QEP RESOURCES, INC. - FORM 10-Q

QEP RESOURCES, INC. - FORM 10-Q - July 29, 2011

Attached files

Attached files

QEP RESOURCES, INC. Reports

file	filename
EX-31.1 - CERTIFICATION SIGNED BY C. B. STANLEY, CHIEF EXECUTIVE OFFICER - QEP RESOURCES, INC.	dex311.htm
EX-31.2 - CERTIFICATION SIGNED BY RICHARD J. DOLESHEK, CHIEF FINANCIAL OFFICER - QEP RESOURCES, INC.	dex312.htm
EXCEL - IDEA: XBRL DOCUMENT - QEP RESOURCES, INC.	Financial_Report.xls
EX-32.1 - CERTIFICATION SIGNED BY C. B. STANLEY AND RICHARD J. DOLESHEK, CEO AND CFO - QEP RESOURCES, INC.	dex321.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarter ended June 30, 2011

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

For the transition period from to

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)

STATE OF DELAWARE

001-34778

87-0287750

(State or other jurisdiction of

incorporation or organization

(Commission

File Number)

(I.R.S. Employer

Identification No.)

1050 17^thStreet, 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 x No ¨

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 x No ¨

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. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

At June 30, 2011, there were 176,905,034 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2011

TABLE OF CONTENTS


			Page
PART I. FINANCIAL INFORMATION				1

	ITEM 1.	FINANCIAL STATEMENTS		1

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		15

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		33

	ITEM 4.	CONTROLS AND PROCEDURES		35

PART II. OTHER INFORMATION				36

	ITEM 1.	LEGAL PROCEEDINGS		36

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		36

	ITEM 3.	EXHIBITS		36

SIGNATURES				37

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in millions, except per share amounts)
REVENUES
Natural gas sales	$	258.1		$	260.6		$	529.1		$	525.2
Oil sales		80.0			44.7			142.3			89.6
NGL sales		16.5			9.0			33.7			18.1
Gathering, processing and other		123.5			80.4			221.4			162.3
Marketing sales		306.0			134.9			453.8			314.6

Total Revenues		784.1			529.6			1,380.3			1,109.8

OPERATING EXPENSES
Lease operating expense		34.3			28.6			67.1			56.9
Gathering, processing and other		27.2			19.6			52.4			43.1
General and administrative		28.7			25.7			60.4			50.9
Separation costs		—			14.0			—			14.0
Production and property taxes		27.1			19.0			50.8			41.9
Depreciation, depletion and amortization		186.6			151.6			377.4			299.0
Exploration expenses		2.3			2.7			5.1			6.3
Abandonment and impairment		5.3			9.3			10.7			16.9
Marketing purchases		303.9			133.9			450.6			311.8

Total Operating Expenses		615.4			404.4			1,074.5			840.8
Net gain from asset sales		0.2			2.4			0.2			1.5


OPERATING INCOME		168.9			127.6			306.0			270.5
Interest and other (loss) income		(0.4	)		2.0			0.2			2.8
Income from unconsolidated affiliates		1.3			0.6			2.2			1.4
Interest expense		(22.1	)		(20.3	)		(44.2	)		(40.2	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		147.7			109.9			264.2			234.5
Income taxes		(54.2	)		(40.4	)		(96.9	)		(86.3	)

INCOME FROM CONTINUING OPERATIONS		93.5			69.5			167.3			148.2
Discontinued operations, net of income tax		—			22.0			—			43.2

NET INCOME		93.5			91.5			167.3			191.4
Net income attributable to noncontrolling interest		(0.7	)		(0.7	)		(1.3	)		(1.3	)

NET INCOME ATTRIBUTABLE TO QEP	$	92.8		$	90.8		$	166.0		$	190.1

Earnings Per Common Share Attributable to QEP
Basic from continuing operations	$	0.52		$	0.39		$	0.94		$	0.84
Basic from discontinued operations		—			0.13			—			0.25

Basic total	$	0.52		$	0.52		$	0.94		$	1.09

Diluted from continuing operations	$	0.52		$	0.39		$	0.93		$	0.83
Diluted from discontinued operations		—			0.12			—			0.24

Diluted total	$	0.52		$	0.51		$	0.93		$	1.07


Weighted-average common shares outstanding
Used in basic calculation		176.6			175.1			176.4			175.0
Used in diluted calculation		178.6			177.6			178.5			177.4
Dividends per common share	$	0.02		$	—		$	0.04		$	—

See notes accompanying the condensed consolidated financial statements

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30, 2011			December 31, 2010
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	—		$	—
Accounts receivable, net		340.7			269.9
Fair value of derivative contracts		183.8			257.3
Inventories, at lower of average cost or market
Gas and oil storage		11.7			16.4
Materials and supplies		85.8			65.4
Prepaid expenses and other		33.6			45.2

Total Current Assets		655.6			654.2

Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties		7,503.8			6,874.3
Unproved properties, not being depleted		323.1			322.0
Midstream field services		1,393.1			1,360.5
Marketing and other		45.6			44.5

Total Property, Plant and Equipment		9,265.6			8,601.3

Less Accumulated Depreciation, Depletion and Amortization
Exploration and production		2,800.2			2,454.4
Midstream field services		270.2			244.6
Marketing and other		13.3			12.3

Total Accumulated Depreciation, Depletion and Amortization		3,083.7			2,711.3

Net Property, Plant and Equipment		6,181.9			5,890.0

Investment in unconsolidated affiliates		44.0			44.5
Goodwill		59.6			59.6
Fair value of derivative contracts		109.3			120.8
Other noncurrent assets		24.6			16.2

TOTAL ASSETS	$	7,075.0		$	6,785.3

LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	18.0		$	19.5
Accounts payable and accrued expenses		430.6			332.2
Production and property taxes		31.4			18.9
Interest payable		24.9			28.1
Fair value of derivative contracts		75.8			139.3
Deferred income taxes		2.2			27.8
Current portion of long-term debt		—			58.5

Total Current Liabilities		582.9			624.3

Long-term debt, less current portion		1,572.6			1,472.3
Deferred income taxes		1,470.3			1,377.7
Asset retirement obligations		155.7			148.3
Fair value of derivative contracts		—			0.3
Other long-term liabilities		109.1			99.3
Commitments and contingencies

EQUITY
Common stock		1.8			1.8
Treasury stock		(10.8	)		(3.8	)
Additional paid-in capital		416.7			398.0
Retained earnings		2,579.4			2,420.0
Accumulated other comprehensive income		145.7			194.3

Total Common Shareholders’ Equity		3,132.8			3,010.3
Noncontrolling interests		51.6			52.8

Total Equity		3,184.4			3,063.1

TOTAL LIABILITIES AND EQUITY	$	7,075.0		$	6,785.3

See notes accompanying the condensed consolidated financial statements

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2011			2010
	(in millions)
OPERATING ACTIVITIES
Net income	$	167.3		$	191.4
Discontinued operations, net of income tax		—			(43.2	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		377.4			299.0
Deferred income taxes		95.7			117.2
Abandonment and impairment		10.7			16.9
Share-based compensation		10.8			7.1
Amortization of debt issuance costs and discounts		1.5			0.6
Dry exploratory well expense		0.5			—
Net gain from asset sales		(0.2	)		(1.4	)
Income from unconsolidated affiliates		(2.2	)		(1.4	)
Distributions from unconsolidated affiliates and other		2.6			1.2
Unrealized gain on basis-only swaps		(58.8	)		(62.1	)
Changes in operating assets and liabilities		23.3			(57.2	)

Net Cash Provided by Operating Activities of Continuing Operations		628.6			468.1

INVESTING ACTIVITIES
Property acquisitions		(29.8	)		(63.8	)
Property, plant and equipment, including dry exploratory well expense		(632.0	)		(592.3	)
Proceeds from disposition of assets		1.6			4.7
Change in notes receivable		—			52.9

Net Cash Used in Investing Activities of Continuing Operations		(660.2	)		(598.5	)

FINANCING ACTIVITIES
Checks outstanding in excess of cash balances		(1.5	)		14.6
Long-term debt issued		200.0			—
Long-term debt issuance costs paid		—			(9.8	)
Current portion long-term debt repaid		(58.5	)		—
Repayments of notes payable		—			(39.3	)
Long-term debt repaid		(100.0	)		(102.0	)
Other capital contributions		1.0			—
Equity contribution		—			250.0
Dividends paid		(7.1	)		—
Distribution from Questar		0.2			—
Distribution to noncontrolling interest		(2.5	)		(2.4	)

Net Cash Provided from Financing Activities of Continuing Operations		31.6			111.1

CASH USED IN CONTINUING OPERATIONS		—			(19.3	)

Cash provided by operating activities of discontinued operations		—			68.6
Cash used in investing activities of discontinued operations		—			(39.9	)
Cash used in financing activities of discontinued operations		—			(26.9	)
Effect of change in cash and cash equivalents of discontinued operations		—			(1.8	)

Change in cash and cash equivalents		—			(19.3	)
Beginning cash and cash equivalents		—			19.3

Ending cash and cash equivalents	$	—		$	—

See notes accompanying the condensed consolidated financial statements

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Nature of Business

QEP Resources, Inc. (QEP or the Company), is an independent natural gas and oil exploration and production company. QEP is a holding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – conducted through 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 and 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, provides risk–management services, and owns and operates an underground gas-storage reservoir.

Operations are focused in the Northern (formerly Rocky Mountain) and Southern (formerly Midcontinent) Regions of the United States. Headquarters are in Denver, Colorado. Shares of QEP common stock trade on the New York Stock Exchange (NYSE: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 U.S. 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 presentation 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, 2010.

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, 2011, are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.

Reincorporation Merger and Spin-off

Effective May 18, 2010, Questar Market Resources, Inc. (Market Resources), then a wholly owned subsidiary of Questar Corporation (Questar), merged with and into a newly formed, wholly owned subsidiary, QEP, a Delaware corporation, in order to reincorporate in the State of Delaware (Reincorporation Merger). The Reincorporation Merger was effected pursuant to an Agreement and Plan of Merger entered into between Market Resources and QEP. The Reincorporation Merger was approved by the boards of directors of Market Resources and QEP and submitted to a vote of, and approved by, the Board of Directors of Questar, as sole shareholder of Market Resources, and by Market Resources, as sole shareholder of QEP on May 18, 2010.

On June 30, 2010, Questar distributed all of the shares of common stock of QEP held by Questar to Questar shareholders in a tax-free, pro rata dividend (the Spin-off). Each Questar shareholder received one share of QEP common stock for each one share of Questar common stock held (including fractional shares) at the close of business on the record date. In connection therewith, QEP distributed Wexpro Company (Wexpro), a wholly owned subsidiary of QEP at the time, to Questar. In addition, Questar contributed $250.0 million of equity to QEP prior to the Spin-off.

The financial information presented in this Form 10-Q presents QEP’s financial results as an independent company separate from Questar and reflects Wexpro’s financial condition and operating results as discontinued operations for all periods presented. A summary of discontinued operations can be found in Note 3 to the condensed consolidated financial statements.

New accounting pronouncements

In June of 2011 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-05, which revises the manner entities are able to present the components of comprehensive income in their financial statements. The new guidance requires entities to report the components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. However, this ASU does not change the items that are reported in other comprehensive income. The amendments are effective for reporting periods (including interim periods) beginning after December 15, 2011. This ASU will require minor disclosure changes to QEP’s financial statements and footnotes once adopted.

In May of 2011, the FASB issued ASU 2011-04, which provides converged guidance on how to measure fair value and requires additional disclosures relating to fair value measurements. Most of the amendments created by this ASU are to bridge the gap between GAAP and International Financial Reporting Standards. However some of the amendments may change how the current fair value measurement guidance is applied. In addition the ASU expands the qualitative and quantitative fair value disclosure requirements, with most of these additional disclosures pertaining to Level 3 measurements. The amendments are effective for reporting periods (including interim periods) beginning after December 15, 2011. QEP is currently evaluating the impact that the ASU will have on its financial statements and disclosures.

Note 3 – Discontinued Operations

Wexpro’s operating results prior to the Spin-off are reflected in this quarterly report on Form 10-Q as discontinued operations and summarized below:


	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011		2010
	(in millions, except per share amounts)
Revenues	$	—	$	64.5		$	—	$	131.2

Income before income taxes		—		34.3			—		67.4
Income taxes		—		(12.3	)		—		(24.2	)

Discontinued operations, net of income taxes	$	—	$	22.0		$	—	$	43.2

Earnings per common share attributable to QEP
Basic from discontinued operations	$	—	$	0.13		$	—	$	0.25
Diluted from discontinued operations		—		0.12			—		0.24

Note 4 – Comprehensive Income

Comprehensive income is the sum of net income attributable to QEP as reported in the Consolidated Statements of Income and other comprehensive income. Other comprehensive income includes certain items that are recorded directly to Equity and classified as accumulated other comprehensive income (AOCI). One component of other comprehensive income is changes in the market value of commodity-based derivative instruments that qualify for hedge accounting. Income or loss associated with commodity-based derivative instruments that qualify for hedge accounting is realized when the gas, oil or NGL underlying the derivative instrument is sold. Comprehensive income also includes changes in the underfunded portion of the defined benefit pension plans and other post retirement plans and changes in deferred income taxes on such amounts. These transactions are not the culmination of the earnings process but result from adjusting historical balances to fair value. Comprehensive income attributable to QEP is shown below:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in millions)
Net income	$	93.5		$	91.5		$	167.3		$	191.4
Other comprehensive income (loss)
Net unrealized income (loss) on derivatives		(4.0	)		(65.0	)		(80.1	)		234.2
Minimum pension liability adjustment		2.8			(38.7	)		2.8			(38.7	)
Other		—			(0.1	)		—			—
Income taxes		0.4			38.6			28.7			(72.7	)

Net other comprehensive income (loss)		(0.8	)		(65.2	)		(48.6	)		122.8

Comprehensive income		92.7			26.3			118.7			314.2
Comprehensive income attributable to noncontrolling interest		(0.7	)		(0.7	)		(1.3	)		(1.3	)

Comprehensive income attributable to QEP	$	92.0		$	25.6		$	117.4		$	312.9

The components of AOCI, net of income taxes, shown on the Condensed Consolidated Balance Sheets are as follows:


	June 30, 2011			December 31, 2010			Change
	(in millions)
Net unrealized gain on derivatives	$	173.5		$	223.8		$	(50.3	)
Pension and postretirement liabilities		(27.8	)		(29.5	)		1.7

Accumulated other comprehensive income	$	145.7		$	194.3		$	(48.6	)

Note 5 – Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income attributable to QEP by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in the money stock options.

Unvested share-based payment awards that contain nonforfeitable 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 nonforfeitable 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. Consequently, in periods of net loss, the two class method will not have an effect on the Company’s basic earnings per share. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share.

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

Three Months Ended
June 30,

Six Months Ended
June 30,

2011

2010

2011

2010

(in millions)

Weighted-average basic common shares outstanding

176.6

175.1

176.4

175.0

Potential number of shares issuable under the Long-term Stock Incentive Plan

2.0

2.5

2.1

2.4

Average diluted common shares outstanding

178.6

177.6

178.5

177.4

Note 6 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. The Company’s ARO liability applies primarily to abandonment costs associated with gas and oil wells, production facilities 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. Income or expense resulting from the settlement of ARO liabilities is included in net gain or (loss) from asset sales in the Consolidated Statements of Income. Changes in ARO were as follows:


	2011			2010
	(in millions)
ARO liability at January 1,	$	148.3		$	124.7
Accretion		4.8			4.2
Liabilities incurred		2.9			12.6
Revisions		—			0.5
Liabilities settled		(0.3	)		(0.7	)

ARO liability at June 30,	$	155.7		$	141.3

Note 7 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below and exclude amounts that were capitalized and subsequently expensed in the period. All of these costs have been capitalized for less than one year.


	2011			2010
	(in millions)
Balance at January 1,	$	13.6		$	51.7
Additions to capitalized exploratory well costs pending the determination of proved reserves		—			1.0
Reclassifications to property, plant and equipment after the determination of proved reserves		(7.4	)		(47.9	)

Balance at June 30,	$	6.2		$	4.8

Note 8 – 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. The Level 2 fair value of derivative contracts (see Note 9) is based on market prices posted on the NYMEX on the last trading day of the reporting period and industry-standard discounted cash flow models. The Level 3 fair value of derivative contracts is based on NYMEX market prices in combination with unobservable volatility inputs and industry-standard option pricing 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.

Certain of QEP’s derivative instruments, however, 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 a counterparty exists.

QEP did not have any assets or liabilities measured at fair value on a non-recurring basis, other than ARO’s, at June 30, 2011, or at December 31, 2010. The fair value of assets and liabilities at June 30, 2011, is shown in the table below:

Fair Value Measurements
June 30, 2011

Level 2

Level 3

Netting
Adjustments

Total

(in millions)

Assets

Derivative contracts - short term

245.7

18.3

(80.2

)

183.8

Derivative contracts - long term

109.3

—

109.3

Total assets

355.0

18.3

(80.2

)

293.1

Liabilities

Derivative contracts - short term

155.3

0.7

(80.2

)

75.8

Derivative contracts - long term

—

Total liabilities

155.3

0.7

(80.2

)

75.8

The change in the fair value of Level 3 assets and liabilities for the first half of 2011 is shown below:


	Derivative Contracts 2011
	(in millions)
Balance at January 1,	$	36.3
Realized gains and losses included in revenues		16.2
Unrealized gains and losses included in other comprehensive income		(18.7	)
Settlements		(16.2	)

Balance at June 30,	$	17.6

The fair value of assets and liabilities at December 31, 2010, is shown in the table below:


	Fair Value Measurements December 31, 2010
	Level 2		Level 3		Netting Adjustments			Total
	(in millions)
Assets
Derivative contracts - short term	$	374.6	$	37.9	$	(155.2	)	$	257.3
Derivative contracts - long term		121.1		—		(0.3	)		120.8

Total assets	$	495.7	$	37.9	$	(155.5	)	$	378.1

Liabilities
Derivative contracts - short term	$	292.9	$	1.6	$	(155.2	)	$	139.3
Derivative contracts - long term		0.6		—		(0.3	)		0.3

Total liabilities	$	293.5	$	1.6	$	(155.5	)	$	139.6

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		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	June 30, 2011				December 31, 2010
	(in millions)
Financial assets
Cash and cash equivalents	$	—	$	—	$	—	$	—
Financial liabilities
Checks outstanding in excess of cash balances		18.0		18.0		19.5		19.5
Long-term debt		1,572.6		1,655.9		1,530.8		1,575.8

The carrying amounts of cash, 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.

Note 9 – Derivative Contracts

QEP uses commodity price derivative instruments in the normal course of business. QEP has established policies and procedures for managing commodity price risks through the use of derivative instruments. The Company follows the provisions of ASC 815 “Derivatives and Hedging,” which require detailed information about derivative transactions including the location and effect on the primary condensed consolidated financial statements.

QEP uses derivative instruments to reduce the impact of downward movements in commodity prices on cash flow, returns on capital, and other financial results. However, these same instruments typically limit future gains from favorable price movements. The volume of production subject to derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may match derivative contracts with up to 100% of forecast production from proved reserves when prices meet return on invested capital and cash flow objectives. QEP does not enter into derivative instruments for speculative purposes.

QEP uses derivative instruments known as fixed-price swaps and price collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Price collars are combinations of put and call options that have a floor price and a ceiling price and payments are made or received only if the settlement price is outside the range between the floor and ceiling prices. QEP’s derivative instruments do not require the physical delivery of natural gas or crude oil between the parties at settlement. Swap and collar transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. QEP Energy also uses natural gas basis-only swaps to protect cash flow, project returns, and other financial results from widening natural gas price basis differentials. As of December 31, 2009, all of the Company’s natural gas basis-only swaps had been paired with NYMEX gas fixed-price swaps or price collars and re-designated as cash flow hedges. Changes in the fair value of these derivative instruments subsequent to their re-designation were recorded in AOCI, while changes in their fair value occurring prior to their re-designation were recorded in the Consolidated Statement of Income.

QEP enters into derivative instruments that do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. 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 by transacting with multiple counterparties.

All derivative instruments are recorded on the balance sheet as either assets or liabilities measured at their fair values. Reported changes in the fair value of derivatives depend upon whether the derivative instrument qualifies for hedge accounting. A derivative instrument qualifies for hedge accounting if, at inception, the derivative is expected to be highly effective in offsetting the underlying unhedged cash flows. Generally, QEP’s derivative instruments are matched to company-owned gas and oil production and are therefore highly effective, thus qualifying as cash flow hedges. Changes in the fair value of effective cash flow hedges are recorded as a component of AOCI in the Condensed Consolidated Balance Sheets and reclassified to earnings as gas and oil sales when the underlying contract is settled. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Oil hedges are typically structured as NYMEX Calendar fixed-price swaps based at Cushing, Oklahoma. Oil fixed-priced swaps inherently contain ineffectiveness because physical sales are priced at the purchaser’s published regional prices. Price collars qualify for cash flow hedge accounting. Basis-only swaps do not qualify for hedge accounting treatment. QEP regularly reviews the effectiveness of derivative instruments. The ineffective portion of cash flow hedges and the mark-to-market adjustment in the value of basis-only swaps are recognized in the determination of net income. The effects of derivative transactions are summarized in the tables below:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in millions)
*Effect of derivative instruments designated as cash flow hedges*
Gains (losses) recognized in AOCI for the effective portion of hedges	$	61.3		$	31.3		$	61.5		$	375.9
*Gains (losses) reclassified from AOCI into income for the effective portion of hedges*
Natural gas sales		64.4			97.5			137.5			143.1
Oil and NGL sales		0.1			(1.8	)		0.1			(3.8	)
Marketing sales		—			—			—			—
Marketing purchases		0.5			0.6			3.9			2.4
*Loss recognized in income for the ineffective portion of hedges*
Interest and other income		0.3			0.3			0.1			(0.1	)
*Effect of derivative instruments not designated as hedges*
Unrealized gain on basis-only swaps		27.6			27.4			58.8			62.1
Realized loss on basis-only swaps		(27.6	)		(27.4	)		(58.8	)		(62.1	)

Based on prices as of June 30, 2011, it is estimated that $104.9 million will be settled and reclassified from AOCI to the Consolidated Statements of Income during the next twelve months.

The following table discloses the fair value of derivative contracts on a gross contract basis as opposed to the net contract basis presentation in the Condensed Consolidated Balance Sheets.


	June 30, 2011		December 31, 2010
	(in millions)
*Assets*
Fixed-price swaps	$	245.7	$	374.6
Price collars		18.3		37.9

Fair value of derivative instruments - short term	$	264.0	$	412.5

Fixed-price swaps	$	109.3	$	121.1
Price collars		—		—

Fair value of derivative instruments - long term	$	109.3	$	121.1

*Liabilities*
Fixed-price swaps	$	96.4	$	175.2
Price collars		0.7		1.6
Basis-only swaps		58.9		117.7

Fair value of derivative instruments - short term	$	156.0	$	294.5

Fixed-price swaps	$	—	$	0.6
Price collars		—		—
Basis-only swaps		—		—

Fair value of derivative instruments - long term	$	—	$	0.6

QEP Energy Production

The following table sets forth QEP Energy’s volumes and average net-to-the-well prices (see definition below table) for its commodity derivative contracts as of June 30, 2011:


Year	Time Period	Quantity	Average Price per Mcf or Bbl, Net to the Well⁽¹⁾
			(estimated)
Gas Fixed-price Swaps (Bcf)
2011	6 months	66.7	$4.50
2012	12 months	112.7	4.71
2013	12 months	50.3	5.54

Gas Price Collars (Bcf)
			Floor-Ceiling
2011	6 months	14.5	$4.14-$6.10

Oil Fixed-price Swaps (Mbbl)
2011	6 months	92.0	$98.00
2012	12 months	915.0	$96.10
2013	12 months	182.5	$103.80

Oil Price Collars (Mbbl)
			Floor-Ceiling
2011	6 months	552.0	$51.73-$102.10

⁽¹⁾	The fixed-price swap and collar prices are adjusted for basis differential, gathering costs and product quality to determine the net-to-the-well price.

QEP Field Services Production

QEP Field Services enters into commodity derivative transactions to lock in a margin on extracted propane sales volumes. The following table sets forth QEP Field Service’s volumes and swap prices for its commodity derivative contracts as of June 30, 2011:


Year	Time Period	Quantity	Average Price per gallon
Propane Sales Fixed-price Swaps (thousands of gallons)
2011	6 months	7,728.0	$1.45
2012	6 months⁽¹⁾	7,644.0	1.45

⁽¹⁾	The swaps outstanding as of June 30, 2011 extend through the first half of 2012.

QEP Marketing Transactions

QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of June 30, 2011:


Year	Time Period	Quantity	Average Price per MMBtu
Gas Sales Fixed-price Swaps (millions of MMBtu)
2011	6 months	3.2	$4.51
2012	12 months	0.8	4.77
Gas Purchases Fixed-price Swaps (millions of MMBtu)
2011	6 months	1.3	$4.17
2012	12 months	—	—

Note 10 – Debt

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


	June 30, 2011		December 31, 2010
	(in millions)
Revolving Credit Facility	$	500.0	$	400.0
7.50% Senior Notes due 2011		—		58.5
6.05% Senior Notes due 2016		176.8		176.8
6.80% Senior Notes due 2018		138.6		138.6


	June 30, 2011			December 31, 2010
	(in millions)
6.80% Senior Notes due 2020		138.0			138.0
6.875% Senior Notes due 2021		625.0			625.0

Total principal amount of debt		1,578.4			1,536.9

Less unamortized discount		(5.8	)		(6.1	)

Total long-term debt outstanding	$	1,572.6		$	1,530.8

Of the total debt outstanding on June 30, 2011, only the $500 million drawn under the revolving credit facility (described below) will mature within the next five years.

Credit Arrangements

QEP has a revolving credit facility which provides for loan commitments of $1.0 billion from a syndicate of financial institutions. The facility matures March 2013. The credit facility has restrictive covenants that limit the amount of funded indebtedness that QEP may incur. At June 30, 2011, QEP was in compliance with all of its debt covenants.

Senior Notes

The Company has $1,078.4 million principal amount of senior notes outstanding with maturities ranging from September 2016 to March 2021 and coupons ranging from 6.05% to 6.875%. The senior notes pay interest semi-annually, are unsecured and 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 indenture governing QEP’s senior notes contains customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

Note 11 – Contingencies

QEP is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company’s financial position, results of operations or cash flows. A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company’s financial position, results of operations or cash flows. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.

Environmental Claims

United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah. The U.S. Environmental Protection Agency (EPA) alleges that QEP Field Services (f/k/a Questar Gas Management) violated the Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for these facilities renders them “major sources” of emissions for criteria and hazardous air pollutants even though controls were installed. Categorization of the facilities as “major sources” affects the particular regulatory program and requirements applicable to those facilities. EPA claims that QEP Field Services failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air pollutant regulations for testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements applicable to non-major sources. QEP Field Services has vigorously defended itself against EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying Utah’s CAA program or EPA’s prior permitting practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all reasonably possible outcomes; however, management believes the Company has accrued a reasonable loss contingency that is an immaterial amount, for the anticipated most likely outcome. The Ute Indian Tribe and individual members of its Business Committee have now intervened as co-plaintiffs asserting the same CAA claims as the federal government.

QEP Energy v. U.S. Environmental Protection Agency, No. 09-9538, U.S. Court of Appeals for the 10^th Circuit. On July 10, 2009 QEP Energy filed a petition with the U.S. 10^th Circuit Court of Appeals challenging an administrative compliance order dated May 12, 2009 (Order), issued by EPA which asserts that QEP Energy’s Flat Rock 14P well in the Uinta Basin and associated equipment is a major source of hazardous air pollutants and its operation fails to comply with certain regulations of the CAA. The Order required immediate compliance. QEP Energy denied that the drilling and operation of the 14P well and associated equipment violated any provisions of the CAA. QEP and EPA entered into an administrative order on consent, effective June 17, 2011, resolving all disputes associated with prospective CAA compliance at the Flat Rock 14P well. Among other matters, the order requires installation of pollution control equipment to destroy vapors from the well’s dehydration equipment and ongoing monitoring and reporting associated with operation of that control equipment.

Note 12 – Share-Based Compensation

QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and performance based share units under its Long-Term Cash Incentive Plan (LTCIP) to certain officers, employees and non-employee directors. QEP recognizes expense over time as the stock options or restricted shares vest. Share-based compensation expense amounted to $3.4 million in the second quarter of 2011 compared to $3.5 million for the second quarter of 2010. Shared based compensation for the first half of 2011 was $10.8 million compared to $7.1 million in the first half of 2010. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 14.2 million shares available for future grants at June 30, 2011.

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. 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 calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:


	Stock Option Variables Six Months Ended June 30, 2011
Fair value of options at grant date	$	18.80
Risk-free interest rate		2.1	%
Expected price volatility		54.7	%
Expected dividend yield		0.21	%
Expected life in years		5.0

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


	Options Outstanding			Price Range	Weighted- Average Price
Balance at January 1, 2011		1,914,922		$7.78 -$27.84	$	19.02
Granted		202,235		39.07		39.07
Exercised		(103,970	)	7.78 - 27.55		15.07
Forfeited		—		—		—

Balance at June 30, 2011		2,013,187		7.78 - 39.07		21.24


Options Outstanding						Options Exercisable				Unvested Options
Range of Exercise Prices	Number Outstanding at June 30, 2011		Weighted- Average Remaining Term in Years		Weighted- Average Exercise Price	Number Exercisable at June 30, 2010		Weighted- Average Exercise Price		Number Unvested at June 30, 2010		Weighted- Average Exercise Price
$7.78 – $11.89		582,050		1.1	$8.57		582,050	$	8.57		—	$	—
19.37 – 27.84		1,228,902		4.2	24.31		759,556		24.45		469,346		24.09
39.07		202,235		6.7	39.07		—		—		202,235		39.07

		2,013,187		3.6	21.24		1,341,606		17.56		671,581		28.60

Restricted Shares

Restricted share grants typically vest in equal installments over a three or four-year period from the grant date. Several grants vest in a single installment after a specified period. The weighted-average vesting period of unvested restricted shares at June 30, 2011, was 17 months. Transactions involving restricted shares under the terms of the LTSIP are summarized below:


	Restricted Shares Outstanding			Price Range	Weighted- Average Price
Balance at January 1, 2011		966,961		$17.03 – $47.28	$	29.05
Granted		416,103		32.29 – 41.04		39.14
Distributed		(249,631	)	19.86 – 47.28		29.05
Forfeited		(9,185	)	17.03 – 40.03		35.58

Balance at June 30, 2011		1,124,248		17.03 – 45.31		32.73

Performance Share Units

During the first half of 2011, the Company granted its first performance based share units. Vesting is dependent upon the Company’s total shareholder return compared to a group of its peers. The awards are denominated in share units but delivered in cash at the end of the performance period. The weighted-average vesting period of unvested performance shares at June 30, 2011, was 32 months. Transactions involving performance shares units under the terms of the LTCIP are summarized below:


	Performance Shares Outstanding			Price Range		Weighted- Average Price
Balance at January 1, 2011		—		$	—	$	—
Granted		116,074			39.07		39.07
Distributed		—			—		—
Forfeited		(800	)		39.07		39.07

Balance at June 30, 2011		115,274			39.07		39.07

Note 13 – Employee Benefits

In association with the Spin-off, the Company established defined-benefit pension and postretirement medical plans providing coverage to approximately one-quarter of its employees. QEP only retained liability for active employees and all retired employees remained participants in Questar’s retirement plans. At the Spin-off, Questar transferred certain assets and liabilities from its defined-benefit pension and postretirement medical plans related to QEP employees into QEP’s newly established plans. The transfer resulted in the establishment of liabilities of $54.9 million related to the unfunded portions of the defined-benefit pension plans and other postretirement benefits with corresponding amounts in AOCI. These changes have been reflected in other long-term liabilities, deferred income taxes and AOCI.

During the six months ended June 30, 2011, the Company made contributions of $2.5 million to its retirement plans which increased plan assets. During the remainder of 2011, the Company expects to contribute $12.3 million to its retirement plan. The components of pension and post retirement benefits expense are as follows. The pension expense includes costs of both qualified and nonqualified pension plans:

Three Months Ended June 30, 2011

Six Months Ended June 30, 2011

Pension

Post Retirement
Benefits

Pension

Post-
Retirement
Benefits

(in millions)

Service cost

0.7

—

1.4

—

Interest cost

1.1

0.1

2.2

0.2

Expected return on plan assets

(0.6

)

—

(1.2

)

—

Amortization of prior service costs

1.3

0.1

2.6

0.2

Recognized net actuarial loss

—

Periodic expense

2.5

0.2

5.0

0.4

Note 14 – Operations by Line of Business

QEP’s lines of business include gas and oil exploration and production (QEP Energy), midstream field services (QEP Field Services) and marketing (QEP Marketing). 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. Following is a summary of operating results by line of business:


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in millions)
Revenues from Unaffiliated Customers
QEP Energy	$	513.2	$	315.8	$	865.9	$	635.5
QEP Field Services		120.2		78.5		215.3		158.8
QEP Marketing and other		150.7		135.3		299.1		315.5

Total	$	784.1	$	529.6	$	1,380.3	$	1,109.8


Revenues from Affiliated Companies
QEP Field Services	$	0.8	$	0.6	$	1.4	$	1.2


	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011		2010
	(in millions)
QEP Marketing and other		145.1		112.4			278.2		255.7

Total	$	145.9	$	113.0		$	279.6	$	256.9

Operating Income
QEP Energy	$	95.3	$	101.0		$	183.2	$	204.8
QEP Field Services		72.3		39.5			119.6		76.6
QEP Marketing and other		1.3		1.1			3.2		3.1
Certain separation costs		—		(14.0	)		—		(14.0	)

Total	$	168.9	$	127.6		$	306.0	$	270.5

Net Income from Continuing Operations Attributable to QEP
QEP Energy	$	46.8	$	52.6		$	89.9	$	106.4
QEP Field Services		44.2		24.3			72.2		47.5
QEP Marketing and other		1.8		0.5			3.9		1.6
Certain separation costs		—		(8.6	)		—		(8.6	)

Total	$	92.8	$	68.8		$	166.0	$	146.9

Note 15 – Subsequent event

In July, construction of QEP Field Services’ Blacks Fork II gas processing plant located in southwestern Wyoming was completed and the company commenced commissioning and start-up operations. The plant is a deep-cut, cryogenic gas processing facility with an inlet capacity of 420 MMcf per day and processes company-owned and third-party natural gas produced primarily from the Pinedale Anticline. In conjunction with the plant start-up, QEP Energy and QEP Field Services executed a long-term, fee-based processing agreement. Approximately half of the volumes processed by the plant are owned by QEP Energy. It is expected that the plant will ultimately recover approximately 15,000 barrels of NGL’s, net to the Company, of which approximately half will be for the account of QEP Energy and the remainder will be for the account of QEP Field Services.

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 2010 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, 2011 and June 30, 2010. 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 2010 Annual Report on Form 10-K.

OVERVIEW

QEP is an independent natural gas and oil exploration and production company. QEP is a holding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – conducted through three principal subsidiaries:

•

QEP Energy Company (QEP Energy) acquires, explores for, develops and produces natural gas, oil, and natural gas liquids (NGL) in two principal operating regions: the Southern Region (formerly referred to as the Midcontinent Region) of the U.S, which includes the Haynesville/Cotton Valley area in northwest Louisiana and the Midcontinent area with properties primarily located in Oklahoma, Arkansas and Texas) and the Northern Region (formerly referred to as the Rocky Mountain Region) of the U.S. which includes the Pinedale Anticline in western Wyoming; the Uinta Basin in eastern Utah; and the Rockies Legacy area that includes all of the Northern Region properties except the Pinedale Anticline and the Uinta Basin;

•

QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil in the Rocky Mountains, Pacific Northwest and Midcontinent that are either close to affiliate reserves and production or accessible by major pipelines; provides risk-management services; and owns and operates an underground gas storage reservoir in western Wyoming.

Reincorporation Merger and Spin-off

Effective May 18, 2010, Market Resources, then a wholly owned subsidiary of Questar, merged with and into QEP, a Delaware corporation and a newly formed, wholly owned subsidiary of Questar, in order to reincorporate in the State of Delaware. The Reincorporation Merger was effected pursuant to an Agreement and Plan of Merger entered into between Market Resources and QEP. On June 30, 2010, Questar distributed to existing Questar stockholders all of the shares of common stock of QEP in a tax-free, pro rata spin-off, establishing QEP as an independent, publicly traded company. In connection with the Spin-off, QEP distributed Wexpro, a wholly owned subsidiary of QEP at the time, to Questar. In addition, Questar contributed $250.0 million of equity to QEP prior to the Spin-off.

Strategies

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

•

Allocate capital to the projects that generate the best returns

•

Maintain a sustainable inventory of low-cost, high margin resource plays

•

Be in the best parts of the best plays

•

Build contiguous acreage positions to drive efficiencies

•

Be the operator of our assets whenever possible

•

Be the low-cost driller and producer in each area where we operate

•

Own and operate midstream infrastructure in our core producing areas to control our future and capture value downstream of the wellhead

•

Build gas processing plants to extract liquids from our gas streams

•

Gather, compress and treat our production to drive down costs

•

Actively market our QEP Energy production to maximize value

•

Utilize commodities derivatives to reduce the impact of a decline in the prices of our natural gas and crude oil and to lock in acceptable cash flows to support future capital expenditures

•

Operate in a safe and environmentally responsible manner

•

Attract and retain the best people

•

Maintain a strong balance sheet and financial flexibility that allows us to take advantage of both organic growth and acquisition opportunities

Outlook

The Company has substantial acreage positions and operations in some of North America’s most economic hydrocarbon resource plays including the Bakken/Three Forks, Pinedale, Haynesville and Woodford “Cana” 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. Resource plays allow the Company the opportunity to gain considerable operational efficiencies through high density and 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 organic production and reserve growth. QEP also has one of the lowest cash cost structures among its exploration and production company peers.

While predominantly 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. Oil and NGL production increased by approximately 32% in the second quarter of 2011 compared with the second quarter of 2010 and oil and NGL revenue accounted for approximately 30% of net production revenues (including realized losses on basis-only swaps) in the second quarter of 2011 compared to 19% in the second quarter of 2010. Oil and NGL production increased by approximately 32% in the first half of 2011 compared with the first half of 2010 and oil and NGL revenue accounted for approximately 27% of net production revenues (including realized losses on basis-only swaps) in the first half of 2011 compared to 19% in the first half of 2010. The Company has allocated almost 40% of its forecasted 2011 capital expenditures to oil and liquids-rich natural gas projects.

The Company also owns and operates gathering and transmission pipelines and natural gas processing and treatment facilities in its core producing areas, which allows the Company to promptly connect its wells, better control its costs, and generate a significant revenue stream by providing transportation and processing services to third parties in addition to QEP Energy. Net income from QEP’s midstream business accounted for approximately 48% of the Company’s total income from continuing operations during the second quarter of 2011 compared with 35% for the second quarter of 2010. Net income from QEP’s midstream business accounted for approximately 43% of the Company’s total income from continuing operations during the first half of 2011 compared with 32% for the first half of 2010.

While QEP believes that it can grow its production and reserves from its extensive inventory of drilling locations, the Company also evaluates acquisition opportunities that might have the potential to create significant long-term value. QEP believes that its experience, expertise and substantial presence in the Southern and Northern Regions, combined with its low-cost operating structure and financial strength, enhance its ability to pursue acquisition opportunities in those geographic areas.

Highlights of Three and Six Months Ended June 30, 2011

In the second quarter of 2011, QEP reported production of 64.7 Bcfe compared to 53.7 Bcfe in the 2010 second quarter. During the six months ended June 30, 2011, QEP production of 130.6 Bcfe was above the comparable period reported production of 105.2 Bcfe. In the second quarter and first half of 2011, the Southern Region (formerly the Midcontinent Region) contributed 57% and 58% and the Northern Region (formerly the Rocky Mountain Region) contributed 43% and 42% of total equivalent production.

QEP Energy continues to focus on the controllable cash cost of production per Mcfe. The Company defines cash cost of production as the sum of lease operating expense, general and administrative expense, allocated interest and production taxes. Cash operating costs were $1.60 per Mcfe in the second quarter of 2011 compared to $1.58 per Mcfe in the second quarter of 2010. The slight increase was due to higher production taxes per Mcfe related to higher field-level crude oil and NGL prices. During the first half of 2011, cash operating costs decreased to $1.56 per Mcfe compared to $1.65 per Mcfe in the first half of 2010. This decrease was a result of increased production volumes partially offset by higher production costs.

QEP Field Services reported gathering system throughput of 1.3 million MMBtu per day for the three and six months ended June 30, 2011, 6% and 5% higher than the three and six months ended June 30, 2010, respectively. The increased volumes were primarily in northwest Louisiana. During the second quarter and first half of 2011 QEP Field Services reported a 36% and 25% increase in NGL sales volumes to a total of 36.4 million and 64.2 million gallons, respectively. The increase in NGL sales volumes along with a 52%

increase in the per unit NGL margin (NGL revenue less fuel and shrinkage) resulted in a 107% increase to the keep-whole processing margin during the second quarter of 2011. For the first half of 2011 the increased NGL sales volumes along with a 31% increase in the per unit NGL margin resulted in a 64% increase to the keep-whole processing margin.

Factors Affecting Results of Operations

Oil and Natural Gas Prices

Historically, 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, natural gas supply has grown faster than natural gas demand, driven by advances in technology, including horizontal drilling and hydraulic fracturing that has allowed producers to extract increasing amounts of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supply has put downward pressure on natural gas prices, while unrest in the Middle East and other factors has caused the price of crude oil to increase. Changes in the market prices for crude oil and natural gas directly impact many aspects of QEP’s business, including its financial condition, revenues, results of operations, liquidity, rate of growth, costs of goods and services required to drill and complete wells, and the carrying value of its oil and natural gas properties. For example, despite a 19% increase in natural gas production in the second quarter of 2011 compared to the second quarter of 2010, natural gas revenues decreased 1% due to significantly lower net realized natural gas prices. When compared to the first half of 2010, natural gas production in the first half of 2011 increased 23%, while natural gas revenues increased only 1% due to lower net realized natural gas prices.

QEP uses commodity derivatives to reduce the variability of the prices QEP receives for a portion of its production and to provide a minimum revenue stream. As of June 30, 2011, QEP had approximately 62% of its remaining forecast 2011 natural gas, oil and NGL production covered with fixed-price swaps or price collars assuming 2011 annual production of 267.0 Bcfe. See “Quantitative and Qualitative Disclosures about Market Risk—Commodity Derivative Transactions” for further details concerning its commodity derivatives transactions. In addition, as a result of the continued spread between oil and natural gas prices, the Company has allocated almost 40% of its forecasted 2011 capital expenditure budget to crude oil and liquids-rich natural gas projects in its portfolio and reduced the overall allocation of capital expenditures directed to the development of dry natural gas plays.

Unrealized Derivative Gains and Losses

Unrealized gains and losses that result from mark-to-market valuations of derivative positions that are not accounted for as cash flow hedges are reflected as unrealized commodity derivative gains or losses in the Company’s income statement. Payments due to or from counterparties in the future on these derivatives will typically be offset by corresponding changes in prices ultimately received from the sale of QEP’s production. QEP has incurred significant unrealized gains and losses in prior periods and may continue to incur these types of gains and losses in the future.

Critical Accounting Estimates

QEP’s significant accounting policies are described in Item 7 of Part II of its 2010 Annual Report on Form 10-K. The Company’s condensed consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles. The preparation of 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, accounting for derivative contracts and revenue recognition, among others, may involve a higher degree of complexity and judgment on the part of management.

RESULTS OF OPERATIONS

Adjusted EBITDA

Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company’s cash flow and liquidity and 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: depreciation, depletion and amortization, abandonment and impairment, interest and other income, interest expense, separation costs, income taxes, unrealized gain and losses on basis-only swaps, discontinued operations, gains and losses from assets sales, and exploration expense.

Following are comparisons of Adjusted EBITDA by line of business:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011		2010		Change		2011		2010		Change
	(in millions)
QEP Energy	$	247.7	$	222.4	$	25.3	$	489.7	$	437.8	$	51.9
QEP Field Services		86.9		52.3		34.6		148.3		102.7		45.6
QEP Marketing and other		2.0		1.3		0.7		4.4		4.0		0.4

Total Adjusted EBITDA	$	336.6	$	276.0	$	60.6	$	642.4	$	544.5	$	97.9

Adjusted EBITDA increased 22% to $336.6 million for the second quarter of 2011 compared to $276.0 million in the 2010 period, despite a 17% decrease in net realized natural gas prices. The impact of lower net realized natural gas prices during the second quarter of 2011 was offset by a 20% increase in total production, 39% higher net realized crude oil prices and 30% higher net realized NGL prices in QEP Energy, along with increased gathering (36% higher) and processing margins (92% higher) in QEP Field Services. Adjusted EBITDA increased 18% to $642.4 million for the first half of 2011 compared to $544.5 million in the 2010 period, despite an 18% decrease in net realized natural gas prices. The lower natural gas prices in the first half of 2011 were offset by a 24% increase in total production, 32% higher net realized crude oil prices and 14% higher net realized NGL prices in QEP Energy, along with a 30% and 59% increase in gathering and processing margins, respectively.

A reconciliation of Adjusted EBITDA to net income follows:


	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
	(in millions)
Net income attributable to QEP Resources	$	92.8		$	90.8		$	2.0		$	166.0		$	190.1		$	(24.1	)
Net income attributable to non-controlling interest		0.7			0.7			—			1.3			1.3			—

Net Income		93.5			91.5			2.0			167.3			191.4			(24.1	)
Discontinued operations, net of tax		—			(22.0	)		22.0			—			(43.2	)		43.2

Income from continuing operations		93.5			69.5			24.0			167.3			148.2			19.1
Unrealized gain on basis-only swaps		(27.6	)		(27.4	)		(0.2	)		(58.8	)		(62.1	)		3.3
Net gain from asset sales		(0.2	)		(2.4	)		2.2			(0.2	)		(1.5	)		1.3
Interest and other loss (income)		0.4			(2.0	)		2.4			(0.2	)		(2.8	)		2.6
Income taxes		54.2			40.4			13.8			96.9			86.3			10.6
Interest expense		22.1			20.3			1.8			44.2			40.2			4.0
Separation costs		—			14.0			(14.0	)		—			14.0			(14.0	)
Depreciation, depletion and amortization		186.6			151.6			35.0			377.4			299.0			78.4
Abandonment and impairment		5.3			9.3			(4.0	)		10.7			16.9			(6.2	)
Exploration expenses		2.3			2.7			(0.4	)		5.1			6.3			(1.2	)

Adjusted EBITDA	$	336.6		$	276.0			60.6		$	642.4		$	544.5		$	97.9

Net Income

Following are comparisons of net income from continuing operations attributable to QEP by line of business:


	Three Months Ended June 30,								Six Months Ended June 30, 2011
	2011		2010			Change			2011		2010			Change
	(in millions)
QEP Energy	$	46.8	$	52.6		$	(5.8	)	$	89.9	$	106.4		$	(16.5	)
QEP Field Services		44.2		24.3			19.9			72.2		47.5			24.7
QEP Marketing and other		1.8		0.5			1.3			3.9		1.6			2.3
Certain separation costs		—		(8.6	)		8.6			—		(8.6	)		8.6

Net Income from continuing operations attributable to QEP	$	92.8	$	68.8		$	24.0		$	166.0		146.9		$	19.1

Earnings per diluted share from continuing operations	$	0.52	$	0.39		$	0.13		$	0.93	$	0.83		$	0.10
Average diluted shares		178.6		177.6			1.0			178.5		177.4			1.1

Revenue, Volumes and Prices


	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
	(in millions)
*Revenues*
Natural gas sales	$	258.1	$	260.6	$	(2.5	)	$	529.1	$	525.2	$	3.9
Oil sales		80.0		44.7		35.3			142.3		89.6		52.7
NGL sales		16.5		9.0		7.5			33.7		18.1		15.6
Gathering, processing and other		123.5		80.4		43.1			221.4		162.3		59.1
Marketing sales		306.0		134.9		171.1			453.8		314.6		139.2

Total Revenues	$	784.1	$	529.6	$	254.5		$	1,380.3	$	1,109.8	$	270.5

QEP Energy’s revenues for the three and six months ended June 30, 2011, derived from the sale of natural gas, oil and NGLs increased primarily due to increased production volumes and higher oil and NGL prices, offset by lower prices for natural gas, as follows:


	Three Months Ended June 30,
	Natural Gas			Oil		NGLS		Total
	(in millions)
*QEP Energy Revenues*
2010 revenues	$	260.6		$	44.7	$	9.0	$	314.3
Changes associated with volumes⁽¹⁾		49.9			12.6		3.7		66.2
Changes associated with prices⁽²⁾		(52.4	)		22.7		3.8		(25.9	)

2011 revenues	$	258.1		$	80.0	$	16.5	$	354.6


	Six Months Ended June 30,
	Natural Gas			Oil		NGLS		Total
	(in millions)
*QEP Energy Revenues*
2010 revenues	$	525.2		$	89.6	$	18.1	$	632.9

Changes associated with volumes⁽¹⁾		122.4			18.3		11.6		152.3
Changes associated with prices⁽²⁾		(118.5	)		34.4		4.0		(80.1	)

2011 revenues	$	529.1		$	142.3	$	33.7	$	705.1

⁽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, 2011, to the three and six months ended June 30, 2010, by the average price or fee for the three and six months ended June 30, 2010.

⁽²⁾	The revenue variance attributed to the change in price is calculated by multiplying the change in prices or fee from the three and six months ended June 30, 2011, to the three and six months ended June 30, 2010, by volume for the quarter ended June 30, 2011.

Gathering, processing and other revenues also increased for the three and six months ended June 30, 2011, as a result of higher volumes and improved processing and gathering fees.


	Three Months Ended June 30,						Six Months Ended June 30,
	Gathering and Processing		Other		Total		Gathering and Processing		Other		Total
	(in millions)
*QEP Field Services and Other Revenues*
2010 revenues	$	71.2	$	9.2	$	80.4	$	141.4	$	20.9	$	162.3
Changes associated with volumes⁽¹⁾		11.3		—		11.3		17.0		—		17.0
Changes associated with fees⁽²⁾		13.5		—		13.5		15.6		—		15.6
Changes associated with other factors		—		18.3		18.3		—		26.5		26.5

2011 revenues	$	96.0	$	27.5	$	123.5	$	174.0	$	47.4	$	221.4

⁽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, 2011, to the three and six months ended June 30, 2010, by the average price or fee for the three and six months ended June 30, 2010.

⁽²⁾	The revenue variance attributed to the change in fees is calculated by multiplying the change in prices or fee from the three and six months ended June 30, 2011, to the three and six months ended June 30, 2010, by volume for the quarter ended June 30, 2011.

Marketing sales, which include QEP Energy purchased gas sales, were $171.1 million and $139.2 higher in the three and six months ended June 30, 2011, respectively. These increases were due to $156.0 million in purchased gas sales during the 2011 second quarter, which increased primarily related to gas purchases made in northwest Louisiana to fulfill pipeline shipping commitments.

Production

QEP Energy reported production of 64.7 Bcfe in the second quarter of 2011 compared to 53.7 Bcfe in the 2010 quarter, a 20% increase. During the first half of 2011 QEP Energy reported production of 130.6 Bcfe compared to 105.2 Bcfe in the first half of 2010. On an energy-equivalent basis, crude oil and NGL comprised approximately 12% and 11%, respectively, of QEP Energy’s second quarter and first half 2011 production. A summary of production is shown in the following table:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011		2010		Change		2011		2010		Change
*QEP Energy production volumes*
Natural gas (Bcf)		57.0		47.9		9.1		116.1		94.2		21.9
Oil (Mbbl)		873.6		681.6		192.0		1,636.6		1,359.4		277.2
NGL (Mbbl)		394.3		280.8		113.5		780.6		476.2		304.4
Total production (Bcfe)		64.7		53.7		11.0		130.6		105.2		25.4
Average daily production (MMcfe)		710.8		590.0		120.8		721.7		581.2		140.5

A summary of natural gas production by major operating area is shown in the following table:


	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
*QEP Energy – Natural Gas (Bcf)*
Southern Region
Haynesville/Cotton Valley		25.5		18.4		7.1			53.6		34.5		19.1
Midcontinent		8.0		6.6		1.4			15.8		14.8		1.0
Northern Region
Pinedale Anticline		17.0		15.7		1.3			32.4		30.4		2.0
Uinta Basin		3.4		3.7		(0.3	)		8.2		7.4		0.8
Rockies Legacy		3.1		3.5		(0.4	)		6.1		7.1		(1.0	)

Total production		57.0		47.9		9.1			116.1		94.2		21.9

A summary of oil production by major operating area is shown in the following table:


	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
*QEP Energy – Oil (Mbbl)*
Southern Region
Haynesville/Cotton Valley		10.5		15.9		(5.4	)		24.0		36.0		(12.0	)
Midcontinent		191.8		159.3		32.5			356.5		324.9		31.6
Northern Region


	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
Pinedale Anticline		139.2		129.8		9.4			269.8		254.8		15.0
Uinta Basin		233.4		235.3		(1.9	)		458.7		470.0		(11.3	)
Rockies Legacy		298.7		141.3		157.4			527.6		273.7		253.9

Total production		873.6		681.6		192.0			1,636.6		1,359.4		277.2

A summary of NGL production by major operating area is shown in the following table:


	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
*QEP Energy – NGL (Mbbl)*
Southern Region
Haynesville/Cotton Valley		—		—		—			—		—		—
Midcontinent		339.3		229.6		109.7			664.8		370.4		294.4
Northern Region
Pinedale Anticline		—		—		—			—		—		—
Uinta Basin		25.2		30.8		(5.6	)		59.5		57.7		1.8
Rockies Legacy		29.8		20.4		9.4			56.3		48.1		8.2

Total production		394.3		280.8		113.5			780.6		476.2		304.4

A summary of natural gas-equivalent production by major operating area is shown in the following table:


	Three Months Ended June 30,							Six Months Ended June 30,						Year Ended December 31,
	2011		2010		Change			2011		2010		Change		2010		2009		2008
QEP Energy – Total Production (Bcfe)
Southern Region
Haynesville/Cotton Valley		25.6		18.5		7.1			53.8		34.7		19.1		78.9		46.5		31.3
Midcontinent		11.3		9.0		2.3			21.9		19.0		2.9		41.5		41.3		36.5
Northern Region
Pinedale Anticline		17.8		16.5		1.3			34.0		32.0		2.0		68.5		61.8		56.8
Uinta Basin		5.0		5.4		(0.4	)		11.4		10.6		0.8		21.4		23.2		26.9
Rockies Legacy		5.0		4.3		0.7			9.5		8.9		0.6		18.7		16.7		19.9

Total production		64.7		53.7		11.0			130.6		105.2		25.4		229.0		189.5		171.4

As shown in the table above, production from the Haynesville/Cotton Valley area continues trending upward from 2008. Continuing this trend, net production in the Haynesville/Cotton Valley area grew 38% to 25.6 Bcfe in the second quarter of 2011 compared to the second quarter of 2010 and represented 40% of the Company’s total production compared to 34% in the year earlier period. During the first half of 2011 net production from the Haynesville/Cotton Valley area was 53.8 Bcfe compared to 34.7 Bcfe in the comparable period, which represented 41% of the Company’s first half of 2011 total production compared to 33% in 2010. Haynesville/Cotton Valley area production growth was driven by ongoing development drilling in the Haynesville Shale play in northwest Louisiana.

Net production in the Midcontinent area grew 26% to 11.3 Bcfe in the second quarter of 2011 compared to the second quarter of 2010 and represented 17% of the Company’s total production for both 2011 and 2010 periods. During the first half of 2011 net production in the Midcontinent was 21.9 Bcfe compared to 19.0 Bcfe in the comparable period, which represented 17% of the Company’s 2011 total production compared to 18% in 2010. Midcontinent production growth was driven by continued development of the Granite Wash/Atoka Wash play in the Texas Panhandle and the Woodford “Cana” Shale horizontal gas play in the Anadarko Basin of western Oklahoma.

Net production from the Pinedale Anticline in western Wyoming grew 8% to 17.8 Bcfe in the second quarter of 2011 compared to the 2010 second quarter as a result of ongoing development drilling. The Pinedale Anticline net production during the first half of 2011 increased 6% to 34.0 Bcfe from the comparable period in 2010.

In the Uinta Basin, production decreased 0.4 Bcfe in the second quarter of 2011 but increased 0.8 Bcfe in the first six months of 2011, due to a first quarter 2011 prior-period adjustment of QEP’s ownership interest within a federal unit, which resulted in a positive adjustment to reported production volumes of 1.6 Bcfe.

Rockies Legacy net production in the second quarter of 2011 increased to 5.0 Bcfe due to increased oil directed drilling activity in the North Dakota Bakken/Three Forks play. During the first half of 2011, Rockies Legacy net production increased by 7% to 9.5 Bcfe from the first half of 2010. Most of QEP’s wells in North Dakota have been connected to oil gathering lines during the first half of 2011 thereby eliminating future weather-related oil sales interruptions. QEP Energy Rockies Legacy properties include all Northern Region properties except the Pinedale Anticline and the Uinta Basin.

Pricing

Field level and realized prices (after hedges) for natural gas and NGLs at QEP Energy were lower than the prior year comparative period, while realized oil prices were higher when compared to the 2010 prior-year. A regional comparison of average field level prices is shown in the following table:


	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
*QEP Energy – Average field-level natural gas price ($ per Mcf)*
Southern Region	$	3.44	$	3.65	$	(0.21	)	$	3.40	$	4.22	$	(0.82	)
Northern Region		3.33		3.14		0.19			3.33		3.88		(0.55	)
Average field-level natural gas price	$	3.39	$	3.40	$	(0.01	)	$	3.37	$	4.06	$	(0.69	)

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
*QEP Energy – Average field-level oil price ($ per bbl)*
Southern Region	$	94.03	$	74.63	$	19.40		$	92.07	$	74.64	$	17.43
Northern Region		90.67		66.14		24.53			85.30		66.62		18.68
Average field-level oil price	$	91.45	$	68.32	$	23.13		$	86.88	$	68.75	$	18.13

	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
*QEP Energy – Average field-level NGL price ($ per bbl)*
Southern Region	$	40.00	$	31.27	$	8.73		$	41.43	$	37.32	$	4.11
Northern Region		53.07		35.80		17.27			52.82		40.07		12.75
Average field-level NGL price	$	41.82	$	32.10	$	9.72		$	43.12	$	37.93	$	5.19

A comparison of net realized average natural gas, oil and NGL prices, including the realized losses on basis-only swaps, which did not qualify for hedge accounting and are therefore not included in revenue, is shown in the following table:


	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
*Natural gas ($ per Mcf)*
Average field-level natural gas price ($ per Mcf)	$	3.39		$	3.40		$	(0.01	)	$	3.37		$	4.06		$	(0.69	)
Natural gas commodity derivative impact ($ per Mcf)		1.13			2.04			(0.91	)		1.19			1.52			(0.33	)

Average revenue ($ per Mcf)⁽¹⁾		4.52			5.44			(0.92	)		4.56			5.58			(1.02	)
Realized losses on basis-only swaps ($ per Mcf)⁽²⁾		(0.48	)		(0.57	)		0.09			(0.51	)		(0.66	)		0.15

Net realized natural gas price ($ per Mcf)	$	4.04		$	4.87		$	(0.83	)	$	4.05		$	4.92		$	(0.87	)

*Oil ($ per bbl)*
Average field-level oil price ($ per bbl)	$	91.45		$	68.32		$	23.13		$	86.88		$	68.75		$	18.13
Oil commodity derivative impact ($ per bbl)		0.14			(2.66	)		2.80			0.07			(2.79	)		2.86

Net realized oil price ($ per bbl) ⁽¹⁾	$	91.59		$	65.66		$	25.93		$	86.95		$	65.96		$	20.99

*NGL ($ per bbl)*
Average field-level NGL price ($ per bbl) ⁽¹⁾	$	41.82		$	32.10		$	9.72		$	43.12		$	37.93		$	5.19

⁽¹⁾	Reported in revenues in the consolidated income statement.

⁽²⁾	Reported below operating income in the consolidated income statement.

Commodity Derivatives Impact

The Company enters into commodity derivative instruments to manage its exposure to price fluctuations on a portion of its forecasted natural gas and oil production. The impact of QEP’s commodity derivatives transactions on the Company’s financial statements for the periods disclosed is presented below. The net effect of the portion of natural gas basis-only swaps that do not qualify for hedge accounting is reported in the Consolidated Statements of Income below operating income. Derivative positions as of June 30, 2011, are summarized in Note 9 to the condensed consolidated financial statements in Item 1 of Part I in this Quarterly Report on Form 10-Q.


	Three Months Ended June 30						Six Months Ended June 30
	2011			2010			2011			2010
*Volumes subject to commodity derivatives as a percent of gas production*
Fixed price swaps		46	%		79	%		44	%		79	%
Price collars		12	%		3	%		12	%		4	%
*Volumes subject to commodity derivatives as a percent of oil production*
Fixed price swaps		3	%		33	%		2	%		33	%
Price collars		31	%		27	%		33	%		27	%


	Three Months Ended June 30, 2011									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
*Impact of settled commodity derivatives on financial statements (millions)*
Natural gas sales	$	64.4		$	97.5		$	(33.1	)	$	137.5		$	143.1		$	(5.6	)
Oil sales	$	0.1		$	(1.8	)	$	1.9		$	0.1		$	(3.8	)	$	3.9
*Impact of settled commodity derivatives that do not qualify for hedge accounting (millions)*
Unrealized gain (loss) on basis-only swaps	$	27.6		$	27.4		$	0.2		$	58.8		$	62.1		$	(3.3	)
Realized (loss) on basis-only swaps	$	(27.6	)	$	(27.4	)	$	(0.2	)	$	(58.8	)	$	(62.1	)	$	3.3

The change in unrealized gains and losses on natural gas basis-only swaps increased the second quarter 2011 net income $17.3 million compared to an increase of $17.2 million in the second quarter of 2010. During the first half of 2011, net income increased $36.9 million from the impact of unrealized gains and losses on natural gas basis-only swaps compared to an increase of $39.0 million in the first half of 2010. As of December 31, 2009, all of the Company’s basis-only swaps had been paired with fixed-price swaps and re-designated as cash flow hedges. Changes in the fair value of these derivative instruments subsequent to their re-designation were recorded in AOCI; however, changes in the fair value of these derivative instruments occurring prior to their re-designation were recorded in the Consolidated Statement of Income.

Gathering

QEP Field Services posted a 36% increase in gathering margin in the second quarter of 2011, primarily due to an increase in the liquids value received from a short-term, third-party gathering and processing arrangement and a 6% increase in gathering system throughput volume to 1.3 million MMBtu per day. QEP Field Service gathering margins increased 30% in the first half of 2011 as a result of an increase in the liquids value received from a short-term third-party gathering and processing arrangement and from a 5% increase in gathering system throughput volume to 1.3 million MMBtu per day. The increased volumes were mainly related to the northwest Louisiana gathering system, which accounted for 20% and 22% of the total throughput during the second quarter and first half of 2011, respectively.

Following is a summary of QEP Field Services’ financial and operating results from gathering activities:


	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
	(in millions)
*Gathering Margin*
Gathering revenues	$	38.7		$	38.4		$	0.3		$	78.1		$	74.4		$	3.7
Other gathering revenues		25.0			7.9			17.1			42.7			18.6			24.1
Gathering expense		(12.4	)		(8.7	)		(3.7	)		(24.3	)		(18.6	)		(5.7	)

Gathering Margin	$	51.3		$	37.6		$	13.7		$	96.5		$	74.4		$	22.1

*Operating Statistics*
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers		66.0			65.2			0.8			127.1			135.7			(8.6	)
For affiliated customers		55.1			49.0			6.1			113.0			92.2			20.8

Total Gas Gathering Volumes		121.1			114.2			6.9			240.1			227.9			12.2

Average gas gathering revenue (per MMBtu)	$	0.32		$	0.34		$	(0.02	)	$	0.33		$	0.33		$	—

Processing

Processing margin increased 92% in the second quarter 2011 and 59% in the first half of 2011 compared to the 2010 comparable periods, due to increased keep-whole processing margins and increased fee-based processing revenues. The increased keep-whole processing margin was mostly the result of increased NGL prices and volume. NGL prices increased 39% in the second quarter and 20% in the first half of 2011 compared to the 2010 periods. NGL volumes increased 36% in the second quarter and 25% in the first half of 2011 compared to the 2010 periods. Processing fees increased 36% during the second quarter 2011 when compared to the second quarter 2010, due to a 6% increase in fee-based processing volumes to 60.3 million MMBtu and a 31% increase in the processing fee rate. During the first half of 2011 processing fees increased 28% over the 2010 comparable period, due to a 6% increase in fee-based process volumes to 117.3 million MMBtu and a 19% increase in the processing fee rate. The increased processing volume was primarily the result of the start-up of the 150 MM per day Iron Horse cryogenic processing plant in the Uinta Basin of eastern Utah during the first quarter of 2011. Approximately 69% and 73% of QEP Field Services’ net operating revenue was derived from fee-based gathering and processing contracts in the three and six months ended June 30, 2011, compared to 77% and 78% during the three and six months ended June 30, 2010. The decline in the relative percentage of fee-based revenues was due primarily to the increase in keep-whole processing margins in 2011.

Following is a summary of QEP Field Services’ processing financial and operating results:


	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
	(in millions)
*Processing Margin*
NGL sales	$	45.1		$	23.8		$	21.3		$	73.7		$	49.7		$	24.0
Processing (fee based) revenues		12.2			9.0			3.2			22.2			17.3			4.9
Processing (expense)		(3.1	)		(3.0	)		(0.1	)		(5.8	)		(6.0	)		0.2
Processing plant fuel and shrinkage (expense)		(11.4	)		(7.5	)		(3.9	)		(21.6	)		(17.9	)		(3.7	)

Processing Margin	$	42.8		$	22.3		$	20.5		$	68.5		$	43.1		$	25.4

Frac spread (NGL sales – processing plant fuel and shrinkage)	$	33.7		$	16.3		$	17.4		$	52.1		$	31.8		$	20.3
*Operating Statistics*
Natural gas processing volumes
NGL sales (MMgal)		36.4			26.7			9.7			64.2			51.5			12.7
Average NGL sales price (per gal)	$	1.24		$	0.89		$	0.35		$	1.15		$	0.96		$	0.19
Fee based processing volumes (in millions of MMBtu)
For unaffiliated customers		33.1			30.4			2.7			64.5			58.5			6.0
For affiliated customers		27.2			26.7			0.5			52.8			52.3			0.5

Total Fee-Based Processing Volumes		60.3			57.1			3.2			117.3			110.8			6.5

Average fee-based processing revenue (per MMBtu)	$	0.21		$	0.16		$	0.05		$	0.19		$	0.16		$	0.03

Operating Expenses

The following table presents QEP’s total operating expenses and the changes from the three and six months ended June 30, 2010 to the three and six months ended June 30, 2011. The narrative below the table explains the significant variances between the periods.


	Three Months Ended June 30,							Six Months Ended June 30
	2011		2010		Change			2011		2010		Change
	(in millions)
Lease operating expense	$	34.3	$	28.6	$	5.7		$	67.1	$	56.9	$	10.2
Gathering, processing and other		27.2		19.6		7.6			52.4		43.1		9.3
General and administrative		28.7		25.7		3.0			60.4		50.9		9.5
Separation costs		—		14.0		(14.0	)		—		14.0		(14.0	)
Production and property taxes		27.1		19.0		8.1			50.8		41.9		8.9
Depreciation, depletion and amortization		186.6		151.6		35.0			377.4		299.0		78.4
Exploration expenses		2.3		2.7		(0.4	)		5.1		6.3		(1.2	)
Abandonment and impairment		5.3		9.3		(4.0	)		10.7		16.9		(6.2	)
Marketing purchases		303.9		133.9		170.0			450.6		311.8		138.8

Total operating expenses	$	615.4	$	404.4	$	211.0		$	1,074.5	$	840.8	$	233.7

The $5.7 million, or 20% increase in lease operating costs to $34.3 million during the second quarter of 2011 compared to the second quarter of 2010 was driven by the 20% increase in production of natural gas and oil equivalents during the period. Lease operating costs increased 18% to $67.1 million during the first half of 2011 compared to the first half of 2010, due to a 24% increase in production of natural gas and oil equivalents. Gathering, processing and other costs increased due to higher gathering and processing volumes in the second quarter and first half of 2011 when compared with the 2010 periods.

Total corporate general and administrative (G&A) costs increased to $28.7 million for the quarter ended June 30, 2011, compared with $25.7 million during the 2010 second quarter. During the first half of 2011, corporate general and administrative costs increased $9.5 million from the first half of 2010. The increases in 2011 resulted from higher insurance costs, increased fees for outside legal and professional services, and higher non-cash stock based compensation expenses due to the increase in QEP’s stock price, and higher compensation expense related to the issuance of additional shares of restricted stock and stock options during the last half of 2010 and the first half of 2011.

During the second quarter of 2010, QEP reported separation costs of $14.0 million related to the Spin-off of QEP Resources, Inc. from Questar Corporation on June 30, 2010. The expenses consisted primarily of QEP’s share of certain fees and expenses for financial, legal and tax advisory services and for severance expenses for terminated employees.

Higher natural gas, oil and NGL production and higher field level oil and NGL prices, resulted in higher total production and property taxes, partially offset by lower field level sales prices for natural gas.

QEP’s total depreciation expense grew $35.0 million or 23% in the second quarter of 2011 compared with the 2010 second quarter, and increased $78.4 million or 26% in the first half of 2011 compared to the first half 2010, as a result of increased production at QEP Energy combined with plant additions at QEP Field Services.

Exploration expenses were $2.3 million in the second quarter of 2011 compared with $2.7 million in the second quarter of 2010 due to reduced seismic acquisition costs of $0.3 million and dry hole cost reduction of $0.1 million. Exploration expenses decreased $1.2 million during the first half of 2011, when compared to the first half of 2010 due to lower seismic acquisition costs of $1.7 million, offset by an increase in dry hole cost of $0.5 million.

Abandonment and impairment expenses decreased to $5.3 million in the second quarter of 2011 compared with $9.3 million in the 2010 second quarter, and decreased to $10.7 million in the first half of 2011 compared to $16.9 million in the first half of 2010, primarily due to increases in the expected level of successful development of the Company’s unproved acreage.

Marketing purchases, which include QEP Energy purchased gas expense, increased due to increased purchased gas expense of $156.0 million during the second quarter of 2011.

CONSOLIDATED RESULTS BELOW OPERATING INCOME

Interest and other income

Interest and other income are comprised primarily of interest earned on investments, gains and losses on warehouse inventory, hedge ineffectiveness and other miscellaneous income. The decrease during the three and six month periods ended June 30, 2011 was primarily due to lower gains on warehouse inventory sales.

Realized and unrealized gain (loss) on basis-only swaps

In the past, the Company has used basis-only swaps to manage the risk of widening basis differentials. Basis-only swaps do not qualify for hedge accounting. As of December 31, 2009, all of the Company’s basis-only swaps had been paired with fixed-price swaps and re-designated as cash flow hedges. Fair value changes occurring prior to re-designation were recorded in the Consolidated Statements of Income. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in AOCI. Realized losses on settlements of basis-only swaps relating to the period prior to re-designation amounted to $27.6 million in the second quarter of 2011 and $27.4 million in the second quarter of 2010. Unrealized gains on basis-only swaps amounted to $27.6 million in the second quarter of 2011 compared to $27.4 million in 2010. Realized losses on settlements of basis-only swaps relating to the period prior to re-designation amounted to $58.8 million in the first half of 2011 and $62.1 million in the first half of 2010. Unrealized gains on basis-only swaps amounted to $58.8 million in the first half of 2011 compared to $62.1 million in 2010.

Interest expense

Interest expense rose by 9% in the second quarter of 2011 and 10% in the first half of 2011 compared to a year ago primarily due to June 30, 2011 debt levels that were approximately $250 million higher than average debt levels in the comparable prior period.

Income taxes

The effective combined federal and state income tax rate was 36.7% for both the three and six months ended June 30, 2011, slightly lower than the 36.8% in both the three and six months ended June 30, 2010.

DISCUSSION BY LINE OF BUSINESS

QEP Energy

QEP Energy reported net income of $46.8 million in the second quarter of 2011 compared with $52.6 million in the 2010 quarter. Net income for the first half of 2011 decreased 16% to $89.9 million compared to $106.4 million a year earlier. The primary reason for the decrease was a 17% decline in net realized natural gas prices to $4.04 per Mcfe in the second quarter of 2011, compared to $4.87 per Mcfe in the second quarter of 2010. Net realized natural gas prices decreased to $4.05 per Mcfe in the first half of 2011 compared to $4.92 per Mcfe in the comparable 2010 period. The decrease in net realized natural gas prices was partially offset by a 20% and 24% increase in natural gas-equivalent production, and a 39% and 32% increase in net realized oil prices in the three and six months ended June 30, 2011. Changes in unrealized basis-only swaps increased net income $17.3 million in the 2011 quarter compared to an increase of $17.2 million in the second quarter of 2010 and increased net income $36.9 million in the first half of 2011 compared to an increase of $39.0 million in the first half 2010. Following is a summary of QEP Energy’s financial and operating results:


	Three Months Ended June 30,							Six Months Ended June 30, 2011
	2011		2010		Change			2011		2010		Change
	(in millions)
*Operating Income*
Revenues
Natural gas sales	$	258.1	$	260.6	$	(2.5	)	$	529.1	$	525.2	$	3.9
Oil sales		80.0		44.7		35.3			142.3		89.6		52.7
NGL sales		16.5		9.0		7.5			33.7		18.1		15.6
Purchased gas sales		156.0		—		156.0			156.0		—		156.0
Other		2.6		1.5		1.1			4.8		2.6		2.2

Total Revenues		513.2		315.8		197.4			865.9		635.5		230.4

Operating expenses
Lease operating expense		35.0		29.3		5.7			68.4		58.1		10.3
General and administrative		22.9		18.9		4.0			46.8		38.0		8.8
Purchased gas expense		154.7		—		154.7			154.7		—		154.7
Production and property taxes		25.4		17.9		7.5			47.6		39.6		8.0
Depreciation, depletion and amortization		172.5		139.2		33.3			349.6		274.3		75.3
Exploration expenses		2.3		2.7		(0.4	)		5.1		6.3		(1.2	)


	Three Months Ended June 30,									Six Months Ended June 30, 2011
	2011			2010			Change			2011			2010			Change
	(in millions)
Abandonment and impairment		5.3			9.3			(4.0	)		10.7			16.9			(6.2	)

Total Operating Expenses		418.1			217.3			200.8			682.9			433.2			249.7
Net gain from asset sales		0.2			2.5			(2.3	)		0.2			2.5			(2.3	)

Operating Income		95.3			101.0			(5.7	)		183.2			204.8			(21.6	)
Interest and other income (loss)		(0.5	)		1.9			(2.4	)		0.2			2.7			(2.5	)
Income from unconsolidated affiliates		0.1			0.1			—			0.1			0.1			—
Interest expense		(20.4	)		(19.0	)		(1.4	)		(40.3	)		(38.0	)		(2.3	)

Income from Continuing Operations before Income Taxes		74.5			84.0			(9.5	)		143.2			169.6			(26.4	)
Income Taxes		(27.7	)		(31.4	)		3.7			(53.3	)		(63.2	)		9.9

Net Income Attributable to QEP	$	46.8		$	52.6		$	(5.8	)	$	89.9		$	106.4		$	(16.5	)

Operating expenses per unit

The table below presents certain QEP Energy operating expenses on a per unit of production basis. QEP Energy total production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, and allocated interest expense and production taxes) per Mcfe of production increased 2% to $4.27 per Mcfe in the second quarter of 2011 compared to $4.17 per Mcfe in 2010. First half 2011 total production costs per Mcfe decreased $0.02 compared to the 2010 period.


	Three Months Ended June 30,							Six Months Ended June 30
	2011		2010		Change			2011		2010		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.67	$	2.59	$	0.08		$	2.68	$	2.61	$	0.07
Lease operating expense		0.54		0.54		—			0.52		0.55		(0.03	)
General and administrative expense		0.35		0.35		—			0.36		0.36		—
Allocated interest expense		0.32		0.35		(0.03	)		0.31		0.36		(0.05	)
Production taxes		0.39		0.34		0.05			0.37		0.38		(0.01	)

Total Production Costs	$	4.27	$	4.17	$	0.10		$	4.24	$	4.26	$	(0.02	)

Depreciation, depletion and amortization (DD&A) expense increased $0.08 per Mcfe in second quarter 2011 from the 2010 second quarter. During the first half of 2011 DD&A expense increased by $0.07 per Mcfe from the first half of 2010. QEP Energy’s DD&A expense increased $33.3 million during the second quarter 2011 from the 2010 second quarter and increased $75.3 million during the first half of 2011 from the 2010 first half. These increases were driven by increased investment and a greater proportion of production coming from the Company’s Haynesville/Cotton Valley properties. The higher DD&A rates in Haynesville/Cotton Valley reflect significant amortization of leasehold pool costs as a result of the 2008 acquisition of producing properties. Lease operating expense per Mcfe was flat for the quarter ended June 30, 2011, but decreased during the first half of 2011 from the 2010 first half primarily as the result of increased production volumes from new high-rate, low operating cost wells in Haynesville/Cotton Valley and in the Pinedale Anticline coupled with declining production from higher-cost areas, which reduced average lease operating expense. G&A expense per Mcfe was flat in the three and six months ended June 30, 2011, as the result of increased production in the three and six months ended June 30, 2011, offset by higher G&A expenses, which were primarily related to stock based compensation expenses. Allocated interest expense per unit of production decreased in the three and six months ended June 30, 2011 period primarily due to higher production volumes. Production taxes per Mcfe increased second quarter of 2011 because of higher field level oil and NGL prices but decreased slightly during the first half of 2011 as a result of lower natural gas field-level sales prices.

The company has continued to lower its average production costs since 2008 as a result of growing production in lower cost operating areas such as Haynesville/Cotton Valley and Pinedale, coupled with lower production in higher cost areas. The following table presents average production cost (lease operating expense) excluding production taxes for QEP Energy by region on a per unit of production basis.


	Three Months Ended June 30,							Six Months Ended June 30							Year Ended December 31,
	2011		2010		Change			2011		2010		Change			2010		2009		2008
	(per Mcfe)
Southern Region	$	0.48	$	0.55	$	(0.07	)	$	0.46	$	0.54	$	(0.08	)	$	0.55	$	0.79	$	0.89
Northern Region		0.62		0.53		0.09			0.61		0.56		0.05			0.56		0.57		0.63
Average production cost	$	0.54	$	0.54	$	—		$	0.52	$	0.55	$	(0.03	)	$	0.56	$	0.67	$	0.73

Major QEP Energy Operating Areas

Southern Area

Haynesville/Cotton Valley

QEP Energy has approximately 50,600 net acres of Haynesville Shale lease rights in northwest Louisiana and additional lease rights that cover the Hosston and Cotton Valley formations. The depth of the top of the Haynesville Shale ranges from approximately 10,500 feet to 12,500 feet across QEP Energy’s leasehold and is below the Hosston and Cotton Valley formations that QEP Energy has been developing in northwest Louisiana for over a decade. As of June 30, 2011, QEP Energy had five operated rigs drilling in the project area at the end of the quarter and intends to add a sixth operated rig during the third quarter. QEP Energy operated or had working interests in 752 gross (445 net) producing wells in northwest Louisiana compared to 656 gross (402 net) wells at June 30, 2010. In the Haynesville/Cotton Valley area, QEP Energy completed 11 gross (6.8 net) and 26 gross (16.1 net) operated wells during the three and six months ended June 30, 2011. QEP Energy has 11 gross (7.0 net) operated wells waiting on completion or being completed and has an interest in 10 gross (0.7 net) outside-operated Haynesville/Cotton Valley wells that are waiting on completions and 9 gross (0.8 net) outside-operated wells that are drilling. QEP Energy intends to drill or participate in up to 80 gross (44 net) horizontal Haynesville/Cotton Valley wells in 2011.

Midcontinent

QEP Energy Midcontinent properties cover all properties in the Southern Region except the Haynesville/Cotton Valley area of northwest Louisiana, and are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas Panhandle, the Arkoma Basin of Oklahoma and western Arkansas, and the Ark-La-Tex region of Arkansas, and Texas. With the exception of the Granite Wash play in the Texas Panhandle and the Woodford “Cana” Shale play in western Oklahoma, QEP Energy Midcontinent leasehold interests are relatively fragmented, with no significant concentration of property interests.

QEP Energy has approximately 77,600 net acres of Woodford Shale lease rights in western Oklahoma. The true vertical depth to the top of the Woodford Shale ranges from approximately 10,500 feet to 14,500 feet across QEP Energy’s leasehold. As of June 30, 2011, QEP Energy had two operated rigs drilling in the project area and had working interests in 152 gross (27 net) producing Woodford Shale wells in western Oklahoma compared to 69 gross (15 net) wells at June 30, 2010. QEP anticipates having three operated rigs drilling in this play for most of the second half of 2011. QEP completed 3 gross (1.7 net) operated wells during the second quarter of 2011 and 8 gross (4.6 net) operated wells in the first half of 2011 in the Woodford Shale play. QEP Energy has interests in 17 gross (1.5 net) wells being drilled and 17 gross (1.7 net) wells waiting on completion that are operated by others. QEP Energy intends to drill or participate in up to 96 gross (18.2 net) horizontal Woodford Shale wells in 2011.

QEP Energy has approximately 40,300 net acres of Granite Wash/Atoka Wash lease rights in the Texas Panhandle and western Oklahoma and has been drilling vertical Granite Wash/Atoka Wash wells for over a decade. The true vertical depth to the top of the Granite Wash/Atoka Wash interval ranges from approximately 11,100 feet to 15,900 feet across QEP Energy’s leasehold. In the past year and a half, QEP and other operators have drilled a number of successful horizontal wells in the Granite Wash/Atoka Wash play but have also drilled some wells with disappointing results. As of June 30, 2011, QEP Energy had three rigs drilling horizontal Granite Wash/Atoka Wash wells in the Texas Panhandle and Western Oklahoma and had working interests in 74 gross (17 net) producing horizontal Granite Wash/Atoka Wash wells in the Texas Panhandle and western Oklahoma compared to 31 gross (4 net) wells at June 30, 2010. QEP intends to decrease its operated drilling rig count in this play to one rig in the second half of 2011. In the Granite Wash/Atoka Wash play, QEP completed 3 gross (2.5 net) and 6 gross (5.1 net) operated wells during the three and six months ended June 30, 2011. QEP Energy is drilling 2 gross (1.5 net) operated wells and has 2 gross (2.0 net) operated well waiting on completion. QEP Energy is also participating in 1 gross (0.1 net) outside-operated wells being drilled and has an interest in 2 gross (0.3 net) outside-operated wells waiting on completion. QEP Energy intends to drill or participate in up to 25 gross (10.7 net) horizontal Granite Wash/Atoka Wash wells in 2011.

Northern Area

Pinedale Anticline

As of June 30, 2011, QEP Energy had interests in 571 gross (335 net) producing wells on the Pinedale Anticline compared to 472 gross (266 net) wells at the end of the second quarter of 2010. Of the 571 gross producing wells, QEP Energy had working interests in 550 gross (335 net) wells and an overriding royalty interest only in an additional 21 wells. QEP completed 36 gross (26 net) operated wells during the second quarter of 2011 and 42 gross (30 net) operated wells in the first half of 2011 on the Pinedale Anticline. QEP Energy has 34 gross (23 net) operated wells drilled and cased waiting on completion. As of June 30, 2011, QEP had four rigs drilling on the Pinedale Anticline and expects to complete 95 to 100 gross (64 to 68 net) wells during 2011.

In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10 acre density drilling for Lance Pool wells on about 12,700 acres of QEP Energy’s 17,872 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of QEP Energy core acreage in the field. In January 2008, the WOGCC approved five acre density drilling for Lance Pool wells on about 4,200 gross acres of QEP Energy’s Pinedale leasehold. The true vertical depth to the top of the Lance Pool tight gas sand reservoir interval ranges from 8,500 to 9,500 feet across QEP Energy’s acreage. The Company currently estimates that up to 1,300 additional wells will be required to fully develop its Pinedale acreage on a combination of 5 and 10 acre density areas.

Uinta Basin

As of June 30, 2011, QEP Energy had an operating interest in 2,626 gross (785 net) producing or shut-in wells in the Uinta Basin of eastern Utah, compared to 2,227 gross (757 net) at June 30, 2010. The majority of Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at depths of 5,000 feet to deeper than 18,000 feet. QEP Energy owns interests in approximately 276,000 net leasehold acres in the Uinta Basin. In the Uinta Basin, QEP completed 1 gross (1.0 net) and 4 gross (2.9 net) operated wells during the three and six months ended June 30, 2011.

Rockies Legacy

The remainder of QEP Energy Northern Region leasehold interests, productive wells and proved reserves are distributed over a number of fields and properties managed as the Rockies Legacy division. Exploration and development activity for 2011 includes wells in the Powder River and Greater Green River Basins in Wyoming and the Williston Basin in North Dakota.

QEP Energy has approximately 90,000 net acres of lease rights in the Williston Basin in western North Dakota, where the Company is targeting the Bakken and Three Forks formations. The true vertical depth to the top of the Bakken Formation ranges from approximately 9,500 feet to 10,000 feet across QEP Energy’s leasehold. The Three Forks Formation lies approximately 60 to 70 feet below the Middle Bakken Formation and is also a target for horizontal drilling. As of June 30, 2011, QEP Energy had three operated rigs drilling in the project area and had working interests in 84 gross (16 net) producing Bakken/Three Forks wells in North Dakota compared to working interests in 39 gross (6 net) wells at June 30, 2010. QEP completed 2 gross (1.6 net) operated wells during the second quarter of 2011 and 5 gross (4.3 net) operated wells in the first half of 2011 in the Bakken/Three Forks play. QEP Energy also has interests in 6 gross (5.1 net) operated wells being drilled, 6 gross (0.3 net) outside-operated wells being drilled and 8 gross (0.4 net) outside-operated wells waiting on completion. QEP Energy intends to drill or participate in 84 gross (30 net) Bakken/Three Forks horizontal wells in 2011.

QEP Field Services

QEP Field Services, which provides gas gathering and processing services, generated net income of $44.2 million in the second quarter of 2011 compared to $24.3 million in the same period of 2010, an 82% increase. Net income was $72.2 million in the first half of 2011 compared to $47.5 million in the first half of 2010. The increase in net income for both periods was the result of higher gathering and processing margins and increased throughput volumes. Following is a summary of QEP Field Services’ financial and operating results:


	Three Months Ended June 30,						Six Months Ended June 30
	2011		2010		Change		2011		2010		Change
	(in millions)
*Operating Income*
Revenues
NGL sales	$	45.1	$	23.8	$	21.3	$	73.7	$	49.7	$	24.0
Processing (fee based)		12.2		9.0		3.2		22.2		17.3		4.9
Gathering		38.7		38.4		0.3		78.1		74.4		3.7
Other gathering		25.0		7.9		17.1		42.7		18.6		24.1

Total Revenues		121.0		79.1		41.9		216.7		160.0		56.7

Operating expenses
Processing		3.1		3.0		0.1		5.8		6.0		(0.2	)
Processing plant fuel and shrinkage		11.4		7.5		3.9		21.6		17.9		3.7
Gathering		12.4		8.7		3.7		24.3		18.6		5.7


	Three Months Ended June 30,									Six Months Ended June 30
	2011			2010			Change			2011			2010			Change
	(in millions)
General and administrative		6.8			7.2			(0.4	)		15.8			14.0			1.8
Taxes other than income taxes		1.6			1.0			0.6			3.0			2.1			0.9
Depreciation, depletion and amortization		13.5			11.9			1.6			26.7			23.7			3.0

Total Operating Expenses		48.8			39.3			9.5			97.2			82.3			14.9
Net gain (loss) from asset sales		0.1			(0.3	)		0.4			0.1			(1.1	)		1.2

Operating Income		72.3			39.5			32.8			119.6			76.6			43.0
Income from unconsolidated affiliates		1.2			0.6			0.6			2.1			1.3			0.8
Interest expense		(3.1	)		(1.2	)		(1.9	)		(6.6	)		(1.9	)		(4.7	)

Income from Continuing Operations before Income Taxes		70.4			38.9			31.5			115.1			76.0			39.1
Income Taxes		(25.5	)		(13.9	)		(11.6	)		(41.6	)		(27.2	)		(14.4	)

Income from Continuing Operations		44.9			25.0			19.9			73.5			48.8			24.7
Net income attributable to noncontrolling interest		(0.7	)		(0.7	)		—			(1.3	)		(1.3	)		—

Net Income Attributable to QEP	$	44.2		$	24.3		$	19.9		$	72.2		$	47.5		$	24.7

QEP Marketing

QEP Marketing and other income from continuing operations increased to $1.8 million and $3.9 million in the three and six months ended June 30, 2011, from $0.5 million and $1.6 million in the three and six months ended June 30, 2010. The increases are related to higher sales volumes and margins for both the three and six months ended June 30, 2011.

LIQUIDITY AND CAPITAL RESOURCES

QEP funds its operations, capital expenditures and working capital requirements with cash flow from its operating activities, borrowings under its credit facility and periodically, proceeds from debt offerings and asset sales. The Company believes cash flow from operations and availability under its credit facility will be sufficient to fund the Company’s planned capital expenditures and operating expenses in 2011. To the extent actual results differ from the Company’s estimates, its liquidity could be adversely affected.

Cash Flow from Operating Activities

Cash flows from operations are primarily affected by natural gas, oil and NGL production volumes and commodity prices (net of 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 oil and gas production for the next 12 to 24 months. See “Commodity Derivative Impact” above.

Net cash provided from continuing operating activities increased 34% in the first half of 2011 compared to the first half of 2010 due to higher noncash adjustments to net income and a source of cash from operating assets and liabilities in 2011 compared with a source of cash in 2010, offset by lower net income. Noncash adjustments to net income consist primarily of depreciation, depletion and amortization; noncash unrealized gains and losses on basis-only swaps and changes in deferred income taxes. Cash sources from operating assets and liabilities were higher in 2011 primarily due to reductions in accounts receivable and prepaid expenses in the first half ended June 30, 2011, compared with the same period ended June 30, 2010. Net cash provided from continuing operating activities is presented below:


	Six Months Ended June 30
	2011		2010			Change
	(in millions)
Income from continuing operations	$	167.3	$	148.2		$	19.1
Noncash adjustments to net income		438.0		377.1			60.9
Changes in operating assets and liabilities		23.3		(57.2	)		80.5

Net cash provided from continuing operating activities	$	628.6	$	468.1		$	160.5

Cash Flow from Investing Activities

A comparison of capital expenditures for continuing operations for the first half of 2011 and 2010 plus a forecast for calendar year 2011 are presented below:


	Six Months Ended June 30,									Current Forecast 12 Months Ended		Prior Forecast 12 Months Ended
	2011			2010			Change			December 31, 2011		December 31, 2011
	(in millions)
QEP Energy	$	639.6		$	547.9		$	91.7		$	1,173.0	$	1,050.0
QEP Field Services		33.2			138.8			(105.6	)		125.0		150.0
QEP Marketing and other		1.3			0.1			1.2			2.0		—

Total accrued capital expenditures of continuing operations		674.1			686.8			(12.7	)		1,300.0		1,200.0
Change in accruals		(12.3	)		(30.7	)		18.4			—		—

Total cash capital expenditures of continuing operations	$	661.8		$	656.1		$	5.7		$	1,300.0	$	1,200.0

QEP Energy capital investment in the first six months of 2011 increased $91.7 million over the prior year period due to an increase in the number of company-operated well completions as a result of ongoing efficiency gains, combined with assumption of additional working interests in certain wells due to partner elections not to participate. QEP Field Services capital investment declined $105.6 million in the first half of 2011 compared to the 2010 period due to completion of major capital projects in eastern Utah and northwest Louisiana in late 2010 and pending completion of the Blacks Fork II plant late in the second quarter of 2011. QEP forecasted capital investments for 2011 total $1,300 million, comprised of $1,173 million in QEP Energy, $125 million in QEP Field Services, and $2 million in QEP Marketing and other. The $123 million increase in forecasted capital investment in QEP Energy for 2011 is due to; 1) a forecasted increase in the number of net completed Pinedale and Haynesville Shale wells by year-end due to continued drilling/completion efficiency gains; 2) QEP’s assumption of additional working interests in certain Pinedale wells due to partner elections not to participate in same; 3) increased completed well costs in the Bakken and Cana Shale plays due to escalating drilling and completion costs that have not been offset by efficiency gains; and 4) the anticipated addition of two additional drilling rigs in each of the Bakken/Three Forks and Pinedale plays in the fourth quarter of 2011. Forecasted capital investment in QEP Field Services declined $25 million versus the prior forecast due to early completion of the Blacks Fork II gas processing plant and slight changes in timing of expenditures on certain other gathering and processing projects.

Cash Flow from Financing Activities

In the first half of 2011, net cash used in investing activities of $660.2 million exceeded net cash provided by operating activities of $628.6 million by $31.6 million. Net cash used in investing activities during the first half of 2010 was $598.5 million, which exceeded net cash provided by operating activities of $468.1 million by $130.4 million. Long-term debt (including the current portion of long-term debt) increased by $41.8 million from year-end 2010, primarily due to the semi-annual interest payments on the senior notes. At June 30, 2011, long-term debt consisted of $500.0 million outstanding under QEP’s revolving credit facility and $1,072.6 million in senior notes (including $5.8 million of net original issue discount). At June 30, 2011, combined short-term and long-term debt was 33% and equity was 67% of total capital.

Credit Facility

QEP has a revolving credit facility that provides for loan commitments of $1.0 billion from a syndicate of financial institutions. The facility matures in March 2013. The credit facility has restrictive covenants that limit the amount of funded indebtedness that QEP may incur. At June 30, 2011, QEP was in compliance with all of its debt covenants. At July 25, 2011, QEP had $500.0 million outstanding under its revolving credit facility and $4.0 million of letters of credit issued.

Senior Notes

The Company’s senior notes outstanding as of June 30, 2011, totaled $1,078.4 million principal amount and are comprised of four issues as follows:

•

$176.8 million 6.05% Senior Notes due September 2016

•

$138.6 million 6.80% Senior Notes due April 2018

•

$138.0 million 6.80% Senior Notes due March 2020

•

$625.0 million 6.875% Senior Notes due March 2021

Capital Expenditures

In 2011, QEP intends to fund capital expenditures with cash flow from operating activities and borrowings under its revolving credit facility, if needed. The Company plans to allocate capital to higher return plays and to its core dry gas plays as necessary to generate profitable growth while maintaining a competitive cost structure. As a result of the continued spread between oil and natural gas prices, QEP has allocated almost 40% of its forecasted 2011 capital expenditures to oil and liquids-rich natural gas projects in its portfolio and reduced the allocation of its capital expenditures to dry natural gas plays. The Company has budgeted approximately $1,300.0 million for capital expenditures in 2011 (excluding acquisitions), of which it has allocated $1,173.0 million to QEP Energy, with approximately 25% targeted for each of the following: (i) plays in the Rockies Legacy division, including the Bakken and Three Forks formations in North Dakota, the Sussex play in the Powder River Basin of Wyoming and other Rockies oil and liquids-rich gas plays; (ii) Midcontinent liquid rich gas plays; (iii) the Pinedale Anticline and (iv) the Haynesville/Cotton Valley area. QEP plans to invest approximately $125.0 million in capital expenditures to grow its midstream business, including the completion of its Black Fork II cryogenic gas processing plant. The aggregate levels of capital expenditures for 2011 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, natural gas and oil prices, industry conditions, the extent to which properties 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.

During the first half of 2011, capital expenditures increased 1% to $661.8 million, which included $29.8 million for property acquisitions, compared to $656.1 million during the same period of 2010. The increase was driven by higher capital investment in development drilling in the Midcontinent and the Rockies Legacy divisions, partially offset by reduced development drilling in the Haynesville/Cotton Valley and Pinedale Anticline along with lower investment at QEP Field Services due to the completion of the Iron Horse processing plant in January 2011.

Delivery Commitments

The Company sells NGLs under a term sales agreement that contains a delivery commitment for 8,500 barrels per day of NGL’s derived from several of QEP Field Services’ gas processing facilities in the Northern Region. The agreement, which was effective May 1, 2010, extends for a period of seven years and contains terms and conditions customary for an agreement of this type in the oil and gas industry. The Company believes that the reserves dedicated to its gas processing facilities and projected processing volumes are adequate to satisfy its delivery commitments under this agreement.

The Company is a party to various long-term sales commitments for physical delivery of natural gas with the following future firm delivery commitments:


Period	Delivery Commitments
	(millions of MMbtu)
2^nd half 2011		65.8
2012		101.5
2013		33.1
2014		9.4
2015		3.8

These commitments are physical delivery obligations with prices related to the prevailing index prices for natural gas at the time of delivery. None of these commitments require the Company to deliver natural gas produced specifically from any of the Company’s properties. The Company believes that its production and reserves are adequate to meet these term sales commitments. If for some reason the Company’s natural gas production is not sufficient to satisfy its term sales commitments, the Company believes it can purchase sufficient volumes of natural gas in the market at index related prices to satisfy its commitments.

In addition, none of the Company’s production from QEP Energy-owned properties is subject to any priorities, proration or third-party imposed curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in “Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

QEP’s primary market-risk exposure arises from changes in the market price for natural gas, oil and NGL, and to a lesser extent, volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. QEP Marketing and QEP Energy 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. If energy prices decline or increase significantly, revenues and cash flow may significantly decline or increase. 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. A sensitivity analysis of the Company’s commodity price related derivative instruments to changes in the price of the underlying commodities is presented below.

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. However, these same arrangements typically limit future gains from favorable price movements. The Company’s risk-management policies provide for the use of derivative instruments to manage this risk. The types of commodity derivative instruments utilized by the Company include fixed-price swaps, price collars, and basis-only swaps. The volume of commodity derivative instruments utilized by the Company may vary from year to year. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or its counterparties in order to satisfy these margin requirements. 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, 2011, QEP held commodity price derivative contracts covering about 253.5 million MMBtu of natural gas and 1.7 million barrels of oil. A year earlier, the QEP derivative contracts covered 325.4 million MMBtu of natural gas, 1.9 million barrels of oil. Changes in the fair value of derivative contracts from December 31, 2010 to June 30, 2011, are presented below:


	Cash Flow Hedges			Basis-Only Swaps			Total
	(in millions)
Net fair value of gas and oil derivative contracts outstanding at Dec. 31, 2010	$	356.2		$	(117.7	)	$	238.5
Contracts settled		(141.5	)		58.8			(82.7	)
Change in gas and oil prices on futures markets		38.0			—			38.0
Contracts added		23.5			—			23.5

Net fair value of gas, oil and NGL derivative contracts outstanding at June 30, 2011	$	276.2		$	(58.9	)	$	217.3

A table of the net fair value of gas and oil derivative contracts as of June 30, 2011, is shown below. Derivatives representing approximately 60% of the net fair value will settle in the next twelve months and will be reclassified from AOCI to the Consolidated Statements of Income:


	Cash Flow Hedges		Basis-Only Swaps			Total
	(in millions)
Contracts maturing by June 30, 2012	$	167.0	$	(58.9	)	$	108.1
Contracts maturing between July 1, 2012 and June 30, 2013		75.0		—			75.0
Contracts maturing between July 1, 2013 and June 30, 2014		34.2		—			34.2
Contracts maturing between July 1, 2014 and June 30, 2015		—		—			—

Net fair value of gas, oil and NGL derivative contracts outstanding at June 30, 2011	$	276.2	$	(58.9	)	$	217.3

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


	June 30, 2011		December 31, 2010
	(in millions)
Net fair value - asset (liability)	$	217.3	$	238.5
Fair value if market prices of gas, oil and NGL and basis differentials decline by 10%		351.1		356.2
Fair value if market prices of gas, oil and NGL and basis differentials increase by 10%		93.0		132.1

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $124.3 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $133.8 million. However, a gain or loss would eventually 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 Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commodity Derivatives Impact under Part I, Item 2 of this Form 10-Q.

Interest-Rate Risk Management

The Company’s ability to borrow and the rates quoted by lenders can be adversely affected by the illiquid credit markets. The Company’s credit facility has floating interest rates and as such, exposes QEP to interest rate risk. If interest rates were to increase 10% over their six month ending June 30, 2011 and 2010 average levels and at our average level of borrowing for those same periods, our interest expense would increase by $0.6 million and $0.1 million for the six months ended June 30, 2011 and 2010, respectively, or less than 2% in either year.

Forward-Looking Statements

This quarterly report contains or incorporates by reference 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:

•

plans to drill or participate in wells;

•

expenses;

•

belief that QEP has one of the lowest cash cost structures among its peers;

•

the outcome of contingencies such as legal proceedings;

•

expected contributions to the Company’s retirement plan;

•

trends in operations;

•

amount and allocation of forecasted capital expenditures for 2011;

•

timing of completion of Black Forks II processing plant;

•

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

•

the ability of QEP to use derivative instruments to manage commodity price risk;

•

adequacy of QEP’s production and reserves to satisfy delivery commitments and our ability to purchase natural gas and NGLs in the market to cover any shortfalls;

•

acquisition plans; and

•

growth strategy.

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, 2010; and

•

changes in natural gas, oil and NGL prices;

•

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

•

shortages of oilfield equipment, services and personnel;

•

operating risks such as unexpected drilling conditions;

•

weather conditions;

•

the availability and cost of credit;

•

changes in maintenance and construction costs;

•

changes in industry trends;

•

changes in laws or regulations; 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, 2011. Based on such evaluation, such officers have concluded that, as of June 30, 2011, the Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company’s reports filed or submitted under the Exchange Act. The Company’s Chief Executive Officer and Chief Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls.

There were no changes in the Company’s internal controls over financial reporting during the quarter ended June 30, 2011, that materially affect, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS.

For further information regarding the Company’s legal proceedings, see Note 11 – Contingencies under Part I, Item 1 of this
Form 10-Q.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

QEP had no unregistered sales of equity during the first quarter of 2011.

ITEM 3.

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		The following materials from QEP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income for the three and six months ended June 30, 2011 and 2010, (ii) Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010, (iii) Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010, and (iv) Notes Accompanying the Condensed Consolidated Financial Statements, tagged as a block of text*.

Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

SIGNATURES

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


		QEP RESOURCES, INC.
		(Registrant)

July 29, 2011		/s/ C. B. Stanley
		C. B. Stanley,
		President and Chief Executive Officer

July 29, 2011		/s/ Richard J. Doleshek
		Richard J. Doleshek,
		Executive Vice President,
		Chief Financial Officer and Treasurer

Exhibit Index


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		The following materials from QEP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income for the three and six months ended June 30, 2011 and 2010, (ii) Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010, (iii) Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010, and (iv) Notes Accompanying the Condensed Consolidated Financial Statements, tagged as a block of text*.

Large accelerated filer

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Smaller reporting company