandon; or (b) to the extent plugged and abandoned, have not been plugged in accordance with applicable material requirements of each Governmental Authority having jurisdiction over the Assets.

4.18Calls on Production. Except pursuant to the Material Contracts, no Person has any call upon, option to purchase or similar rights with respect to the production from the Assets; production from the Assets is not bound by any gas dedications or subject to any monetary or in kind through-put fees or charges in connection with gathering or transportation; and the Assets are not bound by any Hedge Contract that will continue after Closing. Proceeds from the sale of oil, condensate and gas from the Assets are being received by such Seller, as applicable, in a timely manner and are not being held in suspense for any reason.

4.19Tax Partnerships. The Assets are not subject to any tax partnership agreements requiring a partnership income tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code.

4.20Wells. During the period of a Seller’s ownership of its Assets, and to such Seller’s Knowledge, prior to such Seller’s ownership, the Wells have been or are being drilled, completed and operated within the boundaries of the Leases or within the limits otherwise permitted or prescribed by contract, pooling or unit agreement, and by Law.

4.21Brokers’ Fees. Such Seller has incurred no 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.

4.22EnerVest Assets. Each Seller has sufficient assets and resources to fulfill its indemnity obligations under Section 13.2 and its special warranty of title under Section 11.1(b).

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Exhibit 10.1

ARTICLE V

REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer represents and warrants to Sellers, as of the Execution Date and as of the Closing Date, the following:

5.1Organization, Existence and Qualification. Buyer is a corporation duly organized, validly existing and in good standing under the Laws of the State of Texas and 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 except where the failure to be so qualified would not have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement.

5.2Authority, Approval and Enforceability. Buyer has full power and authority to enter into and perform this Agreement, 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. Assuming the due authorization, execution and delivery by the other parties to such documents, this Agreement is, and the Transaction Documents to which Buyer is a party when executed and delivered by Buyer will be, the valid and binding obligations 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).

5.3No 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 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, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a material effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

5.4Consents. There are no consents, including requirements for consents from Third Parties, in each case, that Buyer is required to obtain in connection with its acquisition and ownership of the Assets as contemplated by this Agreement.

5.5Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s knowledge, threatened in writing against Buyer or any Affiliate of Buyer.

5.6Litigation. As of the date of this Agreement, there is no suit, action or litigation by any Person by or before any Governmental Authority, and no legal, administrative or arbitration proceeding, in each case, pending, or to Buyer’s knowledge, threatened in writing against Buyer that would have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement.

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Exhibit 10.1

5.7Financing. Buyer has, and Buyer shall have as of the Closing Date, sufficient cash in immediately available funds with which to pay the Purchase Price, consummate the transactions contemplated by this Agreement and perform its obligations under this Agreement and the Transaction Documents.

5.8Regulatory. Buyer is and hereafter shall continue to be qualified to own and assume operatorship of the Assets in all jurisdictions where the Assets are located, and the consummation of the transactions contemplated by this Agreement will not cause Buyer to be disqualified as such an owner or operator. To the extent required by any Laws, Buyer has maintained, and will hereafter continue to maintain, lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, all Laws governing the ownership and operation of such leases and has filed any and all required reports necessary for such ownership and operation with all Governmental Authorities having jurisdiction over such ownership and operation.

5.9Independent 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 (a) has relied or shall rely solely 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 the express provisions of this Agreement and not on any comments, statements, projections or other materials made or given by any representatives or consultants or advisors of Sellers, and (b) subject to the express provisions of this Agreement, has satisfied or shall satisfy itself through its own due diligence as to the environmental and physical condition of and contractual arrangements and other matters affecting the Assets. Buyer has no knowledge of any breach of any representation, warranty or covenant of any Seller given hereunder.

5.10Brokers’ 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.

5.11Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, 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 of 1933, as amended, and the rules and regulations thereunder, any state blue sky Laws or any other securities Laws.

ARTICLE VI

CERTAIN AGREEMENTS

6.1Conduct of Business.

(a)    Except (w) as set forth on Schedule 6.1, (x) for the operations covered by the AFEs and other capital commitments described on Schedule 4.13, (y) for actions taken in connection with emergency situations or maintain a lease and (z) 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 date hereof until Closing:

(i)    operate the Assets in the usual, regular and ordinary manner consistent with past practice (including the proper, timely and legal payment, in accordance with the terms of each Lease and Laws, of (A) all Burdens and (B) rentals, shut-in payments and other lease maintenance payments, in each case, with respect to the Assets due by a Seller prior to Closing); and

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Exhibit 10.1

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

(b)    Except (w) as set forth on Schedule 6.1, (x) for the operations covered by the AFEs and other capital commitments described on Schedule 4.13, (y) for actions taken in connection with emergency situations or to maintain a lease and (z) 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 date hereof until Closing:

(ii)    not propose any operation reasonably expected to cost Sellers in excess of $500,000, or operations that in the aggregate are reasonably expected to cost Sellers in excess of $2,000,000;

(ii)    not consent to any operation proposed by a Third Party that is reasonably expected to cost Sellers in excess of $500,000 or operations that in the aggregate are reasonably expected to cost Sellers in excess of $2,000,000;

(iii)    not enter into an Applicable Contract that, if entered into on or prior to the date of this Agreement, would be required to be listed on Schedule 4.7, or materially amend or change the terms of any Material Contract;

(iv)    not transfer, sell, mortgage, pledge or dispose of any portion of the Assets other than (A) the sale or disposal of Hydrocarbons in the ordinary course of business, (B) sales of equipment that is no longer necessary in the operation of the Assets or for which replacement equipment has been obtained and (C) disposals of Assets where the consideration is less than $250,000 in the aggregate (pre-disposal);

(v)    not reduce or terminate existing insurance; and

(vi)    not commit to do any of the foregoing.

(c)    Buyer acknowledges that Sellers own undivided interests in certain of the properties comprising the Assets that a Seller 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 an Affiliate of Sellers shall not constitute a breach of the provisions of this Section 6.1, and no action required by a vote of Working Interest owners shall constitute such a breach so long as Sellers have voted their interests in a manner that complies with the provisions of this Section 6.1.

6.2Successor Operator. While Buyer acknowledges that it desires to succeed the applicable Seller as operator of those Assets or portions thereof that such Seller may presently operate, Buyer acknowledges and agrees that Sellers cannot and do not covenant or warrant that Buyer shall become successor operator of such Assets since the Assets or portions thereof may be subject to operating or other agreements that control the appointment of a successor operator. Sellers agree, however, that as to the Assets that a Seller operates, Sellers shall use commercially reasonable efforts to support Buyer’s efforts to become successor operator of such Assets (to the extent permitted under any applicable joint operating agreement) effective as of Closing (at Buyer’s sole cost and expense) and to designate or appoint, to the extent legally possible and permitted under any applicable joint operating agreement, Buyer as successor operator of such Assets effective as of Closing.

6.3Governmental Bonds. Buyer acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by any Seller or its Affiliates with Governmental Authorities and relating to the Assets are transferable to Buyer. On or before the Closing Date, Buyer shall obtain, or cause to be obtained

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Exhibit 10.1

in the name of the Buyer, replacements for such bonds, letters of credit and guarantees to the extent such replacements are necessary (a) for Buyer’s ownership of the Assets and (b) to permit the cancellation of the bonds, letters of credit and guarantees posted by Sellers or their Affiliates with respect to the Assets. In addition, at or prior to Closing, Buyer shall deliver to Sellers evidence of the posting of bonds or other security with all applicable Governmental Authorities meeting the requirements of such authorities to own and, where appropriate, operate the Assets.

6.4Record Retention. Buyer shall, and shall cause its successors and assigns to, for a period of seven years following Closing, (a) retain the Records, (b) provide each Seller, its Affiliates and its and their respective officers, employees and representatives with access to the Records (to the extent that Sellers have not retained the original or a copy) during normal business hours for review and copying at such Seller’s expense and (c) provide each Seller, its Affiliates and its and their respective officers, employees and representatives with access, during normal business hours, to materials received or produced after Closing relating to any indemnity claim made under Section 13.2 for review and copying at such Seller’s expense. At the end of such seven year period and prior to destroying any of the Records, Buyer shall notify Sellers in advance of such destruction and provide Sellers an opportunity to copy such Records at Sellers’ sole cost and expense.

6.5Knowledge of Breach. Buyer will notify Sellers, and Sellers will notify Buyers, promptly and in reasonable detail after any officer of Buyer or Sellers, as the case may be, obtains actual knowledge that any representation or warranty of the other Party contained in this Agreement is, becomes or will be untrue in any material respect on or before the Closing Date. No breach of any representation, warranty, covenant, agreement or condition of this Agreement shall be deemed to be a breach of this Agreement for any purpose under this Agreement, and no Party nor any Affiliate of any Party shall have any claim or recourse against the other Parties or their respective directors, officers, employees, partners, Affiliates, controlling persons, agents, advisors or representatives with respect to such breach, if such Party or any Affiliate had actual knowledge prior to the execution of this Agreement of such breach or of the threat of such breach or the circumstances giving rise to such breach.

6.6Amendment of Schedules. Buyer agrees that, with respect to the representations and warranties of Sellers contained in this Agreement, Sellers shall have the continuing right until Closing to add, supplement or amend the Schedules to its representations and warranties with respect to any matter hereafter arising which, if existing at the date hereof or thereafter, would have been required to be set forth or described in such Schedules. For all purposes of this Agreement, including for purposes of determining whether the conditions set forth in Article VII have been fulfilled, the Schedules to Sellers’ representations and warranties contained in this Agreement shall be deemed to include only that information contained therein on the date of this Agreement and shall be deemed to exclude all information contained in any addition, supplement or amendment thereto; provided, however, that if Closing shall occur, then all matters that are disclosed pursuant to any such addition, supplement or amendment at or prior to Closing and that are not the result of any breach by any Seller of its covenants under Article VI shall be waived and Buyer shall not be entitled to make a claim with respect thereto pursuant to the terms of this Agreement or otherwise.

6.7Non-Solicitation of Employees. Except with respect to the employees identified in the Transition Services Agreement, from the Execution Date until the one year anniversary of either the Closing Date or the termination of this Agreement, Buyer will not, and will cause its Affiliates not to, directly or indirectly, solicit for employment or employ any officer or employee of Sellers or their Affiliates without obtaining the prior written consent of Sellers, which consent shall not be unreasonably withheld. This Section 6.7 shall not apply to general solicitations of employment not specifically directed towards officer or employees of Sellers or their Affiliates or field workers.

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Exhibit 10.1

6.8Sellers’ Existence. Until the expiration of the Survival Period, each Seller shall maintain its valid existence and good standing under the Laws of the state of its formation and continue to be duly licensed or qualified to do business as a foreign limited partnership (except for EnerVest Holding) in the State of Texas.

6.9Financial Statements. From and after the date of this Agreement until December 31, 2016 (the “Records Period”), Sellers shall, and shall cause their Affiliates and their respective officers, directors, managers, employees, agents and representatives to, provide reasonable cooperation to 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”). During the Records Period, Sellers agree to make available to Buyer and its Affiliates and their agents, auditors and representatives any and all books, records, information and documents that are attributable to the Assets in Sellers’ or their Affiliates’ possession or control and access to Sellers’ and their Affiliates’ personnel, in each case as reasonably required by Buyer, its Affiliates and their agents, auditors and representatives in order to prepare and audit, if required, in connection with the Filings, financial statements meeting the requirements of Regulation S-X under the Securities Act of 1933 (“Securities Act”). During the Records Period, Sellers shall, and shall cause their 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 Sellers or their 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, Sellers and their Affiliates shall retain all books, records, information and documents relating to the Assets for the three (3) fiscal years prior to January 1, 2013 and the period from January 1, 2013 through the Closing Date. Buyer will reimburse Sellers and their Affiliates, within ten (10) Business Days after demand in writing therefor, for any reasonable costs and expenses incurred by Sellers and their Affiliates in complying with the provision of this Section 6.9.

ARTICLE VII

BUYER’S CONDITIONS TO CLOSING

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

7.1Representations. The representations and warranties of Sellers set forth in Article IV shall be true and correct in all respects (without regard to materiality or Material Adverse Effect qualifiers in such representations) on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties that would not have a Material Adverse Effect.

7.2Performance. Sellers shall have materially performed or complied with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Sellers is required prior to or on the Closing Date.

7.3No Legal Proceedings. No material suit, action, litigation or other proceeding by any Third Party shall be pending before any Governmental Authority seeking to restrain, prohibit, enjoin or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement.

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Exhibit 10.1

7.4Title Defects and Environmental Defects. In each case subject to the Individual Title Defect Threshold, the Individual Environmental Threshold and the Aggregate Deductible, as applicable, the sum of (a) all Title Defect Amounts determined under Section 11.2(g) prior to Closing, less the sum of all Title Benefit Amounts determined under Section 11.2(h) prior to Closing, plus (b) all Remediation Amounts for Environmental Defects determined under Article XII prior to Closing, plus (c) all Net Casualty Losses prior to Closing shall be less than 20% of the Purchase Price.

7.5Closing Deliverables. Sellers shall have delivered (or be ready, willing and able to deliver at Closing) to Buyer the documents and other items required to be delivered by Sellers under Section 9.3.

ARTICLE VIII

SELLERS’ CONDITIONS TO CLOSING

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

8.1Representations. The representations and warranties of Buyer set forth in Article V shall be true and correct in all material respects (without regard to materiality qualifiers in such representations) on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date).

8.2Performance. 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.

8.3No Legal Proceedings. No material suit, action, litigation or other proceeding by any Third Party shall be pending before any Governmental Authority seeking to restrain, prohibit or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement.

8.4Title Defects and Environmental Defects. In each case subject to the Individual Title Defect Threshold, the Individual Environmental Threshold and the Aggregate Deductible, as applicable, the sum of (a) all Title Defect Amounts determined under Section 11.2(g) prior to Closing, less the sum of all Title Benefit Amounts determined under Section 11.2(h) prior to Closing, plus (b) all Remediation Amounts for Environmental Defects determined under Article XII prior to Closing, plus (c) all Net Casualty Losses prior to Closing shall be less than 20% of the Purchase Price.

8.5Replacement Bonds and Guarantees. Buyer shall have obtained, in the name of Buyer, replacements for Sellers’ and their Affiliates’ bonds, letters of credit and guarantees, to the extent required by Section 6.3.

8.6Closing Deliverables. Buyer shall have delivered (or be ready, willing and able to deliver at Closing) to Sellers the documents and other items required to be delivered by Buyer under Section 9.3.

ARTICLE IV

CLOSING

9.1Date of Closing. Subject to the conditions stated in this Agreement, the sale by Sellers and the purchase by Buyer of the Assets pursuant to this Agreement (the “Closing”) shall occur on January 31,

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Exhibit 10.1

2014, or such other date as Buyer and Sellers may agree upon in writing. The date on which the Closing actually occurs shall be the “Closing Date.”

9.2Place of Closing. The Closing shall be held at the offices of Vinson & Elkins L.L.P., 1001 Fannin, Suite 2500, Houston, Texas 77002, or such other place as mutually agreed upon by the Parties.

9.3Closing Obligations. At 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 of Sellers and Buyer shall execute, acknowledge and deliver the Assignment in sufficient counterparts to facilitate recording in the applicable counties covering the Assets.

b.Each of Sellers and Buyer shall execute and deliver assignments on appropriate forms of any state Leases included in the Assets in sufficient counterparts to facilitate filing with the applicable Governmental Authority.

c.Each of Sellers and Buyer shall execute and deliver the Preliminary Settlement Statement.

d.Subject to Section 11.2(c), Buyer shall deliver to Sellers, to the account designated in the Preliminary Settlement Statement, by direct bank or wire transfer in immediately available funds, the Adjusted Purchase Price after giving effect to the Deposit and interest earned on the Deposit and for the avoidance of doubt, less such amount to be held in escrow pursuant to Section 11.2(c).

e.Buyer and Sellers shall execute joint written instructions to the Escrow Agent to (i) deliver interest earned on the Deposit prior to Closing to Sellers, to the account designated in the Preliminary Settlement Statement, by direct bank or wire transfer in immediately available funds and (ii) retain the Deposit in accordance with Section 3.10.

f.Each Seller shall deliver, on forms supplied by Buyer and reasonably acceptable to Sellers, transfer orders or letters in lieu thereof 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.

g.Each Seller shall deliver an executed certificate of non-foreign status that meets the requirements set forth in Treasury Regulation § 1.1445-2(b)(2).

h.To the extent required under any Law or by any Governmental Authority for any Lease or Well, Sellers and Buyer shall deliver state change of operator forms designating Buyer as the operator of the Wells and the Leases currently operated by any Seller.

i.An authorized officer of each Seller shall execute and deliver a certificate, dated as of Closing Date, certifying that the conditions set forth in Section 7.1 and Section 7.2 have been fulfilled and, if applicable, any exceptions to such conditions that have been waived by Buyer.

j.An authorized officer of Buyer shall execute and deliver a certificate, dated as of Closing, certifying that the conditions set forth in Section 8.1 and Section 8.2 have been fulfilled and, if applicable, any exceptions to such conditions that have been waived by Sellers.

k.Sellers and Buyer shall execute and deliver the Transition Services Agreement.

l.Sellers and Buyer shall deliver any instruments and documents required by Section 6.3.

m.Each of Sellers and Buyer shall execute and deliver any other agreements, instruments

9.4Records. In addition to the obligations set forth under Section 9.3, but notwithstanding anything herein to the contrary, no later than 30 Business Days after the Closing Date, Sellers shall make available to Buyer the Records for pickup from Sellers’ offices during normal business hours.

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Exhibit 10.1

ARTICLE X

ACCESS; DISCLAIMERS

10.1Access.

(a)    From and after the date hereof and up to and including the Closing Date (or earlier termination of this Agreement) but subject to the other provisions of this Section 10.1 and obtaining any required consents of Third Parties, including Third Party operators of the Assets, Sellers shall afford to Buyer and its officers, employees, agents, accountants, consultants, attorneys and other authorized representatives (“Buyer’s Representatives”) reasonable access between the hours of 7:00 a.m. and 6:00 p.m., local time, Mondays through Fridays (excluding holidays), as mutually agreed by the Parties on Saturdays and Sundays (excluding holidays) and upon Buyer’s request, between the hours that the Parties may mutually agree, on December 7, 2013 and December 8, 2013,to the Assets and all Records in Sellers’ or any of their Affiliates’ possession. Buyer shall be permitted to make photocopies of the Records, which photocopies may be removed from the Records facilities by Buyer solely for use in connection with Buyer’s investigation and conduct of due diligence related to the Assets. 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 to be conducted by a reputable environmental consulting or engineering firm approved in advance in writing by Sellers; provided further that any sampling or invasive activity by Buyer or Buyer’s Representatives shall require the prior written consent of Sellers, which consent shall not be unreasonably withheld, and Sellers shall have the right to be present during any stage of the assessment. Buyer shall give Sellers reasonable prior written notice before entering onto any of the Assets, and Sellers or their designee shall have the right to accompany Buyer and Buyer’s Representatives whenever they are on site on the Assets. 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 assessment) with respect to, any Assets with respect to which Sellers do not have the authority to grant access for such due diligence. Sellers shall use commercially reasonable efforts to obtain access rights from Third Parties for Buyer to conduct its investigation and due diligence of the Assets; provided that Sellers shall not be required to incur any Liability or pay any money in order to obtain such access rights.

(c)    Buyer shall coordinate its environmental property assessments and physical inspections of the Assets with Sellers 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 Sellers’, and any Third Party operator’s, safety rules, regulations and operating policies while conducting its due diligence evaluation of the Assets, including any environmental or other inspection or assessment of the Assets and, to the extent required by Sellers or any Third Party operator, execute and deliver any required boarding agreement of Sellers or any such Third Party operator. Buyer hereby defends, indemnifies and holds 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 LIABILITIES TO THE EXTENT ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES.

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Exhibit 10.1

(d)    Buyer agrees to provide Sellers, on or before the Environmental Claim Date, copies of all final reports and test results prepared by Buyer or any of Buyer’s Representatives which contain data collected or generated from Buyer’s due diligence with respect to Environmental Defects as to which Buyer provides Sellers an Environmental Defect Notice. Sellers shall not be deemed by their receipt of said documents or otherwise to have made any representation or warranty, expressed, implied or statutory, as to the condition of the Assets or to the accuracy of said documents or the information contained therein.

(e)    Upon completion of Buyer’s due diligence, Buyer shall at its sole cost and expense and without any cost or expense to Sellers or their Affiliates (i) repair all damage done to the Assets in connection with Buyer’s due diligence, (ii) restore the Assets to the approximate same condition as, or better condition than, they were prior to commencement of Buyer’s due diligence and (iii) remove all equipment, tools or other property brought onto the Assets in connection with Buyer’s due diligence. Any disturbance to the Assets (including the leasehold associated therewith) resulting from Buyer’s due diligence will be promptly corrected by Buyer.

(f)    During all periods that Buyer or any of Buyer’s Representatives are on the Assets, Buyer shall maintain, at its sole expense and with insurers reasonably satisfactory to Sellers, policies of insurance of the types and in the amounts reasonably requested by Sellers. Coverage under all insurance required to be carried by Buyer hereunder will (i) be primary insurance, (ii) list Seller Indemnified Parties as additional insureds, (iii) waive subrogation against Seller Indemnified Parties and (iv) provide for ten days’ prior notice to Sellers in the event of cancellation or modification of the policy or reduction in coverage. Upon request by Sellers, Buyer shall provide evidence of such insurance to Sellers prior to entering the Assets.

10.2Confidentiality. Buyer acknowledges that, pursuant to its right of access to the Records or the Assets, Buyer will become privy to confidential and other information of Sellers or their Affiliates and Buyer shall ensure that such confidential information shall be held confidential by Buyer and Buyer’s Representatives in accordance with the terms of the Confidentiality Agreement. If 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).

10.3Disclaimers.

a.EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE IV, SECTION 11.1(b) OR THE ASSIGNMENT, (I) SELLERS MAKE NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLERS EXPRESSLY DISCLAIM 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 SELLERS OR ANY OF THEIR AFFILIATES).

b.EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE IV, SECTION 11.1(b) OR THE ASSIGNMENT, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLERS EXPRESSLY DISCLAIM ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE

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Exhibit 10.1

TO ANY OF THE ASSETS, (II) 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, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES TO BE GENERATED BY THE ASSETS, (V) THE PRODUCTION OF OR ABILITY TO PRODUCE HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLERS OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES, OR ITS OR THEIR RESPECTIVE EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE IV OR SECTION 11.1(b), SELLERS FURTHER DISCLAIM ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM 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 ASSETS IN THEIR 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 AS BUYER DEEMS APPROPRIATE.

c.EXCEPT AS TO THE LIMITED EXTENT REPRESENTED OTHERWISE IN SECTION 4.15, SELLERS HAVE NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS 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 BUYER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE.

d.SELLERS AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 10.3 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY LAW.

ARTICLE XI

TITLE MATTERS; CASUALTY; TRANSFER RESTRICTIONS

11.1Sellers’ Title.

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Exhibit 10.1

(a)    General Disclaimer of Title Warranties and Representations. Except for the special warranty of title as set forth in Section 11.1(b) and the Assignment and without limiting Buyer’s remedies for Title Defects set forth in this Article XI, Sellers make no warranty or representation, express, implied, statutory or otherwise, with respect to Sellers’ title to any of the Assets, and Buyer hereby acknowledges 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 11.2(d) or if applicable, Section 14.1(c) and (ii) after Closing, shall be pursuant to the special warranty of title set forth in Section 11.1(b) and the Assignment.

(b)    Special Warranty of Title. Effective as of the Closing Date and until the end of the Survival Period, each Seller warrants Defensible Title to the Leases, Wells and Well Locations (subject to any reservations, limitations or depth restrictions in the Leases or otherwise described on Exhibit A, Exhibit B or Schedule 3.8) unto Buyer against every Person whomsoever lawfully claims the same or any part thereof by, through or under such Seller, but not otherwise, subject, however, to the Permitted Encumbrances; provided, however, that, except with respect to any liability of Sellers for any claim asserted in writing by Buyer to Sellers in accordance with Section 11.1(c) on or before the expiration of the Survival Period for breach of such special warranty, such special warranty shall cease and terminate at the end of such Survival Period.

(c)    Recovery on Special Warranty.

(i)    Buyer’s Assertion of Title Warranty Breaches. Prior to the expiration of the period of time commencing as of the Closing Date and ending at 5:00 p.m. (Central Time) on the first Business Day that is 273 days after the Closing Date (the “Survival Period”), Buyer shall furnish Sellers a written notice (the “Special Warranty Claim Notice”) meeting the requirements of Section 11.2(a) setting forth any matters which Buyer intends to assert as a breach of Sellers’ special warranty in Section 11.1(b). For all purposes of this Agreement, Buyer shall be deemed to have waived, and Sellers shall have no further liability for, any breach of Sellers’ special warranty that Buyer fails to assert by a Special Warranty Claim Notice given to Sellers on or before the expiration of the Survival Period. Sellers shall have a reasonable opportunity, but not the obligation, to cure any Title Defect asserted by Buyer pursuant to this Section 11.1(c)(i). Buyer agrees to reasonably cooperate with any attempt by Sellers to cure any such Title Defect.

(ii)    Limitations on Special Warranty. For purposes of Sellers’ special warranty of title, the value of the Wells and Well Locations set forth on Schedule 3.8, as appropriate (subject to any reservations, limitations or depth restrictions in the Leases or otherwise described on Exhibit A, Exhibit B or Schedule 3.8), shall be deemed to be the Allocated Value thereof, as adjusted herein. Recovery on Sellers’ special warranty of title shall be limited to an amount (without any interest accruing thereon) equal to the reduction in the Purchase Price to which Buyer would have been entitled had Buyer asserted the defect giving rise to such breach of Sellers’ special warranty of title as a Title Defect prior to Closing pursuant to Section 11.2 (including subject to the limitations described in Section 11.2(i)).

11.2Notice of Title Defects; Defect Adjustments.

(a)    Title Defect Notices.Buyer must deliver no later than 5:00 p.m. (Central Time) on January 24, 2014 (the “Title Claim Date”) claim notices to Sellers meeting the requirements of this Section 11.2(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 11.2(a). For all purposes of this Agreement and notwithstanding anything herein to the contrary (except as provided in Section 11.1), Buyer shall be deemed to have waived, and Sellers shall have no liability for, any Title Defect which Buyer fails to assert as a Title Defect by a properly delivered Title Defect Notice received by Sellers on or before the Title Claim Date; provided,

22

Exhibit 10.1

however, that, for purposes of Sellers’ special warranty to title under Section 11.1(b), such waiver shall not apply to any matter that prior to the Title Claim Date is not discovered by any of Buyer’s or any of its Affiliate’s employees, title attorneys, landmen or other title examiners while conducting Buyer’s due diligence with respect to the Assets and may be claimed by Buyer pursuant to Section 11.1. To be effective, each Title Defect Notice shall be in writing and shall include (i) a description of the alleged Title Defect and the Asset (including the legal description of such Asset and the Leases applicable to such Asset), or portion thereof, affected by such Title Defect (each a “Title Defect Property”), (ii) the Allocated Value of each Title Defect Property, (iii) supporting documents reasonably necessary for Sellers to verify the existence of such alleged Title Defect, (iv) Buyer’s preferred manner of curing each Title Defect and (v) the amount by which Buyer reasonably believes the Allocated Value of each Title Defect Property is reduced by such alleged Title Defect and the computations upon which Buyer’s belief is based. To give Sellers an opportunity to commence reviewing and curing Title Defects, Buyer agrees to use reasonable efforts to give Sellers, on or before the end of each calendar week prior to the Title Claim Date, written notice of all alleged Title Defects (as well as any claims that would be claims under the special warranty set forth in Section 11.1) discovered by Buyer during the preceding calendar week, which notice may be preliminary in nature and supplemented prior to the Title Claim Date. Buyer shall also, promptly upon discovery, furnish Sellers with written notice of any Title Benefit which is discovered by any of Buyer’s or any of its Affiliate’s employees, title attorneys, landmen or other title examiners while conducting Buyer’s due diligence with respect to the Assets prior to the Title Claim Date.

(b)    Title Benefit Notices. Sellers shall have the right, but not the obligation, to deliver to Buyer on or before 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 the Asset, or portion thereof, affected by such alleged Title Benefit (each a “Title Benefit Property”), and (ii) the amount by which Sellers reasonably believe the Allocated Value of such Title Benefit Property is increased by such alleged Title Benefit and the computations upon which Sellers’ belief is based. Except as set forth in Section 11.1(c)(ii) and Section 11.2(a), Sellers shall be deemed to have waived all Title Benefits for which a Title Benefit Notice has not been delivered on or before the Title Claim Date.

(c)    Sellers’ Right to Cure. Each Seller shall have the right, but not the obligation, to attempt, at its sole cost, to cure at any time prior to 120 days after Closing (the “Cure Period”), any Title Defects of which it has been advised by Buyer. During the period of time from Closing to the expiration of the Cure Period, Buyer agrees to afford such Seller and its officers, employees and other authorized representatives reasonable access, during normal business hours, to the Assets and all Records in Buyer’s or any of its Affiliates’ possession in order to facilitate such Seller’s attempt to cure any such Title Defects. The Title Defect Amount claimed in good faith by Buyer for any Title Defect as to which such Seller has provided notice to Buyer that such Seller intends to attempt to cure the Title Defect during the Cure Period, shall be paid by Buyer at Closing to the Escrow Agent pursuant to an escrow agreement mutually acceptable to the Parties and any such amount shall be paid to Sellers or Buyer, as applicable, upon the expiration of the Cure Period and as agreed by the Sellers and Buyer or determined pursuant to Section 11.2(j). An election by such Seller to attempt to cure a Title Defect shall be without prejudice to its rights under Section 11.2(j) and shall not constitute an admission against interest or a waiver of such Seller’s right to dispute the existence, nature or value of, or cost to cure, the alleged Title Defect. Notwithstanding anything to the contrary herein, with respect to any Asset that is owned by more than one Seller, Sellers shall make their elections described in Sections 11.2(c), 11.2(d), 12.1(a) or 12.1(b) as a group through the Seller Representative.

(d)    Remedies for Title Defects. Subject to each Seller’s continuing right to dispute the existence of a Title Defect and the Title Defect Amount asserted with respect thereto, and subject to the rights of the Parties pursuant to Section 14.1(c), in the event that any Title Defect timely and effectively asserted

23

Exhibit 10.1

by Buyer in accordance with Section 11.2(a) is not waived in writing by Buyer or cured during the Cure Period, Sellers shall, at their sole option, elect to:

(i)    subject to the Individual Title Defect Threshold and the Aggregate Deductible, convey the Title Defect Property to Buyer at Closing, and reduce the Purchase Price or Final Price, as applicable, by the Title Defect Amount determined pursuant to Section 11.2(g) or Section 11.2(j);

(ii)    with the written consent of Buyer, retain the entirety of the Title Defect Property that is subject to such Title Defect, together with all associated Assets, in which event the Purchase Price or Final Price, as applicable, shall be reduced by an amount equal to the Allocated Value of such Title Defect Property and such associated Assets; or

(iii)    if applicable, terminate this Agreement pursuant to Section 14.1(c).

(e)    Remedies for Title Benefits. The amount resulting from a Title Benefit (the “Title Benefit Amount”) shall be determined pursuant to Section 11.2(h) or Section 11.2(j). Any Title Benefit Amounts shall be offset against the total Title Defect Amounts for all Title Defects. Notwithstanding anything to the contrary in this section, if the total of all Title Benefit Amounts exceeds the total of all Title Defect Amounts for the Assets, there shall be no upward adjustment to the Purchase Price or other remedies provided to Sellers for such Title Benefits.

(f)    Exclusive Remedy. Except for Buyer’s rights under Sellers’ special warranty of title under Section 11.1(b) and Buyer’s rights to terminate this Agreement pursuant to Section 14.1(c), the provisions set forth in Section 11.2(d) shall be the exclusive right and remedy of Buyer with respect to such Seller’s failure to have Defensible Title with respect to any Asset or any other title matter.

(g)    Title Defect Amount. The amount by which the Allocated Value of a Title Defect Property is reduced as a result of the existence of a Title Defect shall be the “Title Defect Amount” and shall be determined in accordance with the following terms and conditions:

i.if Buyer and the affected Sellers 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 the Title Defect represents a discrepancy between (A) Sellers’ Net Revenue Interest for any Title Defect Property and (B) the Net Revenue Interest set forth for such Title Defect Property on Schedule 3.8, then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property multiplied by a fraction, the numerator of which is the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest set forth for such Title Defect Property on Schedule 3.8;

iv.if the Title Defect represents an obligation or 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 potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Buyer and the affected Seller and such other reasonable factors as are necessary to make a proper evaluation;

v.the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any losses included in another Title Defect Amount hereunder; and

vi.notwithstanding anything to the contrary in this Article XI, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

24

Exhibit 10.1

(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 affected Sellers agree on the Title Benefit Amount, then that amount shall be the Title Benefit Amount;

(ii)if the Title Benefit represents a discrepancy between (A) the affected Sellers’ Net Revenue Interest for any Title Benefit Property and (B) the Net Revenue Interest set forth for such Title Benefit Property on Schedule 3.8, then the Title Benefit Amount shall be the product of the Allocated Value of such Title Benefit Property multiplied by a fraction, the numerator of which is the Net Revenue Interest increase and the denominator of which is the Net Revenue Interest set forth for such Title Benefit Property on Schedule 3.8; 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 Title Benefit Property, the portion of such 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 such Title Benefit Property, the values placed upon the Title Benefit by Buyer and affected Sellers and such other reasonable factors as are necessary to make a proper evaluation.

(i)Title Defect Threshold and Deductible. Except as provided in this Section 11.2(i), (i) there shall not be any adjustments to the Purchase Price or other remedies provided by Sellers for any individual Title Defect for which the Title Defect Amount does not exceed $25,000 (the “Individual Title Defect Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Sellers for any Title Defect that exceeds the Individual Title Defect Threshold unless (A) the amount of the sum of (1) the aggregate Title Defect Amounts of all such Title Defects that exceed the Individual Title Defect Threshold (but excluding any such Title Defects cured by Sellers), plus (2) the aggregate Remediation Amounts of all Environmental Defects that exceed the Individual Environmental Threshold (but excluding any Environmental Defects cured by Sellers), exceeds (B) the Aggregate Deductible, after which point Buyer shall be entitled to adjustments to the Purchase Price or other applicable remedies available hereunder, but only with respect to the amount by which the aggregate amount of such Title Defect Amounts and Remediation Amounts exceeds the Aggregate Deductible. Notwithstanding anything to the contrary in this Agreement, the Individual Title Threshold and the Aggregate Deductible shall not apply to any Title Defect which arises from typographical, clerical or scrivener’s error (such as misplaced decimal points, transposed digits and similar erroneous entries of data in the ARIES database as compared to the documents in Sellers’ possession from which such information was extracted) in the Exhibits or Schedules to this Agreement. For the avoidance of doubt, if Sellers retain any Title Defect Property pursuant to Section 11.2(d)(ii), the Title Defect Amount related to such Title Defect Property will not be counted towards the Aggregate Deductible.

(j)Title Dispute Resolution. Sellers and Buyer shall attempt to agree on matters regarding (i) all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts, and (ii) the adequacy of any curative materials provided by Sellers to cure an alleged Title Defect (the “Disputed Title Matters”) prior to Closing. If Sellers and Buyer are unable to agree by Closing (or by the end of the Cure Period if Sellers elect to attempt to cure a Title Defect after Closing), the Disputed Title Matters shall be exclusively and finally resolved pursuant to this Section 11.2(j). There shall be a single arbitrator, who shall be a title attorney with at least ten 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 Sellers within 15 days after the Closing or the end of the Cure Period, as applicable, and absent such agreement, by the Houston, Texas office of the American Arbitration Association (the “Title Arbitrator”). Each of Buyer and Sellers shall submit to the Title Arbitrator its proposed resolution of the Disputed Title Matter. The proposed resolution of the Disputed Title Matter shall include the best offer of the submitting Party in a single monetary amount that such Party is willing to pay or accept (as applicable) to settle the Disputed Title Matter. The Title Arbitrator shall be limited to awarding only one or the other of the two proposed settlement amounts. The

25

Exhibit 10.1

arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section 11.2(j). The Title Arbitrator’s determination shall be made within 20 days after submission of the matters in dispute and shall be final and binding upon the Parties, without right of appeal. In making its determination, the Title Arbitrator shall be bound by the rules set forth in Section 11.2(g) and Section 11.2(h) and, subject to the foregoing, may consider such other matters as in the opinion of the Title Arbitrator are necessary to make a proper determination. The Title Arbitrator, however, may not award Buyer a greater Title Defect Amount than the Title Defect Amount claimed by Buyer in its applicable Title Defect Notice. The Title Arbitrator shall act as an expert for the limited purpose of determining the specific Disputed Title Matter 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. Sellers and Buyer shall 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 Purchase Price pursuant to Section 3.5 or Section 3.6, then within ten days after the Title Arbitrator delivers written notice to Buyer and Sellers of his award with respect to a Title Defect Amount or a Title Benefit Amount and, subject to Section 11.2(i), (i) Buyer shall pay to Sellers the amount, if any, so awarded by the Title Arbitrator to Sellers, and (ii) Sellers shall pay to Buyer the amount, if any, so awarded by the Title Arbitrator to Buyer. Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section 11.2(j) and, to the extent any adjustments are not agreed upon by the Parties as of Closing, the Purchase Price shall not be adjusted therefor at Closing, such amount shall be paid by Buyer into escrow pursuant to Section 11.2(c) and subsequent adjustments to the Purchase Price, if any, will be made pursuant to the Final Settlement Statement described in Section 3.6 and this Section 11.2.

11.3Casualty Loss.

a.Notwithstanding anything herein to the contrary, from and after the Effective Time, if Closing occurs, Buyer shall assume all risk of loss with respect to production of Hydrocarbons through normal depletion (including watering out of any well, collapsed casing or sand infiltration of any well) and the depreciation of Personal Property due to ordinary wear and tear, in each case, with respect to the Assets, and Buyer shall not assert such matters as Casualty Losses or Title Defects hereunder.

b.If, after the date of this Agreement but prior to the Closing Date, any portion of the Assets is damaged or destroyed by fire or other casualty or is taken in condemnation or under right of eminent domain (each, a “Casualty Loss”), and the Closing thereafter occurs and if the estimated cost to repair such Asset (with equipment of similar utility) is greater than $100,000, Buyer shall not be obligated to purchase such Asset. If Buyer declines to purchase such Asset, the Purchase Price shall be reduced by the Allocated Value of such Asset. If Buyer elects to purchase such Asset, the Purchase Price shall be reduced by the estimated cost to repair such Asset (with equipment of similar utility), less all insurance proceeds which Seller shall cause to be paid to Buyer, up to the Allocated Value thereof (the reduction being the “Net Casualty Loss”). Sellers, at their sole option, may elect to cure such Casualty Loss to Buyer’s reasonable satisfaction and, in such event, Sellers shall be entitled to all insurance proceeds. If Sellers elect to cure such Casualty Loss, Sellers may replace any personal property that is the subject of a Casualty Loss with equipment of similar grade and utility. If Sellers cure the Casualty Loss to Buyer’s reasonable satisfaction, Buyer shall purchase the affected Asset at Closing for the Allocated Value thereof.

11.4    Consents to Assign. With respect to each Consent set forth on Schedule 4.4, Sellers, prior to Closing, shall send to the holder of each such Consent a notice in material compliance with the contractual provisions applicable to such Consent seeking such holder’s consent to the transactions contemplated hereby.

26

Exhibit 10.1

a.If (i) Sellers fail to obtain a Consent set forth on Schedule 4.4 prior to Closing and the failure to obtain such Consent would cause (A) the assignment of the Assets (or portion thereof) affected thereby to Buyer to be void or voidable under the terms thereof or (B) the termination of a Lease or Contract under the terms thereof, or (ii) a Consent requested by Sellers is denied in writing, then, in each case, the Asset (or portion thereof) affected by such un-obtained Consent shall be excluded from the Assets to be assigned to Buyer at Closing, and the Purchase Price shall be reduced by the Allocated Value of such Asset (or portion thereof) so excluded. In the event that a Consent (with respect to an Asset excluded pursuant to this Section 11.4(a)) that was not obtained prior to Closing is obtained within 120 days following Closing, then, within ten days after such Consent is obtained (x) Buyer shall purchase the Asset (or portion thereof) that was so excluded as a result of such previously un-obtained Consent and pay to Sellers the amount by which the Purchase Price was reduced at Closing with respect to the Asset (or portion thereof) so excluded and (y) Sellers shall assign to Buyer the Asset (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment.

b.If (i) Sellers fail to obtain a Consent set forth on Schedule 4.4 prior to Closing and the failure to obtain such Consent would not cause (A) the assignment of the Assets (or portion thereof) affected thereby to Buyer to be void or voidable under the terms thereof or (B) the termination of a Lease or Contract under the terms thereof, and (ii) such Consent requested by Sellers is not denied in writing by the holder thereof, then the Asset (or portion thereof) subject to such un-obtained Consent shall nevertheless be assigned by Sellers to Buyer at Closing as part of the Assets and Buyer shall have no claim against, and Sellers shall have no Liability for, the failure to obtain such Consent.

c.Prior to Closing, Sellers and Buyer shall use their commercially reasonable efforts to obtain all Consents listed on Schedule 4.4; provided, however, that no Party shall be required to incur any Liability or pay any money in order to obtain any such Consent. Subject to the foregoing, Buyer agrees to provide Sellers with any information or documentation that may be reasonably requested by Sellers or the Third Party holder(s) of such Consents in order to facilitate the process of obtaining such Consents.

ARTICLE XII

ENVIRONMENTAL MATTERS

12.1Notice of Environmental Defects.

(a)    Environmental Defects Notice. Buyer must deliver no later than 5:00 p.m. (Central Time) on January 17, 2014 (the “Environmental Claim Date”) claim notices to Sellers meeting the requirements of this Section 12.1(a) (collectively the “Environmental Defect Notices” and individually an “Environmental Defect Notice”) setting forth any matters which, in Buyer’s reasonable opinion, constitute Environmental Defects and which Buyer intends to assert as Environmental Defects pursuant to this Section 12.1. For all purposes of this Agreement, 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 a properly delivered Environmental Defect Notice received by Sellers on or before the Environmental Claim Date, with such liabilities being “Buyer’s Environmental Liabilities.” To be effective, each Environmental Defect Notice shall be in writing and shall include (i) a description of the matter constituting the alleged Environmental Condition (including the applicable Environmental Law violated or implicated thereby) and the Assets affected by such alleged Environmental Condition, (ii) the Allocated Value of the Assets (or portions thereof) affected by such alleged Environmental Condition, (iii) supporting documents reasonably necessary for Sellers to verify the existence of such alleged Environmental Condition, and (iv) a calculation of the Remediation Amount (itemized in reasonable detail) that Buyer asserts is attributable to such alleged Environmental Defect. Buyer’s calculation of the Remediation Amount included in the Environmental Defect

27

Exhibit 10.1

Notice must describe in reasonable detail the Remediation proposed for the alleged Environmental Condition that gives rise to the asserted Environmental Defect and identify all assumptions used by the Buyer in calculating the Remediation Amount, including the standards that Buyer asserts must be met to comply with Environmental Laws. Sellers shall have the right, but not the obligation, to cure any asserted Environmental Defect on or before the expiration of the Cure Period. To give Sellers an opportunity to commence reviewing and curing Environmental Defects, Buyer agrees to use reasonable efforts to give Sellers, on or before the end of each calendar week prior to the Environmental Claim Date, written notice of all alleged Environmental Defects discovered by Buyer during the preceding calendar week, which notice may be preliminary in nature and supplemented prior to the Environmental Claim Date.

(b)    Remedies for Environmental Defects. Subject to each Seller’s continuing right to dispute the existence of an Environmental Defect or the Remediation Amount asserted with respect thereto, and subject to the rights of the Parties pursuant to Section 14.1(c), in the event that any Environmental Defect timely asserted by Buyer in accordance with Section 12.1(a) is not waived in writing by Buyer or cured during the Cure Period, such Seller shall, at its sole option, elect to:

(i)subject to the Individual Environmental Threshold and the Aggregate Deductible, reduce the Purchase Price by the Remediation Amount;

(ii)retain the entirety of the Asset that is subject to such Environmental Defect, together with all associated Assets, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Asset and such associated Assets;

(iii)if applicable, terminate this Agreement pursuant to Section 14.1(c).

If any Seller 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 all Liabilities with respect thereto and such responsibility of Buyer shall be deemed to constitute part of the Assumed Obligations hereunder.

(c)    Exclusive Remedy. Except for Buyer’s rights to terminate this Agreement pursuant to Section 14.1(c), the provisions set forth in Section 12.1(b)shall be the exclusive right and remedy of Buyer with respect to any Environmental Defect with respect to any Asset or other environmental matter.

(d)    Environmental Deductibles. Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Sellers for any individual Environmental Defect for which the Remediation Amount does not exceed $50,000 (the “Individual Environmental Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Sellers for any Environmental Defect for which the Remediation Amount exceeds the Individual Environmental Threshold unless (A) the amount of the sum of (1) the aggregate Remediation Amounts of all such Environmental Defects that exceed the Individual Environmental Threshold (but excluding any Environmental Defects cured by Sellers), plus (2) the aggregate Title Defect Amounts of all Title Defects that exceed the Individual Title Defect Threshold (but excluding any Title Defects cured by Sellers), exceeds (B) the Aggregate Deductible, after which point Buyer shall be entitled to adjustments to the Purchase Price or other applicable remedies available hereunder, but only with respect to the amount by which the aggregate amount of such Remediation Amounts and Title Defect Amounts exceeds the Aggregate Deductible. For the avoidance of doubt, if Sellers retain any Assets pursuant to Section 12.1(b)(ii), the Remediation Amounts relating to such retained Assets will not be counted towards the Aggregate Deductible.

28

Exhibit 10.1

(e)    Environmental Dispute Resolution. Sellers and Buyer shall attempt to agree on all Environmental Defects and Remediation Amounts prior to Closing. If Sellers and Buyer are unable to agree by Closing, the Environmental Defects and Remediation Amounts in dispute shall be exclusively and finally resolved by arbitration pursuant to this Section 12.1(e). There shall be a single arbitrator, who shall be an environmental attorney with at least ten 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 Sellers within 15 days after the Closing Date, and absent such agreement, by the Houston, Texas office of the American Arbitration Association (the “Environmental Arbitrator”). The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section 12.1. 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 the Parties, without right of appeal. In making its determination, the Environmental Arbitrator shall be bound by the rules set forth in this Section 12.1 and, subject to the foregoing, may consider such other matters as in the opinion of the Environmental Arbitrator are necessary or helpful to make a proper determination. The Environmental Arbitrator, however, may not award Buyer its share of 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 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. Each of Sellers and Buyer shall bear one-half of the costs and expenses of the Environmental Arbitrator. To the extent that the award of the Environmental Arbitrator with respect to any Remediation Amount is not taken into account as an adjustment to the Purchase Price pursuant to Section 3.5 or Section 3.6, then, within ten days after the Environmental Arbitrator delivers written notice to Buyer and Sellers of his award with respect to any Remediation Amount, and subject to Section 12.1(d), (i) Buyer shall pay to Sellers the amount, if any, so awarded by the Environmental Arbitrator to Sellers, and (ii) Sellers shall pay to Buyer the amount, if any, so awarded by the Environmental Arbitrator to Buyer. Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section 12.1(e). To the extent any adjustments are not agreed upon by the Parties as of Closing, the Purchase Price shall be adjusted therefor at Closing and the disputed Remediation Amounts asserted by Buyer in good faith to be deposited in an escrow account pursuant to a mutually agreeable escrow agreement.

12.2NORM, Asbestos, Wastes and Other Substances. Buyer acknowledges that the Assets have been used for exploration, development and production of oil and gas and that 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, 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, asbestos and other wastes or Hazardous Substances. NORM containing material and 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. The presence of NORM, asbestos-containing materials that are non-friable, Hydrocarbons or Hazardous Substances cannot be claimed as an Environmental Defect, except to the extent constituting a violation of Environmental Laws.

29

Exhibit 10.1

ARTICLE XIII

ASSUMPTION; INDEMNIFICATION; SURVIVAL

13.1Assumed Obligations; Specified Obligations.

(a)    Without limiting Buyer’s rights to indemnity under this Article XIII, from and after Closing, and except for the Specified Obligations for which a valid Claim Notice is given by Buyer as set forth in Section 13.1(b) within the applicable Survival Period, 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, arising from, based upon, related to or associated with the Assets, regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, including (i) ownership and operation of the Assets; (ii) furnishing of makeup gas and settlement of Imbalances including those set forth on Schedule 4.12 according to the terms of applicable gas sales, processing, gathering or transportation Contracts; (iii) payment of Working Interests, royalties, overriding royalties and other interest owners’ revenues or proceeds attributable to sales of Hydrocarbons including those amounts held in suspense for which the Purchase Price was adjusted pursuant to Section 3.3(b)(viii)); (iv) Decommissioning the Assets; (v) subject to Sellers’ obligations under Article XII, clean up and Remediation of the Assets in accordance with applicable Contracts and Laws; (vi) performance of all obligations applicable to or imposed on the lessee, owner or operator under the Leases and the Applicable Contracts, or as required by Law; (vii) subject to Article XII, Environmental Defects; and (viii) Buyer’s Environmental Liabilities (all of said Liabilities herein being referred to as the “Assumed Obligations”); provided that Buyer does not assume any Liabilities to the extent that they are Specified Obligations or attributable to or arise out of the ownership, use or operation of the Excluded Assets.

(b)    Upon Closing, and except for the Assumed Obligations, with respect to specific Claims for the following for which a valid Claim Notice is given within the applicable survival period as set forth in Section 13.8, Sellers retain and hereby agree to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid and discharged) all obligations and Liabilities, arising from, based upon, related to or associated with (i) any Seller’s failure to properly, timely and legally pay, in accordance with the terms of any Lease and applicable Laws, all Burdens with respect to the Assets due by such Seller and attributable to periods prior to the Effective Time; (ii) personal injury or wrongful death relating to events occurring prior to the Closing Date; (iii) (A) Income Taxes imposed by Law on any Seller, any of its direct or indirect owners, or any combined, unitary or consolidated group of which such Seller is or was a member, (B) Asset Taxes allocable to Sellers pursuant to Section 15.2 (except to the extent any such Asset Tax is economically borne by any Seller pursuant to the application of Section 3.3(b)(v) and Section 15.2(d)), and (C) any Taxes imposed on or with respect to any Excluded Asset; and (iv) offsite waste transportation or disposal occurring prior to the Closing Date (all of said Liabilities herein being referred to as the “Specified Obligations”).

13.2Indemnities of Sellers. Effective as of Closing, subject to the limitations set forth in Section 13.4 and Section 13.8 or otherwise in this Agreement, each Seller, jointly and severally with each other Seller, shall be responsible for, shall pay on a current basis and hereby defend, indemnify, hold harmless and forever release Buyer and its Affiliates, and all of its and their respective equityholders, partners, members, directors, officers, managers, employees, agents and representatives (collectively, “Buyer Indemnified Parties”) from and against any and all Liabilities, whether or not relating to Third Party Claims or incurred in the investigation or defense of any of the same or in asserting, preserving or enforcing any of their respective rights hereunder, arising from, based upon, related to or associated with:

30

Exhibit 10.1

(a)    any breach by such Seller of any of its representations or warranties contained in Article IV;

(b)    any breach by such Seller of any of its covenants or agreements under this Agreement; and

(c)    the Specified Obligations.

13.3Indemnities of Buyer. Effective as of Closing, Buyer shall assume and be responsible for, shall pay on a current basis, and hereby defends, indemnifies, holds harmless and forever releases Sellers and their Affiliates, and all of their respective equityholders, partners, members, directors, officers, managers, employees, agents and representatives (collectively, “Seller Indemnified Parties”) from and against any and all Liabilities, whether or not relating to Third Party Claims or incurred in the investigation or defense of any of the same or in asserting, preserving or enforcing any of their respective rights hereunder, arising from, based upon, related to or associated with:

(a)    any breach by Buyer of any of its representations or warranties contained in Article V;

(b)    any breach by Buyer of any of its covenants or agreements under this Agreement; and

(c)    the Assumed Obligations.

13.4Limitation on Liability.

(a)    Sellers shall not have any liability for any indemnification under Section 13.2 for any Liability (without duplication) arising from a single event unless the amount with respect to such Liability exceeds $100,000 (the “Individual Indemnity Threshold”) and until and unless the aggregate amount of all Liabilities exceeding the Individual Indemnity Threshold and for which Claim Notices are delivered by Buyer during the Survival Period exceeds the Indemnity Deductible, and then only to the extent such Liabilities exceed the Indemnity Deductible.

(b)    Notwithstanding anything to the contrary contained in this Agreement, Sellers shall not be required to indemnify Buyer for aggregate Liabilities in excess of 20% of the Purchase Price (the “Indemnity Cap”).

(c)    Notwithstanding the foregoing in this Section 13.4, the adjustments to the Purchase Price under Section 3.3, Section 3.5, Section 3.6 or Section 3.7 and any payments in respect thereof, and Liabilities for Specified Obligations under Section 13.1(b)(i), Section 13.1(b)(ii) and Section 13.1(b)(iii), shall not be limited by Sections 13.4(a) and 13.4(b) and the total amount of such adjustments and Liabilities from the first dollar and without regard to the Individual Indemnity Threshold, the Indemnity Deductible and the Indemnity Cap shall be applied or recovered in accordance with the terms hereof.

(d)    Notwithstanding anything to the contrary stated in this Agreement, Buyer’s obligation to indemnify Seller Indemnified Parties with respect to the Specified Obligations attributable to a period (or partial period) prior to Sellers’’ ownership of the applicable Assets, shall not extend to any amount for which Sellers receive indemnification from a prior owner of such Assets. Sellers shall use their commercially reasonable efforts to secure indemnification from any applicable prior owner of such Assets; provided that Sellers shall not be required to initiate any legal action to enforce the indemnification from a prior owner unless Buyer agrees to indemnify Sellers for (i) costs of any legal action to enforce the indemnification from a prior owner and (ii) Liabilities resulting from or relating to any counterclaim arising thereunder.

31

Exhibit 10.1

13.5Express Negligence. EXCEPT AS OTHERWISE PROVIDED IN SECTION 10.1(C), THE DEFENSE, INDEMNIFICATION, HOLD HARMLESS, RELEASE AND ASSUMED OBLIGATIONS PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LIABILITIES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE GROSS, SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY. BUYER AND SELLERS ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS “CONSPICUOUS.”

13.6Exclusive Remedy. Except for causes of action based on actual fraud, notwithstanding anything to the contrary contained in this Agreement, the Parties agree that, from and after Closing, Section 10.1(c), Section 11.1(c), Section 13.2 and Section 13.3, contain the Parties’ exclusive remedies against each other with respect to the transactions contemplated hereby, including breaches of the representations, warranties, covenants and agreements of the Parties contained in this Agreement or in any document or certificate delivered pursuant to this Agreement. Except as specified in Section 11.1(c) and Section 13.2, effective as of Closing, Buyer, on its own behalf and on behalf of the Buyer Indemnified Parties, hereby releases, remises and forever discharges Sellers and their Affiliates and all of such Persons’ equityholders, partners, members, directors, officers, employees, agents and representatives from any and all suits, legal or administrative proceedings, Liabilities or interest whatsoever, in Law or in equity, known or unknown, which Buyer or the Buyer Indemnified Parties might now or subsequently have, based on, relating to or arising out of this Agreement, the transactions contemplated by this Agreement, the ownership, use or operation of any of the Assets prior to Closing or the condition, quality, status or nature of any of the Assets prior to Closing, including rights to contribution under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, breaches of statutory or implied warranties, nuisance or other tort actions, rights to punitive damages, common law rights of contribution and rights under insurance maintained by Sellers or any of their Affiliates (except as provided in Section 11.3(b)).

13.7Indemnification Procedures. All claims for indemnification under Section 10.1(c), Section 13.2 and Section 13.3 shall be asserted and resolved as follows:

(a)    For purposes of Section 10.1(c) and this Article XIII, 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 Section 10.1(c) or this Article XIII, 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 Section 10.1(c) or this Article XIII.

(b)    To make claim for indemnification under Section 10.1(c), Section 13.2 and Section 13.3, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 13.7, 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 “Third Party Claim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section 13.7(b) shall not relieve the Indemnifying Party of its obligations under Section 10.1(c), Section 13.2 or Section 13.3 (as applicable) except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Third Party Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. In the event that the claim for indemnification is based upon an inaccuracy or breach of a

32

Exhibit 10.1

representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement that was inaccurate or breached.

(c)    In the case of a claim for indemnification based upon a Third Party 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 Third Party 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 Indemnified Party against a Third Party Claim, it shall have the right and obligation to diligently defend, at its sole cost and expense, the Indemnified Party against such Third Party Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in contesting any Third Party Claim which the Indemnifying Party elects to contest. The Indemnified Party may participate in, but not control, at its own expense, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 13.7(d). An Indemnifying Party shall not, without the written consent of the Indemnified Party, (i) settle any Third Party Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all liability in respect of such Third Party Claim or (ii) settle any Third Party Claim or consent to the entry of any judgment with respect thereto 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 or admits its liability to defend the Indemnified Party against a Third Party Claim, but fails to diligently prosecute, indemnify against or settle the Third Party Claim, then the Indemnified Party shall have the right to defend against the Third Party 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 and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its liability to defend the Indemnified Party against a Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option for ten days following receipt of such notice to (i) admit in writing its liability to indemnify the Indemnified Party from and against the liability and consent to such settlement and (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement, or (iii) deny liability. Any failure by the Indemnifying Party to respond to such notice shall be deemed to be an election under subsection (i) above.

(f)    In the case of a claim for indemnification not based upon a Third Party 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, the amount of such Liabilities shall conclusively be deemed a liability of the Indemnifying Party hereunder. If the Indemnifying Party disputes the claim for such Liabilities, the running of any survival period for the claim shall be tolled.

13.8Survival.

(a)    Except for the Specified Representations and the representations and warranties of Sellers in Section 4.15, the last sentence of Section 4.16 and Section 4.19, the representations and warranties

33

Exhibit 10.1

of the Parties in Article IV and Article V and the covenants and agreements of the Parties in Sections 6.1 shall survive Closing for the Survival Period. The representation and warranty of Sellers in Section 4.15 shall terminate on the Closing Date. The representations and warranties of Sellers in the last sentence of Section 4.16 and Section 4.19 shall terminate upon the expiration of the applicable statute of limitations. The Specified Representations shall survive Closing without time limit. The representation and warranty of Sellers in Section 11.1(b) shall terminate as of the expiration of the Survival Period, and the covenants and agreements of the Parties in this Agreement shall survive Closing for a period that is the longer of the Survival Period and the time periods specifically applicable to such covenants and agreements in accordance with their terms. Subject to the foregoing and Section 13.8(b), the remainder of this Agreement shall survive 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.

(b)    The indemnities in Section 13.2(a), Section 13.2(b), Section 13.3(a) and Section 13.3(b) shall terminate as of the expiration 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 expiration date. Sellers’ indemnity in Section 13.2(c) (except as such indemnities relate to Specified Obligations described in Section 13.1(b)(iii)(A) or Section 13.1(b)(iii)(C), which shall survive Closing without time limit) shall survive Closing for the Survival Period. Buyer’s indemnities in Section 10.1(c) and Section 13.3(c) shall survive Closing without time limit.

13.9Waiver of Right to Rescission. Sellers and Buyer acknowledge that, following 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 Closing, Buyer and Sellers waive any right to rescind this Agreement or any of the transactions contemplated hereby.

13.10Insurance, Taxes. The amount of any Liabilities for which any of the Buyer Indemnified Parties or the Seller Indemnified Parties, as applicable, 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 from insurance policies carried by a Party realized or that could reasonably be expected to be realized by such Party if a claim were properly pursued under the relevant insurance arrangements (net of any collection costs, and excluding the proceeds of any insurance underwritten by the party claiming indemnity or its Affiliates).

13.11Non-Compensatory Damages. None of the Buyer Indemnified Parties nor Seller Indemnified Parties shall be entitled to recover from Sellers or Buyer, as applicable, or their respective Affiliates, any loss of profits, special, indirect, consequential, punitive, exemplary, remote or speculative damages arising under or in connection with this Agreement or the transactions contemplated hereby, except to the extent any such Party suffers such damages to a Third Party, which damages (including costs of defense and reasonable attorneys’ 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 Seller Indemnified Parties, each waive any right to recover any loss of profits, special, indirect, consequential, punitive, exemplary, remote or speculative damages arising in connection with or with respect to this Agreement or the transactions contemplated hereby.

34

Exhibit 10.1

13.12    Disclaimer of Application of Anti-Indemnity Statutes. The Parties acknowledge and agree that the provisions of any anti-indemnity statute relating to oilfield services and associated activities shall not be applicable to this Agreement or the transactions contemplated hereby.

13.13    Specified Obligation Disputes.

(a)Any claim, counterclaim, demand, cause of action, dispute, or any other controversy arising out of or relating in any way to Sellers’ indemnity obligations under Section 13.2(c) or the release of the Holdback Amount related thereto (“Dispute”) shall be finally resolved through binding arbitration as described in this Section 13.13. The agreement to arbitrate any Dispute shall be binding on and shall inure to the benefit of the Parties and their Affiliates.

(b)Buyer or Sellers, as applicable, may initiate arbitration proceedings against Sellers or Buyer pursuant to this Section 13.13 by sending a request for arbitration to the other Party or Parties.

(c)The place of the arbitration shall be Houston, Texas.

(d)Buyer shall nominate one arbitrator and Sellers shall nominate another arbitrator. If either side fails to nominate an arbitrator within thirty (30) days of receipt of the request for arbitration, then that arbitrator shall be nominated by the Houston office of the American Arbitration Association (“AAA”) in accordance with its Commercial Arbitration Rules. The first two arbitrators nominated in accordance with this Section 13.13 shall nominate a third arbitrator within thirty (30) days after the appointment of the later-nominated of those two (2) arbitrators. If the first two arbitrators fail to nominate a third arbitrator within the time period prescribed above or if the nominated third arbitrator fails within ten (10) days after the time period prescribed above to accept his or her nomination, then the AAA shall appoint the third arbitrator and shall promptly notify the parties of the appointment. The third arbitrator shall act as chairman of the tribunal.

(e)All arbitrators shall be and remain at all times independent and impartial, and, once appointed, no arbitrator shall have any ex parte communications with any of the Parties or any of their Affiliates concerning the arbitration or the underlying Dispute other than communications directly concerning the selection of the presiding arbitrator, when applicable. No arbitrator (or such arbitrator’s current employer or firm) shall have been an employee, counsel or consultant to any Party or any of its Affiliates within the one-year period preceding the arbitration, or have any financial interest in the Dispute. All arbitrators shall be attorneys having at least ten (10) years of experience in the oil and/or gas business in Texas. The arbitrators may prescribe the rules of the arbitration not inconsistent with this Section 13.13.

(f)Notwithstanding anything to the contrary herein, if a Dispute arises regarding the rights or remedies available to a Party or an Affiliate of a Party pursuant to a final award of an arbitral tribunal that is issued pursuant to this Section 13.13, such Dispute shall be heard and resolved by the same arbitral tribunal that issued the award, unless one or more of the arbitrators serving on the arbitral tribunal that issued the award is unable or unwilling to serve as arbitrator. In such event, a new tribunal will be constituted in accordance with this Section 13.13 and the applicable rules, and no member of the original tribunal shall be eligible to serve.

(g)A Party may amend the claims that are the subject of an arbitration under this agreement to arbitrate, the defenses to such claims, and any counterclaims or cross-claims asserted in response to such claims, by leave of the arbitrators, which shall be freely given when justice so requires in accordance with the applicable rules.

35

Exhibit 10.1

(h)All decisions of the arbitral tribunal shall be made by majority vote. The award of the arbitral tribunal shall be final and binding, subject only to grounds and procedures for vacating or modifying the award under Law.

(i)The arbitration hearing on the merits shall begin no later than sixty (60) days after the appointment of the arbitrators is completed, and the award shall be rendered no later than thirty (30) days after the hearing on the merits is concluded; provided, however, that the arbitrators shall have the discretion, on their own initiative or on application of a Party or Parties, to extend those time periods for good cause, as necessary and appropriate to permit a fair presentation of the claims and defenses and to provide sufficient time to the arbitrators to issue an award that addresses the merits of those claims and defenses.

(j)The arbitral tribunal may award costs, reasonable attorneys’ fees, and expert witness fees to the prevailing party or parties as it deems appropriate in its discretion.

(k)The arbitrators may not award special, exemplary, punitive, consequential or indirect damages (including loss of, damage to or delay in profit, revenue or production) to the extent those damages are waived in this Agreement.

(l)All negotiations, mediation, and arbitration relating to a Dispute (including a settlement resulting from negotiation or mediation, an arbitral award, documents exchanged or produced during a mediation or arbitration proceeding, and memorials, briefs or other documents prepared for the arbitration) are confidential and may not be disclosed by the Parties, their respective Affiliates or their respective employees, officers, directors, counsel, consultants, and expert witnesses, except to the extent necessary to enforce any settlement agreement or arbitration award, to cause distributions under the Escrow Agreement, to enforce other rights of a Party, as required by Law or regulation, or for a bona fide business purpose, such as disclosure to accountants, shareholders, or third-party purchasers; provided, however, that breach of this confidentiality provision shall not void any settlement or award.

(m)Any papers, notices, or process necessary or proper for an arbitration hereunder, or any court action in connection with an arbitration or an award, may be served on a Party in the manner set forth elsewhere in this Agreement for the giving of notices.

(n)Any arbitration award may be recognized and enforced, and judgment on the award may be entered, by any court of competent jurisdiction. The Parties and their Affiliates agree to jointly request that any application for recognition or enforcement of an award be decided by the court on an expedited basis. All Parties and their Affiliates waive their right to appeal any court order confirming, recognizing, or enforcing an award to the maximum extent permitted by law. The Parties and their Affiliates do not waive any rights they may have to appeal a court order refusing to confirm, recognize, or enforce an award.

ARTICLE XIV

TERMINATION, DEFAULT AND REMEDIES

14.1Right of Termination. This Agreement and the transactions contemplated herein may be terminated at any time prior to Closing:

(a)    by Sellers, at Sellers’ option, if any of the conditions set forth in Article VIII have not been satisfied on or before the Closing Date and, following written notice thereof from Sellers to Buyer specifying the reason such condition is unsatisfied (including any breach by Buyer of this Agreement), such condition remains unsatisfied for a period of ten Business Days after Buyer’s receipt of written notice thereof from Seller;

36

Exhibit 10.1

(b)    by Buyer, at Buyer’s option, if any of the conditions set forth in Article VII have not been satisfied on or before the Closing Date and, following written notice thereof from Buyer to Sellers specifying the reason such condition is unsatisfied (including any breach by Sellers of this Agreement), such condition remains unsatisfied for a period of ten Business Days after Sellers’ receipt of written notice thereof from Buyer;

(c)    by Buyer if the condition set forth in Section 7.4 has not been satisfied on or before the Closing Date or by Sellers if the condition set forth in Section 8.4 is not satisfied on or before the Closing Date; or

(d)    by Sellers or Buyer if Closing shall not have occurred on or before March 31, 2014;

provided, however, that no Party shall have the right to terminate this Agreement pursuant to clause (a), (b) or (d) above if such Party or its Affiliates are at such time in material breach of any provision of this Agreement.

14.2Effect of Termination. If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 14.1, then, except as provided in Section 3.2 and except for the provisions of Section 10.1(c) through Section 10.1(f), Section 10.2, Section 10.3, Section 13.11, this Section 14.2, Section 14.3, Article I and Article XV (other than Section 15.2(b), Section 15.7 and Section 15.8) and such of the defined terms set forth in Annex I to give context to such Sections, this Agreement shall forthwith become void, and the Parties shall have no liability or obligation hereunder except and to the extent such termination results from the material breach by a Party of any of its covenants or agreements hereunder, in which case the other Party shall have the right to seek all remedies available at law, and with respect to instructions to the Escrow Agent by Sellers and Buyer required under this Agreement or Buyer’s obligations under Section 6.3, specific performance or other equitable remedies for such material breach. The provision for retention of the Deposit in this Section 14.2 has been included because, in the event of a termination of this Agreement permitting Sellers to retain the Deposit, the actual damages which would be suffered by Sellers would be difficult if not impossible to measure accurately as of the date of this Agreement.

14.3Return of Documentation and Confidentiality. Upon termination of this Agreement, Buyer shall return to Sellers all title, engineering, geological and geophysical data, environmental assessments and reports, maps and other information furnished by Sellers to Buyer or prepared by or on behalf of Buyer in connection with its due diligence investigation of the Assets, in each case in accordance with the Confidentiality Agreement, and an officer of Buyer shall certify same to Sellers in writing.

ARTICLE XV

MISCELLANEOUS

15.1Appendices, Exhibits and Schedules. All of the Annexes, Exhibits and Schedules referred to in this Agreement are hereby incorporated into this Agreement by reference and constitute a part of this Agreement. Each Party to this Agreement and its counsel has received a complete set of Annexes, Exhibits and Schedules prior to and as of the execution of this Agreement.

15.2Expenses and Taxes.

(a)    Except as otherwise specifically provided, all fees, costs and expenses incurred by Buyer or Sellers in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including, legal and accounting fees, costs and expenses.

(b)    Seller shall be allocated and bear all Asset Taxes attributable to (A) any Tax period ending prior to the Effective Time and (B) the portion of any Straddle Period ending immediately prior to

37

Exhibit 10.1

the date on which the Effective Time occurs. Buyer shall be allocated and bear all Asset Taxes attributable to (A) any Tax period or portion thereof beginning on or after the Effective Time and (B) the portion of any Straddle Period beginning on the date on which the Effective Time occurs.

(c)    For purposes of determining the allocations described in Section 15.2(b), (i) 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, (ii) 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 (i)), shall be allocated to the period in which the transaction giving rise to such Asset Taxes occurred, and (iii) 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 immediately prior to the date on which the Effective Time occurs and the portion of such Straddle Period beginning on the date on which the Effective Time occurs by prorating each such Asset Tax based on the number of days in the applicable Straddle Period that occur before the date on which the Effective Time occurs, on the one hand, and the number of days in such Straddle Period that occur on or after the date on which the Effective Time occurs, on the other hand. For purposes of clause (iii) of the preceding sentence, the period for such Asset Taxes shall begin on the date on which ownership of the applicable Assets gives rise to liability for the particular Asset Tax and shall end on the day before the next such date.

(d)    To the extent the actual amount of an Asset Tax is not determinable at the Closing or at the time of the determination of the Final Settlement Statement pursuant to Section 3.6, as applicable, (i) the Parties shall utilize the most recent information available in estimating the amount of such Asset Tax for purposes of such adjustment, and (ii) upon the later determination of the actual amount of such Asset Tax, timely payments will be made from one Party to the other to the extent necessary to cause each Party to bear the amount of such Asset Tax that is allocable to such Party under this Section 15.2.

(e)    Buyer shall be responsible for payment to the applicable Taxing Authorities of all Asset Taxes that become due and payable on or after the Closing Date, and Buyer shall indemnify and hold Seller harmless for any failure to make such payments.

(f)    All required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to the Assets to Buyer shall be borne by Buyer. Any and all sales, use, transfer, stamp, documentary, registration or similar Taxes incurred or imposed with respect to the transactions described in this Agreement (collectively, “Transfer Taxes”) shall be borne by Buyer.

(g)The Parties shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of tax returns and any audit, litigation, or other proceeding with respect to Taxes relating to the Assets. Such cooperation shall include the retention and (upon another Party’s request) the provision of records and information that are relevant to any such tax return or audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided under this Agreement. The Parties agree to retain all books and records with respect to Tax matters pertinent to the Assets relating to any taxable period beginning before the Closing Date until the expiration of the statute of limitations of the respective Taxable periods and to abide by all record retention agreements entered into with any Governmental Authority.

15.3Assignment. Subject to Section 15.18, this Agreement may not be assigned by any Seller or Buyer without prior written consent of the other Party; provided, however, that after the Survival Period, any Seller may assign its rights under this Agreement to an Affiliate of EnerVest, Ltd. and Buyer may assign its

38

Exhibit 10.1

rights under this Agreement to an Affiliate of Buyer, in each case, without prior written consent of the other Party. In the event the non-assigning Party consents to any such assignment or the assignment does not require consent pursuant to this Section 15.3, such assignment shall not relieve the assigning Party of any obligations and responsibilities hereunder, including obligations and responsibilities arising following such assignment. Any assignment or other transfer by Buyer or its successors and assigns of any of the Assets shall not relieve Buyer or its successors or assigns of any of their obligations (including indemnity obligations) hereunder, as to the Assets so assigned or transferred.

15.4Preparation of Agreement. Sellers and Buyer and their respective counsel participated in the preparation of this Agreement. In the event of any ambiguity in this Agreement, no presumption shall arise based on the identity of the draftsman of this Agreement.

15.5Publicity. Sellers and Buyer shall promptly consult with each other with regard to all press releases or other public or private announcements issued or made at or prior to Closing concerning this Agreement or the transactions contemplated herein, and, except as may be required by Laws or the applicable rules and regulations of any stock exchange, neither Buyer nor Sellers shall issue any such press release or other public or private announcement without the prior written consent of the other Party, which shall not be unreasonably withheld or delayed.

15.6Notices. All notices and communications required or permitted to be given hereunder shall be in writing and shall be delivered personally, or sent by overnight courier or mailed by United States Mail with all postage fully prepaid, or sent by electronic mail (“email”) transmission (provided that a receipt of such email is requested and received), addressed to the appropriate Party at the address for such Party shown below or at such other address as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:

If to Sellers:

EnerVest, Ltd.

1001 Fannin, Suite 800

Houston, TX 77002

Attention: Mr. Phil DeLozier

Fax: (713) 659-3556

Email:pdelozier@enervest.net

With a copy to (which shall not constitute notice):

EnerVest, Ltd.

1001 Fannin, Suite 800

Houston, TX 77002

Attention: Ms. Fabené Welch

Fax: (713) 659-3556

39

Exhibit 10.1

Email: fwelch@enervest.net

If to Buyer:

QEP Energy Company

1050 17th Street, Suite 500

Denver, CO 80265

Attention: Mr. Austin Murr

Fax: (303) 573-0307

Email: austin.murr@qepres.com

With a copy to (which shall not constitute notice):

QEP Energy Company

1050 17th Street, Suite 500

Denver, CO 80265

Attention: Mr. Christopher Woosley

Fax: (303) 294-9632

Email: chris.woosley@qepres.com

Any notice given in accordance herewith shall be deemed to have been given only when delivered to the addressee in person, or by courier, or transmitted by email transmission during normal business hours on a Business Day (or if delivered or transmitted after normal business hours on a Business Day or on a day other than a Business Day, then on the next Business Day), or upon actual receipt by the addressee during normal business hours on a Business Day after such notice has either been delivered to an overnight courier or deposited in the United States Mail, as the case may be (or if delivered after normal business hours on a Business Day or on a day other than a Business Day, then on the next Business Day). The Parties may change the address and the email address to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 15.6.

15.7Further Cooperation. After Closing, Buyer and Sellers shall execute and deliver, or shall cause to be executed and delivered, from time to time such further instruments of conveyance and transfer, and shall take such other actions as any Party 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. During the term of the Transition Services Agreement, Sellers will use commercially reasonable efforts to assist Buyer with negotiation and finalization of a written gas gathering agreement between Buyer and Access Midstream Partners LLC.

15.8Filings, Notices and Certain Governmental Approvals. Promptly after Closing, Buyer shall (a) record all assignments executed at Closing in the records of the applicable Governmental Authority, (b) if applicable, send notices to vendors supplying goods and services for the Assets and to the operator of such Assets of the assignment of such Assets to Buyer, (c) actively pursue the unconditional approval of all applicable Governmental Authorities of the assignment of the Assets to Buyer and (d) actively pursue all other consents and approvals that may be required in connection with the assignment of the Assets to Buyer and the assumption of the Liabilities assumed by Buyer hereunder, in each case, that shall not have been obtained prior to Closing. Buyer obligates itself to take any and all commercially reasonable action required by any Governmental Authority in order to obtain such unconditional approval, 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.

15.9Entire Agreement; Conflicts. THIS AGREEMENT, THE ANNEXES, EXHIBITS AND SCHEDULES HERETO, THE TRANSACTION DOCUMENTS AND THE CONFIDENTIALITY

40

Exhibit 10.1

AGREEMENT COLLECTIVELY CONSTITUTE THE ENTIRE AGREEMENT BETWEEN THE PARTIES PERTAINING TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ALL PRIOR AGREEMENTS, UNDERSTANDINGS, NEGOTIATIONS AND DISCUSSIONS, WHETHER ORAL OR WRITTEN, OF THE PARTIES PERTAINING TO THE SUBJECT MATTER HEREOF. THERE ARE NO WARRANTIES, REPRESENTATIONS OR OTHER AGREEMENTS BETWEEN THE PARTIES RELATING TO THE SUBJECT MATTER HEREOF EXCEPT AS SPECIFICALLY SET FORTH IN THIS AGREEMENT, AND NEITHER SELLERS NOR BUYER SHALL BE BOUND BY OR LIABLE FOR ANY ALLEGED REPRESENTATION, PROMISE, INDUCEMENT OR STATEMENTS OF INTENTION NOT SO SET FORTH. IN THE EVENT OF A CONFLICT BETWEEN THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY SCHEDULE OR EXHIBIT HERETO, THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL; PROVIDED, HOWEVER, THAT THE INCLUSION IN ANY OF THE SCHEDULES AND 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 15.9.

15.10Parties in Interest. The terms and provisions of this Agreement shall be binding upon and inure to the benefit of Sellers and Buyer 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 Parties or their 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 a Party and its successors and 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).

15.11Amendment. This Agreement may be amended only by an instrument in writing executed by the Parties against whom enforcement is sought.

15.12Waiver; 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 and no failure by Sellers or Buyer to exercise any of its rights under this Agreement shall, in each case, operate as a waiver thereof or affect in any way the right of such Party at a later time to enforce the performance of such provision. No waiver by any Party 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.

15.13Governing Law; Jurisdiction.

(a)    This Agreement and any claim, controversy or dispute arising under or related to this Agreement or the transactions contemplated hereby or the rights, duties and relationship of the parties hereto and thereto, shall be governed by and construed and enforced in accordance with the Laws of the State of Texas, excluding any conflicts of law, rule or principle that might refer construction of provisions to the Laws of another jurisdiction.

(b)    Subject to Sections 3.7, 11.2(j), 12.1(e) and 13.13, the Parties agree that the appropriate, exclusive and convenient forum for any disputes between any of the Parties arising out of this Agreement,

41

Exhibit 10.1

the Transaction Documents or the transactions contemplated hereby shall be in any state or federal court in Houston, Texas and each of the Parties irrevocably submits to the jurisdiction of such courts solely in respect of any proceeding arising out of or related to this Agreement. The Parties further agree that the Parties shall not bring suit with respect to any disputes arising out of this Agreement, the Transaction Documents or the transactions contemplated hereby in any court or jurisdiction other than the above specified courts. The Parties further agree, to the extent permitted by Law, that a final and nonappealable judgment against a Party in any action or proceeding contemplated above shall be conclusive and may be enforced in any other jurisdiction within or outside the United States by suit on the judgment, a certified or exemplified copy of which shall be conclusive evidence of the fact and amount of such judgment.

(c)    To the extent that any Party hereto or any of its Affiliates has acquired, or hereafter may acquire, any immunity from jurisdiction of any court or from any legal process (whether through service or notice, attachment prior to judgment, attachment in aid of execution, execution or otherwise) with respect to itself or its property, such Party (on its own behalf and on behalf of its Affiliates) hereby irrevocably (i) waives such immunity in respect of its obligations with respect to this Agreement and (ii) submits to the personal jurisdiction of any court described in Section 15.13(b).

(d)    THE PARTIES AGREE THAT THEY HEREBY KNOWINGLY, VOLUNTARILY AND INTENTIONALLY IRREVOCABLY WAIVE THE RIGHT TO TRIAL BY JURY IN ANY ACTION BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH THIS AGREEMENT, THE TRANSACTION DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY.

15.14Severability. 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 Party. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the Parties 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.

15.15Removal of Name. As promptly as practicable, but in any case within 30 days after the Closing Date, Buyer shall eliminate the names “EnerVest Energy Institutional Fund XII-A, L.P.,” “EnerVest Energy Institutional Fund XII-WIB, L.P.,” “EnerVest Energy Institutional Fund XII-WIC, L.P.,” “EnerVest Holding, L.P.,” “EnerVest” and any variants thereof from the Assets and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Sellers or any of their Affiliates.

15.16Counterparts. 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. Any signature hereto delivered by a Party by facsimile or other electronic transmission shall be deemed an original signature hereto.

15.17Seller Representative. Each Seller hereby constitutes and appoints EnerVest, Ltd. (the “Seller Representative”) as such Seller’s true and lawful agent and attorney-in-fact, to act in the name and on behalf of such Seller as follows:

(i)to execute all documents, make all elections, and take all action on such Seller’s behalf with respect to this Agreement and the transactions contemplated hereby, including the negotiation and drafting of this Agreement and the documents to be delivered at Closing;

42

Exhibit 10.1

(ii)to grant such waivers and consents on behalf of such Seller under this Agreement as the Seller Representative in its sole discretion shall deem advisable;

(iii)to receive and give receipt for all notices and other communications required or permitted to be given to such Seller under this Agreement;

(iv)to receive on behalf of Sellers any payments made by Buyer or the Escrow Agent pursuant to the terms hereof;

(v)to exercise any and all of such Seller’s rights under or in connection with this Agreement; and

(vi)to take any other action authorized or required to be taken by the Seller Representative on behalf of such Seller pursuant to the terms of this Agreement.

Each Seller covenants and agrees that it shall be bound by all actions taken by the Seller Representative on such Seller’s behalf arising in connection with or related to this Agreement and the transactions contemplated hereby. Each Seller acknowledges that the powers and authority granted in this Section 15.17 are coupled with an interest sufficient in Law to support an irrevocable power of attorney and, unless this Agreement is terminated pursuant to Article XIV, shall be irrevocable to the fullest extent permitted by Law. Each Seller and the Seller Representative agree to jointly and severally indemnify Buyer for any claims that arise against Buyer as a result of reliance on this power of attorney as to such Seller. Each Seller agrees that it will not bring any claim against the Seller Representative which relates to or results from its performance of the duties of the Seller Representative as set forth in this Section 15.17.

15.18Like-Kind Exchange. At Buyer’s request, Sellers shall take all actions reasonably requested by Buyer to effectuate all or any part of the transactions contemplated by this Agreement as a reverse like-kind exchange for the benefit of Buyer in accordance with Section 1031 of the Code and Rev. Proc. 2000-37, including executing an instrument acknowledging and consenting to any assignment by Buyer of its rights (but not its obligations) hereunder to a qualified intermediary or an exchange accommodation titleholder. In furtherance of the foregoing and notwithstanding anything contained in this Agreement to the contrary, Buyer may assign its rights under this Agreement to a “qualified intermediary” or an “exchange accommodation titleholder” in order to facilitate, at no cost or expense to Sellers, a reverse like-kind exchange under Section 1031 of the Code; provided, however, that neither Buyer’s assignment nor any other actions taken by Buyer or any other Person in connection with the like-kind exchange shall release Buyer from, or modify, any of Buyer’s liabilities and obligations (including indemnity obligations to Sellers) under this Agreement, and Sellers make no representations as to any particular tax treatment that may be afforded to Buyer by reason of such assignment or any other actions taken in connection with the like-kind exchange. Sellers will issue all closing documents to the applicable qualified intermediary or exchange accommodation titleholder if so directed by Buyer prior to Closing. Notwithstanding the foregoing, Sellers shall not be required, solely for the purpose of Sellers’ cooperation with Buyer’s like-kind exchange, to incur any additional cost, obligation or liability, and Buyer shall indemnify, defend and hold Sellers harmless from and against any and all such costs, obligations or liabilities (including reasonable attorneys’ fees), proceedings and causes of actions of any kind incurred or suffered by Sellers and solely attributable to such like-kind exchange transaction. In no event shall the Closing be delayed because of Buyer’s like-kind exchange transaction. The provisions of this Section 15.18 shall survive the Closing of this Agreement.

Signature Pages Follow

IN WITNESS WHEREOF, Sellers and Buyer have executed this Agreement as of the date first written above.

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Exhibit 10.1

SELLERS:

ENERVEST HOLDING, L.P.

By:EnerVest Operating, L.L.C.,

its General Partner

By: /s/ Stephen A. McDaniel

Name:Stephen A. McDaniel

Title: Executive Vice President and

Chief Operating Officer

ENERVEST ENERGY INSTITUTIONAL

FUND XII-A, L.P.

By:EnerVest, Ltd.,

its General Partner

By:EnerVest Management GP, L.C.,

its General Partner

By: /s/James M. Vanderhider

Name:James M. Vanderhider

Title: Executive Vice President and

Chief Financial Officer

ENERVEST ENERGY INSTITUTIONAL

FUND XII-WIB, L.P.

By:EnerVest, Ltd.,

its General Partner

By:EnerVest Management GP, L.C.,

its General Partner

By: /s/James M. Vanderhider

Name:James M. Vanderhider

Title: Executive Vice President and

Chief Financial Officer

44

Exhibit 10.1

ENERVEST ENERGY INSTITUTIONAL

FUND XII-WIC, L.P.

By:EnerVest Holding, LLC,

its General Partner

By:EnerVest, Ltd.,

its Sole Member

By:EnerVest Management GP, L.C.,

its General Partner

By: /s/James M. Vanderhider

Name:James M. Vanderhider

Title: Executive Vice President and

Chief Financial Officer

Acknowledged and agreed solely with respect to Section 15.17:

ENERVEST, LTD.

By:EnerVest Management GP, L.C.,

its General Partner

By: /s/James M. Vanderhider

Name:James M. Vanderhider

Title: Executive Vice President and

Chief Financial Officer

45

Exhibit 10.1

BUYER:

QEP Energy Company

By:/s/Austin S. Murr

Name: Austin S. Murr

Title:Senior Vice President, Land and

Business Development

46

Exhibit 10.1

ANNEX I

DEFINED TERMS

Capitalized terms used herein shall have the meanings set forth in this AnnexI unless the context requires otherwise.

“AAA” shall have the meaning set forth in Section 13.13.

“Accounting Arbitrator” shall have the meaning set forth in Section 3.7.

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

“AFEs” shall have the meaning set forth in Section 4.13.

“Affiliate” shall mean any Person that, directly or indirectly, through one or more intermediaries, controls or is controlled by, or is under common control with, another Person. The term “control” and its derivatives with respect to any Person mean 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.

“Aggregate Deductible” shall mean one and one-half percent (1.5%) of the Purchase Price.

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

“Allocated Values” shall have the meaning set forth in Section 3.8.

“Applicable Contracts” shall mean the Contracts described on Exhibit C to which any Seller is a party or is bound relating to any of the Assets and (in each case) that will be binding on Buyer after Closing, including: communitization agreements; net profits agreements; production payment agreements; area of mutual interest agreements; joint venture agreements; confidentiality agreements; farmin and farmout agreements; bottom hole agreements; crude oil, condensate and natural gas purchase and sale, gathering, transportation and marketing agreements; hydrocarbon storage agreements; acreage contribution agreements; operating agreements; balancing agreements; pooling declarations or agreements; unitization agreements; processing agreements; saltwater disposal agreements; facilities or equipment leases; and other similar contracts and agreements, but exclusive of any master service agreements and Contracts relating to the Excluded Assets.

“Asset Taxes” shall mean ad valorem, property, severance, production, sales, use and similar Taxes (excluding, for the avoidance of doubt, any Income Taxes and Transfer Taxes) based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom or the receipt of proceeds therefrom.

“Assets” shall have the meaning set forth in Section 2.1.

“Assignment” shall mean the Assignment and Bill of Sale from Sellers to Buyer, pertaining to the Assets, substantially in the form attached to this Agreement as Exhibit G.

“Assumed Obligations” shall have the meaning set forth in Section 13.1.

47

Exhibit 10.1

“Burden” shall mean any and all royalties (including lessor’s royalty), overriding royalties, production payments, net profits interests and other burdens upon, measured by or payable out of production (excluding, for the avoidance of doubt, any Taxes).

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

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

“Buyer’s Auditor” shall have the meaning set forth in Section 6.9.

“Buyer’s Environmental Liabilities” shall have the meaning set forth in Section 12.1.

“Buyer Indemnified Parties” shall have the meaning set forth in Section 13.2.

“Buyer’s Representatives” shall have the meaning set forth in Section 10.1(a).

“Casualty Loss” shall have the meaning set forth in Section 11.3(b).

“Claim Notice” shall have the meaning set forth in Section 13.7(b).

“Closing” shall have the meaning set forth in Section 9.1.

“Closing Date” shall have the meaning set forth in Section 9.1.

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

“Confidentiality Agreement” shall mean that certain Confidentiality Agreement between EnerVest, Ltd. and Buyer dated as of October 10, 2013.

“Consent” shall have the meaning set forth in Section 4.4.

“Contract” shall mean any written or oral contract, agreement or any other legally binding arrangement, but excluding, however, any Lease, easement, right-of-way, permit or other instrument creating or evidencing an interest in the Assets or any real or immovable property related to or used in connection with the operations of any Assets.

“Cure Period” shall have the meaning set forth in Section 11.2(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 the assignment of properties similar to the Assets.

“Decommission” shall mean all dismantling and decommissioning activities and obligations as are required by Law, any Governmental Authority or agreements including all well plugging, replugging and abandonment, facility dismantlement and removal, pipeline and flowline removal, dismantlement and removal of all other property of any kind related to or associated with operations or activities and associated site clearance, site restoration and site remediation.

“Defensible Title” shall mean such title of Sellers with respect to the Leases, Wells and Well Locations that, as of the Effective Date and the Defect Notice Date and subject to Permitted Encumbrances:

48

Exhibit 10.1

(a)with respect to each Lease, Well or Well Location (subject to any Specified Limitations), entitles Sellers to receive not less than the Net Revenue Interest set forth on Exhibit A or Schedule 3.8 for the specified zones or depths for such Lease, Well or Well Location, except for (i) decreases in connection with those operations in which Sellers or their successors or assigns may from and after the date of this Agreement elect with Buyer’s consent to be a non-consenting co-owner, (ii) decreases resulting from the establishment or amendment with Buyer’s consent from and after the date of this Agreement of pools or units, (iii) decreases required to allow other Working Interest owners to make up past underproduction or pipelines to make up past under deliveries and (iv) as otherwise set forth on Exhibit A, Exhibit B or Schedule 3.8, as applicable;

(b)with respect to each Lease, Well or Well Location (subject to any Specified Limitations), obligates Sellers to bear not more than the Working Interest set forth on Exhibit A or Schedule 3.8 for the specified zones or depths for such Lease, Well or Well Location, except (i) increases resulting from contribution requirements with respect to defaulting co-owners under applicable operating agreements, (ii) increases to the extent that such increases are accompanied by a proportionate increase in Sellers’ Net Revenue Interest and (iii) as otherwise set forth on Exhibit A, Exhibit B or Schedule 3.8, as applicable; and

(c)is free and clear of all Encumbrances.

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

“Dispute” shall have the meaning set forth in Section 13.13.

“Dispute Notice” shall have the meaning set forth in Section 3.6(a).

“Disputed Title Matters” shall have the meaning set forth in Section 11.2(j).

“Effective Time” shall mean 7:00 a.m. (Central Time) on November 1, 2013.

“email” shall have the meaning set forth in Section 15.6.

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

“EnerVest Holding” shall have the meaning set forth in the first paragraph herein.

“EnerVest XII-A” shall have the meaning set forth in the first paragraph herein.

“EnerVest XII-WIB” shall have the meaning set forth in the first paragraph herein.

“EnerVest XII-WIC” shall have the meaning set forth in the first paragraph herein.

“Environmental Arbitrator” shall have the meaning set forth in Section 12.1(e).

“Environmental Claim Date” shall have the meaning set forth in Section 12.1(a).

“Environmental Condition” shall mean (a) a condition existing on the date of this Agreement with respect to the air, soil, subsurface, surface waters, ground waters and sediments that causes an Asset (or Sellers with respect to an Asset) not to be in compliance with any Environmental Law or (b) the existence as of the date of this Agreement with respect to the Assets or their operation thereof of any environmental

49

Exhibit 10.1

pollution, contamination or degradation where remedial or corrective action is presently required (or if known, would be presently required) under Environmental Laws.

“Environmental Defect” shall mean an Environmental Condition with respect to an Asset.

“Environmental Defect Notice” shall have the meaning set forth in Section 12.1(a).

“Environmental Laws” shall mean all Laws in effect as of the date of this Agreement, including common law, relating to the protection of the public health, welfare and the environment, including, those Laws relating to the storage, handling and use of chemicals and other Hazardous Substances and those Laws relating to the generation, processing, treatment, storage, transportation, disposal or other management thereof. The term “Environmental Laws” does not include (a) good or desirable operating practices or standards that may be employed or adopted by other oil and gas well operators or recommended by a Governmental Authority or (b) the Occupational Safety and Health Act or any other Law governing worker safety or workplace conditions.

“Escrow Agent” shall mean Wells Fargo Bank, N.A.

“Escrow Agreement” shall mean the Escrow Agreement of even date herewith between Sellers, Buyer and the Escrow Agent and related to the Deposit and the Holdback Amount.

“Escrow Claim” shall have the meaning set forth in Section 3.10(b).

“Escrow Claim Notice” shall have the meaning set forth in Section 3.10(b).

“Excluded Assets” shall mean (a) all of Sellers’ corporate minute books, financial records and other business records that relate to Sellers’ business generally (including the ownership and operation of the Assets); (b) to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder, all trade credits, all accounts, all receivables and all other proceeds, income or revenues attributable to the Assets and attributable to any period of time prior to the Effective Time; (c) to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder, all claims and causes of action of any Seller arising under or with respect to any Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds); (d) subject to Section 11.3 and to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder, all rights and interests of Sellers (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 or damage to or destruction of property; (e) all Hydrocarbons produced and sold from the Assets with respect to all periods prior to the Effective Time; (f) all claims of any Seller or its Affiliates for refunds of, rights to receive funds from any Governmental Authority, or loss carry forwards or credits with respect to (i) Asset Taxes attributable to any period (or portion thereof) prior to the Effective Time, (ii) Income Taxes or (iii) any Taxes attributable to the Excluded Assets; (g) all personal computers and associated peripherals and all radio and telephone equipment; (h) all of Sellers’ proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property; (i) all documents and instruments of Sellers that may be protected by an attorney-client privilege or any attorney work product doctrine excluding, however, title opinions; (j) all data that cannot be disclosed to Buyer as a result of confidentiality arrangements under agreements with Third Parties; (k) all audit rights arising under any of the Applicable Contracts or otherwise with respect to any period prior to the Effective Time or to any of the Excluded Assets, except for any Imbalances assumed by Buyer; (l) all geophysical and other seismic and related technical data and information relating to the Assets which Sellers may not disclose, assign or transfer under its existing agreements and licenses without making any additional

50

Exhibit 10.1

payments, or incurring any liabilities or obligations except to the extent such payments, liabilities and obligations are permitted to be assumed by Buyer under the applicable agreements and the same are assumed by Buyer; (m) documents prepared or received by Sellers or their Affiliates with respect to (i) lists of prospective purchasers for such transactions compiled by Sellers, (ii) bids submitted by other prospective purchasers of the Assets, (iii) analyses by Sellers or their Affiliates of any bids submitted by any prospective purchaser, (iv) correspondence between or among Sellers, its respective representatives, and any prospective purchaser other than Buyer and (v) correspondence between Sellers or any of their representatives with respect to any of the bids, the prospective purchasers or the transactions contemplated by this Agreement; (n) any offices, office leases and any personal property located in or on such offices or office leases; (o) any leases and other assets specifically listed on Exhibit F; (p) any Hedge Contracts; (q) any debt instruments; and (r) any assets described in Section 2.1(d) or Section 2.1(e) that are not assignable.

“Execution Date” shall have the meaning set forth in the introductory paragraph herein.

“Filings” shall have the meaning set forth in Section 6.9.

“Final Price” shall have the meaning set forth in Section 3.6(a).

“Final Settlement Statement” shall have the meaning set forth in Section 3.6(a).

“GAAP” shall mean United States generally accepted accounting principles as in effect on the date hereof.

“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.

“Hazardous Substances” shall mean any pollutants, contaminants, toxins or hazardous or extremely hazardous substances, materials, wastes, constituents, compounds or chemicals that are regulated by, or may form the basis of liability under, any Environmental Laws.

“Hedge Contract” shall mean any Contract to which any Seller is a party with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions.

“Holdback Amount” shall have the meaning set forth in Section 3.10(a).

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

“Imbalances” shall mean all Well Imbalances and Pipeline Imbalances.

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

“Indemnified Party” shall have the meaning set forth in Section 13.7(a).

“Indemnifying Party” shall have the meaning set forth in Section 13.7(a).

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Exhibit 10.1

“Indemnity Cap” shall have the meaning set forth in Section 13.4(b).

“Indemnity Deductible” shall mean one and one-half percent (1.5%) of the Purchase Price.

“Individual Environmental Threshold” shall have the meaning set forth in Section 12.1(d).

“Individual Indemnity Threshold” shall have the meaning set forth in Section 13.4(a).

“Individual Title Defect Threshold” shall have the meaning set forth in Section 11.2(i).

“Interim Period” shall mean that period of time commencing with the Effective Time and ending at 7:00 a.m. (Central Time) on the Closing Date.

“Knowledge” shall mean with respect to Sellers, the actual knowledge (after due inquiry) of the following Persons: Jud Walker, Brandon Harbaugh, Kevin Leonard, Josh Coldwell and Mike Walther.

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

“Leases” shall have the meaning set forth in Section 2.1(a).

“Liabilities” shall mean any and all claims, obligations, causes of action, payments, charges, demands, judgments, assessments, liabilities, losses, damages, penalties, fines and costs and expenses, including any attorneys’ fees, legal or other expenses incurred in connection therewith.

“Material Adverse Effect” shall mean an event or circumstance that, individually or in the aggregate, results in (i) a material adverse effect on the ownership, operation or value of the Assets that is reasonably expected to equal or exceed ninety five million dollars ($95,000,000) or (ii) a material adverse effect on the ability of Sellers to consummate the transactions contemplated by this Agreement and perform its obligations hereunder; provided, however, that a Material Adverse Effect shall not include any material adverse effects resulting from: (a) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (b) any action or omission of Sellers taken in accordance with the terms of this Agreement without the violation thereof or with the prior written consent of Buyer; (c) changes in general market, economic, financial or political conditions (including changes in commodity prices, fuel supply or transportation markets, interest or rates) in the area in which the Assets are located, the United States or worldwide; (d) changes in conditions or developments generally applicable to the oil and gas industry in the area where the Assets are located; (e) acts of God, including hurricanes, storms or other naturally occurring events; (f) acts or failures to act of Governmental Authorities; (g) civil unrest, any outbreak of disease or hostilities, terrorist activities or war or any similar disorder; (h) matters that are cured or no longer exist by the earlier of Closing and the termination of this Agreement; (i) a change in Laws and any interpretations thereof from and after the date of this Agreement; (j) any reclassification or recalculation of reserves in the ordinary course of business; (k) changes in the prices of Hydrocarbons; and (l) natural declines in well performance.

“Material Contracts” shall have the meaning set forth in Section 4.7(a).

“Net Casualty Loss” shall have the meaning set forth in Section 11.3(b).

“Net Revenue Interest” shall mean, with respect to any Lease, Well or Well Location (subject to any reservations, limitations or depth restrictions set forth on Exhibit A or Exhibit B), the interest in and to all Hydrocarbons produced, saved and sold from or allocated to such Lease, Well or Well Location (subject to

52

Exhibit 10.1

any reservations, limitations or depth restrictions set forth on Exhibit A or Exhibit B), after giving effect to all Burdens.

“New Wells” shall have the meaning set forth in Section 2.3.

“NORM” shall mean naturally occurring radioactive material.

“Operating Expenses” shall have the meaning set forth in Section 2.3.

“Overhead Costs” shall mean with respect to those Assets that are operated by a Sellers or a Third Party and (a) are burdened by an existing joint operating agreement covering such Assets, the amount representing the overhead or general and administrative fee that is charged to other working interest owners with interests in such Assets as set forth in the accounting procedures attached to such joint operating agreement, which amount is attributable to the Assets during the Interim Period, and (b) with respect to those Assets that are not burdened by an existing joint operating agreement, an amount equal to a portion of $12,000.00 per Well per month undergoing drilling or completion operations and $1,200.00 per producing Well per month attributable to the Assets during the Interim Period.

“Party” and “Parties” shall have the meaning set forth in the introductory paragraph herein.

“Permitted Encumbrances” shall mean:

(a)all Burdens if the net cumulative effect of such Burdens does not operate to reduce the Net Revenue Interest of Sellers with respect to any Lease, Well or Well Location to an amount less than the Net Revenue Interest set forth on Exhibit A or Exhibit B for such Lease, Well or Well Location, and does not obligate Sellers to bear a Working Interest with respect to any Lease, Well or Well Location in any amount greater than the Working Interest set forth on Exhibit A or Exhibit B for such Lease, Well or Well Location (unless the Net Revenue Interest for such Lease, Well or Well Location is greater than the Net Revenue Interest set forth on Exhibit A or Exhibit B in the same or greater proportion as any increase in such Working Interest);

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

(c)required consents to assignment and similar agreements;

(d)Customary Post-Closing Consents;

(e)conventional rights of reassignment;

(f)such Title Defects as Buyer may have waived or is deemed to have waived pursuant to the terms of this Agreement;

(g)all Laws and all rights reserved to or vested in any Governmental Authority (i) to control or regulate any Asset in any manner; (ii) by the terms of any right, power, franchise, grant, license or permit, or by any provision of Law, to terminate such right, power, franchise, grant, license or permit or to purchase, condemn, expropriate or recapture or to designate a purchaser of any of the Assets; (iii) to use such property in a manner which does not materially impair the use of such property for the purposes for which it is currently owned and operated; or (iv) to enforce any obligations or duties affecting the Assets to any Governmental Authority with respect to any franchise, grant, license or permit;

53

Exhibit 10.1

(h)rights of a common owner of any interest in rights-of-way, permits or easements held by Sellers and such common owner as tenants in common or through common ownership;

(i)easements, conditions, covenants, restrictions, servitudes, permits, rights-of-way, surface leases and other rights in the Assets for the purpose of operations, facilities, roads, alleys, highways, railways, pipelines, transmission lines, transportation lines, distribution lines, power lines, telephone lines, removal of timber, grazing, logging operations, canals, ditches, reservoirs and other like purposes, or for the joint or common use of real estate, rights-of-way, facilities and equipment, which, in each case, do not materially impair with the ownership, operation or use of the affected Asset;

(j)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 which are being contested in good faith by appropriate proceedings by or on behalf of Sellers;

(k)liens created under the Assets or operating agreements or by operation of Law in respect of obligations that are not yet due or that are being contested in good faith by appropriate proceedings by or on behalf of Sellers;

(l)with respect to any interest in the Assets acquired through compulsory pooling, failure of the records of any Governmental Authority to reflect Sellers as the owner of an Asset;

(m)any Encumbrance affecting the Assets that is discharged by Sellers at or prior to Closing;

(n)any matter set forth on Exhibit A or Exhibit B; and

(o)mortgage liens burdening a lessor’s interest in the Assets, provided that with respect to any Lease entered into after the date of such mortgages, such mortgages are subordinated to the interests of Sellers in the affected Lease.

“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 have the meaning set forth in Section 2.1(f).

“Pipeline Imbalance” shall mean any marketing imbalance between the quantity of Hydrocarbons attributable to the Assets required to be delivered by Sellers under any Contract relating to the purchase and sale, gathering, transportation, storage, processing (including any production handling and processing at a separation facility) or marketing of Hydrocarbons and the quantity of Hydrocarbons attributable to the Assets actually delivered by Sellers pursuant to the relevant Contract, together with any appurtenant rights and obligations concerning production balancing at the delivery point into the relevant sale, transportation, storage or processing facility.

“Preferential Purchase Right” shall have the meaning set forth in Section 4.10.

“Preliminary Settlement Statement” shall have the meaning set forth in Section 3.5.

“Purchase Price” shall have the meaning set forth in Section 3.1.

“Records” shall have the meaning set forth in Section 2.1(g).

54

Exhibit 10.1

“Records Period” shall have the meaning set forth in Section 6.9.

“Remediation” shall mean, with respect to an Environmental Condition, the implementation and completion of any remedial, removal, response, construction, closure, disposal or other corrective actions required under Environmental Laws to correct or remove such Environmental Condition.

“Remediation Amount” shall mean, with respect to an Environmental Condition, the present value as of the Closing Date (using an annual discount rate of 10%) of the cost (net to Sellers’ interest prior to the consummation of the transactions contemplated by this Agreement) of the most cost-effective Remediation of such Environmental Condition.

“Securities Act” shall have the meaning set forth in Section 6.9.

“Seller” and “Sellers” shall have the meanings set forth in the introductory paragraph of this Agreement.

“Seller Indemnified Parties” shall have the meaning set forth in Section 13.3.

“Seller Representative” shall have the meaning set forth in Section 15.17.

“Special Warranty Claim Notice” shall have the meaning set forth in Section 11.1(c)(i).

“Specified Limitations” shall mean, subject to any matter set forth on Exhibit A or Exhibit B, as applicable, any reservations, limitations or depth restrictions described on Schedule 3.8.

“Specified Obligations” shall have the meaning set forth Section 13.1(b).

“Specified Representations” shall mean the representations and warranties in Sections 4.1, 4.2, 4.21, 5.1, 5.2, 5.10 and 5.11.

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

“Survival Period” shall have the meaning set forth in Section 11.1(c)(i).

“Taxes” shall mean any taxes, assessments and other governmental charges imposed by any Governmental Authority, including income, profits, gross receipts, employment, stamp, occupation, premium, alternative or add-on minimum, ad valorem, real property, personal property, transfer, real property transfer, value added, sales, use, customs, duties, capital stock, franchise, excise, withholding, social security (or similar), unemployment, disability, payroll, windfall profit, severance, production, estimated or other tax, including any interest, penalty or addition thereto, whether disputed or not.

“Taxing Authority” shall mean, with respect to any Tax, the governmental entity or political subdivision thereof that imposes such Tax, and the agency (if any) charged with the collection of such Tax for such entity or subdivision, including any governmental or quasi-governmental entity or agency 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.

“Third Party Claim” shall have the meaning set forth in Section 13.7(b).

“Title Arbitrator” shall have the meaning set forth in Section 11.2(j).

55

Exhibit 10.1

“Title Benefit” shall mean, with respect to each Lease, Well and Well Location shown on Exhibit A or Exhibit B, any right, circumstance or condition that operates to increase the Net Revenue Interest of Sellers above that shown for such Lease, Well or Well Location on Exhibit A or Exhibit B to the extent the same does not cause a greater than proportionate increase in Sellers’ Working Interest therein above that shown on Exhibit A or ExhibitB, or (b) to decrease the Working Interest of Sellers in any Lease, Well or Well Location below that shown for such Lease, Well or Well Location on Exhibit A or Exhibit B to the extent the same causes a decrease in Sellers’ Working Interest that is proportionately greater than the decrease in Sellers’ Net Revenue Interest therein below that shown on Exhibit A or Exhibit B.

“Title Benefit Amount” shall have the meaning set forth in Section 11.2(e).

“Title Benefit Notice” shall have the meaning set forth in Section 11.2(b).

“Title Benefit Property” shall have the meaning set forth in Section 11.2(b).

“Title Claim Date” shall have the meaning set forth in Section 11.2(a).

“Title Defect” shall mean any Encumbrance, defect or other matter that causes Sellers not to have Defensible Title in and to the Leases, Wells or Well Locations as of the Effective Time, without duplication; provided that the following shall not be considered Title Defects:

(a)defects arising out of lack of corporate or other entity authorization unless Buyer provides affirmative evidence that such corporate or other entity action was not authorized and results in another Person’s superior claim of title to the relevant Asset;

(b)defects based on a gap in Sellers’ chain of title in the applicable federal, state or county records, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain which documents shall be included in a Title Defect Notice;

(c)defects based on the failure to recite marital status in a document or omission of successors or heirship or estate proceedings unless Buyer provides affirmative evidence that such failure or omission results in another Person’s actual and superior claim of title to the relevant Asset;

(d)any Encumbrance or loss of title resulting from Sellers’ conduct of business in compliance with this Agreement;

(e)defects arising from any prior oil and gas lease relating to the lands covered by a Lease not being surrendered of record, unless Buyer provides affirmative evidence that such prior oil and gas lease is still in effect and results in another Person’s actual and superior claim of title to the relevant Lease or Well;

(f)defects that affect only which Person has the right to receive royalty payments (rather than the amount or the proper payment of such royalty payment);

(g)defects based solely on: (i) lack of information in Sellers’ files; (ii) references to an unrecorded document(s) to which neither Sellers nor any Affiliate is a party, if such document is dated earlier than January 1, 1960 and is not in Sellers’ files; or (iii) Tax assessment, Tax payment or similar records (or the absence of such activities or records);

(h)defects arising out of lack of survey, unless a survey is expressly required by Laws; and

56

Exhibit 10.1

(i)defects that have been cured by Laws of limitations or presumptions.

“Title Defect Amount” shall have the meaning set forth in Section 11.2(g).

“Title Defect Notice” shall have the meaning set forth in Section 11.2(a).

“Title Defect Property” shall have the meaning set forth in Section 11.2(a).

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

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

“Transition Services Agreement” shall mean the Transition Services Agreement by and between Sellers and Buyer, pertaining to the Assets, substantially in the form attached to this Agreement as Exhibit H.

“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 have the meaning set forth in Section 2.1(c).

“Wells” shall have the meaning set forth in Section 2.1(b).

“Well Imbalance” shall mean any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well and allocable to the interests of Sellers therein and the shares of production from the relevant Well to which Sellers are entitled, together with any appurtenant rights and obligations concerning future in kind or cash balancing at the wellhead.

“Well Location” shall mean each well location set forth on Exhibit B.

“Working Interest” shall mean, with respect to any Lease, Well or Well Location (subject to any reservations, limitations or depth restrictions described on Exhibit A or Exhibit B), the interest that is burdened with the obligation to bear and pay costs and expenses of maintenance, development, operation and production.

57

Exhibit 10.1

FIRST AMENDMENT TO PURCHASE AND SALE AGREEMENT

This First Amendment to Purchase and Sale Agreement (this "Amendment'), dated as of January 31, 2014, is by and among EnerVest Holding, L.P., a Texas limited partnership, EnerVest Energy Institutional Fund XII -A, L.P., a Delaware limited partnership, EnerVest ­ Energy Institutional Fund XII-WIB, L.P., a Delaware limited partnership, and EnerVest Energy Institutional Fund XII-WIC, L.P., a Delaware limited partnership (collectively "Sellers" and each individually a "Seller"), and QEP Energy Company, a Texas corporation ("Buyer" ). Sellers and Buyer are collectively referred to herein as the "Parties,"and are sometimes referred to individually as a "Party." Capitalized terms used but not defined herein shall have the meanings ascribed to such terms in the Purchase and Sale Agreement (as defined below).

RECITALS

WHEREAS, Sellers and Buyer are parties to that certain Purchase and Sale Agreement dated December 6, 2013 (the "Purchase and Sale Agreement" ); and

WHEREAS, the Parties wish to amend the Purchase and Sale Agreement in accordance with the provisions of this Amendment.

NOW, THEREFORE, for and in consideration of the mutual agreements contained in the Purchase and Sale Agreement and this Amendment and other good and valuable consideration, Sellers and Buyer agree as follows:

AGREEMENT

Section 1. Amendments to the Purchase and Sale Agreement.

(a) Section 9.1 of the Purchase and Sale Agreement is amended by replacing "January 31" with "February 19".

(b) Section 9.3(f) of the Purchase and Sale Agreement is deleted and replaced in its entirety with the words "[Reserved]".

(c) Exhibit D to the Purchase and Sale Agreement is deletedand replaced in its entirety by Exhibit D attached to this Amendment.· .

(d) The Purchase and Sale Agreement is amended by adding a new Section 6.10 as follows:

6.10 Letters-in-lieu.Upon Buyer's reasonable request after the Closing, each Seller as applicable shall deliver, on forms supplied by Buyer and reasonably acceptable to Sellers, transfer orders or letters in lieu thereof 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.

Section 2. Confirmation. Except as specifically provided in this Amendment, all terms and provisions of the Purchase and Sale Agreement shall remain unchanged and in full force and effect, and the Purchase and Sale Agreement, as modified by this Amendment, is hereby ratified, acknowledged and reaffirmed by the Parties. The execution of this Amendment shall not directly or indirectly in any way whatsoever either: (a} impair, prejudice or otherwise adversely affect any Party 's right at any time to exercise any right, privilege or remedy in connection with the Purchase and Sale Agreement; (b) amend or alter any provision of the Purchase and Sale Agreement (other than the amendments provided for in this Amendment); or (c) constitute any course of dealing or other basis for altering any obligation of any Party 's or any right, privilege or remedy of any Party's under the Purchase and Sale Agreement.

Exhibit 10.1

Section 3. Amendment. This Amendment may be amended only by an instrument in writing executed by all Parties.

Section 4. Entire Agreement.This Amendment, the Exhibit hereto , the Purchase and Sale Agreement (together with the annexes, exhibits and schedules thereto), the Transaction Documents and the Confidentiality Agreement collectively constitute the entire agreement between the Parties pertaining to the subject matter hereof and supersede all prior agreements , understandings, negotiations and discussions, whether oral or written , of the Parties pertaining to the subject matter hereof.

Section 5. Counterparts. This Amendment may be executed in any number of counterparts and all such counterparts shall be taken together as one document. Signatures on this Amendment transmitted by fax or other electronic means shall constitute and be deemed original signatures and be binding for all purposes.

Section 6. Miscellaneous. Each reference in the Purchase and Sale Agreement to "this Agreement", "hereunder", "hereof ', "herein" or any other word or words of similar import shall mean and be a reference to the Purchase and Sale Agreement as amended hereby. Capitalized terms used, but not defined herein, shall have the meanings given to those terms in the Purchase and Sale Agreement. Sections 15.3 (Assignment), 15.6 (Notices), 15.10 (Parties in Interest) ,

15.13 (Governing Law; Jurisdiction) and 15.14 (Severability) of the Purchase and Sale Agreement shall apply to this Amendment as if set forth in full in this Amendment, mutatis mutandis.

Signature Pages Follow

Exhibit 10.1

EXECUTED as of the date first written above.

SELLERS:

ENERVEST ENERGY INSTITUTIONAL FUND XII-A, L.P.

ENERVEST ENERGY INSTITUTIONAL FUND XII-WIB, L.P.

By:EnerVest, Ltd.,

its General Partner

By:EnerVest Management GP, L.C.,

its General Partner

By:/s/James M. Vanderhider

Name:    James M. Vanderhider

Title:    Executive Vice President and

Chief Financial Officer

ENERVEST ENERGY INSTITUTIONAL FUND XII-WIC, L.P.

By:EnerVest Holding, LLC,

its General Partner

By:     EnerVest, Ltd.,

its Sole Member

By:EnerVest Management GP, L.C.,

its General Partner

By:/s/James M. Vanderhider

Name:James M. Vanderhider

Title: Executive Vice President and

Chief Financial Officer

Signature Page to First Amendment to PSA

Exhibit 10.1

ENERVEST HOLDING, L.P.

By:EnerVest Operating L.L.C,

its General Partner

By:/s/James M. Vanderhider

Name:James M. Vanderhider

Title: Executive Vice President and

Chief Financial Officer

BUYER:

QEP Energy Company

By:/s/Austin S. Murr

Name: Austin S. Murr

Title: Senior Vice President, Land and

Business Development

Signature Page to First Amendment to PSA

Exhibit 10.1

SECOND AMENDMENT TO PURCHA SE AND SALE AGREEMENT

This Second Amendment to Purchase and Sale Agreement (this "Amendment' ), dated as of February 15, 2014, is by and among EnerVest Holding, L.P., a Texas limited partnership, EnerVest Energy Institutional Fund XTT-A, L.P., a Delaware limited partnership, EnerVest Energy Institutional Fund XI I-WIB, L.P., a Delaware limited partnership , and EnerVest Energy Institutional Fund XII-WIC, L.P., a Delaware limited partnership (collectively "Sellers"and each individually a "Seller") , and QEP Energy Company, a Texas corporation (''Buyer"). Sellers and Buyer are collectively referred to herein as the "Parties," and are sometimes referred to individually as a "Party." Capitalized terms used but not defined herein shall have the meanings ascribed to such terms in the Purchase and Sale Agreement (as defined below).

RECITALS

WHEREAS, Sellers and Buyer are parties to that certain Purchase and Sale Agreement dated December 6, 2013, as amended by that certain First Amendment to Purchase and Sale Agreement dated January 31, 20 14 (the "Purchase and Sale Agreement'"); and

WHEREAS , the Parties wish to amend the Purchase and Sale Agreement in accordance with the provisions of this Amendment.

NOW, THEREFORE , for and in consideration of the mutual agreements contained in the Purchase and Sale Agreement and this Amendment and other good and valuable consideration, Sellers and Buyer agree as follows:

AGREEMENT

Section 1. Amendments to the Purchase and Sale Agreement.

(a) Section 9.1 of the Purchase and Sale Agreement is amended by replacing "February 19" with "February 25".

Section 2. Confirmation. Except as specifically provided in this Amendment , all terms and provisions of the Purchase and Sale Agreement shall remain unchanged and in full force and effect, and the Purchase and Sale Agreement , as modified by this Amendment, is hereby ratified, acknowledged and reaffirmed by the Parties. The execution of this Amendment shall not directly or indirectly in any way whatsoever either: (a) impair, prejudice or otherwise adversely affect any Party's right at any time to exercise any right , privilege or remedy in connection with the Purchase and Sale Agreement; (b) amend or alter any provision of the Purchase and Sale Agreement (other than the amendments provided for in this Amendment); or (c) constitute any course of dealing or other basis for altering any obligation of any Party's or any right, privilege or remedy of any Party's under the Purchase and Sale Agreement.

Section 3. Amendment.This Amendment may be amended only by an instrument in writing executed by all Parties.

Section 4. Entire Agreement. This Amendment , the Exhibit hereto, the Purchase and Sale Agreement (together with the annexes, exhibits and schedules thereto) , the Transaction Documents and the Confidentiality Agreement collectively constitute the entire agreement between the Parties pertaining to the subject matter hereof and supersede all prior agreements, understandings , negotiations and discussions, whether oral or written , of the Parties pertaining to the subject matter hereof.

Section 5. Counterparts.This Amendment may be executed i n any number of counterparts and all such counterparts shall be taken together as one document. Signatures on this Amendment transmitted by fax or other electronic means shall constitute and be deemed original signatures and be binding for all purposes.

Section 6. Miscellaneous. Each reference in the Purchase and Sale Agreement to "this Agreement" ,

Exhibit 10.1

''hereunder", ..hereof ', ''herein" or any other word or words of similar import shall mean and be a reference to the Purchase and Sale Agreement as amended hereby. Capitalized terms used , but not defined herein, shall have the meanings given to those terms in the Purchase and Sale Agreement. Sections 15.3 (Assignment). 15.6 (Notices), 15.l 0 (Parties in Interest),

15.13 (Governing Law; Jurisdiction) and 15.14 (Severability) of the Purchase and Sale Agreement shall apply to this Amendment as if set forth in full in this Amendment , mutatis mutandis.

Signature Pages Follow

Exhibit 10.1

EXECUTED as of the date first written above.

SELLERS:

ENERVEST ENERGY INSTITUTIONAL FUND XII-A, L.P.

ENERVEST ENERGY INSTITUTIONAL FUND XII-WIB, L.P.

By:EnerVest, Ltd.,

its General Partner

By:EnerVest Management GP, L.C.,

its General Partner

By:/s/James M. Vanderhider

Name:    James M. Vanderhider

Title:    Executive Vice President and

Chief Financial Officer

ENERVEST ENERGY INSTITUTIONAL FUND XII-WIC, L.P.

By:EnerVest Holding, LLC,

its General Partner

By:     EnerVest, Ltd.,

its Sole Member

By:EnerVest Management GP, L.C.,

its General Partner

By:/s/James M. Vanderhider

Name:James M. Vanderhider

Title: Executive Vice President and

Chief Financial Officer

Signature Page to Second Amendment to PSA

Exhibit 10.1

ENERVEST HOLDING, L.P.

By:EnerVest Operating L.L.C,

its General Partner

By:/s/James M. Vanderhider

Name:James M. Vanderhider

Title: Executive Vice President and

Chief Financial Officer

BUYER:

QEP Energy Company

By:/s/Austin S. Murr

Name: Austin S. Murr

Title: Senior Vice President, Land and

Business Development

Signature Page to Second Amendment to PSA

EX-10.2

Exhibit 10.2

EXECUTION COPY

SECOND AMENDMENT TO TERM LOAN AGREEMENT AND

COMMITMENT INCREASE AGREEMENT

This SECOND AMENDMENT TO TERM LOAN AGREEMENT AND COMMITMENT INCREASE AGREEMENT (this “Amendment”) is made and entered into as of January 31, 2014, by and among QEP RESOURCES, INC., a Delaware corporation (the “Borrower”), the Lenders named on the signature pages hereto, and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent for the Lenders (in such capacity, the “Administrative Agent”).

W I T N E S S E T H:

WHEREAS, the Borrower, the Lenders and the Administrative Agent are parties to that certain Term Loan Agreement dated as of April 18, 2012, as amended by that certain First Amendment to Term Loan Agreement dated as of August 13, 2013 (the “Existing Loan Agreement” and as amended by this Amendment, the “Loan Agreement”);

WHEREAS, the Borrower has requested that the Existing Loan Agreement be amended to increase the aggregate amount of the Commitments by $300,000,000 to an aggregate total amount of $600,000,000 (the “Commitment Increase”), and to make certain other amendments to the Existing Loan Agreement as set forth herein;

WHEREAS, the Borrower, through its wholly-owned subsidiary, QEP Energy Company, as buyer, and EnerVest Holding, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P., and EnerVest Energy Institutional Fund XII-WIC, L.P. as sellers (collectively, the “Seller”), have entered into that certain Purchase and Sale Agreement dated as of December 6, 2013, as it may be amended (the “Permian Acquisition Agreement”), pursuant to which the Borrower, through QEP Energy Company, has agreed to purchase certain oil and natural gas interests in the Midland sub-basin of the Permian Basin in Martin and Andrews Counties, Texas as more particularly described therein (such acquisition, the “Permian Acquisition”);

WHEREAS, the Borrower intends to structure the Permian Acquisition to qualify for reverse like-kind exchange treatment under Section 1031 of the Internal Revenue Code and the regulations and revenue procedures promulgated thereunder; and

WHEREAS, subject to terms of this Amendment, the Existing Lenders whose signatures appear below, collectively constituting the Required Lenders, each New Lender and the Administrative Agent have agreed to the Commitment Increase and to amend the Existing Loan Agreement as set forth in Section 3 below, such amendments to be effective on the Second Amendment Effective Date as hereinafter defined.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

1.Definitions.

(a)As used herein: “Existing Lender” means each Lender who is a party to the Existing Loan Agreement; “Increasing Lender” means each Existing Lender whose Commitment shown on Schedule 2.01 attached hereto is greater than its Commitment set forth in Schedule 2.01 attached to the Existing Loan Agreement; and “New Lender” means each institution named on Schedule 2.01 attached hereto as a Lender that is not an Existing Lender. “Transactions” means collectively, the Permian Acquisition, the execution of this Amendment, the Borrowing of Loans on the Second Amendment Effective Date and the incurrence of Indebtedness by the Borrower or its Subsidiaries on the Second Amendment Effective Date or in connection with the Permian Acquisition. “Arrangers” means Wells Fargo Securities, LLC and BMO Capital Markets, Inc.

(b)Unless otherwise defined in this Amendment, all other terms used in this Amendment which are defined in the Existing Loan Agreement shall have the meanings assigned to such terms in the Existing Loan Agreement. The interpretive provisions set forth in Section 1.02 of the Existing Loan Agreement shall apply to this Amendment.

1

Exhibit 10.2

2.Commitment Increase; Amended Schedule 2.01.

(a)Commitment Increase.On and as of Second Amendment Effective Date: (a) Schedule 2.01 attached to the Existing Loan Agreement shall be amended to read as set forth on Schedule 2.01 attached hereto, (b) each Increasing Lender agrees that its Commitment shall increase to the amount set forth opposite its name on Schedule 2.01 attached hereto, and (c) each New Lender agrees that it shall be a “Lender” under and as defined in the Loan Agreement and shall have a Commitment in the amount set forth opposite its name on the Schedule 2.01 attached hereto. Subject to the conditions to Borrowings set forth herein and in the Loan Agreement, each Increasing Lender and each New Lender agrees to fund Loans on the Second Amendment Effective Date in an amount equal to its Pro Rata Share (as set forth in Schedule 2.01 attached hereto) of the Borrowings requested by the Borrower on such date, in each case in an amount up to its Commitment as shown on Schedule 2.01.

(b)Break Funding Charges. The Borrower acknowledges that if, as a result of the refinancing of existing Loans on the Second Amendment Effective Date, any Existing Lender incurs any loss, cost or expense as a result of any payment of a Eurodollar Rate Loan prior to the last day of the Interest Period applicable thereto and such Lender makes a request for compensation in accordance with Section 3.05 of the Loan Agreement, the Borrower shall be obligated to compensate such Lender in accordance with such Section.

(c)New Lenders. Each New Lender represents and agrees as follows: (i) it has received a copy of the Existing Loan Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to Section 6.01 thereof, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Amendment, (ii) it has, independently and without reliance upon the Administrative Agent, any other agent, any Lender or any arranger, and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Amendment, and (iii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

3.Amendments to the Existing Loan Agreement. The following amendments to the Existing Loan Agreement shall be effective on the date (the “Second Amendment Effective Date”) that the conditions set forth in Section 4 of this Amendment have been satisfied.

(a)Certain Amended Definitions. The following defined terms appearing in Section 1.01 (Defined Terms) of the Existing Loan Agreement are amended as set forth below:

(i)The definition of “Aggregate Commitments” is amended by replacing the reference to “$300,000,000” with “$600,000,000”.

(ii)The definition of “Availability Period” is amended as follows: in clause (a) the reference to “June 30, 2012” is replaced with “the Second Amendment Closing Date”; the word “and” that appears after clause (c) is moved so that it follows the end of clause (b); and clause (d) is deleted.

(iii)The definition of “Eurodollar Rate” is amended to read in its entirety as follows:

“Eurodollar Rate” means, for any interest rate calculation with respect to a Eurodollar Rate Loan, the rate of interest per annum determined on the basis of the rate for deposits in Dollars for a period equal to the applicable Interest Period which appears on Reuters Screen LIBOR01 Page (or any applicable successor page) at approximately 11:00 a.m. (London time) two (2) Business Days prior to the first day of the applicable Interest Period (rounded upward, if necessary, to the nearest 1/100th of 1%). If, for any reason, such rate does not appear on Reuters Screen LIBOR01 Page (or any applicable successor page), then the “Eurodollar Rate” shall be determined by the Administrative Agent to be the arithmetic average of the rate per annum at which deposits in Dollars in minimum amounts of at least $5,000,000 would be

2

Exhibit 10.2

offered by first class banks in the London interbank market to the Administrative Agent at approximately 11:00 a.m. (London time) two (2) Business Days prior to the first day of the applicable Interest Period for a period equal to such Interest Period.

(b)Certain Additional Definitions. The following defined terms are hereby added to Section 1.01 (Defined Terms) of the Loan Agreement in the appropriate alphabetical order:

“Acquired Permian Assets” has the meaning set forth in the definition of “Permian Acquisition”.

“OFAC” means the U.S. Department of the Treasury’s Office of Foreign Assets Control.

“Permian Acquisition” means the acquisition by the Borrower, through its wholly-owned subsidiary, QEP Energy Company, of certain oil and natural gas interests in the Midland sub-basin of the Permian Basin, in Martin and Andrews Counties, Texas (the “Acquired Permian Assets”) pursuant to the Permian Acquisition Agreement.

“Permian Acquisition Agreement” means the Purchase and Sale Agreement dated as of December 6, 2013, as it may be amended, among QEP Energy Company as purchaser and EnerVest Holding, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P., and EnerVest Energy Institutional Fund XII-WIC, L.P. as seller (collectively, the “Seller”).

“Sanctioned Country” means a country subject to a sanctions program identified on the list maintained by OFAC and available at http://www.treasury.gov/resource-center/sanctions/Programs/ Pages/Programs.aspx, or as otherwise published from time to time.

“Sanctioned Person” means (a) a Person named on the list of “Specially Designated Nationals and Blocked Persons” maintained by OFAC available at http://www.treasury.gov/resource-center/sanctions /SDN-List/Pages/default.aspx, or as otherwise published from time to time, or (b) (i) an agency of the government of a Sanctioned Country, (ii) an organization controlled by a Sanctioned Country, or (iii) a person resident in a Sanctioned Country, to the extent subject to a sanctions program administered by the U.S. Department of the Treasury’s Office of Foreign Assets Control.

“Second Amendment Effective Date” means January 31, 2014.

(c)Amendments toArticle III(Taxes, Yield Protection and Illegality) and Certain Definitions Relating Thereto. Section 3.01 (Taxes) of the Existing Loan Agreement, Section 3.04 (Increased Cost and Reduced Return; Capital Adequacy; Reserves on Eurodollar Rate Loans) of the Existing Loan Agreement and certain definitions used therein, are amended, and new definitions used therein are added, all as set forth on Annex A attached hereto.

(d)Amendment toSection 2.01. Section 2.01 (Loans) of the Existing Loan Agreement is amended as follows: in Section 2.01(b) the words “under Section 2.01(a)” are changed to “under Sections 2.01(a) and 2.01(b)”; Section 2.01(b) becomes Section 2.01(c); and a new Section 2.01(b) is added is added as follows:

“(b)The Borrower shall deliver to the Administrative Agent Loan Notice(s) requesting one or more Borrowings to be made on the Second Amendment Effective Date in an aggregate amount not to exceed the Aggregate Commitments. Subject to satisfaction of the conditions to Borrowings set forth in Section 4.02, Borrowings outstanding on the Second Amendment Effective Date shall be refinanced with the proceeds of such Borrowings and the remainder of the requested Borrowings shall

3

Exhibit 10.2

be funded to the Borrower. Any portion of the Aggregate Commitments not utilized on the Second Amendment Effective Date shall terminate.”

(e)Amendment toSection 2.06(b). Section 2.06(b) (Termination or Reduction of Commitments) of the Existing Loan Agreement is amended to read “Reserved.”.

(f)Addition ofSection 5.19. Section 5.19 (OFAC) shall be added to the Loan Agreement immediately following Section 5.18 and shall read as follows:

“Section 5.19 OFAC. Neither the Borrower nor any Restricted Subsidiary (i) is an “enemy” or an “ally of the enemy” within the meaning of Section 2 of the Trading with the Enemy Act of the United States (50 U.S.C. App. §§ 1 et seq.), (ii) is in violation of (A) the Trading with the Enemy Act, (B) any of the foreign assets control regulations of the United States Treasury Department (31 CFR, Subtitle B, Chapter V) or any enabling legislation or executive order relating thereto or (C) the PATRIOT Act, (iii) is a Sanctioned Person or (iv) has more than 10% of its assets in Sanctioned Countries. No part of the proceeds of any Loan will be used directly or indirectly to fund any operations in, finance any investments or activities in or make any payments to, a Sanctioned Person or a Sanctioned Country.”.

(g)Amendment toSection 7.09. Section 7.09 (Dispositions of Property) of the Existing Loan Agreement is amended by deleting the word “and” at the end of Section 7.09(l) and adding the following new subsection (m) after Section 7.09(l), which shall read in its entirety as follows:

“(m)assignments, made in order to structure and consummate the Permian Acquisition and a qualifying asset sale as a reverse like kind exchange under Section 1031 of the Code, that are to exchange intermediaries, title holders and/or similar entities that are parties to such reverse like kind exchange transaction, including the assignments of the Permian Acquisition Agreement and other purchase agreements and loan receivables created in connection with such like kind exchange.”

(h)Addition of Exhibits. Exhibit E-1, Exhibit E-2, Exhibit E-3 and Exhibit E-4 attached hereto are added as Exhibit E-1, Exhibit E-2, Exhibit E-3 and Exhibit E-4 to the Loan Agreement.

4.Conditions of Effectiveness. This effectiveness of this Amendment is subject to the satisfaction of the following conditions precedent.

(a)The Administrative Agent shall have received each of the following:

(i)counterparts of this Amendment executed by the Borrower, the Administrative Agent, Existing Lenders constituting Required Lenders (including all Increasing Lenders), and each New Lender;

(ii)a Note executed by the Borrower in favor of each New Lender requesting a Note;

(iii)a certificate of a secretary or assistant secretary of the Borrower (A) certifying as to the incumbency and genuineness of the signature of each officer of the Borrower executing this Amendment, (B) certifying that attached thereto is a true, correct and complete copy of the Organization Documents of the Borrower, or certifying that such Organization Documents were delivered on the Closing Date and certifying that since such date there have been no changes thereto, and (C) attaching resolutions adopted by the board of directors (or other governing body) of the Borrower authorizing and approving the transactions contemplated hereunder and the execution, delivery and performance of this Amendment;

(iv)certificates evidencing the existence and good standing of the Borrower, issued by the applicable Governmental Authority of its jurisdiction of organization;

4

Exhibit 10.2

(v)a certificate of a Responsible Officer of the Borrower (A) attaching and certifying as to a true, correct and complete copy of the Permian Acquisition Agreement or certifying as to a copy that has been filed publicly or previously delivered, (B) demonstrating compliance on a pro forma basis with the financial covenants contained in Section 7.11 of the Existing Loan Agreement, after giving effect to the Transactions (hereinafter defined), as of the end of the most recent fiscal quarter, (C) certifying that, after giving effect to the Transactions, the Borrower and its Subsidiaries, on a consolidated basis, are solvent on such date, and (D) certifying as to the matters set forth in clauses (b) - (h) and as to the representations and warranties set forth in Section 5 below;

(vi)a favorable opinion of Latham & Watkins, LLP, covering such matters concerning the Borrower and this Amendment as the Arrangers may reasonably request, in form and substance reasonably satisfactory to the Arrangers, such opinion to be addressed to the Administrative Agent and each Lender;

(vii)(A) pro forma consolidated financial statements for the Borrower and its Subsidiaries for the four-quarter period most recently ended prior to the Second Amendment Effective Date for which financial statements are available, consisting of a consolidated statements of earnings, cash flows, and shareholders’ equity and (B) a pro forma balance sheet of the Borrower and its Subsidiaries as of December 31, 2013, in each case giving pro forma effect to the Transactions as if the Transactions had occurred as of such date (in the case of such balance sheet) or at the beginning of such period (in the case of the financial statements referenced in clause (A));

(viii)(A) copies of any environmental reviews and/or reports relating to the Acquired Assets prepared by or for, or provided to, the Borrower in connection with the Permian Acquisition, and (B) in the event that work is required in order to remedy environmental defects, copies of information related to such work; and

(ix)A Loan Notice in an amount equal to the Loans outstanding on the Second Amendment Effective Date plus the additional amounts requested to be borrowed on such date, in an aggregate amount not to exceed the Aggregate Commitments as set forth on Schedule 2.01 attached hereto.

(b)Before and after taking into account the Transactions, since December 31, 2012, there shall not have occurred any event, development or circumstance that has or could reasonably be expected to, either individually or in the aggregate, result in a Material Adverse Effect.

(c)There shall be no action, suit, investigation or proceeding pending or, to the knowledge of the Borrower, threatened in any court or before any arbitrator or Governmental Authority with respect to the Permian Acquisition.

(d)All material consents and approvals of any Governmental Authority or third party necessary in order to borrow under the Loan Agreement and to consummate the Permian Acquisition shall have been obtained and shall be in full force and effect.

(e)(i) The Permian Acquisition shall have been, or concurrently with the funding of Loans on the Second Amendment Effective Date, shall be, consummated in accordance in all material respects with the terms of the Permian Acquisition Agreement, and (ii) no provision of the Permian Acquisition Agreement, in the form of the Permian Acquisition Agreement as in effect on January 7, 2014 and provided to the Arrangers, shall have been waived, amended, supplemented or otherwise modified, and no consent or request by the Borrower or any of its Subsidiaries shall have been provided thereunder, in each case in a manner which is materially adverse to the interests of the Lenders without the Arrangers’ written consent.

(f)Both before and immediately after giving effect to the Transactions, no Default shall exist.

5

Exhibit 10.2

(g)The Administrative Agent shall have received, to the extent not previously delivered and to the extent requested all documentation and other information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including the USA Patriot Act.

(h)The Borrower shall have paid all Lender upfront fees, Arranger fees and the Administrative Agent and Arranger expenses, including Attorney Costs of one counsel to the Administrative Agent and Wells Fargo Securities, LLC.

(i)The Second Amendment Effective Date shall occur on or prior to February 28, 2014.

5.Representations and Warranties. The Borrower represents and warrants that on the Second Amendment Effective Date both before and after giving effect to the Transactions:

(a)This Amendment has been duly authorized, executed and delivered by the Borrower, and this Amendment and the Loan Agreement as modified hereby each constitutes a legal, valid and binding obligation of the Borrower enforceable in accordance with its respective terms, except as such enforcement may be limited by bankruptcy, insolvency or similar Laws of general application relating to the enforcement of creditors’ rights or by general principles of equity, regardless of whether considered in a proceeding in equity or at law.

(b)The Specified Representations (hereinafter defined) are true and correct in all material respects (except that such materiality qualifier shall not be applicable to representations and warranties that already are qualified or modified by materiality in the text thereof), except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects (except that such materiality qualifier shall not be applicable to representations and warranties that already are qualified or modified by materiality in the text thereof) as of such earlier date. “Specified Representations” means the representations and warranties of the Borrower set forth in Section 5.02, Section 5.03, Section 5.04, Section 5.05, Section 5.15 and Section 5.16 (after giving effect to the Transactions) of the Loan Agreement.

(c)The Permian Acquisition Agreement Representations (hereinafter defined) are true and correct in all material respects (except that such materiality qualifier shall not be applicable to representations and warranties that already are qualified or modified by materiality in the text thereof), except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects (except that such materiality qualifier shall not be applicable to representations and warranties that already are qualified or modified by materiality in the text thereof) as of such earlier date. “Permian Acquisition Agreement Representations” means the representations made by or on behalf of the Seller (as defined in the Permian Acquisition Agreement) as are material to the interests of the Lenders, but only to the extent the Borrower has (or its applicable affiliate has) the right to terminate its obligations under the Permian Acquisition Agreement (or the right not to consummate the Permian Acquisition) as a result of a breach of such representations in the Permian Acquisition Agreement.

(d)No Default exists.

(e)The Borrower has received (i) all approvals required by the Organization Documents of the Borrower for the consummation of the Permian Acquisition and (ii) all material consents and approvals of Governmental Authorities required for the consummation of the Permian Acquisition. The Permian Acquisition has been consummated or is being consummated on the Second Amendment Effective Date in accordance in all material respects with the terms of the Permian Acquisition Agreement and in compliance in all material respects with applicable Laws and regulatory approvals.

6.Effect of Amendment. This Amendment, except as expressly provided herein, shall not be deemed to be a consent to the modification or waiver of any other term or condition of the Existing Loan Agreement. Except as otherwise expressly provided by this Amendment, all of the terms, conditions and provisions of the Existing Loan Agreement and the other Loan Documents shall remain the same, and are hereby ratified and affirmed, and the Loan Agreement, as amended hereby, and the other Loan Documents shall continue in full force and effect. From and after

6

Exhibit 10.2

the date hereof, each reference in the Loan Agreement, including the schedules and exhibits thereto and the other documents delivered in connection therewith, to the “Loan Agreement,” “this Amendment,” “hereunder,” “hereof,” “herein,” or words of like import, shall mean and be a reference to the Loan Agreement as amended hereby.

7.Miscellaneous. This Amendment shall for all purposes be construed in accordance with and governed by the laws of the State of New York. The captions in this Amendment are for convenience of reference only and shall not define or limit the provisions hereof. This Amendment may be executed in one or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument. Delivery of an executed counterpart of this Amendment by facsimile or in electronic form shall be effective as the delivery of a manually executed counterpart. This Amendment shall be a “Loan Document” as defined in the Loan Agreement.

8.Entire Agreement. THE LOAN AGREEMENT (AS AMENDED BY THIS AMENDMENT) AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

[SIGNATURES PAGES FOLLOW]

7

Exhibit 10.2

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers effective as of the date first written above.

QEP RESOURCES, INC., as the Borrower

By: /s/ Richard J. Doleshek

Name: Richard J. Doleshek

Title: Executive Vice President and Chief Financial Officer

WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, L/C Issuer, Swing Line Lender and a Lender

By: /s/ Leanne S. Phillips

Name: Leanne S. Phillips

Title: Director

BMO CAPITAL MARKETS FINANCING, INC., as a Lender

By:/s/ Kevin Utsey

Name: Kevin Utsey

Title: Director

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as a Lender

By: /s/ Mark Oberreuter

Name: Mark Oberreuter

Title: Vice President

CITIBANK, N.A., as a Lender

By: /s/ John Miller

Name: John Miller

Title: Vice President

COMPASS BANK, as a Lender

By: /s/ James Neblett

Name: James Neblett

Title: Vice President

8

Exhibit 10.2

SUNTRUST BANK, as a Lender

By:/s/ Shannon Juhan

Name: Shannon Juhan

Title:Vice President

U.S. BANK NATIONAL ASSOCIATION, as a Lender

By: /s/ Justin M. Alexander

Name: Justin M. Alexander

Title: Senior Vice President

BRANCH BANKING AND TRUST COMPANY, as a Lender

By:/s/ James Giordano

Name: James Giordano

Title: Vice President

EXPORT DEVELOPMENT CANADA, as a Lender

By: /s/ Christopher Wilson

Name: Christopher Wilson

Title: Senior Associate

By: /s/ Ranya Gabriel

Name: Ranya Gabriel

Title: Financing Manager

CAPITAL ONE, NATIONAL ASSOCIATION, as a Lender

By: /s/ Robert James

Name: Robert James

Title: Vice President

CREDIT AGRICOLE CORPORATE AND INVESTMENT

BANK, as a Lender

By: /s/ Michael Willis

Name: Michael Willis

Title: Managing Director

By: /s/ Sharada Manne

Name: Sharada Manne

Title: Managing Director

PNC BANK, NATIONAL ASSOCIATION, as a Lender

By: /s/ John Berry

Name: John Berry

Title: Vice President

9

Exhibit 10.2

COMERICA BANK, as a Lender

By: /s/ Mark Fuqua

Name: Mark Fuqua

Title: Senior Vice President

DNB CAPITAL LLC, as a Lender

By: /s/ Joe Hykle

Name: Joe Hykle

Title: Senior Vice President

By: /s/ Asuiv Tvelt

Name: Asuiv Tvelt

Title: Vice President

FIFTH THIRD BANK, as a Lender

By: /s/ Byron L. Cooley

Name: Byron L. Cooley

Title: Executive Director

SUMITOMO MITSUI BANKING CORPORATION, NY BRANCH, as a Lender

By: /s/ James D. Weinstein

Name: James D. Weinstein

Title:Managing Director

DEUTSCHE BANK AG NEW YORK BRANCH, as a Lender

By: /s/ Michael Getz

Name: Michael Getz

Title: Vice President

By:/s/ Lisa Wong

Name: Lisa Wong

Title: Vice President

GOLDMAN SACHS BANK USA, as a Lender

By: /s/ Mark Walton

Name: Mark Walton

Title: Authorized Signatory

JPMORGAN CHASE BANK, N.A., as a Lender

By: /s/ Robert Traband

Name: Robert Traband

Title: Managing Director

10

Exhibit 10.2

Annex A

Certain Amendments to Article III and Certain Definitions Relating Thereto

(a)The following defined terms appearing in Section 1.01 (Defined Terms) of the Existing Loan Agreement are amended as set forth below:

(i)The definition of “Excluded Taxes” is amended to read in its entirety as follows:

“Excluded Taxes” means any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its applicable Lending Office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes (b) U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan or Commitment pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Loan or Commitment (other than pursuant to an assignment request by the Borrower under Section 10.15) or (ii) such Lender changes its Lending Office, except in each case to the extent that, pursuant to Section 3.01, amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its Lending Office, (c) Taxes attributable to such Recipient’s failure to comply with Section 3.01(g) and (d) any U.S. federal withholding Taxes imposed under FATCA.

(ii)The definition “FATCA” is amended by deleting the period at the end of such definition and inserting the following: “and any agreements entered into pursuant to Section 1471(b)(1) of the Code or otherwise pursuant to any of the foregoing.”

(iii)The definition of “Foreign Lender” is amended to read in its entirety as follows:

“Foreign Lender” means (a) if the Borrower is a U.S. Person, a Lender that is not a U.S. Person, and (b) if the Borrower is not a U.S. Person, a Lender that is resident or organized under the Laws of a jurisdiction other than that in which the Borrower is resident for tax purposes.

(iv)The definition of “Indemnified Taxes” is amended by inserting “(a)” immediately after “means”, deleting the period at the end of such definition, and inserting the following: “, imposed on or with respect to any payment made by or on account of any obligation of the Borrower under any Loan Document and (b) to the extent not otherwise described in (a), Other Taxes.”

(v)The definition of “Other Taxes” is amended to read in its entirety as follows:

“Other Taxes” means all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 10.15).

11

Exhibit 10.2

(b)The following defined terms are hereby added to Section 1.01 (Defined Terms) of the Existing Loan Agreement in the appropriate alphabetical order:

“Other Connection Taxes” means, with respect to any Recipient, Taxes imposed solely as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Loan or Loan Document).

“Recipient” means (a) the Administrative Agent, and (b) any Lender, as applicable.

“Withholding Agent” means the Borrower and the Administrative Agent.

(c)Section 3.01 (Taxes) of the Existing Loan Agreement is amended to read in its entirety as follows:

“3.01.Taxes.

(a)Defined Terms. For purposes of this Section 3.01, the term “applicable law” includes FATCA.

(b)Payments Free of Taxes. Any and all payments by or on account of any obligation of the Borrower under any Loan Document shall to the extent permitted by applicable Laws be made without deduction or withholding for any Taxes, except as required by applicable law. If any applicable law (as determined in the good faith discretion of an applicable Withholding Agent) requires the deduction or withholding of any Tax from any such payment by a Withholding Agent, then the applicable Withholding Agent shall be entitled to make such deduction or withholding and shall timely pay the full amount deducted or withheld to the relevant Governmental Authority in accordance with applicable law and, if such Tax is an Indemnified Tax, then the sum payable by the Borrower shall be increased as necessary so that after such deduction or withholding has been made (including such deductions and withholdings applicable to additional sums payable under this Section) the applicable Recipient receives an amount equal to the sum it would have received had no such deduction or withholding been made.

(c)Payment of Other Taxes by the Borrower. The Borrower shall timely pay to the relevant Governmental Authority in accordance with applicable law, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes.

(d)Indemnification by the Borrower. The Borrower shall jointly and severally indemnify each Recipient, within 10 days after demand therefor, for the full amount of any Indemnified Taxes (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section) payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

(e)Indemnification by the Lenders. Each Lender shall severally indemnify the Administrative Agent, within 10 days after demand therefor, for (i) any Indemnified Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Borrower to do so), (ii) any

12

Exhibit 10.2

Taxes attributable to such Lender’s failure to comply with the provisions of Section 10.07(f) relating to the maintenance of a Participant Register and (iii) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under any Loan Document or otherwise payable by the Administrative Agent to the Lender from any other source against any amount due to the Administrative Agent under this paragraph (e).

(f)Evidence of Payments. As soon as practicable after any payment of Taxes by the Borrower to a Governmental Authority pursuant to this Section 3.01, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(g)Status of Lenders; Tax Documentation.

(i)Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Section 3.01(g)(ii)(A), (ii)(B) and (ii)(D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(ii)Without limiting the generality of the foregoing:

(A)any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed originals of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;

(B)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:

(i)in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed originals of IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. federal

13

Exhibit 10.2

withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Loan Document, IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(ii)executed originals of IRS Form W-8ECI;

(iii)in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate substantially in the form of Exhibit E-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Code, a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B) of the Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code (a “U.S. Tax Compliance Certificate”) and (y) executed originals of IRS Form W-8BEN; or

(iv)to the extent a Foreign Lender is not the beneficial owner, executed originals of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN, a U.S. Tax Compliance Certificate substantially in the form of Exhibit E-2 or Exhibit E-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit E-4 on behalf of each such direct and indirect partner.

(C)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed originals of any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by applicable law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made; and

(D)if a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

14

Exhibit 10.2

Each Lender agrees that if any form or certification it previously delivered expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so. For purposes of this Section 3.01(g), references to a Lender shall include the Administrative Agent.

(h)Treatment of Certain Refunds. If any party determines, in its sole discretion exercised in good faith, that it has received a refund of any Taxes as to which it has been indemnified pursuant to this Section 3.01 (including by the payment of additional amounts pursuant to this Section 3.01), it shall pay to the indemnifying party an amount equal to such refund (but only to the extent of indemnity payments made under this Section with respect to the Taxes giving rise to such refund), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund). Such indemnifying party, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this paragraph (h) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event that such indemnified party is required to repay such refund to such Governmental Authority. Notwithstanding anything to the contrary in this paragraph (h), in no event will the indemnified party be required to pay any amount to an indemnifying party pursuant to this paragraph (h) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to indemnification and giving rise to such refund had not been deducted, withheld or otherwise imposed and the indemnification payments or additional amounts with respect to such Tax had never been paid. This paragraph shall not be construed to require any indemnified party to make available its Tax returns (or any other information relating to its Taxes that it deems confidential) to the indemnifying party or any other Person.

(i)Survival. Each party’s obligations under this Section 3.01 shall survive the resignation or replacement of the Administrative Agent or any assignment of rights by, or the replacement of, a Lender, the termination of the Commitments and the repayment, satisfaction or discharge of all obligations under any Loan Document.

(j)Designation of a Different Lending Office. If any Lender requests compensation under Section 3.01(b), or requires the Borrower to make any payments pursuant to Section 3.01(c), then such Lender shall (at the request of the Borrower) use reasonable efforts to designate a different Lending Office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 3.01(b) or Section 3.01(c) in the future, and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. If the Borrower requests a Lender to designate a different Lending Office or assign its rights and obligations to another of its offices, branches or affiliates, the Borrower hereby agrees to pay all reasonable costs and expenses incurred by such Lender in connection with any such designation or assignment. Subject to the foregoing, Lenders agree to use reasonable efforts to select lending offices which will minimize taxes and other costs and expenses for the Borrower.”

(d)Section 3.04(a) (Increased Cost and Reduced Return; Capital Adequacy; Reserves on Eurodollar Rate Loans) of the Existing Loan Agreement is amended by revising clause (ii) thereof to read as follows:

“(ii)subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (b) through (d) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto; or”.

15

Exhibit 10.2

Annex B

Revised Cover Page For Term Loan Agreement

See the following page

16

Exhibit 10.2

Published CUSIP Number: 74733YAF1

TERM LOAN AGREEMENT

Dated as of April 18, 2012

amended by First Amendment to Term Loan Agreement

dated as of August 13, 2013 and by

Second Amendment to Term Loan Agreement and Commitment Increase Agreement

dated as of February 19, 2014 among

QEP RESOURCES, INC.,

as the Borrower,

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Administrative Agent, and

The Lenders Party Hereto

SunTrust Bank

and

Compass Bank,

Co-Syndication Agents

Citibank, N.A.,

U.S. Bank National Association, and

Bank Of Tokyo Mitsubishi UFJ, Ltd., Co-Documentation Agents

WELLS FARGO SECURITIES, LLC, BMO CAPITAL MARKETS, INC.,

SUNTRUST ROBINSON HUMPHREY, INC., BBVA COMPASS,

CITIGROUP GLOBAL MARKETS INC.,

and

U.S. BANK NATIONAL ASSOCIATION,

Joint Lead Arrangers and Joint Bookrunners

17

Exhibit 10.2

SCHEDULE2.01

COMMITMENTS

AND PRO RATA SHARES

QEP Resources, Inc. Term Loan Agreement

Lender	Commitment	Pro Rata Share
Wells Fargo Bank, National Association	$51,000,000	8.500000000%
BMO Harris Financing, Inc.	$42,000,000	7.000000000%
The Bank of Tokyo Mitsubishi UFJ, Ltd.	$48,000,000	8.000000000%
Citibank, N.A.	$48,000,000	8.000000000%
Compass Bank	$48,000,000	8.000000000%
SunTrust Bank	$48,000,000	8.000000000%
U.S. Bank National Association	$48,000,000	8.000000000%
Branch Banking and Trust Company	$45,000,000	7.500000000%
Export Development Canada	$45,000,000	7.500000000%
Capital One, National Association	$27,000,000	4.500000000%
Credit Agricole Corporate and Investment Bank	$27,000,000	4.500000000%
PNC Bank, National Association	$27,000,000	4.500000000%
Comerica Bank	$15,000,000	2.500000000%
DNB Capital LLC	$15,000,000	2.500000000%
Fifth Third Bank	$15,000,000	2.500000000%
Sumitomo Mitsui Banking Corporation, NY Branch	$15,000,000	2.500000000%
Deutsche Bank AG New York Branch	$12,000,000	2.000000000%
Goldman Sachs Bank USA	$12,000,000	2.000000000%
JPMorgan Chase Bank, N.A.	$12,000,000	2.000000000%
Total	$600,000,000.00	100.000000000%

18

Exhibit 10.2

EXHIBIT E -1

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Term Loan Agreement dated as of April 18, 2012 (as amended, supplemented or otherwise modified from time to time, the “Loan Agreement”), among QEP RESOURCES, INC., as Borrower, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, and the Lenders from time to time parties thereto.

Pursuant to the provisions of Section 3.01 of the Loan Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the Loan(s) (as well as any Note(s) evidencing such Loan(s)) in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Code, (iii) it is not a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code and (iv) it is not a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished the Administrative Agent and the Borrower with a certificate of its non-U.S. Person status on IRS Form W-8BEN. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Borrower and the Administrative Agent, and (2) the undersigned shall have at all times furnished the Borrower and the Administrative Agent with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Loan Agreement and used herein shall have the meanings given to them in the Loan Agreement.

[NAME OF LENDER]
By:
	Name:
	Title:

Date: ________ __, 20[ ]

19

Exhibit 10.2

EXHIBIT E -2

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Term Loan Agreement dated as of April 18, 2012 (as amended, supplemented or otherwise modified from time to time, the “Loan Agreement”), among QEP RESOURCES, INC., as Borrower, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, and the Lenders from time to time parties thereto.

Pursuant to the provisions of Section 3.01 of the Loan Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the participation in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Code, (iii) it is not a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code, and (iv) it is not a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished its participating Lender with a certificate of its non-U.S. Person status on IRS Form W-8BEN. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender in writing, and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Loan Agreement and used herein shall have the meanings given to them in the Loan Agreement.

[NAME OF PARTICIPANT]
By:
	Name:
	Title:

Date: ________ __, 20[ ]

20

Exhibit 10.2

EXHIBIT E -3

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Term Loan Agreement dated as of April 18, 2012 (as amended, supplemented or otherwise modified from time to time, the “Loan Agreement”), among QEP RESOURCES, INC., as Borrower, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, and the Lenders from time to time parties thereto.

Pursuant to the provisions of Section 3.01 of the Loan Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the participation in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such participation, (iii) with respect such participation, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished its participating Lender with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Loan Agreement and used herein shall have the meanings given to them in the Loan Agreement.

[NAME OF PARTICIPANT]
By:
	Name:
	Title:

Date: ________ __, 20[ ]

21

Exhibit 10.2

EXHIBIT E -4

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Term Loan Agreement dated as of April 18, 2012 (as amended, supplemented or otherwise modified from time to time, the “Loan Agreement”), among QEP RESOURCES, INC., as Borrower, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, and the Lenders from time to time parties thereto.

Pursuant to the provisions of Section 3.01 of the Loan Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the Loan(s) (as well as any Note(s) evidencing such Loan(s)) in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such Loan(s) (as well as any Note(s) evidencing such Loan(s)), (iii) with respect to the extension of credit pursuant to this Loan Agreement or any other Loan Document, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished the Administrative Agent and the Borrower with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Borrower and the Administrative Agent, and (2) the undersigned shall have at all times furnished the Borrower and the Administrative Agent with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Loan Agreement and used herein shall have the meanings given to them in the Loan Agreement.

[NAME OF LENDER]
By:
	Name:
	Title:

Date: ________ __, 20[ ]

22

EX-10.3

Exhibit 10.3

EXECUTION COPY

THIRD AMENDMENT TO CREDIT AGREEMENT

This THIRD AMENDMENT TO CREDIT AGREEMENT (this “Amendment”) is made and entered into as of January 31, 2014, by and among QEP RESOURCES, INC., a Delaware corporation (the “Borrower”), the Lenders named on the signature pages hereto, and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent for the Lenders (in such capacity, the “Administrative Agent”), L/C Issuer and Swing Line Lender.

W I T N E S S E T H:

WHEREAS, the Borrower, the Lenders and the Administrative Agent are parties to that certain Credit Agreement dated as of August 25, 2011, as amended by that certain First Amendment to Credit Agreement dated as of July 6, 2012, and that certain Second Amendment to Credit Agreement dated as of August 13, 2013 (the “Existing Credit Agreement” and as amended by this Amendment, the “Credit Agreement”);

WHEREAS, the Borrower, through its wholly-owned subsidiary, QEP Energy Company, as buyer, and EnerVest Holding, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P., and EnerVest Energy Institutional Fund XII-WIC, L.P. as sellers (collectively, the “Seller”), have entered into that certain Purchase and Sale Agreement dated as of December 6, 2013, as it may be amended (the “Permian Acquisition Agreement”), pursuant to which the Borrower, through QEP Energy Company, has agreed to purchase certain oil and natural gas interests in the Midland sub-basin of the Permian Basin in Martin and Andrews Counties, Texas as more particularly described therein (such acquisition, the “Permian Acquisition”);

WHEREAS, the Borrower intends to structure the Permian Acquisition to qualify for reverse like-kind exchange treatment under Section 1031 of the Internal Revenue Code and the regulations and revenue procedures promulgated thereunder; and

WHEREAS, subject to terms of this Amendment, the Borrower, the Administrative Agent and the undersigned Lenders have agreed to amend the Existing Credit Agreement as set forth in Section 2 below, such amendments to be effective on the Third Amendment Effective Date as hereinafter defined.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

1.Definitions.

(a)As used herein, “Transactions” means collectively, the Permian Acquisition, the execution of this Amendment and the incurrence of Indebtedness by the Borrower or its Subsidiaries in connection with the Permian Acquisition.

(b)Unless otherwise defined in this Amendment, all other terms used in this Amendment which are defined in the Existing Credit Agreement shall have the meanings assigned to such terms in the Existing Credit Agreement. The interpretive provisions set forth in Section 1.02 of the Existing Credit Agreement shall apply to this Amendment.

2.Amendments to the Existing Credit Agreement. The following amendments to the Existing Credit Agreement shall be effective on the date (the “Third Amendment Effective Date”) that the conditions set forth in Section 3 of this Amendment have been satisfied.

(a)Amended Definition of Eurodollar Rate. The definition of Eurodollar Rate appearing in Section 1.01 (Defined Terms) of the Existing Credit Agreement is amended in its entirety to read as follows:

1

Exhibit 10.3

“Eurodollar Rate” means, for any interest rate calculation with respect to a Eurodollar Rate Loan, the rate of interest per annum determined on the basis of the rate for deposits in Dollars for a period equal to the applicable Interest Period which appears on Reuters Screen LIBOR01 Page (or any applicable successor page) at approximately 11:00 a.m. (London time) two (2) Business Days prior to the first day of the applicable Interest Period (rounded upward, if necessary, to the nearest 1/100th of 1%). If, for any reason, such rate does not appear on Reuters Screen LIBOR01 Page (or any applicable successor page), then the “Eurodollar Rate” shall be determined by the Administrative Agent to be the arithmetic average of the rate per annum at which deposits in Dollars in minimum amounts of at least $5,000,000 would be offered by first class banks in the London interbank market to the Administrative Agent at approximately 11:00 a.m. (London time) two (2) Business Days prior to the first day of the applicable Interest Period for a period equal to such Interest Period.

(b)Certain Additional Definitions. The following defined terms are hereby added to Section 1.01 (Defined Terms) of the Credit Agreement in the appropriate alphabetical order:

“Acquired Permian Assets” has the meaning set forth in the definition of “Permian Acquisition”.

“OFAC” means the U.S. Department of the Treasury’s Office of Foreign Assets Control.

“Permian Acquisition” means the acquisition by the Borrower, through its wholly-owned subsidiary, QEP Energy Company, of certain oil and natural gas interests in the Midland sub-basin of the Permian Basin, in Martin and Andrews Counties, Texas (the “Acquired Permian Assets”) pursuant to the Permian Acquisition Agreement.

“Permian Acquisition Agreement” means the Purchase and Sale Agreement dated as of December 6, 2013, as it may be amended, among QEP Energy Company as purchaser and EnerVest Holding, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P., and EnerVest Energy Institutional Fund XII-WIC, L.P. as seller (collectively, the “Seller”).

“Sanctioned Country” means a country subject to a sanctions program identified on the list maintained by OFAC and available at http://www.treasury.gov/resource-center/sanctions/Programs/ Pages/Programs.aspx, or as otherwise published from time to time.

“Sanctioned Person” means (a) a Person named on the list of “Specially Designated Nationals and Blocked Persons” maintained by OFAC available at http://www.treasury.gov/resource-center/sanctions /SDN-List/Pages/default.aspx, or as otherwise published from time to time, or (b) (i) an agency of the government of a Sanctioned Country, (ii) an organization controlled by a Sanctioned Country, or (iii) a person resident in a Sanctioned Country, to the extent subject to a sanctions program administered by the U.S. Department of the Treasury’s Office of Foreign Assets Control.

(c)Amendments toArticle III(Taxes, Yield Protection and Illegality) and Certain Definitions Relating Thereto. Section 3.01 (Taxes) of the Existing Credit Agreement, Section 3.04 (Increased Cost and Reduced Return; Capital Adequacy; Reserves on Eurodollar Rate Loans) of the Existing Credit Agreement and certain definitions used therein, are amended, and new definitions used therein are added, all as set forth on Annex A attached hereto.

(d)Addition ofSection 5.19. Section 5.19 (OFAC) shall be added to the Credit Agreement immediately following Section 5.18 of the Credit Agreement and shall read as follows:

“Section 5.19 OFAC. Neither the Borrower nor any Restricted Subsidiary (i) is an “enemy” or an “ally of the enemy” within the meaning of Section 2 of the Trading

2

Exhibit 10.3

with the Enemy Act of the United States (50 U.S.C. App. §§ 1 et seq.), (ii) is in violation of (A) the Trading with the Enemy Act, (B) any of the foreign assets control regulations of the United States Treasury Department (31 CFR, Subtitle B, Chapter V) or any enabling legislation or executive order relating thereto or (C) the PATRIOT Act, (iii) is a Sanctioned Person or (iv) has more than 10% of its assets in Sanctioned Countries. No part of the proceeds of any Loan will be used directly or indirectly to fund any operations in, finance any investments or activities in or make any payments to, a Sanctioned Person or a Sanctioned Country.”

(e)Amendment toSection 7.09. Section 7.09 (Dispositions of Property) of the Existing Credit Agreement is amended by deleting the word “and” at the end of Section 7.09(k), deleting the period at the end of Section 7.09(l) and adding the following new subsection (m) after Section 7.09(l), which shall read in its entirety as follows:

“(m)assignments, made in order to structure and consummate the Permian Acquisition and a qualifying asset sale as a reverse like kind exchange under Section 1031 of the Code, that are to exchange intermediaries, title holders and/or similar entities that are parties to such reverse like kind exchange transaction, including the assignments of the Permian Acquisition Agreement and other purchase agreements and loan receivables created in connection with such like kind exchange.”

(f)Addition of Exhibits. Exhibit E-1, Exhibit E-2, Exhibit E-3 and Exhibit E-4 attached hereto are added as Exhibit E-1, Exhibit E-2, Exhibit E-3 and Exhibit E-4 to the Credit Agreement.

3.Conditions of Effectiveness. This effectiveness of this Amendment is subject to the satisfaction of the following conditions precedent: (a) the Administrative Agent shall have received counterparts of this Amendment executed by the Borrower, the Administrative Agent and the Required Lenders; and (b) the Borrower shall have paid Attorney Costs of one counsel to the Administrative Agent incurred in connection with this Amendment, to the extent invoiced prior to the Third Amendment Effective Date.

4.Representations and Warranties. The Borrower represents and warrants that on the Third Amendment Effective Date both before and after giving effect to the Transactions:

(a)This Amendment has been duly authorized, executed and delivered by the Borrower, and this Amendment and the Credit Agreement as modified hereby each constitutes a legal, valid and binding obligation of the Borrower enforceable in accordance with its respective terms, except as such enforcement may be limited by bankruptcy, insolvency or similar Laws of general application relating to the enforcement of creditors’ rights or by general principles of equity, regardless of whether considered in a proceeding in equity or at law.

(b)The representations and warranties of the Borrower set forth in the Credit Agreement are true and correct in all material respects (except that such materiality qualifier shall not be applicable to representations and warranties that already are qualified or modified by materiality in the text thereof), except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects (except that such materiality qualifier shall not be applicable to representations and warranties that already are qualified or modified by materiality in the text thereof) as of such earlier date.

(c)No Default exists.

5.Effect of Amendment. This Amendment, except as expressly provided herein, shall not be deemed to be a consent to the modification or waiver of any other term or condition of the Existing Credit Agreement. Except as otherwise expressly provided by this Amendment, all of the terms, conditions and provisions of the Existing Credit Agreement and the other Loan Documents shall remain the same, and are hereby ratified and affirmed, and the Credit Agreement, as amended hereby, and the other Loan Documents shall continue in full force and effect. From and after

3

Exhibit 10.3

the date hereof, each reference in the Credit Agreement, including the schedules and exhibits thereto and the other documents delivered in connection therewith, to the “Credit Agreement,” “this Amendment,” “hereunder,” “hereof,” “herein,” or words of like import, shall mean and be a reference to the Credit Agreement as amended hereby.

6.Miscellaneous. This Amendment shall for all purposes be construed in accordance with and governed by the laws of the State of New York. The captions in this Amendment are for convenience of reference only and shall not define or limit the provisions hereof. This Amendment may be executed in one or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument. Delivery of an executed counterpart of this Amendment by facsimile or in electronic form shall be effective as the delivery of a manually executed counterpart. This Amendment shall be a “Loan Document” as defined in the Credit Agreement.

7.Entire Agreement. THE CREDIT AGREEMENT (AS AMENDED BY THIS AMENDMENT) AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

[SIGNATURES PAGES FOLLOW]

4

Exhibit 10.3

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers effective as of the date first written above.

QEP RESOURCES, INC., as the Borrower

By: /s/ Richard J. Doleshek

Name: Richard J. Doleshek

Title: Executive Vice President and Chief Financial Officer

WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, L/C Issuer, Swing Line Lender and a Lender

By: /s/ Leanne S. Phillips

Name: Leanne S. Phillips

Title: Director

BMO CAPITAL MARKETS FINANCING, INC., as a Lender

By:/s/ Kevin Utsey

Name: Kevin Utsey

Title: Director

DEUTSCHE BANK TRUST COMPANY AMERICAS, as a Lender

By: /s/ Michael Getz

Name: Michael Getz

Title: Vice President

By:/s/ Lisa Wong

Name: Lisa Wong

Title: Vice President

JPMORGAN CHASE BANK, N.A., as a Lender

By: /s/ Robert Traband

Name: Robert Traband

Title: Managing Director

U.S. BANK NATIONAL ASSOCIATION, as a Lender

By:/s/ Justin M. Alexander

Name: Justin M. Alexander

Title: Senior Vice President

5

Exhibit 10.3

AMEGY BANK NATIONAL ASSOCIATION, as a

Lender

By: /s/ Kevin Donaldson

Name: Kevin Donaldson

Title: SVP

BRANCH BANKING AND TRUST COMPANY, as a Lender

By: /s/ James Giordano

Name: James Giordano

Title:Vice President

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as a Lender

By: /s/ Mark Oberreuter

Name: Mark Oberreuter

Title: Vice President

CIBC, INC., as a Lender

By: /s/ Trudy Nelson

Name: Trudy Nelson

Title: Authorized Signatory

By:/s/ Richard Antl

Name: Richard Antl

Title: Authorized Signatory

CITIBANK, N.A., as a Lender

By: /s/ John Miller

Name: John Miller

Title: Vice President

COMERICA BANK, as a Lender

By: /s/ Ekaterina V. Evseey

Name: Ekaterina V. Evseey

Title: Assistant Vice President

6

Exhibit 10.3

COMPASS BANK, as a Lender

By: /s/ James Neblett

Name: James Neblett

Title: Vice President

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK, as a Lender

By: /s/ Michael Willis

Name: Michael Willis

Title: Managing Director

By: /s/Sharada Manne

Name: Sharada Manne

Title: Managing Director

DNB CAPITAL LLC, as a Lender

By: /s/ Joe Hykle

Name: Joe Hykle

Title: Senior Vice President

By: /s/ Asuiv Tvelt

Name: Asuiv Tvelt

Title: Vice President

EXPORT DEVELOPMENT CANADA, as a Lender

By: /s/ Trevor Mulligan

Name: Trevor Mulligan

Title: Asset Manager

By:/s/ Richard Leong

Name: Richard Leong

Title:Asset Manager

GOLDMAN SACHS BANK USA, as a Lender

By: /s/ Michelle Latzoni

Name: Michelle Latzoni

Title: Authorized Signatory

7

Exhibit 10.3

MORGAN STANLEY BANK, N.A., as a Lender

By: /s/ Dmitriy Barskiy

Name: Dmitriy Barskiy

Title: Authorized Signatory

SUNTRUST BANK, as a Lender

By:/s/ Shannon Juhan

Name: Shannon Juhan

Title:Vice President

TORONTO DOMINION (NEW YORK) LLC, as a Lender

By: /s/ Masood Fikree

Name: Masood Fikree

Title: Authorized Signatory

8

Exhibit 10.3

Annex A

Certain Amendments to Article III and Certain Definitions Relating Thereto

(a)The following defined terms appearing in Section 1.01 (Defined Terms) of the Existing Credit Agreement are amended as set forth below:

(i)The definition of “Excluded Taxes” is amended to read in its entirety as follows:

“Excluded Taxes” means any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its applicable Lending Office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes (b) U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan or Commitment pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Loan or Commitment (other than pursuant to an assignment request by the Borrower under Section 10.15) or (ii) such Lender changes its Lending Office, except in each case to the extent that, pursuant to Section 3.01, amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its Lending Office, (c) Taxes attributable to such Recipient’s failure to comply with Section 3.01(g) and (d) any U.S. federal withholding Taxes imposed under FATCA.

(ii)The definition “FATCA” is amended by deleting the period at the end of such definition and inserting the following: “and any agreements entered into pursuant to Section 1471(b)(1) of the Code or otherwise pursuant to any of the foregoing.”.

(iii)The definition of “Foreign Lender” is amended to read in its entirety as follows:

“Foreign Lender” means (a) if the Borrower is a U.S. Person, a Lender that is not a U.S. Person, and (b) if the Borrower is not a U.S. Person, a Lender that is resident or organized under the Laws of a jurisdiction other than that in which the Borrower is resident for tax purposes.

(iv)The definition of “Indemnified Taxes” is amended by inserting “(a)” immediately after “means”, deleting the period at the end of such definition, and inserting the following: “, imposed on or with respect to any payment made by or on account of any obligation of the Borrower under any Loan Document and (b) to the extent not otherwise described in (a), Other Taxes.”

(v)The definition of “Other Taxes” is amended to read in its entirety as follows:

“Other Taxes” means all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 10.15).

(b)The following defined terms are hereby added to Section 1.01 (Defined Terms) of the Existing Credit Agreement in the appropriate alphabetical order:

9

Exhibit 10.3

“Other Connection Taxes” means, with respect to any Recipient, Taxes imposed solely as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Loan or Loan Document).

“Recipient” means (a) the Administrative Agent, (b) any Lender, and (c) any L/C Issuer, as applicable.

“Withholding Agent” means the Borrower and the Administrative Agent.

(c)Section 3.01 (Taxes) of the Existing Credit Agreement is amended to read in its entirety as follows:

“3.01.Taxes.

(a)Defined Terms. For purposes of this Section 3.01, the term “Lender” includes each L/C Issuer and the Swing Line Lender and the term “applicable law” includes FATCA.

(b)Payments Free of Taxes. Any and all payments by or on account of any obligation of the Borrower under any Loan Document shall to the extent permitted by applicable Laws be made without deduction or withholding for any Taxes, except as required by applicable law. If any applicable law (as determined in the good faith discretion of an applicable Withholding Agent) requires the deduction or withholding of any Tax from any such payment by a Withholding Agent, then the applicable Withholding Agent shall be entitled to make such deduction or withholding and shall timely pay the full amount deducted or withheld to the relevant Governmental Authority in accordance with applicable law and, if such Tax is an Indemnified Tax, then the sum payable by the Borrower shall be increased as necessary so that after such deduction or withholding has been made (including such deductions and withholdings applicable to additional sums payable under this Section) the applicable Recipient receives an amount equal to the sum it would have received had no such deduction or withholding been made.

(c)Payment of Other Taxes by the Borrower. The Borrower shall timely pay to the relevant Governmental Authority in accordance with applicable law, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes.

(d)Indemnification by the Borrower. The Borrower shall jointly and severally indemnify each Recipient, within 10 days after demand therefor, for the full amount of any Indemnified Taxes (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section) payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

(e)Indemnification by the Lenders. Each Lender shall severally indemnify the Administrative Agent, within 10 days after demand therefor, for (i) any Indemnified Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Borrower to do so), (ii) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 10.07(f) relating

10

Exhibit 10.3

to the maintenance of a Participant Register and (iii) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under any Loan Document or otherwise payable by the Administrative Agent to the Lender from any other source against any amount due to the Administrative Agent under this paragraph (e).

(f)Evidence of Payments. As soon as practicable after any payment of Taxes by the Borrower to a Governmental Authority pursuant to this Section 3.01, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(g)Status of Lenders; Tax Documentation.

(i)Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Section 3.01(g)(ii)(A), (ii)(B) and (ii)(D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(ii)Without limiting the generality of the foregoing:

(A)any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed originals of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;

(B)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:

(i)in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed originals of IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y)

11

Exhibit 10.3

with respect to any other applicable payments under any Loan Document, IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(ii)executed originals of IRS Form W-8ECI;

(iii)in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate substantially in the form of Exhibit E-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Code, a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B) of the Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code (a “U.S. Tax Compliance Certificate”) and (y) executed originals of IRS Form W-8BEN; or

(iv)to the extent a Foreign Lender is not the beneficial owner, executed originals of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN, a U.S. Tax Compliance Certificate substantially in the form of Exhibit E-2 or Exhibit E-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit E-4 on behalf of each such direct and indirect partner.

(C)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed originals of any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by applicable law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made; and

(D)if a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

12

Exhibit 10.3

Each Lender agrees that if any form or certification it previously delivered expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so. For purposes of this Section 3.01(g), references to a Lender shall include the Administrative Agent.

(h)Treatment of Certain Refunds. If any party determines, in its sole discretion exercised in good faith, that it has received a refund of any Taxes as to which it has been indemnified pursuant to this Section 3.01 (including by the payment of additional amounts pursuant to this Section 3.01), it shall pay to the indemnifying party an amount equal to such refund (but only to the extent of indemnity payments made under this Section with respect to the Taxes giving rise to such refund), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund). Such indemnifying party, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this paragraph (h) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event that such indemnified party is required to repay such refund to such Governmental Authority. Notwithstanding anything to the contrary in this paragraph (h), in no event will the indemnified party be required to pay any amount to an indemnifying party pursuant to this paragraph (h) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to indemnification and giving rise to such refund had not been deducted, withheld or otherwise imposed and the indemnification payments or additional amounts with respect to such Tax had never been paid. This paragraph shall not be construed to require any indemnified party to make available its Tax returns (or any other information relating to its Taxes that it deems confidential) to the indemnifying party or any other Person.

(i)Survival. Each party’s obligations under this Section 3.01 shall survive the resignation or replacement of the Administrative Agent or any assignment of rights by, or the replacement of, a Lender, the termination of the Commitments and the repayment, satisfaction or discharge of all obligations under any Loan Document.

(j)Designation of a Different Lending Office. If any Lender requests compensation under Section 3.01(b), or requires the Borrower to make any payments pursuant to Section 3.01(c), then such Lender shall (at the request of the Borrower) use reasonable efforts to designate a different Lending Office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 3.01(b) or Section 3.01(c) in the future, and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. If the Borrower requests a Lender to designate a different Lending Office or assign its rights and obligations to another of its offices, branches or affiliates, the Borrower hereby agrees to pay all reasonable costs and expenses incurred by such Lender in connection with any such designation or assignment. Subject to the foregoing, Lenders agree to use reasonable efforts to select lending offices which will minimize taxes and other costs and expenses for the Borrower.”

(d)Section 3.04(a) (Increased Cost and Reduced Return; Capital Adequacy; Reserves on Eurodollar Rate Loans) of the Existing Credit Agreement is amended by revising clause (ii) thereof to read as follows:

“(ii)subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (b) through (d) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto; or”.

13

Exhibit 10.3

EXHIBIT E -1

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement dated as of August 25, 2011 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among QEP RESOURCES, INC., as Borrower, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, L/C Issuer and Swing Line Lender and the Lenders and L/C Issuers from time to time parties thereto.

Pursuant to the provisions of Section 3.01 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the Loan(s) (as well as any Note(s) evidencing such Loan(s)) in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Code, (iii) it is not a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code and (iv) it is not a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished the Administrative Agent and the Borrower with a certificate of its non-U.S. Person status on IRS Form W-8BEN. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Borrower and the Administrative Agent, and (2) the undersigned shall have at all times furnished the Borrower and the Administrative Agent with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF LENDER]
By:
	Name:
	Title:

Date: ________ __, 20[ ]

14

Exhibit 10.3

EXHIBIT E -2

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement dated as of August 25, 2011 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among QEP RESOURCES, INC., as Borrower, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, L/C Issuer and Swing Line Lender and the Lenders and L/C Issuers from time to time parties thereto.

Pursuant to the provisions of Section 3.01 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the participation in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Code, (iii) it is not a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code, and (iv) it is not a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished its participating Lender with a certificate of its non-U.S. Person status on IRS Form W-8BEN. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender in writing, and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF PARTICIPANT]
By:
	Name:
	Title:

Date: ________ __, 20[ ]

15

Exhibit 10.3

EXHIBIT E -3

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement dated as of August 25, 2011 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among QEP RESOURCES, INC., as Borrower, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, L/C Issuer and Swing Line Lender and the Lenders and L/C Issuers from time to time parties thereto.

Pursuant to the provisions of Section 3.01 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the participation in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such participation, (iii) with respect such participation, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished its participating Lender with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF PARTICIPANT]
By:
	Name:
	Title:

Date: ________ __, 20[ ]

16

Exhibit 10.3

EXHIBIT E -4

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement dated as of August 25, 2011 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among QEP RESOURCES, INC., as Borrower, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, L/C Issuer and Swing Line Lender and the Lenders and L/C Issuers from time to time parties thereto.

Pursuant to the provisions of Section 3.01 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the Loan(s) (as well as any Note(s) evidencing such Loan(s)) in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such Loan(s) (as well as any Note(s) evidencing such Loan(s)), (iii) with respect to the extension of credit pursuant to this Credit Agreement or any other Loan Document, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished the Administrative Agent and the Borrower with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Borrower and the Administrative Agent, and (2) the undersigned shall have at all times furnished the Borrower and the Administrative Agent with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF LENDER]
By:
	Name:
	Title:

Date: ________ __, 20[ ]

17

EX-31.1

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.

May 7, 2014

/s/ Charles B. Stanley

Charles B. Stanley

Chairman, President and Chief Executive Officer

EX-31.2

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.

May 7, 2014

/s/ Richard J. Doleshek

Richard J. Doleshek

Executive Vice President, Chief Financial Officer and Treasurer

EX-32.1

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 March 31, 2014, 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, Chief Financial Officer and Treasurer of the Company, 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.
May 7, 2014
	/s/ Charles B. Stanley
	Charles B. Stanley
	Chairman, President and Chief Executive Officer
May 7, 2014
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President,
	Chief Financial Officer and Treasurer

XML

QEP Midstream (Reconciliation of Proceeds from Subsidiary Initial Public Offering) (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Aug. 14, 2013
Reconciliation of Proceeds from Subsidiary IPO [Line Items]
Total proceeds from the Subsidiary IPO	$ 483.0
Offering costs	(33.4)
Net proceeds from Subsidiary IPO	449.6
Revolving credit facility origination fees	(3.0)
Repayment of outstanding debt with QEP	(95.5)
Net proceeds distributed to QEP from the IPO	$ 351.1

XML

Equity-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Share-based Compensation [Abstract]
Shares available for future grants	10,900,000
Options Outstanding [RollForward]
Excess tax benefit on share-based compensation	$ 0.6		$ (1.0)
Weighted-Average Price [Abstract]
Share-based compensation	6.8		6.1
Stock Options [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Fair value of options at grant date	$ 10.12
Risk-free interest rate (in hundredths)	1.31%
Expected price volatility (in hundredths)	37.20%
Expected dividend yield (in hundredths)	0.25%
Expected life in years	4 years 6 months
Options Outstanding [RollForward]
Outstanding Beginning Balance (in shares)	1,794,187
Granted (in shares)	279,458
Exercised (in shares)	(29,479)
Outstanding Ending Balance (in shares)	2,044,166
Options Excercisable (in shares)	1,480,337
Unvested Options (in shares)	563,829
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning (in dollars per share)	$ 27.90
Weighted-Average Price, Granted (in dollars per share)	$ 31.67
Weighted-Average Price, Exercised (in dollars per share)	$ 23.01
Weighted-Average Price, Ending (in dollars per share)	$ 28.49
Weighted-Average Price, Options Excercisable	$ 27.56
Weighted-Average Price, Unvested Options	$ 30.93
Weighted-Average Remaining Contractual Term, Outstanding	3 years 10 months 27 days
Aggregate Intrinsic Value, Outstanding	5.2
Weighted-Average Remaining Contractual Term, Options Excercisable	3 years 0 months 7 days
Aggregate Intrinsic Value, Options Excercisable	5.1
Weighted-Average Remaining Contractual Term, Unvested Options	6 years 2 months 26 days
Aggregate Intrinsic Value, Unvested Options	0.1
Intrinsic value of options exercised	0.2		4.2
Unrecognized compensation cost	4.7
Weighted-average period for recognition of compensation costs	2 years 5 months 4 days
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options	0.7
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	0.1		1.4
Restricted Stock [Member]
Options Outstanding [RollForward]
Total fair value of stock that vested	15.1		14.8
Shares Outstanding [Roll Forward]
Balance, beginning (in shares)	1,388,953
Granted (in shares)	844,552
Vested and paid out (in shares)	(524,672)
Forfeited (in shares)	(18,170)
Balance, Ending (in shares)	1,690,663
Weighted-Average Price [Abstract]
Weighted-Average Price, Forfeited (in dollars per share)	$ 31.28
Weighted-Average Price, beginning balance (in dollars per share)	$ 30.96
Weighted-Average Price, Granted (in dollars per share)	$ 31.69		$ 30.12
Weighted-Average Price, Vested and paid out (in dollars per share)	$ 31.89
Weighted-Average Price, Ending Balance (in dollars per share)	$ 31.03
Unrecognized compensation cost	35.5
Weighted-average period for recognition of compensation costs	2 years 6 months 10 days
Vesting period (in years)	3 years 0 months 0 days
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	1.5		0.3
Performance Share Units [Member]
Shares Outstanding [Roll Forward]
Balance, beginning (in shares)	480,660
Granted (in shares)	241,321
Vested and paid out (in shares)	(55,659)
Vested and canceled (in shares)	(51,361)	[1]
Balance, Ending (in shares)	614,961
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning balance (in dollars per share)	$ 32.33
Weighted-Average Price, Granted (in dollars per share)	$ 31.69		$ 30.12
Weighted-Average Price, Vested and paid out (in dollars per share)	$ 39.07
Weighted-Average Price, Vested and canceled (in dollars per share)	$ 39.07
Weighted-Average Price, Ending Balance (in dollars per share)	$ 30.90
Unrecognized compensation cost	12.8
Weighted-average period for recognition of compensation costs	2 years 4 months 24 days
QEP Midstream Long-Term Incentive Plan [Member]
Weighted-Average Price [Abstract]
Share-based compensation	$ 0.4

[1] (1) Represents units that vested but were not paid out. Payout of the performance share units are dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period.

XML

Debt (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended	3 Months Ended
	Aug. 14, 2013	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Debt Instrument [Line Items]
Total principal amount of debt		$ 3,923.3		$ 3,001.8
Long-term debt issuance costs paid		(1.1)	0
Revolving credit facility origination fees	(3.0)
Less unamortized discount		(4.1)		(4.3)
Total long-term debt outstanding		3,919.2		2,997.5
Debt Maturity Period		5 years 0 months 0 days
Proceeds from Issuance of Long-term Debt		300.0	0
Principal amount of senior notes outstanding		2,221.8
Debt Instrument, Maturity Date Range, Start		Sep. 01, 2016
Debt Instrument, Maturity Date Range, End		May 01, 2023
Senior Notes, stated interest rate, minimum (in hundredths)		5.25%
Senior Notes, stated interest rate, maximim (in hundredths)		6.875%
Revolving Credit Facility due 2016 [Member]
Debt Instrument [Line Items]
Total principal amount of debt		1,101.5		480.0
Maturity date of long-term debt		Aug. 25, 2016
Borrowing capacity		1,500.0
Potential increased borrowing capacity		2,000.0
Number of maturity date extentions		2
Additional period with in which maturity to be extended		1 year
Weighted-average interest rate (in hundredths)		2.19%	2.35%
Amount outstanding		1,101.5
Letters of credit outstanding		3.8
QEP Midstream's Credit Facility [Member]
Debt Instrument [Line Items]
Total principal amount of debt		0		0
Maturity date of long-term debt		Aug. 14, 2018
Borrowing capacity		500.0
Potential increased borrowing capacity		750.0
Term Loan due 2017 [Member]
Debt Instrument [Line Items]
Total principal amount of debt		600.0		300.0
Maturity date of long-term debt		Apr. 18, 2017
Derivative Liability, Notional Amount		600.0
Additional period with in which maturity to be extended		1 year
Weighted-average interest rate (in hundredths)		1.59%	2.26%
6.05% Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Total principal amount of debt		176.8		176.8
Long-term debt, interest rate (in hundredths)		6.05%
Maturity date of long-term debt		Sep. 01, 2016
6.80% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Total principal amount of debt		134.0		134.0
Long-term debt, interest rate (in hundredths)		6.80%
Maturity date of long-term debt		Apr. 01, 2018
6.80% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Total principal amount of debt		136.0		136.0
6.875% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Total principal amount of debt		625.0		625.0
5.375% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Total principal amount of debt		500.0		500.0
5.25% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Total principal amount of debt		$ 650.0		$ 650.0

XML

Employee Benefits (Tables)

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefit Costs

	Pension
	Three Months Ended
	March 31,
	2014			2013
	(in millions)
Service cost	$	0.7		$	1.0
Interest cost	1.4			1.2
Expected return on plan assets	(1.2		)	(1.0		)
Amortization of prior service costs (1)	1.2			1.2
Amortization of actuarial losses (1)	0.2			0.6
Periodic expense	$	2.3		$	3.0

____________________________

⁽¹⁾  Amortization of prior service costs and actuarial losses out of AOCI are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."

	Postretirement Benefits
	Three Months Ended
	March 31,
	2014		2013
	(in millions)
Service cost	$	—	$	—
Interest cost	0.1		0.1
Amortization of prior service costs (1)	0.1		0.1
Periodic expense	$	0.2	$	0.2

____________________________

⁽¹⁾  Amortization of prior service costs out of AOCI are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."

XML

QEP Midstream (Tables)

3 Months Ended

Mar. 31, 2014

QEP Midstream [Abstract]

Schedule of Sale of Stock by Subsidiary or Equity Method Investee Disclosure [Table Text Block]

Total proceeds from the IPO	$	483.0
IPO Costs	(33.4		)
Net proceeds from the IPO	449.6
QEPM Revolving credit facility origination fees	(3.0		)
QEPM Repayment of outstanding debt with QEP	(95.5		)
Net proceeds distributed to QEP from the IPO	$	351.1

XML

Operations by Line of Business (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	57.80%
Revenues
Total Revenues	$ 883.9	$ 696.5
Operating expenses
Purchased gas, oil and NGL expense	224.3	196.8
Lease operating expense	55.3	40.1
Natural gas, oil and NGL transportation and other handling costs	43.4	32.8
Gathering, processing and other	25.8	20.6
General and administrative	56.6	46.0
Production and property taxes	49.3	35.9
Depreciation, depletion and amortization	240.2	254.2
Other operating expenses	4.2	5.1
Total Operating Expenses	699.1	631.5
Net (loss) gain from asset sales	2.4	(0.2)
Operating (loss) income	187.2	64.8
Realized and unrealized gains (losses) on derivative contracts	(80.9)	(34.6)
Interest and other income	2.9	2.0
Income from unconsolidated affiliates	2.2	1.3
Interest expense	(42.5)	(39.4)
Income (loss) before income taxes	68.9	(5.9)
Income taxes	(23.4)	2.2
Net (loss) income	45.5	(3.7)
Net income attributable to noncontrolling interest	(5.8)	(0.6)
Net income (loss) attributable to QEP	39.7	(4.3)
Assets	10,579.6	9,143.9	9,376.8
Unaffiliated customers [Member]
Revenues
Total Revenues	883.9	696.5
Affiliated customers [Member]
Revenues
Total Revenues	0	0
QEP Energy [Member]
Revenues
Total Revenues	613.2	508.2
Operating expenses
Purchased gas, oil and NGL expense	38.0	65.7
Lease operating expense	56.4	41.0
Natural gas, oil and NGL transportation and other handling costs	64.5	56.2
Gathering, processing and other	0	0
General and administrative	41.8	36.7
Production and property taxes	47.4	34.7
Depreciation, depletion and amortization	223.4	238.1
Other operating expenses	4.2	5.1
Total Operating Expenses	475.7	477.5
Net (loss) gain from asset sales	2.4	0.1
Operating (loss) income	139.9	30.8
Realized and unrealized gains (losses) on derivative contracts	(78.5)	(34.2)
Interest and other income	2.9	1.7
Income from unconsolidated affiliates	0	0
Interest expense	(48.9)	(45.3)
Income (loss) before income taxes	15.4	(47.0)
Income taxes	(5.9)	17.2
Net (loss) income	9.5	(29.8)
Net income attributable to noncontrolling interest	0	0
Net income (loss) attributable to QEP	9.5	(29.8)
Assets	9,004.1	7,756.8
QEP Energy [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	613.2	508.2
QEP Energy [Member] | Affiliated customers [Member]
Revenues
Total Revenues	0	0
QEP Field Services [Member]
Revenues
Total Revenues	106.2	92.0
Operating expenses
Purchased gas, oil and NGL expense	0	5.1
Lease operating expense	0	0
Natural gas, oil and NGL transportation and other handling costs	3.6	2.8
Gathering, processing and other	25.7	20.3
General and administrative	14.4	9.5
Production and property taxes	1.8	1.1
Depreciation, depletion and amortization	16.5	15.8
Other operating expenses	0	0
Total Operating Expenses	62.0	54.6
Net (loss) gain from asset sales	0	(0.3)
Operating (loss) income	44.2	37.1
Realized and unrealized gains (losses) on derivative contracts	0	0
Interest and other income	0	0.3
Income from unconsolidated affiliates	2.2	1.3
Interest expense	(0.6)	(4.0)
Income (loss) before income taxes	45.8	34.7
Income taxes	(14.6)	(12.5)
Net (loss) income	31.2	22.2
Net income attributable to noncontrolling interest	(5.8)	(0.6)
Net income (loss) attributable to QEP	25.4	21.6
Assets	1,515.5	1,660.6
QEP Field Services [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	79.8	64.4
QEP Field Services [Member] | Affiliated customers [Member]
Revenues
Total Revenues	26.4	27.6
QEP Marketing and Other [Member]
Revenues
Total Revenues	503.0	341.1
Operating expenses
Purchased gas, oil and NGL expense	497.9	342.5
Lease operating expense	0	0
Natural gas, oil and NGL transportation and other handling costs	0	0
Gathering, processing and other	0.4	0.3
General and administrative	1.2	1.0
Production and property taxes	0.1	0.1
Depreciation, depletion and amortization	0.3	0.3
Other operating expenses	0	0
Total Operating Expenses	499.9	344.2
Net (loss) gain from asset sales	0	0
Operating (loss) income	3.1	(3.1)
Realized and unrealized gains (losses) on derivative contracts	(2.4)	(0.4)
Interest and other income	48.8	51.2
Income from unconsolidated affiliates	0	0
Interest expense	(41.8)	(41.3)
Income (loss) before income taxes	7.7	6.4
Income taxes	(2.9)	(2.5)
Net (loss) income	4.8	3.9
Net income attributable to noncontrolling interest	0	0
Net income (loss) attributable to QEP	4.8	3.9
Assets	314.6	294.9
QEP Marketing and Other [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	190.9	123.9
QEP Marketing and Other [Member] | Affiliated customers [Member]
Revenues
Total Revenues	312.1	217.2
Elimination [Member]
Revenues
Total Revenues	(338.5)	(244.8)
Operating expenses
Purchased gas, oil and NGL expense	(311.6)	(216.5)
Lease operating expense	(1.1)	(0.9)
Natural gas, oil and NGL transportation and other handling costs	(24.7)	(26.2)
Gathering, processing and other	(0.3)	0
General and administrative	(0.8)	(1.2)
Production and property taxes	0	0
Depreciation, depletion and amortization	0	0
Other operating expenses	0	0
Total Operating Expenses	(338.5)	(244.8)
Net (loss) gain from asset sales		0
Operating (loss) income	0	0
Realized and unrealized gains (losses) on derivative contracts	0	0
Interest and other income	(48.8)	(51.2)
Income from unconsolidated affiliates	0	0
Interest expense	48.8	51.2
Income (loss) before income taxes	0	0
Income taxes	0	0
Net (loss) income	0	0
Net income attributable to noncontrolling interest	0	0
Net income (loss) attributable to QEP	0	0
Assets	(254.6)	(568.4)
Elimination [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	0	0
Elimination [Member] | Affiliated customers [Member]
Revenues
Total Revenues	$ (338.5)	$ (244.8)

XML

Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 3.9	$ 11.9	$ 0	$ 0
Cash and Cash Equivalents, Fair Value Disclosure	3.9	11.9
Financial liabilities
Derivative instruments - long-term	2.9	0
Fair Value, Measurements, Recurring [Member]
Financial Assets
Total financial assets	3.9	1.2
Financial liabilities
Total financial liabilities	74.7	26.7
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	0	0.2
Derivative instruments - long-term	1.1	0.4
Financial liabilities
Derivative instruments - short-term	67.1	24.1
Derivative instruments - long-term	2.9	0.6
Fair Value, Measurements, Recurring [Member] | Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	2.8
Financial liabilities
Derivative instruments - short-term	4.7	2.6
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member]
Financial liabilities
Checks outstanding in excess of cash balances	78.4	90.9
Long-term debt	3,919.2	2,997.5
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Financial Assets
Total financial assets	0	0
Financial liabilities
Total financial liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	0	0
Derivative instruments - long-term	0	0
Financial liabilities
Derivative instruments - short-term	0	0
Derivative instruments - long-term	0	0
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	0
Financial liabilities
Derivative instruments - short-term	0	0
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Fair Value [Member]
Financial liabilities
Checks outstanding in excess of cash balances	78.4	90.9
Long-term debt	4,018.0	3,034.9
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Financial Assets
Total financial assets	9.2	6.5
Financial liabilities
Total financial liabilities	80.0	32.0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	5.9	5.5
Derivative instruments - long-term	0.5	0.4
Financial liabilities
Derivative instruments - short-term	73.0	29.4
Derivative instruments - long-term	2.3	0.6
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	2.8
Financial liabilities
Derivative instruments - short-term	4.7	2.6
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial Assets
Total financial assets	0	0
Financial liabilities
Total financial liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	0	0
Derivative instruments - long-term	0	0
Financial liabilities
Derivative instruments - short-term	0	0
Derivative instruments - long-term	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	0
Financial liabilities
Derivative instruments - short-term	0	0
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member]
Financial Assets
Total financial assets	(5.3)	(5.3)
Financial liabilities
Total financial liabilities	(5.3)	(5.3)
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member] | Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	(5.9)	(5.3)
Derivative instruments - long-term	0.6	0
Financial liabilities
Derivative instruments - short-term	(5.9)	(5.3)
Derivative instruments - long-term	0.6	0
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member] | Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	0
Financial liabilities
Derivative instruments - short-term	$ 0	$ 0

XML

Acquisitions & Divestitures Supplemental Proforma Results of Operations (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Business Acquisition [Line Items]
Total Revenues	$ 883.9	$ 696.5
Net Income (Loss) Attributable to Parent	39.7	(4.3)
Earnings Per Share, Basic	$ 0.22	$ (0.02)
Earnings Per Share, Diluted	$ 0.22	$ (0.02)
Business Acquisition, Pro Forma Revenue	910.0	731.0
Business Acquisition, Pro Forma Net Income (Loss)	$ 46.7	$ 3.6
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 0.26	$ 0.02
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 0.26	$ 0.02

XML

Schedule of Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Accrual for Environmental Loss Contingencies	$ 0.2
Deferred Revenue		$ 9.9

XML

Basis of Presentation of Interim Consolidated Financial Statements

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation of Interim Consolidated Financial Statements

Basis of Presentation of Interim Consolidated Financial Statements

The interim condensed consolidated financial statements contain the accounts of QEP and its majority-owned or controlled subsidiaries, including QEP Midstream (see Note 4 - QEP Midstream). The condensed consolidated financial statements also include the accounts of a variable interest entity where the Company is the primary beneficiary of the arrangements. 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, 2013.

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 months endedMarch 31, 2014, are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

Reclassifications

In the first quarter of 2013, QEP presented certain credit facility payments and borrowings on a net basis on the Condensed Consolidated Statements of Cash Flow. These borrowings and payments were reclassified to be presented on a gross basis on the Condensed Consolidated Statement of Cash Flow in order to conform with the current period presentation. This reclassification is entirely within "Financing Activities" and has no effect on other categories or total cash on the Condensed Consolidated Statements of Cash Flows or net income or earnings per share on the Condensed Consolidated Statements of Operations.

New accounting pronouncements

During the three months ended March 31, 2014, there were no new accounting pronouncements that were applicable to QEP.

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Derivative Contracts (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Forecasted production from proved reserves (in hundredths)	100.00%
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ 0	[1]	$ 20.1	[1]
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross	9.2				6.5
Derivative Liability, Fair Value, Gross	80.0				32.0
Commodity Contract [Member] | Short-term [Member]
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross					5.5
Derivative Liability, Fair Value, Gross	73.0				29.4
Commodity Contract [Member] | Long-term [Member]
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross					0.4
Derivative Liability, Fair Value, Gross	2.3				0
Interest Rate Swap [Member] | Short-term [Member]
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross	0				0
Derivative Liability, Fair Value, Gross	4.7				2.6
Interest Rate Swap [Member] | Long-term [Member]
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross					0.6
Derivative Liability, Fair Value, Gross	0				0
Interest Rate Swap [Member] | QEP Resources [Member]
Derivative Contracts - Volumes and Prices
Maturity	Mar. 31, 2017
Fixed Rate Paid (in hundredths)	0.96%
Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2014 [Member] | NYMEX [Member]
Derivatives, Fair Value [Line Items]
Year	2014
Index	NYMEX
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	22,000,000
Average Swap price per unit ($ per unit)	4.22
Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2014 [Member] | IFNPCR [Member]
Derivatives, Fair Value [Line Items]
Year	2014
Index	IFNPCR
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	60,500,000
Average Swap price per unit ($ per unit)	4.08
Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2015 [Member] | NYMEX [Member]
Derivatives, Fair Value [Line Items]
Year	2015
Index	NYMEX
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	25,600,000
Average Swap price per unit ($ per unit)	4.14
Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2015 [Member] | IFNPCR [Member]
Derivatives, Fair Value [Line Items]
Year	2015
Index	IFNPCR
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	7,300,000
Average Swap price per unit ($ per unit)	3.97
Swap [Member] | Oil Sales (Bbls) [Member] | 2014 [Member] | NYMEX WTI less ICE Brent Differential [Member]
Derivatives, Fair Value [Line Items]
Year	2014
Index	ICE Brent
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	600,000
Average Swap price per unit ($ per unit)	13.78
Swap [Member] | Oil Sales (Bbls) [Member] | 2014 [Member] | NYMEX WTI [Member]
Derivatives, Fair Value [Line Items]
Year	2014
Index	NYMEX WTI
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	8,100,000
Average Swap price per unit ($ per unit)	92.61
Swap [Member] | Oil Sales (Bbls) [Member] | 2014 [Member] | NYMEX WTI less LLS Differential [Member]
Derivatives, Fair Value [Line Items]
Index	LLS
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	500,000
Average Swap price per unit ($ per unit)	4.00
Swap [Member] | Oil Sales (Bbls) [Member] | 2015 [Member] | NYMEX WTI less ICE Brent Differential [Member]
Derivatives, Fair Value [Line Items]
Year	2015
Swap [Member] | Oil Sales (Bbls) [Member] | 2015 [Member] | NYMEX WTI [Member]
Derivatives, Fair Value [Line Items]
Index	NYMEX WTI
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	4,000,000
Average Swap price per unit ($ per unit)	87.64
Swap [Member] | Oil Sales (Bbls) [Member] | 2015 [Member] | BRENT ICE [Member]
Derivatives, Fair Value [Line Items]
Year	2015
Swap [Member] | Oil Sales (Bbls) [Member] | 2015 [Member] | NYMEX WTI less LLS Differential [Member]
Derivatives, Fair Value [Line Items]
Index	LLS
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	100,000
Average Swap price per unit ($ per unit)	4.00
Swap [Member] | QEP Marketing [Member] | 2014 [Member] | IFNPCR [Member]
Derivatives, Fair Value [Line Items]
Year	2014
Index	IFNPCR
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	2,900,000
Average Swap price per unit ($ per unit)	3.75
Swap [Member] | Purchased Gas and Oil Expense [Member] | 2014 [Member] | IFNPCR [Member]
Derivatives, Fair Value [Line Items]
Year	2014
Index	IFNPCR
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	900,000
Average Swap price per unit ($ per unit)	3.82
Term Loan due 2017 [Member]
Derivatives, Fair Value [Line Items]
Debt Instrument, Interest Rate, Effective Percentage	2.96%
First Term Loan Tranche [Member] | Interest Rate Swap [Member]
Derivative Contracts - Volumes and Prices
Variable Rate Received	One-month LIBOR
First Term Loan Tranche [Member] | Interest Rate Swap [Member] | QEP Resources [Member]
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Notional amount of interest rate derivatives	300.0
Derivative Contracts - Volumes and Prices
Notional amount of interest rate derivatives	300.0
Fixed Rate Paid (in hundredths)	1.07%
Second Term Loan Tranche [Member] | Interest Rate Swap [Member]
Derivative Contracts - Volumes and Prices
Variable Rate Received	One-month LIBOR
Second Term Loan Tranche [Member] | Interest Rate Swap [Member] | QEP Resources [Member]
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Notional amount of interest rate derivatives	300.0
Derivative Contracts - Volumes and Prices
Notional amount of interest rate derivatives	$ 300.0
Maturity	Mar. 31, 2017
Fixed Rate Paid (in hundredths)	0.86%

[1] Presented net of income tax benefit of $11.9 million during the three months ended March 31, 2013

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Derivative Contracts (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Volumes and Average Prices

QEP Energy Derivative Contracts

The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative contracts as of March 31, 2014: 

Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	NYMEX	22.0	$	4.22
2014	SWAP	IFNPCR	60.5	$	4.08
2015	SWAP	NYMEX	25.6	$	4.14
2015	SWAP	IFNPCR	7.3	$	3.97
Oil sales			(Bbls)
2014	SWAP	NYMEX WTI	8.1	$	92.61
2015	SWAP	NYMEX WTI	4.0	$	87.64

The following table sets forth QEP Energy's oil basis swaps as of March 31, 2014:

Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
Oil basis swaps			(Bbls)
2014	NYMEX WTI	ICE Brent	0.6	$	13.78
2014	NYMEX WTI	LLS	0.5	$	4.00
2015	NYMEX WTI	LLS	0.1	$	4.00

QEP Marketing Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage and for marketing transactions in which QEP Marketing sells gas volumes at a fixed price. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of March 31, 2014:

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	IFNPCR	2.9	$	3.75
Gas purchases			(MMBtu)
2014	SWAP	IFNPCR	0.9	$	3.82

QEP's Derivative Contracts

The following table sets forth QEP’s notional amount and interest rate for its interest rate swaps outstanding as of March 31, 2014:

Notional amount	Type of Contract	Maturity	Fixed Rate Paid	Variable Rate Received
(in millions)
$300.0	Swap	March 2017	1.07%	One-month LIBOR
$300.0	Swap	March 2017	0.86%	One-month LIBOR
$600.0			0.96%

Fair values of Derivatives by Balance Sheet Location

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	March 31, 2014		December 31, 2013		March 31, 2014		December 31, 2013
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	5.9	$	5.5	$	73.0	$	29.4
Interest rate swaps	Fair value of derivative contracts	—		—		4.7		2.6
Long-term:
Commodity	Fair value of derivative contracts	0.5		0.4		2.3		—
Interest rate swaps	Fair value of derivative contracts	2.8		0.6		—		—
Total derivative instruments		$	9.2	$	6.5	$	80.0	$	32.0

Effects of Derivative Transactions

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

	Three Months Ended
Derivative instruments not designated as cash flow hedges	March 31,
	2014			2013
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	(20.4	)	$	44.6
Oil derivative contracts	(12.9		)	5.2
QEP Marketing
Gas derivative contracts	(1.4		)	1.5
Total realized (losses) gains on commodity derivative contracts	(34.7		)	51.3
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	(24.3		)	(64.3		)
Oil derivative contracts	(20.9		)	(19.7		)
QEP Marketing
Gas derivative contracts	(0.3		)	(1.7		)
Total unrealized losses on commodity derivative contracts	(45.5		)	(85.7		)
Total realized and unrealized losses on commodity derivative contracts	$	(80.2	)	$	(34.4	)
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(0.7	)	$	(0.6	)
Unrealized gains (losses) on interest rate swaps
Unrealized (losses) gains on interest rate swaps	—			0.4
Total realized and unrealized losses on interest rate swaps	$	(0.7	)	$	(0.2	)
Total net realized (losses) gains on derivative contracts	$	(35.4	)	$	50.7
Total net unrealized losses on derivative contracts	(45.5		)	(85.3		)
Grand Total	$	(80.9	)	$	(34.6	)

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair value of financial assets and liabilities

The fair value of financial assets and liabilities at March 31, 2014, is shown in the table below:

	Fair Value Measurements
	March 31, 2014
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.9	$	—	$	(5.9	)	$	—
Commodity derivative instruments - long-term	—		0.5		—		0.6			1.1
Interest rate swaps - long-term	—		2.8		—		—			2.8
Total financial assets	$	—	$	9.2	$	—	$	(5.3	)	$	3.9
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	73.0	$	—	$	(5.9	)	$	67.1
Interest rate swaps - short-term	—		4.7		—		—			4.7
Commodity derivative instruments - long-term	—		2.3		—		0.6			2.9
Total financial liabilities	$	—	$	80.0	$	—	$	(5.3	)	$	74.7

____________________________

⁽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 8 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

The fair value of financial assets and liabilities at December 31, 2013, is shown in the table below:

	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.5	$	—	$	(5.3	)	$	0.2
Commodity derivative instruments - long-term	—		0.4		—		—			0.4
Interest rate swaps - long-term	—		0.6		—		—			0.6
Total financial assets	$	—	$	6.5	$	—	$	(5.3	)	$	1.2
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	29.4	$	—	$	(5.3	)	$	24.1
Interest rate swaps - short-term	—		2.6		—		—			2.6
Total financial liabilities	$	—	$	32.0	$	—	$	(5.3	)	$	26.7

Fair value and related carrying amount of certain financial instruments

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to 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
	March 31, 2014				December 31, 2013
	(in millions)
Financial assets
Cash and cash equivalents	$	3.9	$	3.9	$	11.9	$	11.9
Financial liabilities
Checks outstanding in excess of cash balances	$	78.4	$	78.4	$	90.9	$	90.9
Long-term debt	$	3,919.2	$	4,018.0	$	2,997.5	$	3,034.9

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Derivative Contracts - Gain (Loss) in Statement of Financial Performance (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) derivative contracts not designated as hedging instruments	$ (35.4)	$ 50.7
Unrealized gain (loss) derivative contracts not designated as hedging instruments	(45.5)	(85.3)
Total gain (loss) on commodity derivative instruments	(80.9)	(34.6)
Natural gas derivative contracts [Member] | QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(20.4)	44.6
Unrealized gain (loss) on commodity derivative contracts	(24.3)	(64.3)
Natural gas derivative contracts [Member] | QEP Marketing [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(1.4)	1.5
Unrealized gain (loss) on commodity derivative contracts	(0.3)	(1.7)
Oil derivative contracts [Member] | QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(12.9)	5.2
Unrealized gain (loss) on commodity derivative contracts	(20.9)	(19.7)
Interest Rate Swap [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(0.7)	(0.6)
Unrealized gain (loss) on commodity derivative contracts	0	0.4
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	(0.7)	(0.2)
Realized and unrealized gains on commodity derivative instruments [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(34.7)	51.3
Unrealized gain (loss) on commodity derivative contracts	(45.5)	(85.7)
Total gain (loss) on commodity derivative instruments	$ (80.2)	$ (34.4)

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Restructuring Costs (Tables)

3 Months Ended

Mar. 31, 2014

Restructuring Costs [Abstract]

Reconciliation of QEP Energy's restructuring cost

	Total Restructuring Costs
	Total Expected to be Incurred		Recognized in Income
			Period from Inception to March 31, 2014		Three Months Ended March 31,
					2014		2013
QEP Energy	(in millions)
One-time termination benefits	$	3.3	$	3.3	$	—	$	0.2
Retention & relocation expense	3.7		3.7		—		0.1
Lease termination costs	0.6		0.6		—		—
Total restructuring costs	$	7.6	$	7.6	$	—	$	0.3
QEP Field Services
One-time termination benefits	$	—	$	—	$	—	$	—
Retention & relocation expense	10.1		3.2		2.3		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	10.1	$	3.2	$	2.3	$	—
QEP Marketing
One-time termination benefits	$	0.3	$	0.3	$	—	$	0.1
Retention & relocation expense	—		—		—		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	0.3	$	0.3	$	—	$	0.1
Total QEP
One-time termination benefits	$	3.6	$	3.6	$	—	$	0.3
Retention & relocation expense	13.8		6.9		2.3		0.1
Lease termination costs	0.6		0.6		—		—
Total restructuring costs	$	18.0	$	11.1	$	2.3	$	0.4

Schedule of Restructuring Reserve by Type of Cost [Table Text Block]

	QEP Energy		QEP Field Services		QEP Marketing		Total
	(in millions)
Balance at December 31, 2013	$	—	$	0.8	$	—	$	0.8
Costs incurred and charged to expense	—		2.3		—		2.3
Costs paid or otherwise settled	—		—		—		—
Balance at March 31, 2014	$	—	3.1		—		$	3.1

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Debt (Tables)

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Debt Outstanding

As of the indicated dates, the principal amount of QEP’s debt, including amounts outstanding under its and QEP Midstream's revolving credit facilities, QEP's term loan and QEP's senior notes consisted of the following:

	March 31, 2014			December 31, 2013
	(in millions)
QEP's revolving credit facility due 2016	$	1,101.5		$	480.0
QEP Midstream's revolving credit facility due 2018	—			—
Term loan due 2017	600.0			300.0
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
Total principal amount of debt	3,923.3			3,001.8
Less unamortized discount	(4.1		)	(4.3		)
Total long-term debt outstanding	$	3,919.2		$	2,997.5

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Nature of Business

3 Months Ended

Mar. 31, 2014

Nature Of Business [Abstract]

Nature of Business

Nature of Business

QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business: oil and gas exploration and production; midstream field services; and energy marketing. These businesses are conducted through the Company’s three principal subsidiaries:

• QEP Energy Company (QEP Energy) acquires, explores for, develops and produces gas, oil, and NGL;

• QEP Field Services Company (QEP Field Services), which includes the ownership and operations of QEP Midstream Partners, LP (QEP Midstream), provides midstream field services, including gathering of natural gas, oil and water, natural gas processing, compression, and treating services, as well as NGL marketing services for affiliates and third parties; and

• QEP Marketing Company (QEP Marketing) markets affiliate and third-party oil and gas, and owns and operates an underground gas storage reservoir.

QEP's operations are focused in two major regions: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Oklahoma, Louisiana, and Texas) of the United States. QEP's corporate headquarters are located in Denver, Colorado.

Shares of QEP’s common stock trade on the New York Stock Exchange under the ticker symbol “QEP.”

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Equity-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2014

Share-based Compensation [Abstract]

Schedule of calculated fair value of options granted and major assumptions used

	Stock Option Assumptions
	Three Months Ended
	March 31, 2014
Weighted-average grant-date fair value of awards granted during the period	$	10.12
Weighted-average risk-free interest rate	1.31		%
Weighted-average expected price volatility	37.2		%
Expected dividend yield	0.25		%
Expected term in years at the date of grant	4.5

Summary of stock option transactions under the terms of LTSIP

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, 2013	1,794,187		$	27.90
Granted	279,458		31.67
Exercised	(29,479	)	23.01
Outstanding at March 31, 2014	2,044,166		$	28.49	3.91	$	5.2
Options Exercisable at March 31, 2014	1,480,337		$	27.56	3.02	$	5.1
Unvested Options at March 31, 2014	563,829		$	30.93	6.24	$	0.1

Restricted Share Units Activity

	Restricted Shares Outstanding		Weighted- Average Grant-Date Fair Value
			(per share)
Unvested balance at December 31, 2013	1,388,953		$	30.96
Granted	844,552		31.69
Vested	(524,672	)	31.89
Forfeited	(18,170	)	31.28
Unvested balance at March 31, 2014	1,690,663		$	31.03

Schedule of Performance Share Units Activity

	Performance Share Units Outstanding		Weighted- Average Grant-Date Fair Value
Unvested balance at December 31, 2013	480,660		$	32.33
Granted	241,321		31.69
Vested and paid out	(55,659	)	39.07
Vested and canceled (1)	(51,361	)	39.07
Unvested balance at March 31, 2014	614,961		$	30.90

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Earnings Per Share (Details) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Earnings Per Share [Abstract]
Anti-dilutive shares not included in diluted common share outstanding (in shares)	0	0.3
Weighted-average basic common shares outstanding (in shares)	179.7	177.0
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan	0.3	0
Average diluted common shares outstanding (in shares)	180.0	177.0

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
REVENUES
Natural gas sales	$ 222.5	$ 197.6
Oil sales	288.7	194.2
NGL sales	101.1	68.4
Gathering, processing and other	44.4	45.6
Purchased gas, oil and NGL sales	227.2	190.7
Total Revenues	883.9	696.5
OPERATING EXPENSES
Purchased gas, oil and NGL expense	224.3	196.8
Lease operating expense	55.3	40.1
Natural gas, oil and NGL transportation and other handling costs	43.4	32.8
Gathering, processing and other	25.8	20.6
General and administrative	56.6	46.0
Production and property taxes	49.3	35.9
Depreciation, depletion and amortization	240.2	254.2
Exploration expenses	2.2	5.1
Impairment	2.0	0
Total Operating Expenses	699.1	631.5
Net (loss) gain from asset sales	2.4	(0.2)
OPERATING INCOME	187.2	64.8
Realized and unrealized losses on derivative contracts (See Note 8)	(80.9)	(34.6)
Interest and other income	2.9	2.0
Income from unconsolidated affiliates	2.2	1.3
Interest expense	(42.5)	(39.4)
(LOSS) INCOME BEFORE INCOME TAXES	68.9	(5.9)
Income tax benefit (provision)	(23.4)	2.2
NET (LOSS) INCOME	45.5	(3.7)
Net income attributable to noncontrolling interest	(5.8)	(0.6)
NET (LOSS) INCOME ATTRIBUTABLE TO QEP	$ 39.7	$ (4.3)
Earnings Per Common Share Attributable to QEP
Earnings Per Share, Basic	$ 0.22	$ (0.02)
Earnings Per Share, Diluted	$ 0.22	$ (0.02)
Weighted-average common shares outstanding
Used in basic calculation (in shares)	179.7	177.0
Used in diluted calculation (in shares)	180.0	177.0
Dividends per common share (in dollars per share)	$ 0.02	$ 0.02

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Restructuring Costs (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	$ 18.0
Restructuring and Related Cost, Cost Incurred to Date	11.1
Restructuring Charges	2.3	0.4
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at Beginning of Period	0.8
Restructuring Reserve, Accrual Adjustment	2.3
Costs paid or otherwise settled	0
Balance at End of Period	3.1
Number of regional offices created	1
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.6
Restructuring and Related Cost, Cost Incurred to Date	3.6
Restructuring Charges	0	0.3
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	13.8
Restructuring and Related Cost, Cost Incurred to Date	6.9
Restructuring Charges	2.3	0.1
Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.6
Restructuring and Related Cost, Cost Incurred to Date	0.6
Restructuring Charges	0	0
QEP Energy [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	7.6
Restructuring and Related Cost, Cost Incurred to Date	7.6
Restructuring Charges	0	0.3
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at Beginning of Period	0
Restructuring Reserve, Accrual Adjustment	0
Costs paid or otherwise settled	0
Balance at End of Period	0
QEP Energy [Member] | One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.3
Restructuring and Related Cost, Cost Incurred to Date	3.3
Restructuring Charges	0	0.2
QEP Energy [Member] | Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.7
Restructuring and Related Cost, Cost Incurred to Date	3.7
Restructuring Charges	0	0.1
QEP Energy [Member] | Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.6
Restructuring and Related Cost, Cost Incurred to Date	0.6
Restructuring Charges	0	0
QEP Field Services [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	10.1
Restructuring and Related Cost, Cost Incurred to Date	3.2
Restructuring Charges	2.3	0
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at Beginning of Period	0.8
Restructuring Reserve, Accrual Adjustment	2.3
Costs paid or otherwise settled	0
Balance at End of Period	3.1
QEP Field Services [Member] | One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0
Restructuring and Related Cost, Cost Incurred to Date	0
Restructuring Charges	0	0
QEP Field Services [Member] | Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	10.1
Restructuring and Related Cost, Cost Incurred to Date	3.2
Restructuring Charges	2.3	0
QEP Field Services [Member] | Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0
Restructuring and Related Cost, Cost Incurred to Date	0
Restructuring Charges	0	0
QEP Marketing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.3
Restructuring and Related Cost, Cost Incurred to Date	0.3
Restructuring Charges	0	0.1
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at Beginning of Period	0
Restructuring Reserve, Accrual Adjustment	0
Costs paid or otherwise settled	0
Balance at End of Period	0
QEP Marketing [Member] | One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.3
Restructuring and Related Cost, Cost Incurred to Date	0.3
Restructuring Charges	0	0.1
QEP Marketing [Member] | Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0
Restructuring and Related Cost, Cost Incurred to Date	0
Restructuring Charges	0	0
QEP Marketing [Member] | Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0
Restructuring and Related Cost, Cost Incurred to Date	0
Restructuring Charges	$ 0	$ 0

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
EQUITY
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500	500
Common stock, shares issued (in shares)	180.7	179.7
Treasury stock (in shares)	0.6	0.4

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Acquisitions & Divestitures (Narrative) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended
	Mar. 31, 2014 acre	Mar. 31, 2014 acre	Mar. 31, 2013
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 945.0
Net acres of producing and undeveloped oil and gas properties	26,500	26,500
Number of vertical producing wells	270	270
Escrow Deposit	50.0	50.0
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	14.9
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	3.7
Business Acquisition, Transaction Costs	0.5	0.5
Long-term debt issuance costs paid		(1.1)	0
Revolving Credit Facility due 2016 [Member]
Business Acquisition [Line Items]
Borrowings to Fund Acquisition		595.0
Term Loan due 2017 [Member]
Business Acquisition [Line Items]
Borrowings to Fund Acquisition		300.0
Permian Basin [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 945.0

XML

Subsequent Event

3 Months Ended

Mar. 31, 2014

Subsequent Event [Abstract]

Subsequent Events

Subsequent Events

QEP Energy Divestitures

In May 2014, QEP Energy entered into three separate purchase and sale agreements related to the disposition of certain of its non-core properties in the Midcontinent Region and other non-core assets in the Northern Region for an aggregate sales price of approximately $807.5 million, subject to customary purchase price adjustments. The aggregate net book value of the properties being sold is approximately $886.0 million as of the effective date of the sale, January 1, 2014. Any gain or loss on the sale recorded by the Company will be determined based upon the final purchase price, which is subject to customary purchase price adjustments. The Company expects to close these transactions in the second quarter of 2014 and will use proceeds to repay indebtedness under our revolving credit facility.

QEP Field Services Divestiture

In May 2014, QEP Field Services entered into a purchase and sale agreement to sell 40% of the membership interests in Green River Processing, LLC (Green River Processing) for approximately $230.0 million, subject to customary purchase price adjustments, to QEP Midstream. The transaction is expected to close in July 2014 and will be accounted for as a transaction between entities under common control with the difference between the carrying amount and the purchase price recorded to equity.

Green River Processing is a wholly owned subsidiary of QEP Field Services and will own the Blacks Fork processing complex and the Emigrant Trail processing plant, both of which are located in southwest Wyoming. The combined processing capacity of Green River Processing is 890 MMcf per day, of which 560 MMcf per day is cryogenic capacity and 330 MMcf per day is Joule-Thomson processing capacity. In addition, there is 15,000 bbl per day of NGL fractionation capacity at the Blacks Fork processing complex.

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Acquisitions & Divestitures (Schedule Of Purchase Accounting Entries) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Significant Acquisitions and Disposals [Line Items]
Payments to Acquire Businesses, Gross	$ 945.0
Fair value of assets acquired (liabilities assumed)	945.0
Proved Property [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	516.1
Unproved Property [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	439.7
Asset Retirement Obligation Costs [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	(9.7)
Other Liabilities [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	(1.1)
Permian Basin [Member]
Significant Acquisitions and Disposals [Line Items]
Payments to Acquire Businesses, Gross	$ 945.0

XML

Acquisitions & Divestitures (Tables)

3 Months Ended

Mar. 31, 2014

Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]

Business Combination, Separately Recognized Transactions [Table Text Block]

	As of March 31, 2014
	(in millions)
Consideration given:
Cash consideration	$	945.0
Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
Proved properties	$	516.1
Unproved properties	439.7
Asset retirement obligations	(9.7		)
Liabilities assumed	(1.1		)
Total fair value	$	945.0

Business Acquisition, Pro Forma Information [Table Text Block]

	Three Months Ended				Three Months Ended
	March 31, 2014				March 31, 2013
	Actual		Pro forma		Actual			Pro forma
	(in millions, except per share data)
Revenues	$	883.9	$	910.0	$	696.5		$	731.0
Net income attributable to QEP	39.7		46.7		(4.3		)	3.6
Earnings per common share attributable to QEP
Basic	$	0.22	$	0.26	$	(0.02	)	$	0.02
Diluted	0.22		0.26		(0.02		)	0.02

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
OPERATING ACTIVITIES
Net (loss) income	$ 45.5	$ (3.7)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	240.2	254.2
Deferred income taxes	20.7	(9.3)
Impairment	2.0	0
Share-based compensation	6.8	6.1
Amortization of debt issuance costs and discounts	1.7	1.5
Net gain from asset sales	(2.4)	0.2
Income from unconsolidated affiliates	(2.2)	(1.3)
Distributions from unconsolidated affiliates and other	2.7	1.5
Unrealized loss (gain) on derivative contracts	45.5	85.3
Changes in operating assets and liabilities	(38.1)	(162.4)
Net Cash Provided by Operating Activities	322.4	172.1
INVESTING ACTIVITIES
Property acquisitions	(946.6)	(23.6)
Property, plant and equipment, including dry exploratory well expense	(330.2)	(361.0)
Proceeds from disposition of assets	2.9	1.5
Escrow Deposit Disbursements Related to Property Acquisition	50.0	0
Net Cash Used in Investing Activities	(1,223.9)	(383.1)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(12.5)	60.0
Long-term debt issued	300.0	0
Long-term debt issuance costs paid	(1.1)	0
Proceeds from credit facility	1,643.0	1,027.0
Repayments of credit facility	(1,021.5)	(866.5)
Payments for Repurchase of Common Stock	(5.5)	(7.5)
Other capital contributions	2.9	2.1
Dividends paid	(3.6)	(3.6)
Excess tax benefit on share-based compensation	(0.6)	1.0
Distribution to noncontrolling interest	(7.6)	(1.5)
Net Cash Provided by Financing Activities	893.5	211.0
Change in cash and cash equivalents	(8.0)	0
Beginning cash and cash equivalents	11.9	0
Ending cash and cash equivalents	3.9	0
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	43.8	40.7
Cash paid (received) for income taxes	0	4.9
Non-cash investing activities
Change in capital expenditure accrual balance	$ (11.6)	$ 42.6

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
Net (loss) income	$ 45.5		$ (3.7)
Other comprehensive (loss) income, net of tax:
Reclassification of previously deferred derivative gains(1)	0	[1]	(20.1)	[1]
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss	0.1	[2]	0.4	[2]
Amortization of prior service cost	0.9	[3]	0.8	[3]
Total pension and other postretirement plans adjustments	1.0		1.2
Other comprehensive loss	1.0		(18.9)
Comprehensive (loss) income	46.5		(22.6)
Comprehensive income attributable to noncontrolling interests	(5.8)		(0.6)
Comprehensive (loss) income attributable to QEP	$ 40.7		$ (23.2)

[1] Presented net of income tax benefit of $11.9 million during the three months ended March 31, 2013

[2] Presented net of income tax expense of $0.1 million during the three months ended March 31, 2014 and $0.2 million during the three months ended March 31, 2013, respectively.

[3] Presented net of income tax expense of $0.4 million during the three months ended March 31, 2014 and $0.5 million during the three months ended March 31, 2013, respectively.

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Debt

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Debt

Debt

As of the indicated dates, the principal amount of QEP’s debt, including amounts outstanding under its and QEP Midstream's revolving credit facilities, QEP's term loan and QEP's senior notes consisted of the following:

	March 31, 2014			December 31, 2013
	(in millions)
QEP's revolving credit facility due 2016	$	1,101.5		$	480.0
QEP Midstream's revolving credit facility due 2018	—			—
Term loan due 2017	600.0			300.0
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
Total principal amount of debt	3,923.3			3,001.8
Less unamortized discount	(4.1		)	(4.3		)
Total long-term debt outstanding	$	3,919.2		$	2,997.5

Of the total debt outstanding on March 31, 2014, amounts outstanding under QEP's revolving credit facility due August 25, 2016, QEP Midstream's revolving credit facility due August 14, 2018, QEP's term loan due April 18, 2017, the 6.05% Senior Notes due September 1, 2016, and the 6.80% Senior Notes due April 1, 2018, will mature within the next five years.

Credit Facilities

QEP's Credit Facility

QEP’s unsecured revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a syndicate of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit facility also contains an accordion provision that would allow for the amount of the facility to be increased to $2.0 billion and a provision whereby the maturity can be extended for up to two additional one-year periods, with the agreement of the lenders.

During the three months endedMarch 31, 2014 and 2013, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.19% and 2.35%, respectively. At March 31, 2014 and December 31, 2013, QEP was in compliance with the covenants under the credit agreement. At March 31, 2014, there was $1,101.5 million outstanding and $3.8 million of letters of credit issued under the credit facility.

QEP Midstream's Credit Facility

On August 14, 2013, QEP Midstream entered into a $500.0 million senior secured revolving credit facility with a group of financial institutions, which matures on August 14, 2018. QEP Midstream's credit facility contains an accordion provision that allows for the amount of the facility to be increased to $750.0 million with the agreement of the lenders. QEP Midstream's credit facility is available for QEP Midstream's working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of QEP Midstream's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries, are pledged as collateral under the credit facility. In addition, the credit agreement contains restrictions and events of default customary for agreements of this nature.

There have been no borrowings under QEP Midstream's credit facility, and at March 31, 2014, and December 31, 2013, QEP Midstream was in compliance with the covenants under the QEP Midstream credit agreement.

QEP is not a borrower or guarantor of QEP Midstream's credit facility. In addition, QEP is not subject to any of the restrictions or covenants contained in QEP Midstream's credit agreement. Outstanding indebtedness under QEP Midstream's credit facility is not included in the definition of indebtedness under QEP's credit agreement.

Term Loan

QEP's $600.0 million unsecured term loan facility provides for borrowings at short-term interest rates and contains covenants, restrictions, and interest rates that are substantially the same as QEP’s revolving credit facility. The term loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. In conjunction with the Permian Basin Acquisition, QEP borrowed the incremental $300.0 million available under the facility and increased total borrowings under the term loan to $600.0 million. There were no changes to the maturity date, pricing or covenants in the credit agreement. QEP incurred $1.1 million of debt issuance costs associated with the new term loan issuance.

During the three months endedMarch 31, 2014 and 2013, QEP’s weighted-average interest rate on borrowings from the term loan was 1.59% and 2.26%, respectively. At March 31, 2014 and December 31, 2013, QEP was in compliance with the covenants under the term loan credit agreement.

Senior Notes

At March 31, 2014, 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 some or 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.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	QEP RESOURCES, INC.
Entity Central Index Key	0001108827
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	180,070,357
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014

XML

Contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Contingencies

Note 11 - Contingencies

QEP is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. QEP assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated 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 could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, QEP may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matter. QEP's litigation loss contingencies are discussed below. QEP is unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. QEP believes, however, that the resolution of pending proceedings (after accruals and insurance coverage) will not be material to QEP's financial position, but could be material to results of operations in a particular quarter or year.

Environmental Claims

In October 2009, QEP received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from unpermitted work resulting in the discharge of dredged and/or fill material into waters of the United States at three sites located in Caddo and Red River Parishes, Louisiana. Region 6 of the U.S. Environmental Protection Agency (EPA) has assumed lead responsibility for enforcement of the cease and desist order and any possible future orders for the removal of unauthorized fills and/or civil penalties under the Clean Water Act. On June 28, 2013, the EPA issued to QEP an Administrative Complaint for the alleged violations. QEP and the EPA reached an agreement to settle the alleged violations through an Administrative Order, under the terms of which QEP paid an administrative penalty of $0.2 million. The Administrative Order is final. In 2012, QEP completed a field audit, which identified 112 additional instances affecting approximately 90 acres where work may have been conducted in violation of the Clean Water Act. QEP has disclosed each of these instances to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. QEP is working with the EPA and the COE to resolve these matters, which will require the Company to undertake certain mitigation and permitting activities, and may require QEP to pay a monetary penalty.

In July 2010, QEP received a Notice of Potential Penalty (NOPP) from the Louisiana Department of Environmental Quality (LDEQ) regarding the assumption of ownership and operatorship of a single facility in Louisiana prior to transferring the facility's air quality permit. In 2011, QEP completed an internal audit, which identified 424 facilities in Louisiana for which QEP both failed to submit a complete permit application and to receive approval from the department prior to construction, modification, or operation. QEP has corrected and disclosed all instances of non-compliance to the LDEQ and is working with the department to resolve the NOPP. The LDEQ has assumed lead responsibility for enforcement of the NOPP, and may require the Company to pay a monetary penalty. 

Litigation

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services' former affiliate, Questar Gas Company (QGC), filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the 1993 Agreement) executed when the parties were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of QEP Field Services' systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of the Offering, the assets and agreement discussed above were assigned to QEP Midstream. QGC netted the disputed amount from its monthly payments of the gathering fees to QEP Field Services and has continued to net such amounts from its monthly payment to QEP Midstream. As of March 31, 2014, QEP Midstream has deferred revenue of $9.9 million related to the QGC disputed amount. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add QEP Midstream as a defendant in the litigation. QEP Midstream has been indemnified by QEP for costs, expenses and other losses incurred by QEP Midstream in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement entered into between QEP Midstream and QEP in connection with the IPO.

Rocky Mountain Resources, LLC v. QEP Energy Company, Wexpro Company, Ultra Resources, Inc. and Lance Oil & Gas Company, Inc., Civil No. 2011-7816, District Court of Sublette County, Wyoming. Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint on March 30, 2011, seeking determination of the existence of a 4% overriding royalty interest in State of Wyoming oil and gas Lease No. 79-0645 covering Section 16, T32-N R-109-W, Sublette County, Wyoming. QEP and the other defendants are current lessees of Lease 79-0645. Rocky Mountain alleges that the defendants have received benefits from Lease 79-0645 and 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. Rocky Mountain asserts claims for quiet title, declaratory judgment, breach of contract, breach of duty of good faith, conversion, constructive trust and prejudgment interest. The plaintiffs seek damages, but specific monetary damages are not asserted.

Gatti et al v. State of Louisiana et al, 589,350, 19th JDC, Parish of East Baton Rouge, Louisiana. In this putative class action arising out of the unitization practices and orders of the Louisiana Commissioner of Conservation (Commissioner), plaintiffs seek to represent a class of all Haynesville Shale mineral owners (alleged to be over 50,000 in number) against the Commissioner and all Haynesville Shale unit operators. Plaintiffs filed their complaint on April 8, 2010, and claim that the Commissioner exceeded his statutory authority in creating and perpetuating units larger than the area that can be efficiently and economically drained by a single well. They seek declaratory relief that would nullify all such improper orders, along with an unspecified amount of monetary damages from the unit operators sufficient to compensate the putative class members for the alleged dilution of their true interest in unit production as a result of "oversized" units and the "cloud on title" caused by having excessive and improperly sized units purport to hold their mineral leases via unit operations. All defendants filed exceptions to the plaintiffs' petition on the primary ground that plaintiffs had failed to comply with the exclusive statutory judicial review procedure (Louisiana Revised Statutes 30:12), which the trial court granted, dismissing the action in its entirety. On January 15, 2014, the Louisiana First Circuit Court of Appeal reversed and reinstated plaintiffs' claims. Defendants intend to seek review of the Louisiana Supreme Court, which review is discretionary.

Yannick Gagné and others similarly situated v. QEP Resources, Inc., No. 480-06-1-132, Superior Court, Province of Quebec, Canada. Plaintiffs seek to represent a class of all persons who sustained damages as a result of the July 6, 2013 train derailment in Lac-Mégantic, Quebec, which resulted in substantial loss of life and property. The fourth amended motion to authorize the bringing of a class action was filed on February 19, 2014, and names numerous defendants. The plaintiffs contend that QEP, and other producer defendants, sold Bakken crude oil to third-party purchasers in North Dakota, who resold the oil and transported it on the derailed train. The allegations are that QEP and the producer defendants, among other things, failed to ensure that the oil was adequately processed to remove volatile gases and vapors, knowingly added volatile light end petroleum liquids and/or vapors or blended the crude with condensate, failed to conduct adequate well site testing to determine the proper hazard classification of the oil, failed to properly classify the shipping requirements for the oil, failed to take reasonable care to ensure that the oil was properly labeled and shipped, failed to identify the risk of the train derailment and take action to prevent it, and failed to adopt, implement and enforce rules and procedures pertaining to the safe shipment of the oil. The plaintiffs seek damages, but specific monetary damages are not asserted.

XTO Energy Inc. v. QEP Field Services Company, Civil No. 140900709, Third Judicial District Court, State of Utah. XTO Energy Inc. (XTO), filed this complaint in Utah state court on January 30, 2014, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, unjust enrichment and an accounting related to a 2010 gas processing agreement (the Agreement). QEP Field Services processes XTO’s natural gas on a firm basis under the Agreement. The Agreement requires QEP Field Services to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is disputing QEP Field Services allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes. The plaintiffs seek damages, but specific monetary damages are not asserted.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Other comprehensive income (loss), tax
Tax expense (benefit) on gains (losses) on changes in unrealized fair value of derivatives designated as cash flow hedges		$ (11.9)
Pension and other postretirement plans adjustments:
Tax expense (benefit) on net unamortized gain (loss) incurred	0.1	0.2
Tax expense (benefit) on prior service cost incurred	$ 0.4	$ 0.5

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Earnings Per Share

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income attributable to QEP 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 receive dividends.

Unvested equity-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. There were no anti-dilutive shares during the three months endedMarch 31, 2014. During the three months ended March 31, 2013, 0.3 million shares were not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss.

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

	Three Months Ended
	March 31,
	2014	2013
	(in millions)
Weighted-average basic common shares outstanding	179.7	177.0
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.3	—
Average diluted common shares outstanding	180.0	177.0

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QEP Midstream

3 Months Ended

Mar. 31, 2014

QEP Midstream [Abstract]

Noncontrolling Interest Disclosure [Text Block]

Note 4 - QEP Midstream

QEP Midstream is a publicly traded master limited partnership formed by QEP to own, operate, acquire and develop midstream energy assets. QEP Midstream's assets currently consist of ownership interests in four gathering systems and two FERC regulated pipelines, which provide oil and gas gathering and transportation services. These assets are located in, or within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota.

Initial Public Offering

On August 14, 2013, QEP Midstream completed its initial public offering (the IPO) of 20,000,000 common units, representing limited partner interests in QEP Midstream, at a price to the public of $21.00 per common unit. QEP Midstream received net proceeds of $390.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of $29.3 million. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit, providing additional net proceeds of $58.9 million, after deducting $4.1 million of underwriters' discounts and commissions and structuring fees, to QEP Midstream.

QEP Midstream used the net proceeds to repay its outstanding debt balance with QEP, which was assumed with the assets contributed to QEP Midstream, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to QEP Midstream. The following table is a reconciliation of proceeds from the IPO (in millions):

Total proceeds from the IPO	$	483.0
IPO Costs	(33.4		)
Net proceeds from the IPO	449.6
QEPM Revolving credit facility origination fees	(3.0		)
QEPM Repayment of outstanding debt with QEP	(95.5		)
Net proceeds distributed to QEP from the IPO	$	351.1

QEP Midstream Partners GP, LLC (the General Partner), a wholly owned subsidiary of QEP Field Services, serves as the general partner of QEP Midstream. QEP Field Services owns a 57.8% interest in QEP Midstream and consolidates QEP Midstream for financial reporting purposes with the portion not owned by QEP Field Services reflected as a reduction to net income and equity as a noncontrolling interest.

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Basis of Presentation of Interim Consolidated Financial Statements (Policies)

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

New accounting pronouncements

New accounting pronouncements

During the three months ended March 31, 2014, there were no new accounting pronouncements that were applicable to QEP.

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Equity-Based Compensation

3 Months Ended

Mar. 31, 2014

Share-based Compensation [Abstract]

Equity-Based Compensation

Note 12 – Equity-Based Compensation

QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance-based share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over time as the stock options, restricted shares, and performance-based share units vest. Deferred equity-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 10.9 million shares available for future grants under the LTSIP at March 31, 2014. Equity-based compensation expense is recognized in “General and administrative” on the Condensed Consolidated Statements of Operations. During the three months endedMarch 31, 2014, QEP recognized $6.8 million in total compensation expense related to equity-based compensation compared to $6.1 million during the three months endedMarch 31, 2013.

QEP Midstream maintains a unit-based compensation plan for officers, directors and employees of the general partner of QEP Midstream and its affiliates and any consultants, affiliates of the general partner, or other individuals who perform services for QEP Midstream. The QEP Midstream 2013 Long-Term Incentive Plan (the QEP Midstream LTIP) permits various types of awards, including awards of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Awards granted during 2013 under the QEP Midstream LTIP will be settled with QEP Midstream units. During the three months endedMarch 31, 2014, QEP recognized $0.4 million in compensation expense related to QEP Midstream LTIP.

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:

	Stock Option Assumptions
	Three Months Ended
	March 31, 2014
Weighted-average grant-date fair value of awards granted during the period	$	10.12
Weighted-average risk-free interest rate	1.31		%
Weighted-average expected price volatility	37.2		%
Expected dividend yield	0.25		%
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, 2013	1,794,187		$	27.90
Granted	279,458		31.67
Exercised	(29,479	)	23.01
Outstanding at March 31, 2014	2,044,166		$	28.49	3.91	$	5.2
Options Exercisable at March 31, 2014	1,480,337		$	27.56	3.02	$	5.1
Unvested Options at March 31, 2014	563,829		$	30.93	6.24	$	0.1

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.2 million and $4.2 million during the three months endedMarch 31, 2014 and 2013, respectively. The Company realized $0.1 million and $1.4 million of income tax benefit for the three months endedMarch 31, 2014 and 2013, respectively, which had no significant impact on Additional Paid-in-Capital (APIC) pool as of March 31, 2014. As of March 31, 2014, $4.7 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.43 years. During the three months endedMarch 31, 2014, QEP received $0.7 million in cash in relation to the exercise of stock options during 2014.

Restricted Shares

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 three months endedMarch 31, 2014 and 2013, was $15.1 million and $14.8 million, respectively. The Company realized $1.5 million and $0.3 million of income tax expense for the three months endedMarch 31, 2014 and 2013, respectively, with a $0.6 million impact to the Company's APIC pool as of March 31, 2014. The weighted average grant-date fair value of restricted stock was $31.69 per share and $30.12 per share for the three months endedMarch 31, 2014 and 2013, respectively. As of March 31, 2014, $35.5 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.53 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, 2013	1,388,953		$	30.96
Granted	844,552		31.69
Vested	(524,672	)	31.89
Forfeited	(18,170	)	31.28
Unvested balance at March 31, 2014	1,690,663		$	31.03

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 but delivered in cash at the end of the performance period. The weighted average grant-date fair value of the performance share units was $31.69 per share and $30.12 per share for the three months endedMarch 31, 2014 and 2013, respectively. As of March 31, 2014, $12.8 million of unrecognized compensation cost, representing the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.40 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, 2013	480,660		$	32.33
Granted	241,321		31.69
Vested and paid out	(55,659	)	39.07
Vested and canceled (1)	(51,361	)	39.07
Unvested balance at March 31, 2014	614,961		$	30.90

____________________________

⁽¹⁾  Represents units that vested but were not paid out. Payout of the performance share units are dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period.

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Derivative Contracts

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Contracts

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 100.0% of forecasted production from proved reserves. In addition, QEP may enter into commodity derivative contracts on a portion of its extracted NGL volumes in its midstream business and a portion of its gas sales and purchases for marketing transactions. QEP does not enter into commodity derivative instruments for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps to realize a known price 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, oil, or NGL between the parties at settlement. Swap 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 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 IntercontinentalExchange, Inc. (ICE), Brent oil prices as the reference price. QEP also enters into crude oil basis swaps to achieve a fixed price swap for a portion of its oil that it sells at prices that reference ICE Brent and Light Louisiana Sweet (LLS).

QEP enters into commodity derivative transactions that do not 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.

Effective January 1, 2012, QEP elected to de-designate all of its gas, oil and NGL derivative contracts that were previously designated as cash flow hedges and discontinue hedge accounting prospectively. As a result of discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were fixed in Accumulated Other Comprehensive Income (AOCI) as of the de-designation date and are being reclassified into the Condensed Consolidated Statements of Operations as the transactions settle and affect earnings. As of December 31, 2013, all mark-to-market value was reclassified from AOCI. During the three months ended March 31, 2013, $20.1 million of unrealized gains, after tax, were reclassified from AOCI into the Condensed Consolidated Statements of Operations in "Realized and unrealized losses on derivative contracts" as the transactions settled. All realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012, are presented in the Condensed Consolidated Statements of Operations in "Realized and unrealized losses on derivative contracts" below operating income.

QEP also uses interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk associated with its $600.0 million term loan. For the $300.0 million term loan issued during 2012, QEP locked in a fixed interest rate of 1.07% in exchange for a variable interest rate indexed to the one-month LIBOR. For the incremental $300.0 million borrowed under the term loan during 2014, QEP locked in a fixed interest rate of 0.86%. The average effective interest rate on the $600.0 million term loan is 2.96%. The interest rate swaps settle monthly and will mature in March 2017.

QEP Energy Derivative Contracts

The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative contracts as of March 31, 2014: 

Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	NYMEX	22.0	$	4.22
2014	SWAP	IFNPCR	60.5	$	4.08
2015	SWAP	NYMEX	25.6	$	4.14
2015	SWAP	IFNPCR	7.3	$	3.97
Oil sales			(Bbls)
2014	SWAP	NYMEX WTI	8.1	$	92.61
2015	SWAP	NYMEX WTI	4.0	$	87.64

The following table sets forth QEP Energy's oil basis swaps as of March 31, 2014:

Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
Oil basis swaps			(Bbls)
2014	NYMEX WTI	ICE Brent	0.6	$	13.78
2014	NYMEX WTI	LLS	0.5	$	4.00
2015	NYMEX WTI	LLS	0.1	$	4.00

QEP Marketing Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage and for marketing transactions in which QEP Marketing sells gas volumes at a fixed price. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of March 31, 2014:

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	IFNPCR	2.9	$	3.75
Gas purchases			(MMBtu)
2014	SWAP	IFNPCR	0.9	$	3.82

QEP's Derivative Contracts

The following table sets forth QEP’s notional amount and interest rate for its interest rate swaps outstanding as of March 31, 2014:

Notional amount	Type of Contract	Maturity	Fixed Rate Paid	Variable Rate Received
(in millions)
$300.0	Swap	March 2017	1.07%	One-month LIBOR
$300.0	Swap	March 2017	0.86%	One-month LIBOR
$600.0			0.96%

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	March 31, 2014		December 31, 2013		March 31, 2014		December 31, 2013
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	5.9	$	5.5	$	73.0	$	29.4
Interest rate swaps	Fair value of derivative contracts	—		—		4.7		2.6
Long-term:
Commodity	Fair value of derivative contracts	0.5		0.4		2.3		—
Interest rate swaps	Fair value of derivative contracts	2.8		0.6		—		—
Total derivative instruments		$	9.2	$	6.5	$	80.0	$	32.0

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

	Three Months Ended
Derivative instruments not designated as cash flow hedges	March 31,
	2014			2013
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	(20.4	)	$	44.6
Oil derivative contracts	(12.9		)	5.2
QEP Marketing
Gas derivative contracts	(1.4		)	1.5
Total realized (losses) gains on commodity derivative contracts	(34.7		)	51.3
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	(24.3		)	(64.3		)
Oil derivative contracts	(20.9		)	(19.7		)
QEP Marketing
Gas derivative contracts	(0.3		)	(1.7		)
Total unrealized losses on commodity derivative contracts	(45.5		)	(85.7		)
Total realized and unrealized losses on commodity derivative contracts	$	(80.2	)	$	(34.4	)
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(0.7	)	$	(0.6	)
Unrealized gains (losses) on interest rate swaps
Unrealized (losses) gains on interest rate swaps	—			0.4
Total realized and unrealized losses on interest rate swaps	$	(0.7	)	$	(0.2	)
Total net realized (losses) gains on derivative contracts	$	(35.4	)	$	50.7
Total net unrealized losses on derivative contracts	(45.5		)	(85.3		)
Grand Total	$	(80.9	)	$	(34.6	)

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2014

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

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, production facilities, midstream assets, 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 $205.4 million and $193.6 million ARO liability for the periods ended March 31, 2014 and December 31, 2013, $1.1 million and $1.8 million was included, respectively, as a current liability in "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 periods specified below:

	Asset Retirement Obligations
	2014
	(in millions)
ARO liability at January 1,	$	193.6
Accretion	2.0
Additions(1)	10.9
Revisions	(0.3		)
Liabilities settled	(0.8		)
ARO liability at March 31,	$	205.4

____________________________

⁽¹⁾ Additions includes $9.7 million related to the Permian Basin Acquisition.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

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, but does not change existing guidance as to whether or not an instrument is carried at fair value. 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 8 - 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.

In addition, QEP has interest rate swaps that it has determined are Level 2 financial instruments. The fair values of the interest rate swaps are determined using the market standard methodology of discounting the future expected cash flows that would occur under the contractual terms of the swap. The variable interest rates used in the calculation of projected cash flows are based on an expectation of future interest rates derived from observable market interest rate curves. QEP incorporates credit valuation adjustments to reflect both its nonperformance risk and the respective counterparty's nonperformance risk in the fair value measurements. While the credit valuation adjustments are not observable inputs, they are not significant to the overall valuation and the other inputs used to value the interest rate swaps are observable Level 2 inputs.

The fair value of financial assets and liabilities at March 31, 2014, is shown in the table below:

	Fair Value Measurements
	March 31, 2014
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.9	$	—	$	(5.9	)	$	—
Commodity derivative instruments - long-term	—		0.5		—		0.6			1.1
Interest rate swaps - long-term	—		2.8		—		—			2.8
Total financial assets	$	—	$	9.2	$	—	$	(5.3	)	$	3.9
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	73.0	$	—	$	(5.9	)	$	67.1
Interest rate swaps - short-term	—		4.7		—		—			4.7
Commodity derivative instruments - long-term	—		2.3		—		0.6			2.9
Total financial liabilities	$	—	$	80.0	$	—	$	(5.3	)	$	74.7

____________________________

⁽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 8 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

The fair value of financial assets and liabilities at December 31, 2013, is shown in the table below:

	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.5	$	—	$	(5.3	)	$	0.2
Commodity derivative instruments - long-term	—		0.4		—		—			0.4
Interest rate swaps - long-term	—		0.6		—		—			0.6
Total financial assets	$	—	$	6.5	$	—	$	(5.3	)	$	1.2
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	29.4	$	—	$	(5.3	)	$	24.1
Interest rate swaps - short-term	—		2.6		—		—			2.6
Total financial liabilities	$	—	$	32.0	$	—	$	(5.3	)	$	26.7

_______________________

⁽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 8 - 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 to 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
	March 31, 2014				December 31, 2013
	(in millions)
Financial assets
Cash and cash equivalents	$	3.9	$	3.9	$	11.9	$	11.9
Financial liabilities
Checks outstanding in excess of cash balances	$	78.4	$	78.4	$	90.9	$	90.9
Long-term debt	$	3,919.2	$	4,018.0	$	2,997.5	$	3,034.9

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 asset retirement obligations 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 remaining reserve lives. A reconciliation of the Company’s asset retirement obligations is presented in Note 6 – Asset Retirement Obligations.

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Restructuring Costs

3 Months Ended

Mar. 31, 2014

Restructuring Costs [Abstract]

Restructuring Costs

Restructuring Costs

In December 2013, QEP announced its plan to pursue a separation of its midstream business, QEP Field Services. In connection with this announcement, the Board of Directors approved an employee retention plan to provide substantially all QEP Field Services' employees as of December 1, 2013, with a one-time lump-sum cash payment on December 31, 2014, or whenever the separation of QEP Field Services occurs, whichever is earlier, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated prior to such date.

During the first quarter of 2012, QEP began incurring costs related to the closure of its Oklahoma City office and the subsequent consolidation of its Southern Region operations into a single regional office located in Tulsa. During the second half of 2012, QEP incurred additional restructuring and reorganization costs related to consolidating various corporate and accounting functions to the Denver corporate headquarters. The creation of one office for QEP’s Southern Region as well as the consolidation of corporate and accounting functions increased efficiency, team-based collaboration and organizational productivity. As part of the reorganization, QEP incurred costs associated with the severance, retention and relocation of employees, additional pension expenses, exit costs associated with the termination of operating leases arising from office space that will no longer be utilized by the Company and other expenses. All remaining restructuring costs related to the office consolidations were incurred during 2013.

The following table summarizes, by line of business, each major type of restructuring cost expected to be incurred and the total amounts recorded in "General and administrative" expense on the Condensed Consolidated Statements of Operations for the respective periods indicated:

	Total Restructuring Costs
	Total Expected to be Incurred		Recognized in Income
			Period from Inception to March 31, 2014		Three Months Ended March 31,
					2014		2013
QEP Energy	(in millions)
One-time termination benefits	$	3.3	$	3.3	$	—	$	0.2
Retention & relocation expense	3.7		3.7		—		0.1
Lease termination costs	0.6		0.6		—		—
Total restructuring costs	$	7.6	$	7.6	$	—	$	0.3
QEP Field Services
One-time termination benefits	$	—	$	—	$	—	$	—
Retention & relocation expense	10.1		3.2		2.3		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	10.1	$	3.2	$	2.3	$	—
QEP Marketing
One-time termination benefits	$	0.3	$	0.3	$	—	$	0.1
Retention & relocation expense	—		—		—		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	0.3	$	0.3	$	—	$	0.1
Total QEP
One-time termination benefits	$	3.6	$	3.6	$	—	$	0.3
Retention & relocation expense	13.8		6.9		2.3		0.1
Lease termination costs	0.6		0.6		—		—
Total restructuring costs	$	18.0	$	11.1	$	2.3	$	0.4

The following is a reconciliation of the restructuring liability, by line of business, which is included within “Accounts payable and accrued expenses” on the Condensed Consolidated Balance Sheets:

	QEP Energy		QEP Field Services		QEP Marketing		Total
	(in millions)
Balance at December 31, 2013	$	—	$	0.8	$	—	$	0.8
Costs incurred and charged to expense	—		2.3		—		2.3
Costs paid or otherwise settled	—		—		—		—
Balance at March 31, 2014	$	—	3.1		—		$	3.1

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Operations by Line of Business (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Summary of operating results by line of business

Operations by Line of Business

QEP’s lines of business include gas and oil exploration and production (QEP Energy), midstream field services (QEP Field Services), which includes the ownership and operation of QEP Midstream, and marketing and corporate (QEP Marketing & Resources). The lines of business are managed separately and therefore the financial information is presented separately due to the distinct differences in the nature of operations of each line of business, among other factors. QEP Field Services owns a 57.8% ownership interest in QEP Midstream and it is consolidated under the voting interest model in QEP Field Services' operating results. The outside ownership interest in QEP Midstream is presented separately as a noncontrolling interest.

The following table is a summary of operating results for the three months endedMarch 31, 2014, by line of business:

	QEP Energy			QEP Field Services			QEP Marketing  & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	613.2		$	79.8		$	190.9		$	—		$	883.9
From affiliated customers	—			26.4			312.1			(338.5		)	—
Total revenues	613.2			106.2			503.0			(338.5		)	883.9
Operating expenses
Purchased gas, oil and NGL expense	38.0			—			497.9			(311.6		)	224.3
Lease operating expense	56.4			—			—			(1.1		)	55.3
Gas, oil and NGL transportation and other handling costs	64.5			3.6			—			(24.7		)	43.4
Gathering, processing and other	—			25.7			0.4			(0.3		)	25.8
General and administrative	41.8			14.4			1.2			(0.8		)	56.6
Production and property taxes	47.4			1.8			0.1			—			49.3
Depreciation, depletion and amortization	223.4			16.5			0.3			—			240.2
Other operating expenses	4.2			—			—			—			4.2
Total operating expenses	475.7			62.0			499.9			(338.5		)	699.1
Net gain from asset sales	2.4			—			—						2.4
Operating income	139.9			44.2			3.1			—			187.2
Realized and unrealized losses on derivative contracts	(78.5		)	—			(2.4		)	—			(80.9		)
Interest and other income	2.9			—			48.8			(48.8		)	2.9
Income from unconsolidated affiliates	—			2.2			—			—			2.2
Interest expense	(48.9		)	(0.6		)	(41.8		)	48.8			(42.5		)
Income before income taxes	15.4			45.8			7.7			—			68.9
Income tax provision	(5.9		)	(14.6		)	(2.9		)	—			(23.4		)
Net income	9.5			31.2			4.8			—			45.5
Net income attributable to noncontrolling interest	—			(5.8		)	—			—			(5.8		)
Net income attributable to QEP	$	9.5		$	25.4		$	4.8		$	—		$	39.7
Identifiable total assets	$	9,004.1		$	1,515.5		$	314.6		$	(254.6	)	$	10,579.6

The following table is a summary of operating results for the three months endedMarch 31, 2013, by line of business:

	QEP Energy			QEP Field Services			QEP Marketing  & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	508.2		$	64.4		$	123.9		$	—		$	696.5
From affiliated customers	—			27.6			217.2			(244.8		)	—
Total revenues	508.2			92.0			341.1			(244.8		)	696.5
Operating expenses
Purchased gas, oil and NGL expense	65.7			5.1			342.5			(216.5		)	196.8
Lease operating expense	41.0			—			—			(0.9		)	40.1
Gas, oil and NGL transportation and other handling costs	56.2			2.8			—			(26.2		)	32.8
Gathering, processing and other	—			20.3			0.3			—			20.6
General and administrative	36.7			9.5			1.0			(1.2		)	46.0
Production and property taxes	34.7			1.1			0.1			—			35.9
Depreciation, depletion and amortization	238.1			15.8			0.3			—			254.2
Other operating expenses	5.1			—			—			—			5.1
Total operating expenses	477.5			54.6			344.2			(244.8		)	631.5
Net gain (loss) from assets sales	0.1			(0.3		)	—			—			(0.2		)
Operating income (loss)	30.8			37.1			(3.1		)	—			64.8
Realized and unrealized losses on derivative contracts	(34.2		)	—			(0.4		)	—			(34.6		)
Interest and other income	1.7			0.3			51.2			(51.2		)	2.0
Income from unconsolidated affiliates	—			1.3			—			—			1.3
Interest expense	(45.3		)	(4.0		)	(41.3		)	51.2			(39.4		)
(Loss) income before income taxes	(47.0		)	34.7			6.4			—			(5.9		)
Income tax benefit (provision)	17.2			(12.5		)	(2.5		)	—			2.2
Net (loss) income	(29.8		)	22.2			3.9			—			(3.7		)
Net income attributable to noncontrolling interest	—			(0.6		)	—			—			(0.6		)
Net (loss) income attributable to QEP	$	(29.8	)	$	21.6		$	3.9		$	—		$	(4.3	)
Identifiable total assets	$	7,756.8		$	1,660.6		$	294.9		$	(568.4	)	$	9,143.9

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Subsequent Event (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
QEP Energy Divestitures [Member]
Subsequent Event [Line Items]
Aggregate sale price of assets disposed	$ 807.5
Net book value of property disposed	886.0
QEP Field Services Divestitures [Member]
Subsequent Event [Line Items]
Aggregate sale price of assets disposed	$ 230.0
Membership Interest Sold	40.00%

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Operations by Line of Business

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Operations by Line of Business

Operations by Line of Business

QEP’s lines of business include gas and oil exploration and production (QEP Energy), midstream field services (QEP Field Services), which includes the ownership and operation of QEP Midstream, and marketing and corporate (QEP Marketing & Resources). The lines of business are managed separately and therefore the financial information is presented separately due to the distinct differences in the nature of operations of each line of business, among other factors. QEP Field Services owns a 57.8% ownership interest in QEP Midstream and it is consolidated under the voting interest model in QEP Field Services' operating results. The outside ownership interest in QEP Midstream is presented separately as a noncontrolling interest.

The following table is a summary of operating results for the three months endedMarch 31, 2014, by line of business:

	QEP Energy			QEP Field Services			QEP Marketing  & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	613.2		$	79.8		$	190.9		$	—		$	883.9
From affiliated customers	—			26.4			312.1			(338.5		)	—
Total revenues	613.2			106.2			503.0			(338.5		)	883.9
Operating expenses
Purchased gas, oil and NGL expense	38.0			—			497.9			(311.6		)	224.3
Lease operating expense	56.4			—			—			(1.1		)	55.3
Gas, oil and NGL transportation and other handling costs	64.5			3.6			—			(24.7		)	43.4
Gathering, processing and other	—			25.7			0.4			(0.3		)	25.8
General and administrative	41.8			14.4			1.2			(0.8		)	56.6
Production and property taxes	47.4			1.8			0.1			—			49.3
Depreciation, depletion and amortization	223.4			16.5			0.3			—			240.2
Other operating expenses	4.2			—			—			—			4.2
Total operating expenses	475.7			62.0			499.9			(338.5		)	699.1
Net gain from asset sales	2.4			—			—						2.4
Operating income	139.9			44.2			3.1			—			187.2
Realized and unrealized losses on derivative contracts	(78.5		)	—			(2.4		)	—			(80.9		)
Interest and other income	2.9			—			48.8			(48.8		)	2.9
Income from unconsolidated affiliates	—			2.2			—			—			2.2
Interest expense	(48.9		)	(0.6		)	(41.8		)	48.8			(42.5		)
Income before income taxes	15.4			45.8			7.7			—			68.9
Income tax provision	(5.9		)	(14.6		)	(2.9		)	—			(23.4		)
Net income	9.5			31.2			4.8			—			45.5
Net income attributable to noncontrolling interest	—			(5.8		)	—			—			(5.8		)
Net income attributable to QEP	$	9.5		$	25.4		$	4.8		$	—		$	39.7
Identifiable total assets	$	9,004.1		$	1,515.5		$	314.6		$	(254.6	)	$	10,579.6

The following table is a summary of operating results for the three months endedMarch 31, 2013, by line of business:

	QEP Energy			QEP Field Services			QEP Marketing  & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	508.2		$	64.4		$	123.9		$	—		$	696.5
From affiliated customers	—			27.6			217.2			(244.8		)	—
Total revenues	508.2			92.0			341.1			(244.8		)	696.5
Operating expenses
Purchased gas, oil and NGL expense	65.7			5.1			342.5			(216.5		)	196.8
Lease operating expense	41.0			—			—			(0.9		)	40.1
Gas, oil and NGL transportation and other handling costs	56.2			2.8			—			(26.2		)	32.8
Gathering, processing and other	—			20.3			0.3			—			20.6
General and administrative	36.7			9.5			1.0			(1.2		)	46.0
Production and property taxes	34.7			1.1			0.1			—			35.9
Depreciation, depletion and amortization	238.1			15.8			0.3			—			254.2
Other operating expenses	5.1			—			—			—			5.1
Total operating expenses	477.5			54.6			344.2			(244.8		)	631.5
Net gain (loss) from assets sales	0.1			(0.3		)	—			—			(0.2		)
Operating income (loss)	30.8			37.1			(3.1		)	—			64.8
Realized and unrealized losses on derivative contracts	(34.2		)	—			(0.4		)	—			(34.6		)
Interest and other income	1.7			0.3			51.2			(51.2		)	2.0
Income from unconsolidated affiliates	—			1.3			—			—			1.3
Interest expense	(45.3		)	(4.0		)	(41.3		)	51.2			(39.4		)
(Loss) income before income taxes	(47.0		)	34.7			6.4			—			(5.9		)
Income tax benefit (provision)	17.2			(12.5		)	(2.5		)	—			2.2
Net (loss) income	(29.8		)	22.2			3.9			—			(3.7		)
Net income attributable to noncontrolling interest	—			(0.6		)	—			—			(0.6		)
Net (loss) income attributable to QEP	$	(29.8	)	$	21.6		$	3.9		$	—		$	(4.3	)
Identifiable total assets	$	7,756.8		$	1,660.6		$	294.9		$	(568.4	)	$	9,143.9

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Components of basic and diluted shares used in EPS

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

	Three Months Ended
	March 31,
	2014	2013
	(in millions)
Weighted-average basic common shares outstanding	179.7	177.0
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.3	—
Average diluted common shares outstanding	180.0	177.0

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Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 0.7	$ 1.0
Interest cost	1.4	1.2
Expected return on plan assets	(1.2)	(1.0)
Amortization of prior service costs	1.2	1.2
Amortization of actuarial loss	0.2	0.6
Periodic expense	2.3	3.0
Pension [Member] | Funded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan	2.7
Expected to contribute to pension plans	5.4
Pension [Member] | Unfunded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan	0.9
Expected to contribute to pension plans	4.0
Pension [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected to contribute to pension plans	0.2
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0	0
Interest cost	0.1	0.1
Amortization of prior service costs	0.1	0.1
Periodic expense	$ 0.2	$ 0.2

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Current	$ 1.1	$ 1.8
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	193.6
Accretion	2.0
Liabilities incurred	10.9
Revisions	(0.3)
Liabilities settled	(0.8)
ARO liability, Ending Balance	$ 205.4

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Current Assets
Cash and cash equivalents	$ 3.9	$ 11.9
Accounts receivable, net	586.5	408.5
Fair value of derivative contracts	0	0.2
Gas, oil and NGL inventories at lower of average cost or market	7.8	13.4
Deferred income taxes	50.4	30.6
Prepaid expenses and other	61.8	54.4
Total Current Assets	710.4	519.0
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	12,401.4	11,571.4
Unproved properties	1,102.5	665.1
Midstream field services	1,719.2	1,698.1
Marketing and other	89.4	85.5
Material and supplies	64.8	59.0
Total Property, Plant and Equipment	15,377.3	14,079.1
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,146.5	4,930.9
Midstream field services	425.0	409.7
Marketing and other	24.2	22.1
Total Accumulated Depreciation, Depletion and Amortization	5,595.7	5,362.7
Net Property, Plant and Equipment	9,781.6	8,716.4
Investment in unconsolidated affiliates	38.5	39.0
Fair value of derivative contracts	3.9	1.0
Restricted cash	0	50.0
Other noncurrent assets	45.2	51.4
TOTAL ASSETS	10,579.6	9,376.8
Current Liabilities
Checks outstanding in excess of cash balances	78.4	90.9
Accounts payable and accrued expenses	581.0	434.9
Production and property taxes	62.3	51.8
Interest payable	34.2	37.2
Fair value of derivative contracts	71.8	26.7
Total Current Liabilities	827.7	641.5
Long-term debt	3,919.2	2,997.5
Deferred income taxes	1,601.7	1,560.6
Asset retirement obligations	204.3	191.8
Fair value of derivative contracts	2.9	0
Other long-term liabilities	108.1	108.6
Commitments and contingencies
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 180.7 million and 179.7 million shares issued, respectively	1.8	1.8
Treasury stock - 0.6 million and 0.4 million shares, respectively	(20.9)	(14.9)
Additional paid-in capital	508.1	498.4
Retained earnings	2,953.8	2,917.8
Accumulated other comprehensive income	(25.5)	(26.5)
Total Common Shareholders' Equity	3,417.3	3,376.6
Noncontrolling interest	498.4	500.2
Total Equity	3,915.7	3,876.8
TOTAL LIABILITIES AND EQUITY	$ 10,579.6	$ 9,376.8

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Acquisitions & Divestitures

3 Months Ended

Mar. 31, 2014

Acquisitions [Abstract]

Acquisitions [Text Block]

Note 3 - Acquisition

Permian Basin Acquisition

On February 25, 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $945.0 million, subject to customary post-closing adjustments (the Permian Basin Acquisition). The acquired properties consist of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which creates a new core area of operation for QEP Energy. The acquisition was funded with $50.0 million of restricted cash, $300.0 million from the Company's expanded term loan and approximately $595.0 million from its revolving credit facility.

Concurrent with the Permian Basin Acquisition, QEP entered into a transaction structured as a reverse like-kind exchange in accordance with Section 1031 of the Internal Revenue Code. In connection with this reverse like-kind exchange, QEP assigned the ownership of the Permian Basin oil and gas properties acquired to a variable interest entity. QEP operates the properties pursuant to lease and management agreements with that entity, and has a call option which allows the Company to terminate the exchange transaction at any time up and until the expiration date of the exchange. Because the Company is the primary beneficiary of these arrangements, the properties acquired are included in its Condensed Consolidated Balance Sheet as of March 31, 2014, and all revenues earned, expenses incurred, and cash flows related to the properties will be included in the Company’s Condensed Consolidated Statements of Operations and Condensed Consolidated Statements of Cash Flows during the term of the agreement. The agreements will terminate upon the transfer of the acquired properties from the exchange accommodation titleholder to QEP following the exercise of the call option but in no event later than August 24, 2014, the expiration date for this exchange.

The Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included significant proved properties. QEP allocated the cost of the Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $14.9 million and net income of $3.7 million were generated from the acquired properties from February 25, 2014, to March 31, 2014, and are included in QEP's Condensed Consolidated Statements of Operations. During the quarter ended March 31, 2014, QEP Energy's acquisition-related costs of $0.5 million which are included in "General and administrative" on the Condensed Consolidated Statements of Operations. QEP incurred $1.1 million of debt issuance costs associated with increasing the size of term loan borrowings to fund a portion of the acquisition, which are included in "Other noncurrent assets" on the Condensed Consolidated Balance Sheet.

QEP Energy recorded the Permian Basin Acquisition on its Condensed Consolidated Balance Sheets; however, the final purchase price is subject to post-closing adjustments. The following table presents a summary of the Company's preliminary purchase accounting entries:

	As of March 31, 2014
	(in millions)
Consideration given:
Cash consideration	$	945.0
Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
Proved properties	$	516.1
Unproved properties	439.7
Asset retirement obligations	(9.7		)
Liabilities assumed	(1.1		)
Total fair value	$	945.0

The following unaudited, pro forma results of operations are provided for the three months endedMarch 31, 2014 and 2013. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the period presented or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the three months endedMarch 31, 2014 and 2013, the acquired properties' historical results of operations, and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the preliminary purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.

	Three Months Ended				Three Months Ended
	March 31, 2014				March 31, 2013
	Actual		Pro forma		Actual			Pro forma
	(in millions, except per share data)
Revenues	$	883.9	$	910.0	$	696.5		$	731.0
Net income attributable to QEP	39.7		46.7		(4.3		)	3.6
Earnings per common share attributable to QEP
Basic	$	0.22	$	0.26	$	(0.02	)	$	0.02
Diluted	0.22		0.26		(0.02		)	0.02

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2014

Asset Retirement Obligation [Abstract]

Asset retirement obligations roll forward

	Asset Retirement Obligations
	2014
	(in millions)
ARO liability at January 1,	$	193.6
Accretion	2.0
Additions(1)	10.9
Revisions	(0.3		)
Liabilities settled	(0.8		)
ARO liability at March 31,	$	205.4

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QEP Midstream (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended
	Aug. 14, 2013	Mar. 31, 2014
Noncontrolling Interest [Line Items]
Initial Offering Period	August 14, 2013
Shares Issued, Price Per Share	$ 21.00
Total proceeds from the Subsidiary IPO	$ 483.0
Offering costs	33.4
Net proceeds from Subsidiary IPO	449.6
Noncontrolling Interest, Ownership Percentage by Parent		57.80%
Limited Partner Common Units Sold to Public [Member]
Noncontrolling Interest [Line Items]
Partners' Capital Account, Units, Sold in Public Offering	20,000,000
Offering costs	29.3
Net proceeds from Subsidiary IPO	390.7
Limited Partner Common Units Sold to Underwriters [Member]
Noncontrolling Interest [Line Items]
Partners' Capital Account, Units, Sold in Public Offering	3,000,000
Offering costs	4.1
Net proceeds from Subsidiary IPO	$ 58.9

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Employee Benefits

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Employee Benefits

Employee Benefits

The Company maintains closed, defined-benefit pension and postretirement medical plans. QEP's pension plans include a qualified and a nonqualified retirement plan. The Company's postretirement medical plan is unfunded and provides certain health care and life insurance benefits for certain retired employees. During the three months endedMarch 31, 2014, the Company made contributions of $2.7 million to its funded qualified pension plan, and $0.9 million to its unfunded nonqualified retirement plan. Contributions to funded qualified plans increase plan assets while contributions to unfunded nonqualified plans are used to fund current benefit payments. During the remainder of 2014, the Company expects to contribute approximately $5.4 million to its funded qualified pension plan, $4.0 million to its unfunded nonqualified pension plans and approximately $0.2 million for retiree health care and life insurance benefits.

The following table sets forth the Company’s pension and postretirement benefits net periodic benefit costs:

	Pension
	Three Months Ended
	March 31,
	2014			2013
	(in millions)
Service cost	$	0.7		$	1.0
Interest cost	1.4			1.2
Expected return on plan assets	(1.2		)	(1.0		)
Amortization of prior service costs (1)	1.2			1.2
Amortization of actuarial losses (1)	0.2			0.6
Periodic expense	$	2.3		$	3.0

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⁽¹⁾  Amortization of prior service costs and actuarial losses out of AOCI are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."

	Postretirement Benefits
	Three Months Ended
	March 31,
	2014		2013
	(in millions)
Service cost	$	—	$	—
Interest cost	0.1		0.1
Amortization of prior service costs (1)	0.1		0.1
Periodic expense	$	0.2	$	0.2

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⁽¹⁾  Amortization of prior service costs out of AOCI are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."