Edgar Filing: QEP RESOURCES, INC.

QEP-2013.6.30-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2013



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 June 30, 2013, there were 179,289,624 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2013

TABLE OF CONTENTS



			Page
PART I. FINANCIAL INFORMATION			2

	ITEM 1.	FINANCIAL STATEMENTS	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2013 AND 2012	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2013 AND 2012	3

		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT JUNE 30, 2013 AND DECEMBER 31, 2012	4

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2013 AND 2012	5

		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	47

	ITEM 4.	CONTROLS AND PROCEDURES	52

PART II. OTHER INFORMATION			52

	ITEM 1.	LEGAL PROCEEDINGS	52

	ITEM 1A.	RISK FACTORS	52

	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	53

SIGNATURES			54

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
REVENUES	(in millions, except per share amounts)
Natural gas sales	$	218.1		$	138.9		$	415.7		$	300.1
Oil sales	208.3			107.2			402.5			218.0
NGL sales	75.3			82.1			143.7			179.5
Gathering, processing and other	42.6			45.8			88.2			95.6
Purchased gas, oil and NGL sales	206.7			125.3			397.4			309.3
Total Revenues	751.0			499.3			1,447.5			1,102.5
OPERATING EXPENSES
Purchased gas, oil and NGL expense	207.0			124.9			403.8			313.3
Lease operating expense	43.5			40.5			82.4			80.6
Natural gas, oil and NGL transportation and other handling costs	37.3			40.7			71.3			75.2
Gathering, processing and other	23.5			20.6			44.1			44.3
General and administrative	40.9			36.8			86.9			72.8
Production and property taxes	39.3			19.4			75.2			44.1
Depreciation, depletion and amortization	249.8			214.4			504.0			413.7
Exploration expenses	2.6			2.1			7.7			4.1
Impairment	0.2			55.4			0.2			61.9
Total Operating Expenses	644.1			554.8			1,275.6			1,110.0
Net gain from asset sales	100.4			—			100.2			1.5
OPERATING INCOME (LOSS)	207.3			(55.5		)	272.1			(6.0		)
Realized and unrealized gains on derivative contracts (See Note 7)	114.0			82.3			79.4			298.6
Interest and other income	3.1			0.9			5.1			2.6
Income from unconsolidated affiliates	1.6			1.4			2.9			3.3
Loss from early extinguishment of debt	—			(0.6		)	—			(0.6		)
Interest expense	(41.4		)	(28.2		)	(80.8		)	(52.9		)
INCOME BEFORE INCOME TAXES	284.6			0.3			278.7			245.0
Income tax provision	(104.8		)	(0.1		)	(102.6		)	(88.8		)
NET INCOME	179.8			0.2			176.1			156.2
Net income attributable to noncontrolling interest	(1.4		)	(0.9		)	(2.0		)	(1.7		)
NET INCOME (LOSS) ATTRIBUTABLE TO QEP	$	178.4		$	(0.7	)	$	174.1		$	154.5

Earnings Per Common Share Attributable to QEP
Basic total	$	0.99		$	—		$	0.97		$	0.87
Diluted total	$	0.99		$	—		$	0.97		$	0.87

Weighted-average common shares outstanding
Used in basic calculation	179.3			177.7			179.1			177.6
Used in diluted calculation	179.5			177.7			179.4			178.5
Dividends per common share	$	0.02		$	0.02		$	0.04		$	0.04

See notes accompanying the condensed consolidated financial statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(in millions)
Net income	$	179.8		$	0.2		$	176.1		$	156.2
Other comprehensive income (loss), net of tax:
Reclassification of previously deferred derivative gains⁽¹⁾	(20.6		)	(44.7		)	(40.7		)	(91.7		)
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss ⁽²⁾	0.3			0.1			0.7			0.2
Amortization of prior service cost ⁽³⁾	0.9			0.8			1.7			1.7
Total pension and other postretirement plans adjustments	1.2			0.9			2.4			1.9
Other comprehensive loss	(19.4		)	(43.8		)	(38.3		)	(89.8		)
Comprehensive income (loss)	160.4			(43.6		)	137.8			66.4
Comprehensive income attributable to noncontrolling interests	(1.4		)	(0.9		)	(2.0		)	(1.7		)
Comprehensive income (loss) attributable to QEP	$	159.0		$	(44.5	)	$	135.8		$	64.7

____________________________


⁽¹⁾	Presented net of income tax benefit of $12.2 million and $24.1 million during the three and six months ended June 30, 2013 and $26.5 million and $54.3 million during the three and six months ended June 30, 2012, respectively.


⁽²⁾	Presented net of income tax expense of $0.3 million and $0.5 million during the three and six months ended June 30, 2013 and $0.1 million and $0.2 million during the three and six months ended June 30, 2012, respectively.


⁽³⁾	Presented net of income tax expense of $0.5 million and $1.0 million and during the three and six months ended June 30, 2013 and $0.5 million and $1.1 million during the three and six months ended June 30, 2012, respectively.

See notes accompanying the condensed consolidated financial statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2013			December 31, 2012
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	139.7		$	—
Accounts receivable, net	489.8			387.5
Fair value of derivative contracts	104.1			188.7
Gas, oil and NGL inventories, at lower of average cost or market	3.8			13.1
Prepaid expenses and other	49.3			68.0
Deferred income taxes	6.4			—
Total Current Assets	793.1			657.3
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	10,802.2			10,234.3
Unproved properties	919.8			937.9
Midstream field services	1,650.5			1,634.9
Marketing and resources	77.0			64.6
Material and supplies	62.3			61.9
Total Property, Plant and Equipment	13,511.8			12,933.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	4,624.8			4,258.1
Midstream field services	382.1			357.9
Marketing and resources	21.0			18.1
Total Accumulated Depreciation, Depletion and Amortization	5,027.9			4,634.1
Net Property, Plant and Equipment	8,483.9			8,299.5
Investment in unconsolidated affiliates	40.0			41.2
Goodwill	59.5			59.5
Fair value of derivative contracts	18.9			4.1
Other noncurrent assets	51.7			46.9
TOTAL ASSETS	$	9,447.1		$	9,108.5
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	95.5		$	39.7
Accounts payable and accrued expenses	496.7			643.4
Production and property taxes	50.7			41.8
Interest payable	38.0			36.9
Fair value of derivative contracts	2.5			2.6
Deferred income taxes	—			5.0
Total Current Liabilities	683.4			769.4
Long-term debt	3,405.7			3,206.9
Deferred income taxes	1,603.3			1,493.5
Asset retirement obligations	179.9			191.4
Fair value of derivative contracts	—			3.6
Other long-term liabilities	123.7			130.0
Commitments and contingencies
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 179.6 million and 178.5 million shares issued, respectively	1.8			1.8
Treasury stock - 0.3 million and 0.1 million shares, respectively	(12.6		)	(3.7		)
Additional paid-in capital	480.8			462.1
Retained earnings	2,940.0			2,773.0
Accumulated other comprehensive (loss) income	(5.4		)	32.8
Total Common Shareholders' Equity	3,404.6			3,266.0
Noncontrolling interest	46.5			47.7
Total Equity	3,451.1			3,313.7
TOTAL LIABILITIES AND EQUITY	$	9,447.1		$	9,108.5

See notes accompanying the condensed consolidated financial statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended
	June 30,
	2013			2012
	(in millions)
OPERATING ACTIVITIES
Net income	$	176.1		$	156.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	504.0			413.7
Deferred income taxes	121.0			77.1
Impairment	0.2			61.9
Share-based compensation	13.2			12.3
Amortization of debt issuance costs and discounts	3.1			2.4
Dry exploratory well expense	—			0.1
Net gain from asset sales	(100.2		)	(1.5		)
Income from unconsolidated affiliates	(2.9		)	(3.3		)
Distributions from unconsolidated affiliates and other	4.1			3.5
Non-cash loss on early extinguishment of debt	—			0.1
Unrealized loss (gain) on derivative contracts	1.4			(89.9		)
Changes in operating assets and liabilities	(222.1		)	61.7
Net Cash Provided by Operating Activities	497.9			694.3
INVESTING ACTIVITIES
Property acquisitions	(22.0		)	(4.0		)
Property, plant and equipment, including dry exploratory well expense	(719.9		)	(681.5		)
Proceeds from disposition of assets	143.0			3.6
Net Cash Used in Investing Activities	(598.9		)	(681.9		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	55.8			(29.4		)
Long-term debt issued	—			800.0
Long-term debt issuance costs paid	—			(8.8		)
Long-term debt repaid	—			(6.7		)
Proceeds from credit facility	898.5			194.5
Repayments of credit facility	(700.0		)	(801.0		)
Treasury stock repurchases	(7.5		)	(9.8		)
Other capital contributions	2.9			3.4
Dividends paid	(7.2		)	(7.1		)
Excess tax benefit on share-based compensation	1.3			2.0
Distribution to noncontrolling interest	(3.1		)	(3.1		)
Net Cash Provided by Financing Activities	240.7			134.0
Change in cash and cash equivalents	139.7			146.4
Beginning cash and cash equivalents	—			—
Ending cash and cash equivalents	$	139.7		$	146.4

Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	76.7		$	42.7
Cash paid for income taxes	41.5			8.0
Non-cash investing activities:
Change in capital expenditure accrual balance	$	2.8		$	45.3

See notes accompanying the condensed consolidated financial statements.

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Nature of Business

QEP Resources, Inc. (QEP or the Company) is a holding company with three major lines of business: natural gas and crude oil 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 natural gas, oil, and natural gas liquids (NGL);


•	QEP Field Services Company (QEP Field Services) provides midstream field services, including natural gas gathering, processing, compression, and treating services, for affiliates and third parties;


•	QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil, 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 the Texas Panhandle) of the United States. QEP’s corporate headquarters are located in Denver, Colorado.

Shares of QEP Resources’ 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. 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 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, 2012.

The preparation of the condensed consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three and six months ended June 30, 2013, are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

New accounting pronouncements

In February of 2013, the FASB issued ASU 2013-02, Other Comprehensive Income (Topic 220: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income), which seeks to improve the reporting of entities by requiring an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under GAAP to be reclassified in its entirety to net income. For other amounts that are not required under GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under GAAP that provide additional detail about those amounts. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2012. The Company adopted this standard in the first quarter of 2013 and noted that it did not have a significant impact on the Company's consolidated financial statements.

In December of 2011, the FASB issued ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, which enhances disclosure requirements regarding an entity’s financial instruments and derivative instruments that are offset or subject to a master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial statements to understand the effect of those arrangements on the entity’s financial position, including the effect of rights of setoff. Additionally, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,

which clarifies the implementation of ASU 2011-01. The amendments are required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. The Company adopted this standard effective January 1, 2013. It did not have a significant impact on the Company's consolidated financial statements.

In July of 2012, the FASB issued ASU 2012-02, Intangibles - Goodwill and Other: Testing Indefinite-Lived Intangible Assets for Impairment, which revises the way an entity can test indefinite-lived intangible assets for impairment by allowing an entity to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If there is no indication of impairment from the qualitative impairment test, the entity is not required to complete a quantitative impairment test of determining and comparing the fair value with the carrying amount of the indefinite-lived asset. Under the guidance in this ASU, an entity also has the option to bypass the qualitative assessment in any period and proceed directly to performing the quantitative impairment test, while retaining the ability to resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. The Company adopted this standard January 1, 2013, which has allowed the Company to more efficiently complete the annual goodwill impairment test but has not had a significant impact on the Company's consolidated financial statements.

Note 3 - Acquisition and Divestitures

Acquisitions

On September 27, 2012, QEP Energy completed an acquisition of oil and gas properties in the Williston Basin for an aggregate purchase price of approximately $1.4 billion, subject to post-closing adjustments (the 2012 Acquisition). The properties are located in Williams and McKenzie counties of North Dakota, approximately 12 miles west of QEP's then-existing core acreage in the Williston Basin.

The 2012 Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included proved properties. QEP allocated the cost of the 2012 Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $56.5 million and $114.1 million and net income of $10.3 million and $23.4 million were generated from the acquired properties during the three and six months ended June 30, 2013, respectively, and are included in QEP's Condensed Consolidated Statements of Operations.

QEP Energy recorded the 2012 Acquisition on its Condensed Consolidated Balance Sheet; however, the final purchase price is subject to revision based on the settlement of post-closing adjustments. The following table presents a summary of the Company's preliminary purchase accounting entries:



	As of June 30, 2013
	(in millions)
Consideration given:
Cash consideration	$	1,392.3
Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
Proved properties	$	713.8
Unproved properties	683.1
Asset retirement obligations	(0.9		)
Liabilities assumed	(4.5		)
Other assets	0.8
Total fair value	$	1,392.3

The following unaudited, pro forma results of operations are provided for the three and six months ended June 30, 2012. 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 and six months ended June 30, 2012, on the acquired properties' historical results of operations and on 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 2012 Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.



	Three Months Ended					Six Months Ended
	June 30, 2012					June 30, 2012
	Actual			Pro forma		Actual		Pro forma
	(in millions, except per share data)

Revenues	$	499.3		$	543.6	$	1,102.5	$	1,181.5
Net income attributable to QEP	(0.7		)	2.8		154.5		160.1
Earnings per common share attributable to QEP
Basic	$	—		$	0.02	$	0.87	$	0.90
Diluted	—			0.02		0.87		0.90

Divestitures

In June 2013, QEP Energy sold its interests in several non-core oil and gas properties located in the Northern Region for total cash proceeds of $139.7 million and recorded a pre-tax gain on sale of $102.5 million, both of which are subject to post-closing adjustments. During the quarter ended June 30, 2013, QEP Energy recorded the gain on its Condensed Consolidated Statement of Operation in "Net gain from asset sales".

Note 4 – 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 share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company’s unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company’s unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company’s unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. There were no anti-dilutive shares during the three and six months ended June 30, 2013, or during the six months ended June 30, 2012. During the three months ended June 30, 2012, 0.9 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		Six Months Ended
	June 30,		June 30,
	2013	2012	2013	2012
	(in millions)
Weighted-average basic common shares outstanding	179.3	177.7	179.1	177.6
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.2	—	0.3	0.9
Average diluted common shares outstanding	179.5	177.7	179.4	178.5

Note 5 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. The Company’s ARO liability applies primarily to abandonment costs associated with oil and gas wells, 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 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.

The following is a reconciliation of the changes in the Company's asset retirement obligation from January 1, 2013, to June 30, 2013:



	Asset Retirement Obligations
	2013
	(in millions)
ARO liability at January 1,	$	193.1
Accretion	7.7
Liabilities incurred	6.9
Revisions	(16.5		)
Liabilities settled	(9.8		)
ARO liability at June 30,	$	181.4

Note 6 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures”. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements, 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 its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (see Note 7 - Derivative Contracts) is based on market prices posted on the respective commodity exchanges 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.

However, 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 June 30, 2013, is shown in the table below:



	Fair Value Measurements
	June 30, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	105.8	$	—	$	(1.7	)	$	104.1
Commodity derivative instruments - long-term	—		17.6		—		—			17.6
Interest rate swaps - long-term	—		1.3		—		—			1.3
Total financial assets	$	—	$	124.7	$	—	$	(1.7	)	$	123.0

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	1.7	$	—	$	(1.7	)	$	—
Interest rate swaps - short-term	—		2.5		—		—			2.5
Total financial liabilities	$	—	$	4.2	$	—	$	(1.7	)	$	2.5

____________________________

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

The fair value of financial assets and liabilities at December 31, 2012, is shown in the table below:



	Fair Value Measurements
	December 31, 2012
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	189.7	$	—	$	(1.0	)	$	188.7
Commodity derivative instruments - long-term	—		4.2		—		(0.1		)	4.1
Total financial assets	$	—	$	193.9	$	—	$	(1.1	)	$	192.8

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	1.0	$	—	$	(1.0	)	$	—
Interest rate swaps - short-term	—		2.6		—		—			2.6
Commodity derivative instruments - long-term	—		0.1		—		(0.1		)	—
Interest rate swaps - long-term	—		3.6		—		—			3.6
Total financial liabilities	$	—	$	7.3	$	—	$	(1.1	)	$	6.2

_______________________

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
	June 30, 2013				December 31, 2012
	(in millions)
Financial assets
Cash and cash equivalents	$	139.7	$	139.7	$	—	$	—
Financial liabilities
Checks outstanding in excess of cash balances	$	95.5	$	95.5	$	39.7	$	39.7
Long-term debt	$	3,405.7	$	3,465.7	$	3,206.9	$	3,420.7

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 reserve lives. A reconciliation of the Company’s asset retirement obligations is presented in Note 5 – Asset Retirement Obligations.

Note 7 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production from proved reserves. 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 natural 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 natural gas, crude 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 periods. Natural 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. QEP also has oil price derivative fixed-price swaps that use Brent crude oil prices as the reference price. Brent crude oil contracts are traded on the IntercontinentalExchange, Inc. (ICE). NGL price derivative instruments are typically structured as Mont Belvieu, Texas fixed-price swaps.

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 natural gas, crude 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 Statement of Operations as the transactions settle and affect earnings. At June 30, 2013, AOCI included $58.7 million ($36.9 million after tax) of unrealized gains. During the six months ended June 30, 2013 and 2012, $40.7 million and $91.7 million, respectively, of

unrealized gains, after tax, were reclassified from AOCI into the Condensed Consolidated Statement of Operations in "Realized and unrealized gains on derivative contracts" as the transactions settled. QEP expects to reclassify into earnings from AOCI the fixed value related to de-designated natural gas, oil and NGL derivatives over the remainder of 2013. Currently, QEP recognizes all gains and losses from changes in the fair value of natural gas, oil and NGL derivative contracts immediately in earnings rather than deferring any such amounts in AOCI. All commodity derivative instruments are recorded on the Condensed Consolidated Balance Sheets as either assets or liabilities measured at their fair values and all realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012, are presented in the Condensed Consolidated Statement of Operations in “Realized and unrealized gains on derivative contracts” below operating income.

QEP also uses interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk. During the second quarter of 2012, QEP entered into variable-to-fixed interest rate swap agreements having a combined notional principal amount of $300.0 million to minimize the interest rate volatility risk associated with its $300.0 million senior, unsecured term loan. QEP locked in a fixed interest rate of 1.07% in exchange for a variable interest rate indexed to the one-month LIBOR rate. The interest rate swaps settle monthly and will mature in March of 2017.

QEP Energy Derivative Contracts

The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative contracts as of June 30, 2013:



				Swaps
Year	Type of Contract	Index	Total Volumes	Average price per unit
			(in millions)
Natural gas			(MMBtu)
2013	Swap	IFNPCR (1)	36.8	$	5.49
2013	Swap	NYMEX	29.4	$	3.81
2014	Swap	IFNPCR (1)	32.9	$	4.00
2014	Swap	NYMEX	25.6	$	4.19
Crude oil			(Bbls)
2013	Swap	NYMEX WTI	2.9	$	98.33
2013	Swap	BRENT ICE	0.2	$	107.80
2014	Swap	NYMEX WTI	5.5	$	92.59

____________________________


⁽¹⁾	Inside FERC monthly settlement index for the Northwest Pipeline Corp. Rocky Mountains.

QEP Marketing Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on natural 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 June 30, 2013:



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2013	Swap	IFNPCR	1.6	$	3.82
Natural gas purchases			(MMBtu)
2013	Swap	IFNPCR	0.5	$	3.83
2014	Swap	IFNPCR	0.1	$	3.87

QEP Resources Derivative Contracts

The following table sets forth QEP Resources’ notional amount and interest rate for its interest rate swaps outstanding as of June 30, 2013:



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

QEP Derivative Financial Statement Presentation

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



		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	June 30, 2013		December 31, 2012		June 30, 2013		December 31, 2012
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	105.8	$	189.7	$	1.7	$	1.0
Interest rate swaps	Fair value of derivative contracts	—		—		2.5		2.6
Long-term:
Commodity	Fair value of derivative contracts	17.6		4.2		—		0.1
Interest rate swaps	Fair value of derivative contracts	1.3		—		—		3.6
Total derivative instruments		$	124.7	$	193.9	$	4.2	$	7.3

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



	Three Months Ended						Six Months Ended
Derivative instruments not designated as cash flow hedges	June 30,						June 30,
Derivative instruments not designated as cash flow hedges	2013			2012			2013			2012
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Natural gas derivative contracts	$	24.9		$	111.9		$	69.5		$	197.6
Oil derivative contracts	6.4			2.2			11.6			(0.5		)
NGL derivative contracts	—			2.7			—			3.1
QEP Field Services
NGL derivative contracts	—			3.3			—			4.4
QEP Marketing
Natural gas derivative contracts	(0.5		)	0.6			1.0			4.1
Total realized gains on commodity derivative contracts	30.8			120.7			82.1			208.7
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts	61.3			(78.4		)	(3.0		)	53.9
Oil derivative contracts	16.8			38.6			(2.9		)	27.1
NGL derivative contracts	—			4.9			—			7.8
QEP Field Services
NGL derivative contracts	—			1.5			—			4.5
QEP Marketing
Natural gas derivative contracts	1.3			(0.7		)	(0.4		)	0.9
Total unrealized (losses) gains on commodity derivative contracts	79.4			(34.1		)	(6.3		)	94.2
Total realized and unrealized gains on commodity derivative contracts	$	110.2		$	86.6		$	75.8		$	302.9

Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(0.7	)	$	—		$	(1.3	)	$	—
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	4.5			(4.3		)	4.9			(4.3		)
Total realized and unrealized gains (losses) on interest rate swaps	$	3.8		$	(4.3	)	$	3.6		$	(4.3	)
Total net realized gains on derivative contracts	$	30.1		$	120.7		$	80.8		$	208.7
Total net unrealized (losses) gains on derivative contracts	83.9			(38.4		)	(1.4		)	89.9
Grand Total	$	114.0		$	82.3		$	79.4		$	298.6

The Company expects that the remaining derivative contracts that were outstanding in AOCI at June 30, 2013, having a fixed fair value of $36.9 million after tax, will be settled and reclassified from AOCI to the Condensed Consolidated Statements of Operations during the remainder of 2013.

Note 8 – Restructuring Costs

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 is intended to increase efficiency, team-based collaboration and

organizational productivity over the long term. As part of the reorganization, QEP incurred and will continue to incur 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. The Company currently estimates that the remaining restructuring costs will be incurred during the remainder of 2013.

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



	Total Restructuring Costs
	Total Expected to be Incurred		Recognized in Income
			Period from Inception to June 30, 2013		Three Months Ended June 30,				Six Months Ended June 30,
			Period from Inception to June 30, 2013		2013		2012		2013		2012
QEP Energy	(in millions)
One-time termination benefits	$	3.3	$	3.3	$	0.1	$	0.8	$	0.3	$	1.9
Retention & relocation expense	3.7		3.5		0.1		1.5		0.2		3.1
Lease termination costs	0.6		0.6		—		—				—
Total restructuring costs	$	7.6	$	7.4	$	0.2	$	2.3	$	0.5	$	5.0

QEP Field Services
One-time termination benefits	$	—	$	—	$	—	$	—	$	—	$	—
Retention & relocation expense	0.1		0.1		—		—		—		—
Lease termination costs	—		—		—		—		—		—
Total restructuring costs	$	0.1	$	0.1	$	—	$	—	$	—	$	—

QEP Marketing
One-time termination benefits	$	0.3	$	0.2	$	—	$	—	$	0.1	$	—
Retention & relocation expense	—		—		—		—		—		—
Lease termination costs	—		—		—		—		—		—
Total restructuring costs	$	0.3	$	0.2	$	—	$	—	$	0.1	$	—

Total QEP Resources
One-time termination benefits	$	3.6	$	3.5	$	0.1	$	0.8	$	0.4	$	1.9
Retention & relocation expense	3.8		3.6		0.1		1.5		0.2		3.1
Lease termination costs	0.6		0.6		—		—		—		—
Total restructuring costs	$	8.0	$	7.7	$	0.2	$	2.3	$	0.6	$	5.0

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, 2012	$	1.0		$	—	$	—		$	1.0
Costs incurred and charged to expense	0.5			—		0.1			0.6
Costs paid or otherwise settled	(1.2		)	—		(0.1		)	(1.3		)
Balance at June 30, 2013	$	0.3		—		—			$	0.3

Note 9 – Debt

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



	June 30, 2013			December 31, 2012
	(in millions)
Revolving credit facility due 2016	$	888.5		$	690.0
Term loan due 2017	300.0			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	3,410.3			3,211.8
Less unamortized discount	(4.6		)	(4.9		)
Total long-term debt outstanding	$	3,405.7		$	3,206.9

Of the total debt outstanding on June 30, 2013, amounts outstanding under the revolving credit facility due August 25, 2016, the 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 Facility

QEP’s revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a group of financial institutions. The credit facility provides for borrowing 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 for the maturity to be extended for up to two additional one-year periods, with the agreement of the lenders.

During the six months ended June 30, 2013 and 2012, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.33% and 2.05%, respectively. At June 30, 2013 and December 31, 2012, QEP was in compliance with the covenants under the credit agreement. At June 30, 2013, there was $888.5 million outstanding and $3.7 million of letters of credit issued under the credit facility.

Term Loan

Senior Notes

At June 30, 2013, 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 10 – 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 matters. 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 will not have a material effect on QEP's consolidated financial position, results of operations or cash flows.

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. EPA Region 6 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, EPA issued to QEP an Administrative Complaint for the alleged violations. QEP and EPA have reached an agreement to settle the alleged violations through an Administrative Order. In accordance with the terms of the settlement, QEP will pay an administrative penalty of $0.2 million. The Company and EPA are in the process of finalizing the settlement documents, and anticipate that a final order resolving the matter will be entered in the third quarter of 2013. 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. LDEQ has assumed lead responsibility for enforcement of the NOPP and may require the Company to pay a monetary penalty.

Litigation

Chieftain Royalty Company v. QEP Energy Company, Case No CIV-11-0212-R, U. S. District Court for the Western District of Oklahoma. This statewide class action was filed in January 2011 on behalf of QEP's Oklahoma royalty owners asserting various claims for damages related to royalty valuation on all of QEP's Oklahoma wells operated by QEP or from which QEP marketed gas. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The Court certified the class as to the breach of contract, breach of fiduciary duty and unjust enrichment claims. The parties successfully mediated the case in January 2013. On February 13, 2013, the parties executed a Stipulation and Agreement of Settlement (the Chieftain Settlement Agreement) providing for a cash payment from QEP to the class in the amount of $115.0 million. In consideration for the settlement payment, QEP received a full release of all claims regarding the calculation, reporting and payment of royalties from the sale of natural gas and its constituents for all periods prior to February 28, 2013, and all class members are enjoined from asserting claims related to such royalties. As part of the Chieftain Settlement Agreement, the parties also agreed on the methodology for the calculation and payment of future royalties payable by QEP, or its successors and assigns, under all class leases for the life of such leases. On May 31, 2013, the Court issued a final order approving the settlement, which is subject to appeal.

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 (1) breach of contract, (2) breach of implied covenant of good faith and fair dealing, (3) an accounting and (4) declaratory judgment related to a 1993 gathering agreement (1993 Agreement) executed when the parties were affiliates.

Under the 1993 Agreement, QEP Field Services provides gathering services to QGC. QGC is disputing the annual calculation of the gathering rate, which is based on a cost of service concept expressed in the 1993 Agreement and in a 1998 amendment, and is netting this disputed amount from its monthly payments of the gathering fees to QEP Field Services. As of June 30, 2013, QEP has deferred revenue of $5.8 million related to the QGC disputed amount. The annual gathering rate has been calculated in the same manner under the contract since it was amended in 1998, without any prior objection or challenge by QGC. Specific monetary damages are not asserted. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the same agreement. Management does not believe the litigation will have a material effect on QEP's financial position, results of operations or cash flows.

Note 11 – Share-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 share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 12.0 million shares available for future grants under the LTSIP at June 30, 2013. Share-based compensation expense is recognized in “General and administrative” on the Condensed Consolidated Statements of Operations. During the three and six months ended June 30, 2013, QEP recognized $7.1 million and $13.2 million, respectively, in total compensation expense related to share-based compensation compared to $6.6 million and $12.3 million during the three and six months ended June 30, 2012, respectively.

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 option 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.

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
	Six Months Ended
	June 30, 2013
Weighted-average grant-date fair value of awards granted during the period	$	15.32
Weighted-average risk-free interest rate	0.97		%
Weighted-average expected price volatility	58.5		%
Expected dividend yield	0.27		%
Expected term in years at the date of grant	5.5

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, 2012	1,697,471		$	25.23
Granted	321,048		30.12
Exercised	(209,500	)	9.60
Forfeited	—		—
Outstanding at June 30, 2013	1,809,019		$	27.90	4.2	$	3.7
Options Exercisable at June 30, 2013	1,231,704		$	26.35	3.3	$	3.7
Unvested Options at June 30, 2013	577,315		$	31.22	6.1	$	—

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $4.2 million and $6.9 million during the six months ended June 30, 2013 and 2012, respectively. The Company realized $1.4 million and $2.1 million of income tax benefit for the six months ended June 30, 2013 and 2012, which increased its Additional Paid-in-Capital (APIC) pool by $1.4 million as of June 30, 2013. As of June 30, 2013, $5.5 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.4 years. During the six months ended June 30, 2013, QEP received $0.5 million in cash in relation to the exercise of stock options.

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 six months ended June 30, 2013 and 2012, was $15.0 million and $12.6 million, respectively. The Company realized $0.3 million and $0.1 million of income tax expense for the six months ended June 30, 2013 and 2012, respectively, with no impact to the Company's APIC pool as of June 30, 2013. The weighted average grant-date fair value of restricted stock was $30.10 per share and $30.74 per share for the six months ended June 30, 2013 and 2012, respectively. As of June 30, 2013, $28.8 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 2.4 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, 2012	1,300,588		$	31.78
Granted	810,248		30.10
Vested	(499,193	)	31.73
Forfeited	(42,739	)	31.07
Unvested balance at June 30, 2013	1,568,904		$	30.94

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 $30.12 per share and $30.90 per share for the six months ended June 30, 2013 and 2012, respectively. As of June 30, 2013, $9.7 million of unrecognized compensation cost, representing the fair market value of performance shares granted under the CIP, is expected to be recognized over a weighted-average vesting period of 2.2 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, 2012	283,484		$	34.01
Granted	217,573		30.12
Vested	—		—
Forfeited	(1,163	)	30.12
Unvested balance at June 30, 2013	499,894		$	32.33

Note 12 – 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 six months ended June 30, 2013, the Company made contributions of $5.4 million to its funded pension plan, and $0.9 million to its unfunded pension plan. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. During the remainder of 2013, the Company expects to contribute approximately $2.7 million to its funded pension plans, approximately $2.1 million to its unfunded pension plans and approximately $0.1 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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(in millions)
Service cost	$	0.9		$	0.9		$	1.9		$	1.9
Interest cost	1.3			1.2			2.5			2.4
Expected return on plan assets	(1.0		)	(0.9		)	(2.0		)	(1.8		)
Amortization of prior service costs	1.3			1.3			2.5			2.6
Amortization of actuarial loss	0.6			0.2			1.2			0.4
Periodic expense	$	3.1		$	2.7		$	6.1		$	5.5



	Postretirement Benefits
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(in millions)
Service cost	$	—	$	—	$	—	$	—
Interest cost	0.1		0.1		0.2		0.2
Amortization of prior service costs	0.1		0.1		0.2		0.2
Recognized net actuarial loss	—		—		—		—
Periodic expense	$	0.2	$	0.2	$	0.4	$	0.4

Note 13 – Operations by Line of Business

QEP’s lines of business include natural gas and oil exploration and production (QEP Energy), midstream field services (QEP Field Services) 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.

The following table is a summary of operating results for the three months ended June 30, 2013, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	528.5		$	72.3		$	150.2		$	—		$	751.0
From affiliated customers	—			30.6			221.7			(252.3		)	—
Total Revenues	528.5			102.9			371.9			(252.3		)	751.0
Operating expenses
Purchased gas, oil and NGL expense	54.9			3.5			369.9			(221.3		)	207.0
Lease operating expense	45.7			—			—			(2.2		)	43.5
Natural gas, oil and NGL transportation and other handling costs	59.5			5.4			—			(27.6		)	37.3
Gathering, processing and other	—			23.0			0.5			—			23.5
General and administrative	30.0			10.9			1.2			(1.2		)	40.9
Production and property taxes	37.6			1.7			—			—			39.3
Depreciation, depletion and amortization	238.0			11.7			0.1			—			249.8
Other operating expenses	2.8			—			—			—			2.8
Total operating expenses	468.5			56.2			371.7			(252.3		)	644.1
Net gain (loss) from asset sales	100.5			(0.1		)	—			—			100.4
Operating income (loss)	160.5			46.6			0.2			—			207.3
Realized and unrealized gains on derivative contracts	109.4			—			4.6			—			114.0
Interest and other income	3.2			—			54.7			(54.8		)	3.1
Income from unconsolidated affiliates	—			1.6			—			—			1.6
Interest expense	(48.9		)	(5.3		)	(42.0		)	54.8			(41.4		)
Income before income taxes	224.2			42.9			17.5			—			284.6
Income tax provision	(82.1		)	(15.1		)	(7.6		)	—			(104.8		)
Net income	142.1			27.8			9.9			—			179.8
Net income attributable to noncontrolling interest	—			(1.4		)	—			—			(1.4		)
Net income attributable to QEP	$	142.1		$	26.4		$	9.9		$	—		$	178.4

The following table is a summary of operating results for the three months ended June 30, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	335.5		$	83.4		$	80.4		$	—		$	499.3
From affiliated customers	—			30.2			118.2			(148.4		)	—
Total Revenues	335.5			113.6			198.6			(148.4		)	499.3
Operating expenses
Purchased gas, oil and NGL expense	40.6			4.1			197.4			(117.2		)	124.9
Lease operating expense	41.4			—			—			(0.9		)	40.5
Natural gas, oil and NGL transportation and other handling costs	57.2			12.0			—			(28.5		)	40.7
Gathering, processing and other	—			20.4			0.5			(0.3		)	20.6
General and administrative	28.7			8.8			0.8			(1.5		)	36.8
Production and property taxes	18.2			1.2			—			—			19.4
Depreciation, depletion and amortization	198.0			16.3			0.1			—			214.4
Other operating expenses	57.5			—			—			—			57.5
Total operating expenses	441.6			62.8			198.8			(148.4		)	554.8
Operating (loss) income	(106.1		)	50.8			(0.2		)	—			(55.5		)
Realized and unrealized gains (losses) on derivative contracts	81.8			4.8			(4.3		)	—			82.3
Interest and other income	0.7			0.1			26.8			(26.7		)	0.9
Income from unconsolidated affiliates	0.1			1.3			—			—			1.4
Loss on early extinguishment of debt	—			—			(0.6		)	—			(0.6		)
Interest expense	(23.4		)	(3.6		)	(27.9		)	26.7			(28.2		)
(Loss) income before income taxes	(46.9		)	53.4			(6.2		)	—			0.3
Income tax benefit (provision)	16.6			(19.2		)	2.5			—			(0.1		)
Net (loss) income	(30.3		)	34.2			(3.7		)	—			0.2
Net income attributable to noncontrolling interest	—			(0.9		)	—			—			(0.9		)
Net (loss) income attributable to QEP	$	(30.3	)	$	33.3		$	(3.7	)	$	—		$	(0.7	)

The following table is a summary of operating results for the six months ended June 30, 2013, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	1,036.7		$	136.7		$	274.1		$	—		$	1,447.5
From affiliated customers	—			58.2			438.9			(497.1		)	—
Total Revenues	1,036.7			194.9			713.0			(497.1		)	1,447.5
Operating expenses
Purchased gas, oil and NGL expense	120.6			8.6			712.4			(437.8		)	403.8
Lease operating expense	86.7			—			—			(4.3		)	82.4
Natural gas, oil and NGL transportation and other handling costs	115.7			8.2			—			(52.6		)	71.3
Gathering, processing and other	—			43.3			0.8			—			44.1
General and administrative	66.7			20.4			2.2			(2.4		)	86.9
Production and property taxes	72.3			2.8			0.1			—			75.2
Depreciation, depletion and amortization	476.1			27.5			0.4			—			504.0
Other operating expenses	7.9			—			—			—			7.9
Total operating expenses	946.0			110.8			715.9			(497.1		)	1,275.6
Net gain (loss) from asset sales	100.6			(0.4		)	—			—			100.2
Operating income (loss)	191.3			83.7			(2.9		)	—			272.1
Realized and unrealized gains on derivative contracts	75.2			—			4.2			—			79.4
Interest and other income	4.9			0.3			105.9			(106.0		)	5.1
Income from unconsolidated affiliates	—			2.9			—			—			2.9
Interest expense	(94.2		)	(9.3		)	(83.3		)	106.0			(80.8		)
Income before income taxes	177.2			77.6			23.9			—			278.7
Income tax provision	(64.9		)	(27.6		)	(10.1		)	—			(102.6		)
Net income	112.3			50.0			13.8			—			176.1
Net income attributable to noncontrolling interest	—			(2.0		)	—			—			(2.0		)
Net income attributable to QEP	$	112.3		$	48.0		$	13.8		$	—		$	174.1

The following table is a summary of operating results for the six months ended June 30, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	732.3		$	177.0		$	193.2		$	—		$	1,102.5
From affiliated customers	—			56.3			250.5			(306.8		)	—
Total Revenues	732.3			233.3			443.7			(306.8		)	1,102.5
Operating expenses
Purchased gas, oil and NGL expense	113.1			4.1			445.0			(248.9		)	313.3
Lease operating expense	82.2			—			—			(1.6		)	80.6
Natural gas, oil and NGL transportation and other handling costs	107.6			20.8			—			(53.2		)	75.2
Gathering, processing and other	—			43.8			0.7			(0.2		)	44.3
General and administrative	61.1			13.2			1.4			(2.9		)	72.8
Production and property taxes	41.1			2.9			0.1			—			44.1
Depreciation, depletion and amortization	381.7			31.7			0.3			—			413.7
Other operating expenses	66.0			—			—			—			66.0
Total operating expenses	852.8			116.5			447.5			(306.8		)	1,110.0
Net gain from asset sales	1.5			—			—			—			1.5
Operating (loss) income	(119.0		)	116.8			(3.8		)	—			(6.0		)
Realized and unrealized gains on derivative contracts	289.0			8.9			0.7			—			298.6
Interest and other income	2.4			0.1			52.7			(52.6		)	2.6
Income from unconsolidated affiliates	0.1			3.2			—			—			3.3
Loss on early extinguishment of debt	—			—			(0.6		)	—			(0.6		)
Interest expense	(47.0		)	(5.9		)	(52.6		)	52.6			(52.9		)
Income (loss) before income taxes	125.5			123.1			(3.6		)	—			245.0
Income taxes	(47.7		)	(42.7		)	1.6			—			(88.8		)
Net income (loss)	77.8			80.4			(2.0		)	—			156.2
Net income attributable to noncontrolling interest	—			(1.7		)	—			—			(1.7		)
Net income (loss) attributable to QEP	$	77.8		$	78.7		$	(2.0	)	$	—		$	154.5

Note 14 – Subsequent Event

In July 2013, QEP Energy entered into a Purchase and Sale Agreement related to the disposition of certain of its non-core properties in the Southern Region for a purchase price of $66.8 million before purchase price adjustments. The Company expects to close the transaction in the third quarter of 2013.

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 Item 1 of this Quarterly Report on Form 10-Q.

The following information updates the discussion of QEP’s financial condition provided in its 2012 Annual Report on Form 10-K filing and analyzes the changes in the results of operations between the three and six month periods ended June 30, 2013 and 2012. 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 2012 Annual Report on Form 10-K.

OVERVIEW


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


•	QEP Field Services Company (QEP Field Services) provides midstream field services, including natural gas gathering, processing, compression and treating services, for affiliates and third parties; and


•	QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil, 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 the Texas Panhandle) of the United States. QEP's corporate headquarters are located in Denver, Colorado.

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;


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


•	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;


•	own a controlling interest in and operate midstream infrastructure in our core producing areas to capture value downstream of the wellhead;


•	build gas processing plants to extract liquids from our natural gas streams;


•	own or control assets to gather, compress and treat our production to drive down costs;


•	support the growth of our midstream business through the formation of a Master Limited Partnership;


•	actively market our QEP Energy production to maximize value;


•	utilize derivative contracts to mitigate the impact of natural gas, crude 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.

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, Pinedale Anticline, Uinta Basin, Woodford "Cana" and Haynesville Shale. These resource plays are characterized by unconventional oil or natural 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 exploration and production company peers. However, in certain of its resource plays, QEP, along with its peers, has experienced increased drilling and completion costs which could impact future drilling plans.

While historically a natural gas producer, the Company has increased its focus on growing the relative proportion of crude oil and NGL production in its exploration and production business. As part of the Company's liquids growth strategy, during the third quarter of 2012, QEP Energy acquired oil and gas properties in the Williston Basin for an aggregate purchase price of $1.4 billion, subject to post-closing adjustments (the 2012 Acquisition). During the first half of 2013, QEP Energy increased its crude oil and NGL (natural gas liquids) production by 34% compared to the first half of 2012. During the first half of 2013, crude oil and NGL revenue accounted for approximately 55% of QEP Energy’s field-level production revenues, compared to 51% during the first half of 2012.

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 might create significant long-term value. QEP believes that its experience, expertise, and substantial presence in its core operating areas, combined with its low-cost operating model and financial strength, enhance its ability to pursue acquisition opportunities. In addition, the Company will occasionally divest select non-core portfolio assets to redirect capital towards higher-return projects. In the second quarter of 2013, QEP Energy sold its interest in several non-core oil and gas properties located in the Northern Region for total cash proceeds of $139.7 million and a pre-tax gain on sale of $102.5 million, subject to post-closing adjustments. In July 2013, QEP Energy entered into a Purchase and Sale Agreement related to the disposition of certain non-core properties in the Southern Region for a purchase price of $66.8 million and the Company expects to close this transaction in the third quarter of 2013.

QEP owns and operates gathering and natural gas processing and treatment facilities in the majority of its core producing areas. These assets enable the Company to promptly connect its wells, better control its costs, and generate a significant, consistent revenue stream by providing gathering and processing services to third parties.

In January 2013, QEP announced that its Board of Directors had authorized the formation of a Master Limited Partnership (MLP) to support the growth of QEP's midstream business. The Company filed a registration statement with the SEC in the second quarter of 2013 for an initial public offering of common units of the MLP. QEP plans to contribute a majority of its gathering assets in Wyoming and North Dakota to the MLP. QEP expects to sell a minority interest in the MLP and raise $300 million to $400 million of gross proceeds. QEP plans to use the proceeds from the offering to fund ongoing operations, to repay debt under the Company's revolving credit facility and for general corporate purposes. The registration statement has not yet become effective and the common units in the MLP may not be sold nor may offers to buy be accepted prior to the time the registration statement becomes effective. QEP's announcement of this plan and the filing of the registration statement did not, and this disclosure does not, constitute an offer to sell or the solicitation of an offer to buy any securities and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of that jurisdiction.

Financial and Operating Results

QEP Energy reported total equivalent production of 77.9 Bcfe during the second quarter of 2013 and 155.9 Bcfe in the first half of 2013, a decrease of 2% and an increase of 1%, respectively, over the same periods in 2012. Crude oil and NGL production in the second quarter and first half of 2013 was 3,500.2 Mbbls and 6,747.6 Mbbls, an increase of 34% from the same periods in 2012. The Company's 2012 Acquisition contributed 664.1 Mbbls and 1,300.9 Mbbls of liquids production in the second quarter and first half of 2013.

During the second quarter of 2013, QEP Field Services' gathering throughput volumes decreased 16%, and NGL sales volumes decreased 28%, while fee-based processing volumes were 2% higher than the second quarter of 2012. During the first half of 2013, QEP Field Services' gathering throughput volumes decreased 13%, NGL sales volumes decreased 49% and fee-based processing volumes were 4% lower compared to the first half of 2012.

During the second quarter and first half of 2013, QEP Energy benefited from increased average realized prices compared to 2012. QEP Energy’s average total net realized equivalent price (including the impact of settled commodity derivatives) increased 26% to $6.47 per Mcfe for the second quarter of 2013 and increased 21% to $6.39 per Mcfe for the first half of 2013 compared to the first half of 2012. As a result of low ethane prices relative to natural gas prices, QEP Field Services' processing plants, in regard to its keep-whole processing activities, continue to operate in ethane rejection mode (where the majority of ethane is left in the production stream and sold as natural gas). When in ethane rejection mode, NGL volumes are lower and average NGL prices are higher as a result of the remaining components of the NGL stream having a higher price than ethane. During the second quarter and first half of 2013, NGL sales volumes declined, the impact of which was partially offset by an increase in average net realized NGL sales prices of 2% and 5%, respectively. During the second quarter and first half of 2013, QEP Field Services' fee-based processing rates increased 11%, while fee-based gathering rates were flat.

Factors Affecting Results of Operations

Oil, Natural Gas, and NGL Prices

Historically, field-level prices received for QEP's natural gas, NGL, and crude oil 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 crude oil. Changes in the market prices for natural gas, crude 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 June 30, 2013, assuming 2013 annual production of 317.5 Bcfe, QEP Energy had approximately 51% of its forecasted natural gas equivalent production covered with fixed-price swaps, including 57% of its forecasted natural gas production and 55% of its forecasted crude oil production covered with fixed-price swaps. See 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 natural gas prices, QEP Energy has allocated approximately 98% of its forecasted 2013 drilling and completion capital expenditure budget to oil and liquids-rich natural gas projects in its portfolio.

Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the outlook of the global economy, including the European debt crisis and its potential impact on global economic growth and the banking and financial sectors, political unrest in the Middle East and Africa, a slowing of growth in Asia, the United States federal budget deficit, 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 natural gas, NGL and crude oil supply, demand and prices, 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 during 2012 and continues to decrease in the first half of 2013 as producers have reduced drilling for natural gas in response to lower natural gas prices. A reduction in natural gas production has lagged the downturn in the natural gas rig count, because natural gas producers have a significant inventory of drilled wells waiting on completion and new high-rate horizontal wells continue to be completed. As a result of the lag, U.S. natural gas production did not decline in 2012 and has not yet declined in 2013. The U.S. natural gas market entered the storage injection season with record high inventory levels. However, strong natural gas demand from electric power generation resulted in a general firming of natural gas prices during the last half of 2012 and first half of 2013. Despite increased natural gas prices during the second quarter and first half of 2013, QEP expects U.S. natural gas prices to remain volatile 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 natural gas and crude oil. This shift in focus has caused domestic NGL production to increase dramatically. Increased NGL production, warmer-than-average winters, and price dislocations from infrastructure bottlenecks in certain regions, have all contributed to a weakening in domestic NGL prices, particularly ethane. QEP expects NGL prices to remain volatile for the foreseeable future. QEP anticipates global crude oil prices to 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 crude oil prices. In addition, transportation, refining, or other infrastructure constraints could introduce significant price differentials between regional markets where QEP sells its crude 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 commodity price environment, QEP continues to manage its capital spending program and financial flexibility accordingly.

Potential for Future Asset Impairments

The carrying value of the Company's properties is sensitive to declines in natural gas, crude oil and NGL prices. These assets are at risk of impairment if future prices for natural gas, crude oil or NGL prices decline. 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 natural gas, crude oil and NGL prices alone could result in an impairment of properties. The Company did not record any proved property impairments during the first half of 2013.

Critical Accounting Estimates

QEP’s significant accounting policies are described in Item 7 of Part II of its 2012 Annual Report on Form 10-K. The Company’s Condensed Consolidated Financial Statements are prepared in accordance with United States Generally Accepted Accounting Principles (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 obligations, share-based compensation, income taxes, and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.

RESULTS OF OPERATIONS

Net Income (Loss)

QEP Resources’ net income for the second quarter of 2013 was $178.4 million, or $0.99 per diluted share, compared to a net loss of $0.7 million, or no earnings per diluted share, in the second quarter of 2012. The increase in the second quarter of 2013 was due to a $172.4 million increase in QEP Energy’s net income primarily related to the $100.5 million gain recorded in connection with sales of certain non-core properties, higher realized equivalent prices and increased oil volumes partially offset by higher depreciation, depletion and amortization expenses and lower realized gains on derivative instruments when compared to the second quarter of 2012.

QEP Resources’ net income for the first half of 2013 was $174.1 million, or $0.97 per diluted share, compared to net income of $154.5 million, or $0.87 per diluted share in 2012. The increase in the first half of 2013 was due to a $34.5 million increase in QEP Energy’s net income and a $15.8 million increase in QEP Marketing and Resources' net income, offset by a $30.7 million decrease in QEP Field Services net income. QEP Energy's net income increased in the first half of 2013 due to its gain from asset sales, an increase in realized equivalent prices, increased oil volumes and a decrease in property impairments, partially offset by an increase in depreciation, depletion and amortization expense and interest expense and a decrease in unrealized gains on commodity derivative contracts. The increase in QEP Marketing and Resources' net income is related to intercompany interest income from interest expense charges to QEP Resources' subsidiaries. QEP Field Services’ decrease in net income during the first half of 2013 was driven by a 52% decrease in the keep-whole processing margin and 13% lower gathering margins.

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



	Three Months Ended June 30,								Six Months Ended June 30,
	2013		2012			Change			2013		2012			Change
	(in millions)
QEP Energy	$	142.1	$	(30.3	)	$	172.4		$	112.3	$	77.8		$	34.5
QEP Field Services	26.4		33.3			(6.9		)	48.0		78.7			(30.7		)
QEP Marketing and Resources	9.9		(3.7		)	13.6			13.8		(2.0		)	15.8
Net income (loss) attributable to QEP	$	178.4	$	(0.7	)	$	179.1		$	174.1	$	154.5		$	19.6
Earnings per diluted share	$	0.99	$	—		$	0.99		$	0.97	$	0.87		$	0.10
Average diluted shares	179.5		177.7			1.8			179.4		178.5			0.9

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 net income before the following items: certain significant accrued litigation loss contingencies, depreciation, depletion and amortization (DD&A), exploration expense, impairment, gains and losses from asset sales, unrealized gains and losses on derivative contracts, interest and other income, interest expense, loss on early extinguishment of debt and income taxes.

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



	Three Months Ended June 30,								Six Months Ended June 30,
	2013			2012		Change			2013			2012		Change
	(in millions)
QEP Energy	$	332.1		$	266.2	$	65.9		$	655.8		$	534.0	$	121.8
QEP Field Services	58.3			70.1		(11.8		)	111.5			153.0		(41.5		)
QEP Marketing and Resources	(0.9		)	0.6		(1.5		)	(2.8		)	0.6		(3.4		)
Adjusted EBITDA	$	389.5		$	336.9	$	52.6		$	764.5		$	687.6	$	76.9

Adjusted EBITDA increased to $389.5 million in the second quarter of 2013 from $336.9 million in 2012, due to 26% increase in average net realized equivalent prices and an 82% increase in oil production at QEP Energy offset in part by decreases in processing and gathering margins at QEP Field Services.

During the first half of 2013, Adjusted EBITDA increased to $764.5 million from $687.6 million in 2012, due to 4% higher net realized natural gas prices, 6% higher net realized crude oil prices, 11% higher realized NGL prices as a result of the rejection of lower value ethane and a 1% increase in total production at QEP Energy offset in part by decreases in processing and gathering margins at QEP Field Services.

The following tables are reconciliations of Adjusted EBITDA to net income, the most comparable GAAP financial measure:



	QEP Energy			QEP Field Services			QEP Marketing & Resources			QEP Resources
Three Months Ended June 30, 2013	(in millions)
Net income attributable to QEP	$	142.1		$	26.4		$	9.9		$	178.4
Unrealized gains on derivative contracts	(78.1		)	—			(5.8		)	(83.9		)
Net (gain) loss from asset sales	(100.5		)	0.1			—			(100.4		)
Interest and other income	(3.2		)	—			0.1			(3.1		)
Income tax provision	82.1			15.1			7.6			104.8
Interest expense	48.9			5.3			(12.8		)	41.4
Depreciation, depletion and amortization⁽¹⁾	238.0			11.4			0.1			249.5
Impairment	0.2			—			—			0.2
Exploration expenses	2.6			—			—			2.6
Adjusted EBITDA	$	332.1		$	58.3		$	(0.9	)	$	389.5

Three Months Ended June 30, 2012
Net (loss) income attributable to QEP	$	(30.3	)	$	33.3		$	(3.7	)	$	(0.7	)
Unrealized losses (gains) on derivative contracts	34.9			(1.5		)	5.0			38.4
Interest and other income	(0.7		)	(0.1		)	(0.1		)	(0.9		)
Income tax (benefit) provision	(16.6		)	19.2			(2.5		)	0.1
Interest expense	23.4			3.6			1.2			28.2
Loss on early extinguishment of debt	—			—			0.6			0.6
Depreciation, depletion and amortization⁽¹⁾	198.0			15.6			0.1			213.7
Impairment	55.4			—			—			55.4
Exploration expenses	2.1			—			—			2.1
Adjusted EBITDA	$	266.2		$	70.1		$	0.6		$	336.9

Six Months Ended June 30, 2013
Net income attributable to QEP	$	112.3		$	48.0		$	13.8		$	174.1
Unrealized losses (gains) on derivative contracts	5.9			—			(4.5		)	1.4
Net (gain) loss from asset sales	(100.6		)	0.4			—			(100.2		)
Interest and other income	(4.9		)	(0.3		)	0.1			(5.1		)
Income tax provision	64.9			27.6			10.1			102.6
Interest expense	94.2			9.3			(22.7		)	80.8
Depreciation, depletion and amortization⁽¹⁾	476.1			26.5			0.4			503.0
Impairment	0.2			—			—			0.2
Exploration expenses	7.7			—			—			7.7
Adjusted EBITDA	$	655.8		$	111.5		$	(2.8	)	$	764.5



	QEP Energy			QEP Field Services			QEP Marketing & Resources			QEP Resources
Six Months Ended June 30, 2012
Net income (loss) attributable to QEP	$	77.8		$	78.7		$	(2.0	)	$	154.5
Unrealized (gains) losses on derivative contracts	(88.8		)	(4.5		)	3.4			(89.9		)
Net gain from asset sales	(1.5		)	—			—			(1.5		)
Interest and other income	(2.4		)	(0.1		)	(0.1		)	(2.6		)
Income tax provision (benefit)	47.7			42.7			(1.6		)	88.8
Interest expense	47.0			5.9			—			52.9
Accrued litigation loss contingency⁽²⁾	6.5			—			—			6.5
Loss on early extinguishment of debt	—			—			0.6			0.6
Depreciation, depletion and amortization⁽¹⁾	381.7			30.3			0.3			412.3
Impairment	61.9			—			—			61.9
Exploration expenses	4.1			—			—			4.1
Adjusted EBITDA	$	534.0		$	153.0		$	0.6		$	687.6

__________________________

⁽¹⁾Excludes the noncontrolling interest's 22% share, or $0.3 million and $0.7 million during the three months ended June 30, 2013 and 2012, respectively, and $1.0 million and $1.4 million during the six months ended June 30, 2013 and 2012, respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C.

⁽²⁾ Includes certain significant litigation contingency items for the six months ended June 30, 2012.

QEP ENERGY

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Revenues	(in millions)
Natural gas sales	$	218.1		$	138.9		$	79.2		$	415.7		$	300.1		$	115.6
Oil sales	208.3			107.2			101.1			402.5			218.0			184.5
NGL sales	46.1			45.8			0.3			96.7			95.7			1.0
Purchased gas, oil and NGL sales	54.5			41.3			13.2			117.3			113.8			3.5
Other	1.5			2.3			(0.8		)	4.5			4.7			(0.2		)
Total Revenues	528.5			335.5			193.0			1,036.7			732.3			304.4
Operating expenses
Purchased gas, oil and NGL expense	54.9			40.6			14.3			120.6			113.1			7.5
Lease operating expense	45.7			41.4			4.3			86.7			82.2			4.5
Natural gas, oil and NGL transportation and other handling costs	59.5			57.2			2.3			115.7			107.6			8.1
General and administrative	30.0			28.7			1.3			66.7			61.1			5.6
Production and property taxes	37.6			18.2			19.4			72.3			41.1			31.2
Depreciation, depletion and amortization	238.0			198.0			40.0			476.1			381.7			94.4
Exploration expenses	2.6			2.1			0.5			7.7			4.1			3.6
Impairment	0.2			55.4			(55.2		)	0.2			61.9			(61.7		)
Total Operating Expenses	468.5			441.6			26.9			946.0			852.8			93.2
Net gain from asset sales	100.5			—			100.5			100.6			1.5			99.1
Operating Income (Loss)	160.5			(106.1		)	266.6			191.3			(119.0		)	310.3
Realized gains on derivative instruments	31.3			116.7			(85.4		)	81.1			200.2			(119.1		)
Unrealized gains (losses) on derivative instruments	78.1			(34.9		)	113.0			(5.9		)	88.8			(94.7		)
Interest and other income	3.2			0.7			2.5			4.9			2.4			2.5
Income from unconsolidated affiliates	—			0.1			(0.1		)	—			0.1			(0.1		)
Interest expense	(48.9		)	(23.4		)	(25.5		)	(94.2		)	(47.0		)	(47.2		)
Income (Loss) before Income Taxes	224.2			(46.9		)	271.1			177.2			125.5			51.7
Income tax (provision) benefit	(82.1		)	16.6			(98.7		)	(64.9		)	(47.7		)	(17.2		)
Net Income (Loss) Attributable to QEP	$	142.1		$	(30.3	)	$	172.4		$	112.3		$	77.8		$	34.5

Production volumes (Bcfe)
Northern Region
Pinedale	23.2			23.7			(0.5		)	44.9			45.9			(1.0		)
Williston Basin	11.1			3.4			7.7			20.1			6.5			13.6
Uinta Basin	7.0			5.9			1.1			12.8			10.5			2.3
Legacy	3.5			3.1			0.4			7.0			6.8			0.2
Southern Region
Haynesville/Cotton Valley	18.8			30.9			(12.1		)	41.1			58.9			(17.8		)
Midcontinent	14.3			12.6			1.7			30.0			25.2			4.8
Total production	77.9			79.6			(1.7		)	155.9			153.8			2.1
Total equivalent prices (per Mcfe)
Average equivalent field-level price	$	6.07		$	3.66		$	2.41		$	5.87		$	3.99		$	1.88
Commodity derivative impact	0.40			1.47			(1.07		)	0.52			1.30			(0.78		)
Net realized equivalent price	$	6.47		$	5.13		$	1.34		$	6.39		$	5.29		$	1.10

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 and six months ended June 30, 2013 compared to the three and six months ended June 30, 2012:



	Natural Gas			Oil		NGL			Total
	(in millions)
QEP Energy Production Revenues
Three months ended June 30, 2012 Revenues	$	138.9		$	107.2	$	45.8		$	291.9
Changes associated with volumes ⁽¹⁾	(15.3		)	88.2		(6.4		)	66.5
Changes associated with prices ⁽²⁾	94.5			12.9		6.7			114.1
Three months ended June 30, 2013 Revenues	$	218.1		$	208.3	$	46.1		$	472.5

QEP Energy Production Revenues
Six months ended June 30, 2012 Revenues	$	300.1		$	218.0	$	95.7		$	613.8
Changes associated with volumes ⁽¹⁾	(19.4		)	171.7		(11.2		)	141.1
Changes associated with prices ⁽²⁾	135.0			12.8		12.2			160.0
Six months ended June 30, 2013 Revenues	$	415.7		$	402.5	$	96.7		$	914.9

____________________________


⁽¹⁾	The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and six months ended June 30, 2013, as compared to the three and six months ended June 30, 2012, by the average field-level price for the three and six months ended June 30, 2012.


⁽²⁾	The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level prices from the three and six months ended June 30, 2013, as compared to the three and six months ended June 30, 2012, by volumes for the three and six months ended June 30, 2013.

Natural Gas Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012		Change			2013		2012		Change
Natural gas production volumes (Bcf)
Northern Region
Pinedale	20.1		18.2		1.9			39.1		35.2		3.9
Williston Basin	0.8		0.2		0.6			1.5		0.2		1.3
Uinta Basin	4.9		4.0		0.9			9.0		7.3		1.7
Legacy	3.2		2.7		0.5			6.0		5.8		0.2
Southern Region
Haynesville/Cotton Valley	18.7		30.9		(12.2		)	40.9		58.8		(17.9		)
Midcontinent	9.2		8.0		1.2			18.9		16.2		2.7
Total production	56.9		64.0		(7.1		)	115.4		123.5		(8.1		)
Natural gas prices (per Mcf)
Northern Region	$	3.90	$	2.07	$	1.83		$	3.65	$	2.35	$	1.30
Southern Region	3.76		2.23		1.53			3.56		2.48		1.08
Average field-level price	$	3.83	$	2.17	$	1.66		$	3.60	$	2.43	$	1.17
Commodity derivative impact	0.44		1.75		(1.31		)	0.61		1.60		(0.99		)
Net realized price	$	4.27	$	3.92	$	0.35		$	4.21	$	4.03	$	0.18

Natural gas revenues increased $79.2 million, or 57%, in the second quarter of 2013 due to higher field-level prices partially offset by lower volumes. The decrease in production volumes was driven by the suspension of QEP's Haynesville/Cotton Valley operated drilling program partially offset by increased production in QEP's Pinedale, Midcontinent, Uinta Basin and

Williston Basin properties. Natural gas field-level prices increased 76% during the second quarter of 2013 as a result of increased near-term demand.

Natural gas revenues increased $115.6 million, or 39%, during the first half of 2013 due to higher field-level prices offset by lower volumes. The decrease in production volumes was driven by the suspension of QEP's Haynesville/Cotton Valley operated drilling program partially offset by increased production from its drilling programs in Pinedale, the Midcontinent, Uinta Basin and Williston Basin. Natural gas field-level prices increased 48% during the first half of 2013 as a result of increased near-term demand.

Oil Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012		Change			2013		2012			Change
Crude oil production volumes (Mbbl)
Northern Region
Pinedale	161.1		153.8		7.3			309.9		306.1			3.8
Williston Basin	1,573.8		510.2		1,063.6			2,842.8		1,008.4			1,834.4
Uinta Basin	235.3		216.2		19.1			451.6		420.3			31.3
Legacy	67.7		65.0		2.7			152.0		137.6			14.4
Southern Region
Haynesville/Cotton Valley	10.8		13.0		(2.2		)	22.4		22.4			—
Midcontinent	336.5		349.8		(13.3		)	745.4		635.7			109.7
Total production	2,385.2		1,308.0		1,077.2			4,524.1		2,530.5			1,993.6
Crude oil prices (per bbl)
Northern Region	$	86.98	$	78.12	$	8.86		$	89.05	$	83.19		$	5.86
Southern Region	89.27		91.76		(2.49		)	88.57		94.51			(5.94		)
Average field-level price	$	87.31	$	81.90	$	5.41		$	88.97	$	86.14		$	2.83
Commodity derivative impact	2.68		1.70		0.98			2.55		(0.19		)	2.74
Net realized price	$	89.99	$	83.60	$	6.39		$	91.52	$	85.95		$	5.57

Oil revenues increased $101.1 million, or 94%, in the second quarter of 2013 due to higher volumes and higher average prices. The increase in production volumes was primarily driven by properties acquired in QEP's Williston Basin 2012 Acquisition which contributed 578.3 Mbbls during the second quarter of 2013. Oil field-level prices increased 7% in the second quarter of 2013, despite a decrease in Brent crude oil prices and relatively flat WTI Cushing crude oil prices. The increase in QEP's field-level prices was due to improved pricing in the Williston Basin. Williston Basin pricing increased in the second quarter of 2013 due to the improvement in price differentials and the sale of crude oil referenced against Brent prices in the second quarter of 2013. Average Brent spot prices were higher than WTI Cushing in the second quarter of both 2013 and 2012.

Oil revenues increased $184.5 million, or 85%, in the first half of 2013 due to higher volumes and higher average prices. The increase in production volumes was primarily driven by properties acquired in the 2012 Acquisition which contributed 1,138.8 Mbbls during the first half of 2013. The additional 695.6 Mbbls increase in the Williston Basin production relates to development drilling on QEP's pre-acquisition acreage. The increased volumes in the Midcontinent were related to increases in production from QEP's properties in the Granite Wash and Woodford "Cana" shale plays. Oil field-level prices increased 3% in the first half of 2013, despite a decrease in WTI Cushing and Brent crude oil prices due to the improved pricing in the Williston Basin.

NGL Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2013		2012		Change			2013		2012		Change
NGL production volumes (Mbbl)
Northern Region
Pinedale	337.7		748.8		(411.1		)	649.6		1,465.9		(816.3		)
Williston Basin	142.9		24.9		118.0			255.0		40.6		214.4
Uinta Basin	94.7		86.6		8.1			172.1		107.9		64.2
Legacy	20.2		23.3		(3.1		)	30.9		49.0		(18.1		)
Southern Region
Haynesville/Cotton Valley	4.0		2.0		2.0			9.3		4.4		4.9
Midcontinent	515.5		412.2		103.3			1,106.6		851.7		254.9
Total production	1,115.0		1,297.8		(182.8		)	2,223.5		2,519.5		(296.0		)
NGL prices (per bbl)
Northern Region	$	51.21	$	36.76	$	14.45		$	55.37	$	40.52	$	14.85
Southern Region	29.99		32.11		(2.12		)	31.67		33.06		(1.39		)
Average field-level price	$	41.32	$	35.27	$	6.05		$	43.48	$	37.98	$	5.50
Commodity derivative impact	—		2.04		(2.04		)	—		1.23		(1.23		)
Net realized price	$	41.32	$	37.31	$	4.01		$	43.48	$	39.21	$	4.27

NGL revenues increased $0.3 million, or 1%, during the second quarter of 2013, due to an increased average price per barrel partially offset by decreased production volumes. NGL prices increased 17% during the second quarter of 2013 primarily as a result of not removing ethane from the wet gas production stream. When ethane is sold as part of the natural gas stream instead of being recovered as an NGL, the average NGL barrel sales price increases as the price of the remaining NGL components are higher than the ethane price. Production volumes decreased in Pinedale due to processing plants running in ethane rejection mode. The decrease in Pinedale was partially offset by increases in the Midcontinent and Williston Basin. The Midcontinent increase was driven by new well completions in the Woodford "Cana" shale and Granite Wash areas while the Williston Basin's NGL volume growth was the result of the 2012 Acquisition which contributed 85.8 Mbbls to the second quarter of 2013 and continued development drilling on pre-acquisition acreage.

During the first half of 2013, NGL revenues increased $1.0 million, or 1%, due to an increased price per barrel partially offset by decreased production volumes. NGL field-level prices increased 14% as a result of ethane rejection. Production volumes decreased in Pinedale due to ethane rejection. The decrease in Pinedale was partially offset by increases in the Midcontinent, Williston Basin and Uinta Basin. The Midcontinent increase was driven by additional Woodford "Cana" shale wells while the Williston Basin's NGL volume growth was primarily the result of the 2012 Acquisition which contributed 162.1 Mbbls to the first half of 2013. In addition, the Uinta Basin increased volumes despite its processing plants running in ethane rejection mode due to QEP Energy executing a fee-based processing agreement in mid-2012 with QEP Field Services for a portion of the Red Wash Unit's natural gas production.

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 our gas, oil and NGL resale activities:



	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Resale Margin	(in millions)
Purchased gas, oil and NGL sales	$	54.5		$	41.3		$	13.2		$	117.3		$	113.8		$	3.5
Purchased gas, oil and NGL expense	(54.9		)	(40.6		)	(14.3		)	(120.6		)	(113.1		)	(7.5		)
Resale margin (loss) gain	$	(0.4	)	$	0.7		$	(1.1	)	$	(3.3	)	$	0.7		$	(4.0	)

During the second quarter and first half of 2013, QEP Energy recorded a loss on resale margin 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 suspension of its Haynesville drilling program.

QEP Energy Drilling Activity

The following table presents operated and non-operated well completions for the three and six months ended June 30, 2013:



	Operated Completions				Non-operated Completions
	Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended
	June 30, 2013		June 30, 2013		June 30, 2013		June 30, 2013
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	35	27.1	57	42.0	—	—	—	—
Williston Basin	15	12.8	27	23.8	18	1.0	52	2.7
Uinta Basin	13	11.0	20	17.4	59	0.1	93	0.2
Legacy	—	—	—	—	—	—	6	0.2
Southern Region
Haynesville/Cotton Valley	—	—	5	2.4	1	0.1	2	0.2
Midcontinent	10	7.7	19	15.4	23	1.5	65	3.8

The following table presents operated and non-operated wells being drilled or waiting on completion at June 30, 2013:



	Operated				Non-operated
	Being drilled		Waiting on completion		Being drilled		Waiting on completion
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	20	11.3	55	21.0	—	—	—	—
Williston Basin	23	20.6	11	9.8	10	0.3	28	1.1
Uinta Basin⁽¹⁾	4	4.0	7	7.0	—	—	—	—
Legacy	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	7	0.8	—	—
Midcontinent	—	—	1	1.0	21	1.4	50	7.3

___________________________

⁽¹⁾ The non-operated well total for the Uinta Basin does not include wells that are being drilled in the Monument Butte unit in which QEP owns a very small working interest.

Operating expenses

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2013		2012		Change		2013		2012		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	3.06	$	2.49	$	0.57	$	3.06	$	2.48	$	0.58
Lease operating expense	0.59		0.52		0.07		0.56		0.53		0.03
Natural gas, oil and NGL transportation and other handling costs	0.76		0.72		0.04		0.74		0.70		0.04
Production taxes	0.48		0.23		0.25		0.46		0.27		0.19
Operating Expenses	$	4.89	$	3.96	$	0.93	$	4.82	$	3.98	$	0.84

Depreciation, depletion and amortization. DD&A expense increased $40.0 million, or $0.57 per Mcfe, in the second quarter of 2013 when compared to 2012 due to increases in the Williston Basin and Haynesville/Cotton Valley partially offset by a decrease in the Uinta Basin. The increase in the Williston Basin rate is due to the additional proved costs recorded as part of the 2012 Acquisition while the increase in the Haynesville/Cotton Valley rate was due to a year-end 2012 negative revision of proved undeveloped reserves associated with lower prices. These increases were partially offset by a decrease in the Uinta Basin rate due to a 2012 proved property impairment and the addition of proved undeveloped reserves recorded at year-end 2012.

During the first half of 2013, DD&A expense increased $94.4 million, or $0.58 per Mcfe, compared to the first half of 2012 due to increases in the Williston Basin and Haynesville/Cotton Valley partially offset by a decrease in the Uinta Basin. The increase in the Williston Basin rate is due to the additional proved costs recorded as part of the 2012 Acquisition while the increase in the Haynesville/Cotton Valley rate was due to a year-end 2012 negative revision of proved undeveloped reserves associated with lower prices. These increases were partially offset by a decrease in the Uinta Basin rate due to a 2012 proved property impairment and the addition of proved undeveloped reserves recorded at year-end 2012.

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 June 30,						Six Months Ended June 30,
	2013		2012		Change		2013		2012		Change
	(per Mcfe)
Northern Region	$	0.63	$	0.60	$	0.03	$	0.63	$	0.59	$	0.04
Southern Region	0.53		0.46		0.07		0.47		0.49		(0.02		)
Average lease operating expense	0.59		0.52		0.07		0.56		0.53		0.03

QEP Energy’s LOE increased $4.3 million, or 13% per Mcfe, during the second quarter of 2013 compared to 2012. The Southern Region's LOE per Mcfe increase during the second quarter of 2013 was driven by a 19% increase in its Haynesville properties due to its declining production but relatively flat labor, pumper costs and operating expenses due to the slight increase in total well count. The Northern Region increase was driven by an 11% per Mcfe increase in the Uinta Basin due to higher compression and transportation costs. In addition, the Northern Region per Mcfe LOE grew by 18% in Pinedale due to an increase in workover expense in the second quarter of 2013.

QEP Energy’s LOE increased $4.5 million, or 6% per Mcfe, during the first half of 2013 compared to 2012. The Northern Region increase was driven by a 24% per Mcfe increase in the Uinta Basin due to higher compression and transportation costs and a 19% increase in Pinedale due to the increase in workover expense in the first half of 2013. The increase in the Northern Region properties was offset by a decrease in Southern Region properties. The Southern Region LOE per Mcfe decrease in the first half of 2013 was driven by a 29% decline at its Woodford properties due to additional cost savings measures.

Natural gas, oil and NGL transportation and other handling costs. Natural gas, oil and NGL transportation and other handling costs increased $2.3 million, or $0.04 per Mcfe, in the second quarter of 2013 compared to the second quarter of 2012 due to increases in costs in the Haynesville/Cotton Valley field and Williston Basin. Haynesville/Cotton Valley transportation and other handling costs per Mcfe increased 26% due to larger decreases in production volumes than transportation costs. Transportation and other handling costs per Mcfe in the Williston Basin increased 42% due to the addition of the acquired properties from the 2012 Acquisition.

Natural gas, oil and NGL transportation and other handling costs increased $8.1 million, or $0.04 per Mcfe, in the first half of 2013 compared to 2012 due to increases in costs in the Haynesville/Cotton Valley field and Williston Basin. Haynesville/Cotton Valley transportation and other handling costs per Mcfe increased 22% due to larger decreases in production volumes than transportation costs. Transportation and other handling costs per Mcfe in the Williston Basin increased 62% in the first half of 2013 due to increased gathering costs associated with the acquired properties from the 2012 Acquisition.

Production 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 $19.4 million, or $0.25 per Mcfe, during the second quarter of 2013, as a result of increased natural gas, oil and NGL revenues due to higher field-level natural gas, oil and NGL prices and higher oil production.

Production taxes increased $31.2 million, or $0.19 per Mcfe, during the first half of 2013, as a result of increased revenues due to higher field-level prices and higher oil production.

Exploration expense. Exploration expenses increased $0.5 million during the three months ended June 30, 2013, compared with the 2012 period. The second quarter of 2013 increase related to increases in exploration-related labor, environmental expenses and seismic studies.

During the first half of 2013, exploration expenses increased $3.6 million compared to the 2012 period. The 2013 increase primarily related to an increase in seismic studies of $3.2 million.

Impairment expense. During the second quarter and first half of 2013, impairment expense was $0.2 million due to the write-off of expiring unproved leaseholds. Impairment expenses of $55.4 million and $61.9 million were recorded during the second quarter and first half of 2012 on certain proved and unproved properties due to lower natural gas prices.

QEP FIELD SERVICES

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
	(in millions)
Revenues
NGL sales	$	29.2		$	36.3		$	(7.1	)	$	47.0		$	83.8		$	(36.8	)
Processing (fee based)	19.4			17.6			1.8			35.8			33.6			2.2
Other processing fees	—			—			—			4.9			3.0			1.9
Gathering	37.8			45.8			(8.0		)	75.4			87.7			(12.3		)
Other gathering	13.1			9.3			3.8			23.3			20.6			2.7
Purchased gas, oil and NGL sales	3.4			4.6			(1.2		)	8.5			4.6			3.9
Total Revenues	102.9			113.6			(10.7		)	194.9			233.3			(38.4		)
Operating expenses
Purchased gas, oil and NGL expense	3.5			4.1			(0.6		)	8.6			4.1			4.5
Processing	4.1			3.7			0.4			8.2			7.4			0.8
Processing plant fuel and shrinkage	9.3			8.4			0.9			15.2			18.5			(3.3		)
Gathering	9.6			8.3			1.3			19.9			17.9			2.0
Natural gas, oil and NGL transportation and other handling costs	5.4			12.0			(6.6		)	8.2			20.8			(12.6		)
General and administrative	10.9			8.8			2.1			20.4			13.2			7.2
Taxes other than income taxes	1.7			1.2			0.5			2.8			2.9			(0.1		)
Depreciation, depletion and amortization	11.7			16.3			(4.6		)	27.5			31.7			(4.2		)
Total Operating Expenses	56.2			62.8			(6.6		)	110.8			116.5			(5.7		)
Net (loss) gain from asset sales	(0.1		)	—			(0.1		)	(0.4		)	—			(0.4		)
Operating Income	46.6			50.8			(4.2		)	83.7			116.8			(33.1		)
Interest and other income	—			0.1			(0.1		)	0.3			0.1			0.2
Income from unconsolidated affiliates	1.6			1.3			0.3			2.9			3.2			(0.3		)
Realized gains on derivative instruments	—			3.3			(3.3		)	—			4.4			(4.4		)
Unrealized gains on derivative instruments	—			1.5			(1.5		)	—			4.5			(4.5		)
Interest expense	(5.3		)	(3.6		)	(1.7		)	(9.3		)	(5.9		)	(3.4		)
Income before Income Taxes	42.9			53.4			(10.5		)	77.6			123.1			(45.5		)
Income taxes	(15.1		)	(19.2		)	4.1			(27.6		)	(42.7		)	15.1
Net income	27.8			34.2			(6.4		)	50.0			80.4			(30.4		)
Net income attributable to noncontrolling interest	(1.4		)	(0.9		)	(0.5		)	(2.0		)	(1.7		)	(0.3		)
Net Income Attributable to QEP	$	26.4		$	33.3		$	(6.9	)	$	48.0		$	78.7		$	(30.7	)

Gathering Margin

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Gathering Margin	(in millions)
Gathering revenues	$	37.8		$	45.8		$	(8.0	)	$	75.4		$	87.7		$	(12.3	)
Other gathering revenues	13.1			9.3			3.8			23.3			20.6			2.7
Gathering expense	(9.6		)	(8.3		)	(1.3		)	(19.9		)	(17.9		)	(2.0		)
Gathering margin	$	41.3		$	46.8		$	(5.5	)	$	78.8		$	90.4		$	(11.6	)
Operating Statistics
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers	54.8			63.2			(8.4		)	108.9			124.2			(15.3		)
For affiliated customers	57.2			70.7			(13.5		)	114.4			133.4			(19.0		)
Total Gas Gathering Volumes	112.0			133.9			(21.9		)	223.3			257.6			(34.3		)
Average gas gathering revenue (per MMBtu)	$	0.34		$	0.34		$	—		$	0.34		$	0.34		$	—

During the second quarter of 2013, gathering margin declined 12% due to a 16% decrease in gathering system throughput volumes. Gathering system throughput volumes decreased primarily as a result of a 48% decline at QEP Field Services' Northwest Louisiana Hub primarily due to lower QEP Energy production resulting from the suspension of drilling in Haynesville in mid-2012.

During the first half of 2013, gathering margin declined 13% due to a 13% decrease in gathering system throughput volumes. Gathering system throughput volumes decreased due to the 40% decline at QEP Field Services' Northwest Louisiana Hub from decreased production in the Haynesville shale play.

Processing Margin

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Processing Margin	(in millions)
NGL sales	$	29.2		$	36.3		$	(7.1	)	$	47.0		$	83.8		$	(36.8	)
Realized gains from commodity derivative contract settlements	—			3.3			(3.3		)	—			4.4			(4.4		)
Processing (fee-based) revenues	19.4			17.6			1.8			35.8			33.6			2.2
Other processing fees	—			—			—			4.9			3.0			1.9
Processing expense	(4.1		)	(3.7		)	(0.4		)	(8.2		)	(7.4		)	(0.8		)
Processing plant fuel and shrink expense	(9.3		)	(8.4		)	(0.9		)	(15.2		)	(18.5		)	3.3
Natural gas, oil and NGL transportation and other handling costs	(5.4		)	(12.0		)	6.6			(8.2		)	(20.8		)	12.6
Processing margin	$	29.8		$	33.1		$	(3.3	)	$	56.1		$	78.1		$	(22.0	)
Keep-whole processing margin⁽¹⁾	$	14.5		$	19.2		$	(4.7	)	$	23.6		$	48.9		$	(25.3	)

Operating Statistics
Natural gas processing volumes
NGL sales (Mbbl)	708.8			985.3			(276.5		)	1,049.9			2,062.0			(1,012.1		)
Average net realized NGL sales price (per bbl)⁽²⁾	$	41.21		$	40.22		$	0.99		$	44.82		$	42.76		$	2.06
Fee-based processing volumes (in millions of MMBtu)
For unaffiliated customers	28.3			29.7			(1.4		)	48.8			57.7			(8.9		)
For affiliated customers	37.2			34.8			2.4			70.4			66.5			3.9
Total fee-based processing volumes	65.5			64.5			1.0			119.2			124.2			(5.0		)
Average fee-based processing revenue (per MMBtu)	$	0.30		$	0.27		$	0.03		$	0.30		$	0.27		$	0.03

____________________________


⁽¹⁾	Keep-whole processing margin is calculated as NGL sales less processing plant fuel and shrink, natural 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.

Although a significant portion of QEP Field Services' gas processing services are performed for a volumetric-based fee, QEP Field Services also provides “keep-whole” processing services for certain customers. Under a keep-whole processing contract, QEP Field Services retains and sells NGL extracted at its processing plants and keeps the customer “whole” by delivering a Btu-equivalent amount of natural gas to the customer. Keep-whole processing exposes the Company to the “frac” spread. The frac spread is the difference between the market value of NGL extracted at the processing plant and the market value of an energy-equivalent volume of natural gas.

QEP Field Services' keep-whole processing margin decreased 24% during the second quarter of 2013, due to a 28% decrease in NGL sales volumes. The decrease in NGL sales volumes is the result of its processing plants running in ethane rejection mode due to low ethane prices. Partially offsetting this decline was an increase in the average net realized NGL sales price. Including the impact of gains on derivative contract settlements, average NGL realized prices increased 2% in the second quarter of 2013, primarily the result of a higher value NGL barrel due to the reduced amount of ethane in the barrel as the processing plants ran in ethane rejection mode and ethane sales prices were lower than other NGL products' sales prices. In addition, keep-whole margin was positively impacted in the second quarter of 2013 from decreased natural gas, oil, and NGL transportation and other handling costs. Transportation costs were lower in the second quarter of 2013 due to the reduction in ethane volumes.

Fee-based processing revenues increased during the second quarter of 2013 due to an 11% increase in average fee-based processing rate and a 2% increase in fee-based processing volumes. During the second quarter of 2013, the increase in fee-based processing volumes was the result of additional gas processed at the Blacks Fork Hub. Approximately 80% and 78% of

QEP Field Services’ net operating revenue was derived from fee-based gathering and processing agreements in the second quarter of 2013 and 2012, respectively.

QEP Field Services' keep-whole processing margin decreased 52% during the first half of 2013, due to a 49% decrease in NGL sales volumes as a the result of its processing plants running in ethane rejection mode due to low ethane prices. Partially offsetting this decline was an increase in the average net realized NGL sales price. Including the impact of gains on derivative contract settlements, average NGL realized prices increased 5% in the first half of 2013, due to the higher value NGL barrel. Keep-whole margins were positively impacted in the first half of 2013 from decreased natural gas, oil, and NGL transportation and other handling costs due to the reduction in ethane volumes.

Fee-based processing revenues increased during the first half of 2013 due to an 11% increase in average fee-based processing rate, offset by a 4% decrease in fee-based processing volumes. During the first half of 2013, the decrease in fee-based processing volumes was the result of lower unaffiliated volumes from a third-party shipper disruption caused by a fire at one of the shipper's compression stations. Other processing fees increased 63% in the first half of 2013 due to increased deficiency payments from customers who did not meet their contractual annual minimum throughput commitments for gathering or processing volumes. Approximately 81% and 75% of QEP Field Services’ net operating revenue was derived from fee-based gathering and processing agreements in the first half of 2013 and 2012, respectively.

QEP MARKETING AND RESOURCES

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
	(in millions)
Revenues
Purchased gas, oil and NGL sales	$	370.1		$	196.6		$	173.5		$	709.4		$	439.8		$	269.6
Other	1.8			2.0			(0.2		)	3.6			3.9			(0.3		)
Total Revenues	371.9			198.6			173.3			713.0			443.7			269.3
Operating expenses
Purchased gas, oil and NGL expense	369.9			197.4			172.5			712.4			445.0			267.4
Gathering, processing and other	0.5			0.5			—			0.8			0.7			0.1
General and administrative	1.2			0.8			0.4			2.2			1.4			0.8
Production and property taxes	—			—			—			0.1			0.1			—
Depreciation, depletion and amortization	0.1			0.1			—			0.4			0.3			0.1
Total Operating Expenses	371.7			198.8			172.9			715.9			447.5			268.4
Operating Income (Loss)	0.2			(0.2		)	0.4			(2.9		)	(3.8		)	0.9
Realized (loss) gain on derivative instruments	(1.2		)	0.7			(1.9		)	(0.3		)	4.1			(4.4		)
Unrealized gain (loss) on derivative instruments	5.8			(5.0		)	10.8			4.5			(3.4		)	7.9
Interest and other income	54.7			26.8			27.9			105.9			52.7			53.2
Loss on extinguishment of debt	—			(0.6		)	0.6			—			(0.6		)	0.6
Interest expense	(42.0		)	(27.9		)	(14.1		)	(83.3		)	(52.6		)	(30.7		)
Income (Loss) before Income Taxes	17.5			(6.2		)	23.7			23.9			(3.6		)	27.5
Income tax (provision) benefit	(7.6		)	2.5			(10.1		)	(10.1		)	1.6			(11.7		)
Net Income (Loss) Attributable to QEP	$	9.9		$	(3.7	)	$	13.6		$	13.8		$	(2.0	)	$	15.8

Resale Margin

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Resale Margin	(in millions)
Purchased gas, oil and NGL sales	$	370.1		$	196.6		$	173.5		$	709.4		$	439.8		$	269.6
Purchased gas, oil and NGL expense	(369.9		)	(197.4		)	(172.5		)	(712.4		)	(445.0		)	(267.4		)
Realized gain (loss) on derivative instruments	(1.2		)	0.7			(1.9		)	(0.3		)	4.1			(4.4		)
Resale margin loss	$	(1.0	)	$	(0.1	)	$	(0.9	)	$	(3.3	)	$	(1.1	)	$	(2.2	)

QEP Marketing's loss on resale margin was primarily the result of the fulfillment of firm transportation contract commitments. Purchased gas, oil and NGL sales increased by $173.5 million, or 88%, during the second quarter of 2013, due to an $89.9 million increase in resale gas sales and an $83.6 million increase in resale oil and NGL sales. Resale natural gas sales increased due to a 92% increase in the resale price and a 6% increase in resale gas volumes. Resale oil and NGL sales increased due to a 9% increase in resale price and a 61% increase in resale volumes

Purchased gas, oil and NGL expense, which includes transportation expense, increased 87% in the second quarter of 2013, due to an $87.7 million increase in resale gas purchases and an $83.7 million increase in resale oil and NGL purchases. Resale natural gas purchased increased due to a 104% increase in the resale price and a 3% increase in resale purchase volumes. Resale oil and NGL sales increased due to a 61% increase in resale purchase volumes and a 10% increase in resale purchase price.

Purchased gas, oil and NGL sales increased by $269.6 million, or 61%, during the first half of 2013, due to a $110.9 million increase in resale gas sales and a $158.7 million increase in resale oil and NGL sales. Resale natural gas sales increased due to a 53% increase in the resale price while resale gas volumes were consistent period to period. Resale oil and NGL sales increased due to a 60% increase in resale volumes and a 5% increase in resale price.

Purchased gas, oil and NGL expense, which includes transportation expense, increased 60% in the first half of 2013, due to a $107.9 million increase in resale gas purchases and a $158.8 million increase in resale oil and NGL purchases. Resale natural gas purchased increased due to a 57% increase in the resale price, offset by a 1% decrease in resale purchase volumes. Resale oil and NGL sales increased due to a 60% increase in resale purchase volumes and a 5% increase in resale purchase price.

OTHER CONSOLIDATED EXPENSES AND INCOME

General and administrative expense. During the second quarter of 2013, general and administrative (G&A) expense increased $4.1 million, or 11% compared to 2012. The increase in G&A in 2013 was primarily due to a $5.5 million increase in professional and outside services mainly related to ongoing implementation of a new Enterprise Resource Planning system as well as software maintenance costs and other contracted or professional services and a $3.1 million increase in labor costs due to the increased number of employees and the Company's annual compensation program. These increases were partially offset by a $2.4 million decrease in the mark-to-market value of the deferred compensation wrap plan and Cash Incentive Plan (CIP) and a $2.0 million decrease in restructuring costs.

During the first half of 2013, G&A expense increased $14.1 million, or 19%, compared to the first half of 2012. The increase in G&A in 2013 was primarily due to a $10.0 million increase in professional and outside services mainly related to ongoing implementation of a new Enterprise Resource Planning system as well as software maintenance costs and other contracted or professional services and a $7.7 million increase in labor costs due to the increased number of employees and the Company's annual compensation program. These increases were partially offset by a $4.3 million decrease in restructuring costs and a $1.7 million decrease in the mark-to-market value of the deferred compensation wrap plan and CIP.

Realized and unrealized 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 second quarter of 2013, gains on commodity derivative instruments were $110.2 million, of which $30.8 million was realized and $79.4 million was unrealized. During the second quarter of 2012, gains on commodity derivative instruments were $86.6 million, of which $120.7 million was realized gains and $34.1 million was unrealized losses. Additionally, during the second quarter of 2013, gains from interest rate swaps were $3.8 million, of which $0.7 million was realized losses and $4.5 million was unrealized gains.

During the first half of 2013, gains on commodity derivative instruments were $75.8 million, of which $82.1 million was realized gains and $6.3 million was unrealized losses. During the first half of 2012, gains on commodity derivative instruments were $302.9 million, of which $208.7 million was realized and $94.2 million was unrealized. Additionally, during the first half of 2013, losses from interest rate swaps were $3.6 million, of which $1.3 million was realized losses and $4.9 million was unrealized gains.

Interest expense. Interest expense increased $13.2 million, or 47%, during the second quarter of 2013 when compared to the second quarter of 2012. The increase was attributable to average debt levels that were approximately $1.6 billion, or 91%, higher than average debt levels in the second quarter of 2012. The increase in average debt levels is primarily related to the issuance of QEP's $650.0 million 2023 senior notes in the third quarter of 2012, which was used to fund the 2012 Acquisition, as well as higher balances under our revolving credit facility during the period ended June 30, 2013.

Interest expense increased $27.9 million, or 53%, during the first half of 2013 when compared to the first half of 2012. The increase was attributable to average debt levels that were approximately $1.5 billion, or 86%, higher than average debt levels in the first half of 2012. The increase in average debt levels is mostly related to the issuance of QEP's $650.0 million 2023 senior notes in the third quarter of 2012, which was used to fund the 2012 Acquisition, as well as higher balances under our revolving credit facility for the period ended June 30, 2013.

Income taxes. Income tax provision increased $104.7 million during the second quarter of 2013 compared to the second quarter 2012. The increase was primarily the result of higher income before income taxes and a higher combined effective federal and state income tax rate of 36.8% for the second quarter of 2013 compared to 33.3% for the second quarter 2012.

Income tax provision increased $13.8 million, or 16%, during the first half of 2013 compared to the first half of 2012. The increase was primarily the result of higher income before income taxes and a higher combined effective federal and state income tax rate of 36.8% for the first half of 2013 compared to 36.2% for the first half of 2012.

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 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.

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



	June 30, 2013			December 31, 2012
	(in millions, except %)
Cash and cash equivalents	$	139.7		$	—
Amount available under the credit facility ⁽¹⁾	607.8			805.9
Total liquidity	$	747.5		$	805.9
Total debt	$	3,405.7		$	3,206.9
Total common shareholders' equity	3,404.6			3,266.0
Ratio of debt to total capital ⁽²⁾	50		%	50		%

____________________________


⁽¹⁾	See discussion of revolving credit facility below. Availability under the credit facility is reduced by outstanding letters of credit of $3.7 million as of June 30, 2013, and $4.1 million as of December 31, 2012.


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

Credit Facility

QEP’s 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 provisions which would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for two additional one-year periods. QEP’s weighted-average interest rate on borrowings from its credit facility was 2.33% during the first half of 2013. At June 30, 2013, QEP was in compliance with the debt covenants under the credit agreement. At July 26, 2013, QEP had $815.0 million of borrowings and $3.7 million of letters of credit outstanding under its credit facility.

Term Loan

QEP's $300.0 million term loan facility provides for borrowings at short-term interest rates and contains covenants, restrictions and interest rates that are substantially the same as the Company’s revolving credit facility. The term loan matures in April of 2017, and the maturity date may be extended one year with the agreement of the lenders. During the first half of 2013, QEP’s weighted-average interest rate on the term loan was 2.23%. In conjunction with the term loan, QEP entered into interest rate swap contracts with a combined notional principal amount of $300.0 million which will mature in March 2017. Under the swap contracts, QEP pays 1.07% for the life of the swaps and receives one-month LIBOR. The interest rate at June 30, 2013 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 3.07% 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 June 30, 2013, 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 natural 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 18 months.

Net cash provided by operating activities decreased 28% during the first half of 2013 when compared to the first half of 2012 due to a decrease from the use of cash from operating assets and liabilities offset by increased net income and noncash net income adjustments. Changes in operating assets and liabilities used $222.1 million of cash in the first half of 2013, mainly due to a decrease in accounts payable and accrued expenses primarily due to the $115.0 million Chieftain settlement payment in the first quarter of 2013 and an increase in accounts receivable. Changes in operating assets and liabilities provided $61.7 million of cash in the first half of 2012 primarily due to decreases in accounts receivable, offset by decreases in accounts payable. Net cash provided from operating activities is presented below:



	Six Months Ended June 30,
	2013			2012		Change
	(in millions)
Net income	$	176.1		$	156.2	$	19.9
Noncash adjustments to net income	543.9			476.4		67.5
Changes in operating assets and liabilities	(222.1		)	61.7		(283.8		)
Net cash provided from operating activities	$	497.9		$	694.3	$	(196.4	)

Cash Flow from Investing Activities

In the first half of 2013, net cash used in investing activities was $598.9 million compared to $681.9 million in the first half of 2012. The decrease in cash flows used in investing activities was primarily the result of 2013 proceeds of $143.0 million received from the disposition of assets, mainly attributable to QEP Energy's second quarter 2013 oil and gas property divestitures which resulted in total cash proceeds of $139.7 million. The proceeds from dispositions of assets during the first half of 2013 were partially offset by an increase in cash capital expenditures during the first half of 2013 compared to the first half of 2012. A comparison of capital expenditures for the first half of 2013 and 2012 and a forecast for calendar year 2013 are presented in the table below:



	Six Months Ended									Current Forecast Twelve Months Ended ⁽¹⁾		Prior Forecast Twelve Months Ended ⁽²⁾
	June 30,									Current Forecast Twelve Months Ended ⁽¹⁾		Prior Forecast Twelve Months Ended ⁽²⁾
	2013			2012			Change			December 31, 2013		December 31, 2013
	(in millions)
QEP Energy	$	697.1		$	641.5		$	55.6		$	1,530.0	$	1,530.0
QEP Field Services	30.1			85.9			(55.8		)	90.0		120.0
QEP Marketing	0.5			0.6			(0.1		)	1.0		1.0
QEP Resources	11.9			2.8			9.1			24.0		24.0
Total accrued capital expenditures	739.6			730.8			8.8			1,645.0		1,675.0
Change in accruals	(2.8		)	(45.3		)	42.5			—		—
Total cash capital expenditures	$	736.8		$	685.5		$	51.3		$	1,645.0	$	1,675.0

____________________________


⁽¹⁾	Represents the mid-point of the most recent guidance.


⁽²⁾	Forecast as reported in the 2013 Quarterly Report on Form 10-Q, filed on April 30, 2013.

During the first half of 2013, capital expenditures on a cash basis increased 7% to $736.8 million, compared to $685.5 million during the 2012. The increase of $51.3 million in cash capital expenditures during the first half 2013 was primarily the result of QEP Energy's increased capital expenditure budget for Williston Basin oil drilling.

QEP Energy capital investment, on an accrual basis, in the first half of 2013 increased $55.6 million over the first half of 2012 to a total of $697.1 million, of which $18.4 million related to property acquisitions in the Williston Basin and $3.6 million of post-closing adjustments for the 2012 Acquisition. In addition, capital expenditures increased $187.9 million in the Williston Basin due to additional drilling activity and operations in the area as a result of the 2012 Acquisition, offset by $72.4 million decrease in capital expenditures in the Haynesville/Cotton Valley field due to the suspended drilling program, a $56.7 million decrease in Pinedale due to the reduction in the number of drilling rigs from seven to four and a $25.3 million decrease in Midcontinent capital expenditures due to reduced drilling activity.

In the first half of 2013 compared to 2012, QEP Field Services capital investment decreased $55.8 million, on an accrual basis, due to the higher capital expenditures during the first half of 2012 for the new 150 MMcfd cryogenic gas processing plant in the Uinta Basin (Iron Horse II), which was completed during the first quarter of 2013, and the expansion of the fractionation facility at the Blacks Fork processing complex. Currently, there are no processing plants under construction at QEP Field Services.

At June 30, 2013, forecasted capital investments for 2013 is expected to be $1,645.0 million, comprised of $1,530.0 million at QEP Energy, $90.0 million at QEP Field Services, and $25.0 million for QEP Marketing and Resources. For the remainder of 2013, QEP intends to fund capital expenditures with cash flow from operating activities, and, if needed, borrowings under its revolving credit facility. As a result of the continued low natural gas prices, QEP plans minimal capital expenditures for the Haynesville Shale and other dry-gas development areas and to increase capital expenditures for higher return projects, including Pinedale, and oil-directed horizontal drilling in the Williston Basin and Midcontinent during the remainder of 2013. QEP Energy has allocated approximately 98% of its forecasted 2013 drilling and completion capital expenditure budget to crude oil and liquids-rich natural gas plays. QEP plans to invest a total of approximately $90.0 million in capital expenditures during 2013 to maintain and grow its midstream business, including the completion of the Iron Horse II cryogenic processing plant in the Uinta Basin in the first quarter of 2013, the expansion of its gathering system in the Uinta Basin and the completion of a 10,000 Bbl/d expansion of the NGL fractionation facility located at the Blacks Fork processing complex in the second quarter of 2013. QEP Resources plans to invest approximately $24.0 million in capital expenditures related to corporate activities, primarily the implementation of a new Enterprise Resource Planning system. The aggregate levels of capital expenditures for 2013 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, natural gas, oil and NGL prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management’s business assessments as to where QEP’s capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

Cash Flow from Financing Activities

In the first half of 2013, net cash proceeds from financing activities were $240.7 million compared to $134.0 million in the first half of 2012. During the first half of 2013, QEP had borrowings from the credit facility of $898.5 million and repayments on the credit facility of $700.0 million as well increases to the checks outstanding in excess of cash balances of $55.8 million during the first half of 2013.

At June 30, 2013, long-term debt consisted of $888.5 million outstanding under the credit facility, $300.0 million under the term loan and $2,221.8 million in senior notes (including $4.6 million of net original issue discount). The $198.5 million increase in borrowings under the credit facility was primarily due to the payment of $115.0 million for the Chieftain settlement during the first quarter of 2013 and capital expenditures in excess of cash flow.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market risk exposures arise from changes in the market price for natural gas, oil and NGL, and to 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 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 natural 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 periodically interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP’s subsidiaries use commodity price derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. The Company’s risk management policies provide for the use of derivative instruments to manage this risk. 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. The derivative instruments currently 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 June 30, 2013, QEP held commodity price derivative contracts totaling 126.9 million MMBtu of natural gas and 8.6 million barrels of oil. At December 31, 2012, the QEP derivative contracts covered 139.4 million MMBtu of natural gas and 6.9 million barrels of oil.

The following table presents 2013 derivative positions as of July 26, 2013:

QEP Energy Commodity Derivative Positions

Year	Type of Contract	Index	Total Volumes	Weighted-average price per unit
			(in millions)
Natural gas			(MMBtu)
2013	Swap	IFNPCR	31.8	$	5.49
2013	Swap	NYMEX	25.4	$	3.81
2014	Swap	IFNPCR	32.9	$	4.00
2014	Swap	NYMEX	25.6	$	4.19
Crude oil			(Bbls)
2013	Swap	NYMEX WTI	3.6	$	98.28
2013	Swap	BRENT ICE	0.2	$	107.80
2014	Swap	NYMEX WTI	8.0	$	93.29

QEP Marketing Commodity Derivative Positions

Year	Type of Contract	Index	Total Volumes	Weighted-average price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2013	Swap	IFNPCR	2.0	$	3.81
2014	Swap	IFNPCR	1.1	$	3.84
Natural gas purchases			(MMBtu)
2013	Swap	IFNPCR	1.7	$	3.56
2014	Swap	GDKERN	0.2	$	3.53
2014	Swap	IFNPCR	0.2	$	3.82

Changes in the fair value of derivative contracts from December 31, 2012 to June 30, 2013, are presented below:



	Commodity derivative contracts
	(in millions)
Net fair value of gas and oil derivative contracts outstanding at December 31, 2012	$	192.8
Contracts settled	(82.1		)
Change in gas and oil prices on futures markets	(14.6		)
Contracts added	25.5
Net fair value of gas and oil derivative contracts outstanding at June 30, 2013	$	121.6

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:



	June 30, 2013
	(in millions)
Net fair value - asset (liability)	$	121.6
Fair value if market prices of gas and oil and basis differentials decline by 10%	245.0
Fair value if market prices of gas and oil and basis differentials increase by 10%	(1.8		)

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $123.4 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $123.4 million as of June 30, 2013. However, a gain or loss eventually would be substantially offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company’s commodity derivative transactions, see Note 7 – Derivative Contracts under Part I, Item 1 of this 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, 2012. The Company’s credit facility has a floating interest rate which exposes QEP to interest rate risk. At June 30, 2013, the Company had $888.5 million outstanding under its revolving credit facility. If interest rates were to increase or decrease 10% over the six months ended June 30, 2013, at our average level of borrowing for those same periods, our interest expense would increase or decrease by $0.9 million and $0.3 million for the six months ended June 30, 2013 and 2012, or approximately 1% in each period.

The Company’s term loan has a floating interest rate which also exposes QEP to interest rate risk. At June 30, 2013, the Company had $300.0 million outstanding under the term loan. During the second quarter of 2012, QEP entered into interest rate swap contracts, with an aggregate notional amount of $300.0 million, to minimize the interest rate volatility risk associated with its $300.0 million term loan. QEP pays a fixed interest rate and receives a floating interest rate indexed to the one-month LIBOR. At June 30, 2013, the fair value of the interest rate swaps was a derivative liability balance of $1.2 million. A 50 basis point decrease would cause the fair value of the interest rate swaps to decrease by $4.9 million while a 50 basis point increase would cause the fair value of the interest rate swaps to increase by $5.4 million.

The remaining $2,221.8 million of the Company’s debt are Senior Notes with fixed interest rates and therefore are not affected by interest rate movements. For additional information regarding the Company’s debt instruments, see Note 9 – Debt under Part I, Item 1 of this 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;


•	natural 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;


•	QEP's low cash operating costs and ability to control costs;


•	ability to pursue acquisition opportunities;


•	proforma results for acquired properties;


•	expected restructuring costs;


•	the amount and timing of the reclassification of the fixed-value related to de-designated hedges;


•	recognition of compensation costs related to equity compensation grants;


•	impact of pension legislation;


•	expected gain on sale of assets;


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


•	plans to divest of assets, including plans to contribute portions of its gathering assets into a master limited partnership;


•	estimated accrual for loss contingencies and other items;


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


•	effect of recession;


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


•	future expenses and operating costs;


•	operation of processing plants at assumed capacities;


•	the amount and timing of the settlement of derivative contracts;


•	incurrence of unrealized derivative gains and losses;


•	impact of nonperformance by trade creditors or joint venture partners;


•	the outcome of contingencies such as legal proceedings;


•	expected contributions to the Company’s pension plans;


•	impact of recently issued accounting pronouncements;


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


•	payment of dividends;


•	potential for future asset impairments; and


•	estimated future purchase accounting adjustments.

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, 2012;


•	changes in natural 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 inability to successfully integrate acquired assets or dispose 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;


•	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, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the 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) as of June 30, 2013. Based on such evaluation, such officers have concluded that, as of June 30, 2013, the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be included 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 June 30, 2013, that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding legal proceedings is set forth in Note 10 - Contingencies to the Company's 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, 2012. No material changes to such risk factors have occurred during the three months ended June 30, 2013.

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

QEP had no unregistered sales of equity during the second quarter of 2013.

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
31.1		Certification signed by C. 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 C. 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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	QEP RESOURCES, INC.
	(Registrant)

July 31, 2013	/s/ C. B. Stanley
	C. B. Stanley,
	Chairman, President and Chief Executive Officer

July 31, 2013	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President,
	Chief Financial Officer and Treasurer