Edgar Filing: QEP RESOURCES, INC.

form10q.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 September 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 17th Street, Suite 500, Denver, Colorado 80265

(Address of principal executive offices)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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):

Large accelerated filer	¨		Accelerated filer	¨

Non-accelerated filer	x	(Do not check if a smaller reporting company)	Smaller reporting company	¨

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 September 30, 2011, there were 176,952,496 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended September 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	17

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35

	ITEM 4.	CONTROLS AND PROCEDURES	39

PART II. OTHER INFORMATION			39

	ITEM 1.	LEGAL PROCEEDINGS	39

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39

	ITEM 3.	EXHIBITS	39

SIGNATURES			40

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PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions, except per share amounts)
REVENUES
Natural gas sales	$	266.7		$	283.2		$	795.8		$	808.4
Oil sales		76.1			49.9			218.4			139.5
NGL sales		34.1			9.3			67.8			27.4
Gathering, processing and other		118.7			76.4			340.1			238.7
Purchased gas and oil sales		356.8			145.8			810.6			460.4
Total Revenues		852.4			564.6			2,232.7			1,674.4
OPERATING EXPENSES
Purchased gas and oil expense		352.7			143.6			803.3			455.4
Lease operating expense		37.0			32.8			104.1			89.7
Gathering, processing and other		27.0			19.5			79.4			62.6
General and administrative		28.7			24.7			89.1			75.6
Separation costs		-			0.2			-			14.2
Production and property taxes		27.7			19.7			78.5			61.6
Depreciation, depletion and amortization		189.0			170.5			566.4			469.5
Exploration expenses		2.4			2.9			7.5			9.2
Abandonment and impairment		5.7			12.2			16.4			29.1
Total Operating Expenses		670.2			426.1			1,744.7			1,266.9
Net gain from asset sales		1.2			10.8			1.4			12.3
OPERATING INCOME		183.4			149.3			489.4			419.8
Interest and other income (loss)		(0.7	)		1.6			(0.5	)		4.4
Income from unconsolidated affiliates		2.3			1.1			4.5			2.5
Loss from early extinguishment of debt		(0.7	)		(13.3	)		(0.7	)		(13.3	)
Interest expense		(22.8	)		(22.6	)		(67.0	)		(62.8	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		161.5			116.1			425.7			350.6
Income taxes		(59.1	)		(44.2	)		(156.0	)		(130.5	)
INCOME FROM CONTINUING OPERATIONS		102.4			71.9			269.7			220.1
Discontinued operations, net of income tax		-			-			-			43.2
NET INCOME		102.4			71.9			269.7			263.3
Net income attributable to noncontrolling interest		(0.9	)		(0.8	)		(2.2	)		(2.1	)
NET INCOME ATTRIBUTABLE TO QEP	$	101.5		$	71.1		$	267.5		$	261.2

Earnings Per Common Share Attributable to QEP
Basic from continuing operations	$	0.58		$	0.40		$	1.52		$	1.24
Basic from discontinued operations		-			-			-			0.25
Basic total	$	0.58		$	0.40		$	1.52		$	1.49
Diluted from continuing operations	$	0.57		$	0.40		$	1.50		$	1.23
Diluted from discontinued operations		-			-			-			0.24
Diluted total	$	0.57		$	0.40		$	1.50		$	1.47
Weighted-average common shares outstanding
Used in basic calculation		176.6			175.4			176.5			175.2
Used in diluted calculation		178.5			177.9			178.5			177.6
Dividends per common share	$	0.02		$	0.02		$	0.06		$	0.02

See notes accompanying the condensed consolidated financial statements

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QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	-		$	-
Accounts receivable, net		355.3			269.9
Fair value of derivative contracts		225.4			257.3
Inventories, at lower of average cost or market
Gas, oil and NGL		16.1			16.4
Materials and supplies		87.1			65.4
Prepaid expenses and other		35.6			45.2
Total Current Assets		719.5			654.2
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties		7,780.8			6,874.3
Unproved properties, not being depleted		326.3			322.0
Midstream field services		1,430.6			1,360.5
Marketing and other		47.8			44.5
Total Property, Plant and Equipment		9,585.5			8,601.3
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production		2,963.6			2,454.4
Midstream field services		283.7			244.6
Marketing and other		14.0			12.3
Total Accumulated Depreciation, Depletion and Amortization		3,261.3			2,711.3
Net Property, Plant and Equipment		6,324.2			5,890.0
Investment in unconsolidated affiliates		44.1			44.5
Goodwill		59.5			59.6
Fair value of derivative contracts		116.4			120.8
Other noncurrent assets		33.2			16.2
TOTAL ASSETS	$	7,296.9		$	6,785.3
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	26.7		$	19.5
Accounts payable and accrued expenses		455.3			332.2
Production and property taxes		40.4			18.9
Interest payable		6.2			28.1
Fair value of derivative contracts		39.8			139.3
Deferred income taxes		20.7			27.8
Current portion of long-term debt		-			58.5
Total Current Liabilities		589.1			624.3
Long-term debt, less current portion		1,582.7			1,472.3
Deferred income taxes		1,535.0			1,377.7
Asset retirement obligations		160.2			148.3
Fair value of derivative contracts		-			0.3
Other long-term liabilities		103.3			99.3
Commitments and contingencies
EQUITY
Common stock		1.8			1.8
Treasury stock		(11.6	)		(3.8	)
Additional paid-in capital		423.9			398.0
Retained earnings		2,677.2			2,420.0
Accumulated other comprehensive income		184.4			194.3
Total Common Shareholders' Equity		3,275.7			3,010.3
Noncontrolling interest		50.9			52.8
Total Equity		3,326.6			3,063.1
TOTAL LIABILITIES AND EQUITY	$	7,296.9		$	6,785.3

See notes accompanying the condensed consolidated financial statements

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QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(in millions)
OPERATING ACTIVITIES
Net income	$	269.7		$	263.3
Discontinued operations, net of income tax		-			(43.2	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		566.4			469.5
Deferred income taxes		155.9			206.3
Abandonment and impairment		16.4			29.1
Share-based compensation		16.5			11.3
Amortization of debt issuance costs and discounts		2.4			1.8
Dry exploratory well expense		0.5			-
Net gain from asset sales		(1.4	)		(12.3	)
Income from unconsolidated affiliates		(4.5	)		(2.5	)
Distributions from unconsolidated affiliates and other		7.6			2.1
Loss on early extinguishment of debt		0.7			13.3
Unrealized gain on basis-only swaps		(86.7	)		(90.0	)
Changes in operating assets and liabilities		12.2			(80.7	)
Net Cash Provided by Operating Activities of Continuing Operations		955.7			768.0
INVESTING ACTIVITIES
Property acquisitions		(40.7	)		(94.1	)
Property, plant and equipment, including dry exploratory well expense		(957.7	)		(941.8	)
Proceeds from disposition of assets		7.4			25.4
Change in notes receivable		-			52.9
Net Cash Used in Investing Activities of Continuing Operations		(991.0	)		(957.6	)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances		7.2			-
Long-term debt issued		280.0			819.3
Long-term debt issuance costs paid		(10.5	)		(18.1	)
Current portion long-term debt repaid		(58.5	)		(91.5	)
Repayments of notes payable		-			(39.3	)
Long-term debt repaid		(170.0	)		(721.5	)
Long-term debt extinguishment costs		-			(4.9	)
Other capital contributions		1.6			1.4
Equity contribution		-			250.0
Dividends paid		(10.6	)		(3.5	)
Distribution from Questar		0.2			(15.7	)
Distribution to noncontrolling interest		(4.1	)		(3.7	)
Net Cash Provided by Financing Activities of Continuing Operations		35.3			172.5
CASH USED IN CONTINUING OPERATIONS		-			(17.1	)
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		-			(17.1	)
Beginning cash and cash equivalents		-			19.3
Ending cash and cash equivalents	$	-		$	2.2

See notes accompanying the condensed consolidated financial statements

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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. Company 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 nine months ended September 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 September of 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-08, which amends the guidance on testing goodwill for impairment. The new guidance provides entities that are testing goodwill the option of performing a qualitative assessment before calculating the fair value of the reporting unit. If it is determined, based on the qualitative assessment, that the carrying value of the reporting unit is more likely than not less than the fair value, further impairment testing is not required. However, if the qualitative assessment does not provide such conclusive evidence, further testing and calculation of fair value of the reporting unit will be required. The amendments are effective for reporting periods (including interim periods) beginning after December 15, 2011. QEP does not expect that this ASU, once adopted, will have a material impact on its financial statements.

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In June of 2011, the FASB issued 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 this 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 September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in millions, except per share amounts)
Revenues	$	-	$	-	$	-	$	131.2
Income before income taxes		-		-		-		67.4
Income taxes		-		-		-		(24.2	)
Discontinued operations, net of income taxes	$	-	$	-	$	-	$	43.2
Earnings per common share attributable to QEP
Basic from discontinued operations	$	-	$	-	$	-	$	0.25
Diluted from discontinued operations		-		-		-		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:

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)
Net income	$	102.4		$	71.9		$	269.7		$	263.3
Other comprehensive income (loss)
Net unrealized income (loss) on derivatives		59.5			125.0			(20.6	)		359.2
Minimum pension liability adjustment		2.2			(16.2	)		5.0			(54.9	)
Income taxes		(23.0	)		(39.9	)		5.7			(112.6	)
Net other comprehensive income (loss)		38.7			68.9			(9.9	)		191.7
Comprehensive income		141.1			140.8			259.8			455.0
Comprehensive income attributable to noncontrolling interest		(0.9	)		(0.8	)		(2.2	)		(2.1	)
Comprehensive income attributable to QEP	$	140.2		$	140.0		$	257.6		$	452.9

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

	September 30, 2011			December 31 ,2010			Change
	(in millions)
Net unrealized gain on derivatives	$	210.8		$	223.8		$	(13.0	)
Pension and postretirement liabilities		(26.4	)		(29.5	)		3.1
Accumulated other comprehensive income	$	184.4		$	194.3		$	(9.9	)

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 September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in millions)
Weighted-average basic common shares outstanding		176.6		175.4		176.5		175.2
Potential number of shares issuable under the Long-term Stock Incentive Plan		1.9		2.5		2.0		2.4
Average diluted common shares outstanding		178.5		177.9		178.5		177.6

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:

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	2011			2010
	(in millions)
ARO liability at January 1,	$	148.3		$	124.7
Accretion		7.2			6.5
Liabilities incurred		6.5			14.8
Revisions		-			0.5
Liabilities settled		(1.8	)		(2.3	)
ARO liability at September 30,	$	160.2		$	144.2

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 after the completion of drilling.

	2011			2010
	(in millions)
Balance at January 1,	$	13.6		$	51.7
Additions to capitalized exploratory well costs pending the determination of proved reserves		-			18.8
Reclassifications to property, plant and equipment after the determination of proved reserves		(8.3	)		(50.3	)
Balance at September 30,	$	5.3		$	20.2

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. QEP’s Level 2 fair value measurements consist of fixed-price swaps of natural gas, oil and NGL. Level 3 inputs are unobservable inputs for the asset or liability. QEP’s Level 3 measurements are made up of costless collars for natural gas and oil. 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.

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

	Fair Value Measurements September 30, 2011
	Level 2		Level 3		Netting Adjustments			Total
	(in millions)
Assets
Derivative contracts - short term	$	258.1	$	10.7	$	(43.4	)	$	225.4
Derivative contracts - long term		116.4		-		-			116.4
Total assets	$	374.5	$	10.7	$	(43.4	)	$	341.8
Liabilities
Derivative contracts - short term	$	83.2	$	-	$	(43.4	)	$	39.8
Derivative contracts - long term		-		-		-			-
Total liabilities	$	83.2	$	-	$	(43.4	)	$	39.8

The change in the fair value of Level 3 assets and liabilities for the nine months ended September 30, 2011, is shown below:

	Derivative contracts 2011
	(in millions)
Balance at January 1,	$	36.3
Realized gains and losses included in revenues		10.7
Unrealized gains and losses included in other comprehensive income		(25.6	)
Settlements		(10.7	)
Balance at September 30,	$	10.7

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

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The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to the condensed consolidated financial statements in this quarterly report on Form 10-Q:

	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	September 30, 2011				December 31, 2010
	(in millions)
Financial assets
Cash and cash equivalents	$	-	$	-	$	-	$	-
Financial liabilities
Checks outstanding in excess of cash balances		26.7		26.7		19.5		19.5
Long-term debt		1,582.7		1,640.5		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 enter into derivative contracts for up to 100% of forecasted 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 costless collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Costless 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, crude oil, or NGL 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. In the past, QEP Energy has used 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 costless collars and re-designated as cash flow hedges.

QEP generally 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.

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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, oil and NGL 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, oil and NGL 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. NGL hedges are typically structured as Mont Belvieu, Texas fixed-price swaps. Since most of our NGL sales are also based upon Mont Belvieu prices, there is no ineffectiveness. Costless collars qualify for cash flow hedge accounting. Basis-only swaps do not qualify for hedge accounting treatment. 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 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 September 30,						Nine Months Ended September 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	$	129.6		$	221.4		$	191.1		$	597.3
Gains (losses) reclassified from AOCI into income for the effective portion of hedges
Natural gas sales		71.6			97.6			209.1			240.7
Oil sales		0.9			(1.4	)		1.0			(5.2	)
Gathering, processing and other		(0.3	)		-			(0.3	)		-
Purchased gas and oil sales		-			-			-			-
Purchased gas and oil expense		0.4			0.3			4.3			2.7
Loss recognized in income for the ineffective portion of hedges
Interest and other income		(2.7	)		(0.1	)		(2.6	)		(0.2	)
Effect of derivative instruments not designated as hedges
Unrealized gain on basis-only swaps		27.9			27.9			86.7			90.0
Realized loss on basis-only swaps		(27.9	)		(27.9	)		(86.7	)		(90.0	)

Based on prices as of September 30, 2011, it is estimated that $137.7 million will be settled and reclassified from AOCI to the Consolidated Statements of Income during the next twelve months.

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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.

	September 30, 2011		December 31, 2010
	(in millions)
Assets
Fixed-price swaps	$	258.1	$	374.6
Costless collars		10.7		37.9
Fair value of derivative instruments - short term	$	268.8	$	412.5
Fixed-price swaps	$	116.4	$	121.1
Costless collars		-		-
Fair value of derivative instruments - long-term	$	116.4	$	121.1
Liabilities
Fixed-price swaps	$	52.2	$	175.2
Costless collars		-		1.6
Basis-only swaps		31.0		117.7
Fair value of derivative instruments - short term	$	83.2	$	294.5
Fixed-price swaps	$	-	$	0.6
Costless 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 September 30, 2011:

Year	Time period	Quantity	Average Price per Mcf or Bbl, Net to the Well (1)
			(estimated)
	Gas Fixed-price Swaps (Bcf)
2011	3 months	33.8	$4.40
2012	12 months	112.7	4.63
2013	12 months	50.3	5.44
	Gas Costless Collars (Bcf)
			Floor - Ceiling
2011	3 months	7.3	$4.04 - $5.97
	Oil Fixed-price Swaps (Mbbl)
2011	3 months	46.0	$98.00
2012	12 months	915.0	96.10
2013	12 months	182.5	103.80

	Oil Costless Collars (Mbbl)
			Floor - Ceiling
2011	3 months	276.0	$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.

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QEP Field Services NGL Volumes

QEP Field Services enters into commodity derivative transactions to manage price risk on extracted NGL volumes. The following table sets forth QEP Field Services’ volumes and swap prices for its commodity derivative contracts as of September 30, 2011:

Year	Time period	Quantity	Average Price per Gallon
Propane Sales Fixed-price Swaps (millions of gallons)
2011	3 months	3.9	$1.45
2012	6 months (1)	7.6	1.45

_____________________

(1)	The swaps outstanding as of September 30, 2011, extend through the first six months 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 September 30, 2011:

Year	Time period	Quantity	Average Price per MMBtu
Gas Sales Fixed-price Swaps (millions of MMBtu)
2011	3 months	2.1	$4.67
2012	12 months	2.7	4.55
2013	12 months	0.9	4.77
Gas Purchases Fixed-price Swaps (millions of MMBtu)
2011	3 months	2.0	$3.85

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:

	September 30, 2011			December 31, 2010
	(in millions)
Revolving Credit Facility	$	510.0		$	400.0
7.5% 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
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		1,588.4			1,536.9
Less unamortized discount		(5.7	)		(6.1	)
Total long-term debt outstanding	$	1,582.7		$	1,530.8

Of the total debt outstanding on September 30, 2011, the $510.0 million drawn under the revolving credit facility (described below) due August 25, 2016, and the 6.05% Senior Notes due September 1, 2016, will mature within the next five years.

Credit Arrangements

During the third quarter of 2011, QEP entered into a new revolving credit facility, which matures in August 2016 and replaced the previous $1.0 billion credit facility. Proceeds from borrowings under the credit facility were used to refinance outstanding amounts under the Company’s previous credit facility and will be used for general corporate purposes, including working capital and capital expenditures. The terms of the new credit facility provide for loan commitments of $1.5 billion from a syndicate of financial institutions. The new credit facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The agreement also contains provisions that would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for up to two additional one-year periods. In conjunction with the replacement of the previous credit facility, QEP expensed $0.7 million of unamortized financing fees, which are included as a loss on extinguishment of debt on the Consolidated Income Statement. At September 30, 2011, QEP was in compliance with all of its debt covenants. At September 30, 2011 QEP had $510.0 million drawn and $4.0 million in letters of credit outstanding under the credit facility.

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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, 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. Individual members of the Ute Indian Tribe’s Business Committee have now intervened as co-plaintiffs asserting the same CAA claims as the federal government. 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 monitoring, testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed as part of their operational design 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 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.

QEP Energy v. U.S. Environmental Protection Agency, No. 09-9538, U.S. Court of Appeals for the 10th Circuit. On July 10, 2009, QEP Energy filed a petition with the U.S. 10th 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 $5.7 million in the third quarter of 2011 compared to $4.2 million for the third quarter of 2010. Shared based compensation for the nine months ended September 30, 2011 was $16.5 million compared to $11.3 million during the same period of 2010. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 14.1 million shares available for future grants at September 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.

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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 Nine Months Ended September 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		(111,797	)		7.78 - 27.55		15.69
Forfeited		(1,666	)		23.98		23.98
Balance at September 30, 2011		2,003,694			7.78 - 39.07		21.23

Options Outstanding							Options Exercisable				Unvested Options
Range of Exercise Prices	Number Outstanding at September 30, 2011		Weighted- Average Remaining Term in Years		Weighted- Average Exercise Price		Number Exercisable at September 30, 2011		Weighted- Average Exercise Price		Number Unvested at September 30, 2011		Weighted- Average Exercise Price
$7.78 - $11.89		582,050		0.9	$	8.57		582,050	$	8.57		-	$	-
19.37 - 27.84		1,219,409		4.0		24.31		751,729		24.45		467,680		24.09
39.07		202,235		6.4		39.07		-		-		202,235		39.07
		2,003,694		3.3		21.23		1,333,779		17.52		669,915		28.61

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 September 30, 2011, was 15 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		426,953			32.29 - 44.12		39.18
Distributed		(300,478	)		17.03 - 47.28		29.37
Forfeited		(14,150	)		17.03 - 40.03		35.44
Balance at September 30, 2011		1,079,286			19.86 - 44.12		32.48

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Performance Share Units

During the nine months ended September 30, 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 September 30, 2011, was 29 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 September 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 nine months ended September 30, 2011, the Company made contributions of $13.5 million to its retirement plans which increased plan assets. During the remainder of 2011, the Company expects to contribute $1.3 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 September 30, 2011					Nine Months Ended September 30, 2011
	Pension			Postretirement benefits		Pension			Postretirement benefits
	(in millions)
Service cost	$	0.7		$	0.1	$	2.1		$	0.1
Interest cost		1.2			-		3.4			0.2
Expected return on plan assets		(0.7	)		-		(1.9	)		-
Amortization of prior service costs		1.4			0.1		4.0			0.3
Recognized net actuarial loss		-			-		-			-
Periodic expense	$	2.6		$	0.2	$	7.6		$	0.6

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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 and other). 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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)
Revenues from unaffiliated customers
QEP Energy	$	590.6		$	343.5		$	1,456.5		$	979.0
QEP Field Services		116.3			75.3			331.6			234.1
QEP Marketing and other		145.5			145.8			444.6			461.3
Total	$	852.4		$	564.6		$	2,232.7		$	1,674.4
Revenues from affiliated companies
QEP Field Services	$	0.8		$	0.5		$	2.2		$	1.7
QEP Marketing and other		148.7			121.0			426.9			376.7
Total	$	149.5		$	121.5		$	429.1		$	378.4
Operating income
QEP Energy	$	113.9		$	112.2		$	297.1		$	317.0
QEP Field Services		68.4			35.3			188.0			111.9
QEP Marketing and other		1.1			2.0			4.3			5.1
Separation costs		-			(0.2	)		-			(14.2	)
Total	$	183.4		$	149.3		$	489.4		$	419.8
Net income from continuing operations attributable to QEP
QEP Energy	$	58.3		$	58.6		$	148.2		$	165.0
QEP Field Services		42.0			21.0			114.2			68.5
QEP Marketing and other		1.6			2.0			5.5			3.6
Separation and debt extinguishment costs		(0.4	)		(10.5	)		(0.4	)		(19.1	)
Total	$	101.5		$	71.1		$	267.5		$	218.0

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ITEM 2.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related notes included in 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 nine month periods ended September 30, 2011 and September 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, which includes all of the Northern Region properties except the Pinedale Anticline and the Uinta Basin;

●

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 in the Rocky Mountains and in northwest Louisiana; and

●

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

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●

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, crude oil or NGL 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. However, in certain of its resource plays the Company has experienced rising completed well costs which could impact future drilling plans.

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. QEP Energy oil and NGL production increased by approximately 65% in the third quarter of 2011 compared with the third quarter of 2010 and oil and NGL revenue accounted for approximately 32% of net production revenues (including realized losses on basis-only swaps) in the third quarter of 2011 compared to 19% in the third quarter of 2010. QEP Energy oil and NGL production increased by approximately 44% in the nine months ended September 30, 2011, compared with the same period in 2010 and oil and NGL revenue accounted for approximately 29% of net production revenues (including realized losses on basis-only swaps) in the first nine months of 2011 compared to 19% in the first nine months of 2010. The increases in NGL sales volumes were a result of the start-up of the Blacks Fork II plant in July 2011 and the liquids recovered for QEP Energy under the fee-based processing agreement entered into with QEP Field Services along with development of liquids-rich plays in the Midcontinent. The Company has allocated approximately 65% of its forecasted 2011 drilling and completion capital expenditure budget to oil and liquids-rich natural gas plays.

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.

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 gathering and processing services to third parties in addition to QEP Energy. Net income from QEP’s midstream business accounted for approximately 41% of the Company’s total income from continuing operations during the third quarter of 2011 compared with 30% for the third 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 nine months ended September 30, 2011, compared with 31% for the same period in 2010.

Highlights of Three and Nine Months Ended September 30, 2011

During the third quarter and the nine months ended September 30, 2011, QEP had strong performance from QEP Energy, its exploration and production business, and QEP Field Services, its gathering and processing business. Though crude oil and NGL prices decreased in the third quarter of 2011 from the second quarter of 2011, QEP Energy benefitted from higher production and higher crude oil and NGL prices during the three and nine months ended September 30, 2011 from the 2010 comparative periods. Field Services benefited from the Iron Horse plant having two full quarters of operations, the commencement of the Blacks Fork II processing plant, and continued robust gas processing margins.

In the third quarter of 2011, QEP Energy reported production of 70.7 Bcfe compared to 61.7 Bcfe in the 2010 third quarter. During the nine months ended September 30, 2011, QEP Energy production of 201.3 Bcfe was 21% above the comparable period reported production of 166.9 Bcfe. During the three and nine months ended September 30, 2011, the Southern Region (formerly the Midcontinent Region) contributed 55% and 57%, respectively, and the Northern Region (formerly the Rocky Mountain Region) contributed 45% and 43%, respectively, of total equivalent production.

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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 $1.53 per Mcfe in the third quarter of 2011 compared to $1.47 per Mcfe in the third quarter of 2010. The increase was due to higher production taxes per Mcfe related to higher field-level crude oil and NGL prices and higher general and administrative expenses primarily related to employee benefit plan related expenses, increased legal and outside professional services and higher insurance costs, which were partially offset by lower allocated interest expense per Mcfe. During the first nine months of 2011, cash operating costs decreased to $1.55 per Mcfe from $1.58 per Mcfe in the first nine months of 2010. This decrease was a result of increased production volumes partially offset by higher overall production costs.

QEP Field Services reported gathering system throughput of 1.4 million MMBtu per day for the three months ended September 30, 2011 and 2010, respectively. During the nine months ended September 30, 2011 and 2010, QEP Field Services gathering system throughput was 1.3 million MMBtu per day. During the three and nine months ended September 30, 2011, QEP Field Services reported a 32% and 27% increase in NGL sales volumes to a total of 34.0 million and 98.2 million gallons, respectively. The increase in NGL sales volumes along with a 71% increase in the per unit NGL margin (NGL revenue less fuel and shrinkage) resulted in a 126% increase to the keep-whole processing margin during the third quarter of 2011. For the first nine months of 2011, the increased NGL sales volumes along with a 43% increase in the per unit NGL margin resulted in an 82% increase to the keep-whole processing margin.

In January 2011, QEP Field Services put into service its 150 MMcf per day cryogenic Iron Horse processing plant, an expansion of its Stagecoach processing complex in the Uinta Basin of eastern Utah. This plant predominantly provides fee-based processing services to third-parties. In July 2011, QEP Field Services commissioned its 420 MMcf per day Blacks Fork II cryogenic processing plant, an expansion of its Blacks Fork processing complex located in the Green River Basin of southwestern Wyoming, ahead of schedule. The Blacks Fork complex is about 100 miles south of QEP’s operations at Pinedale. QEP expects that the Blacks Fork II plant, when fully operational, will have the capacity to extract an incremental 15,000 Bbls per day of NGL net to QEP.

During the third quarter of 2011, QEP entered into a new revolving credit facility, which matures in August 2016 and replaced the previous $1.0 billion credit facility. The terms of the new credit facility provide for loan commitments of $1.5 billion from a syndicate of financial institutions. The new credit facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The agreement also contains provisions which would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for two additional one-year periods.

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, the domestic natural gas supply has grown faster than natural gas demand, driven by advances in technology, including horizontal drilling and hydraulic fracturing, which have 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 concern about the global economy and other factors has caused the price of crude oil to decrease in the current quarter though they remain higher than comparable 2010 prices. 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 9% increase in natural gas production in the third quarter of 2011 compared to the third quarter of 2010, natural gas revenues decreased 6% due to significantly lower net realized natural gas prices. When compared to the first three quarters of 2010, natural gas production in the first three quarters of 2011 increased 18%, while natural gas revenues decreased 2% 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. In general, QEP plans to hedge approximately 50% of its forecasted production by the end of the first quarter of the current year. As of September 30, 2011, QEP Energy had approximately 60% of its remaining forecasted 2011 natural gas, oil and NGL production covered with fixed-price swaps or costless collars assuming 2011 annual production of 272.0 Bcfe. QEP hedged a greater portion of its second half 2011 natural gas production in light of concerns during the first half of 2011 of oversupply in the natural gas market. See “Quantitative and Qualitative Disclosures about Market Risk—Commodity Derivative Transactions” for further details concerning QEP’s commodity derivatives transactions. In addition, as a result of the continued spread between oil and natural gas prices, the Company has allocated approximately 65% of its forecasted 2011 drilling and completion capital expenditure budget to oil and liquids-rich natural gas projects in its portfolio.

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.

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Blacks Fork II Processing Plant

QEP believes the new Blacks Fork II processing plant will result in increased NGL production from QEP Field Services and QEP Energy, however, QEP expects that the first few months of operation of the Blacks Fork II plant will not be indicative of normal liquids production volumes or of revenue generation. As part of the agreement, QEP Field Services recorded line pack for the NGL line-fill requirements which is recorded as inventory on the QEP Field Services balance sheet at September 30, 2011.

In conjunction with the start up of the Blacks Fork II, QEP Energy entered into a fee-based processing agreement with QEP Field Services to process QEP Energy’s share of Pinedale gas. As a result, about 46% of the NGL recovered at the Blacks Fork II plant will be accounted for as NGL production in QEP Energy, with the about 40% included in the keep-whole volumes in QEP Field Services.

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, loss on early extinguishment of debt, 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 September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
	(in millions)
QEP Energy	$	267.3	$	246.0	$	21.3		$	757.0	$	683.8	$	73.2
QEP Field Services		84.8		48.7		36.1			233.1		151.4		81.7
QEP Marketing and other		1.6		2.8		(1.2	)		6.0		6.8		(0.8	)
Total Adjusted EBITDA	$	353.7	$	297.5	$	56.2		$	996.1	$	842.0	$	154.1

Adjusted EBITDA increased 19% to $353.7 million for the third quarter of 2011 compared to $297.5 million in the 2010 period, despite a 14% decrease in net realized natural gas prices. The impact of lower net realized natural gas prices during the third quarter of 2011 was offset by a 15% increase in total production, 31% higher net realized crude oil prices and 27% higher net realized NGL prices in QEP Energy, along with increased gathering (26% higher) and processing margins (127% higher) in QEP Field Services. Adjusted EBITDA increased 18% to $996.1 million for the first three quarters of 2011 compared to $842.0 million in the 2010 period, despite a 16% decrease in net realized natural gas prices. The lower natural gas prices in the first three quarters of 2011 were offset by a 21% increase in total production, 31% higher net realized crude oil prices and 16% higher net realized NGL prices in QEP Energy, along with a 29% and 80% increase in gathering and processing margins, respectively.

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A reconciliation of Adjusted EBITDA to net income follows:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
	(in millions)
Net income attributable to QEP Resources	$	101.5		$	71.1		$	30.4		$	267.5		$	261.2		$	6.3
Net income attributable to non-controlling interest		0.9			0.8			0.1			2.2			2.1			0.1
Net income		102.4			71.9			30.5			269.7			263.3			6.4
Discontinued operations, net of tax		-			-			-			-			(43.2	)		43.2
Income from continuing operations		102.4			71.9			30.5			269.7			220.1			49.6
Unrealized gain on basis-only swaps		(27.9	)		(27.9	)		-			(86.7	)		(90.0	)		3.3
Net gain from asset sales		(1.2	)		(10.8	)		9.6			(1.4	)		(12.3	)		10.9
Interest and other loss (income)		0.7			(1.6	)		2.3			0.5			(4.4	)		4.9
Income taxes		59.1			44.2			14.9			156.0			130.5			25.5
Interest expense		22.8			22.6			0.2			67.0			62.8			4.2
Separation costs		-			0.2			(0.2	)		-			14.2			(14.2	)
Loss on early extinguishment of debt		0.7			13.3			(12.6	)		0.7			13.3			(12.6	)
Depreciation, depletion and amortization		189.0			170.5			18.5			566.4			469.5			96.9
Abandonment and impairment		5.7			12.2			(6.5	)		16.4			29.1			(12.7	)
Exploration expenses		2.4			2.9			(0.5	)		7.5			9.2			(1.7	)
Adjusted EBITDA	$	353.7		$	297.5		$	56.2		$	996.1		$	842.0		$	154.1

Net Income

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
	(in millions)
QEP Energy	$	58.3		$	58.6		$	(0.3	)	$	148.2		$	165.0		$	(16.8	)
QEP Field Services		42.0			21.0			21.0			114.2			68.5			45.7
QEP Marketing and other		1.6			2.0			(0.4	)		5.5			3.6			1.9
Separation and debt extinguishment costs		(0.4	)		(10.5	)		10.1			(0.4	)		(19.1	)		18.7
Net income from continuing operations attributable to QEP	$	101.5		$	71.1		$	30.4		$	267.5		$	218.0		$	49.5
Earnings per diluted share from continuing operations	$	0.57		$	0.40		$	0.17		$	1.50		$	1.23		$	0.27
Average diluted shares		178.5			177.9			0.6			178.5			177.6			0.9

Revenue, Volumes and Prices

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
	(in millions)
Revenues
Natural gas sales	$	266.7	$	283.2	$	(16.5	)	$	795.8	$	808.4	$	(12.6	)
Oil sales		76.1		49.9		26.2			218.4		139.5		78.9
NGL sales		34.1		9.3		24.8			67.8		27.4		40.4
Gathering, processing and other		118.7		76.4		42.3			340.1		238.7		101.4
Purchased gas and oil sales		356.8		145.8		211.0			810.6		460.4		350.2
Total Revenues	$	852.4	$	564.6	$	287.8		$	2,232.7	$	1,674.4	$	558.3

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QEP Energy’s revenues for the three and nine months ended September 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 September 30,
	Natural Gas			Oil		NGLs		Total
	(in millions)
QEP Energy Revenues
2010 revenues	$	283.2		$	49.9	$	9.3	$	342.4
Changes associated with volumes (1)		23.9			8.3		17.6		49.8
Changes associated with prices (2)		(40.4	)		17.9		7.2		(15.3	)
2011 revenues	$	266.7		$	76.1	$	34.1	$	376.9

	Nine Months Ended September 30,
	Natural Gas			Oil		NGLs		Total
	(in millions)
QEP Energy Revenues
2010 revenues	$	808.4		$	139.5	$	27.4	$	975.3
Changes associated with volumes (1)		144.1			26.6		30.9		201.6
Changes associated with prices (2)		(156.7	)		52.3		9.5		(94.9	)
2011 revenues	$	795.8		$	218.4	$	67.8	$	1,082.0

___________________________

(1) The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and nine months ended September 30, 2011, to the three and nine months ended September 30, 2010, by the average realized price or fee for the three and nine months ended September 30, 2010.

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	Gathering and Processing		Other		Total		Gathering and Processing		Other		Total
	(in millions)
QEP Field Services and Other Revenues
2010 revenues	$	68.7	$	7.7	$	76.4	$	210.1	$	28.6	$	238.7
Changes associated with volumes (1)		7.9		-		7.9		25.0		-		25.0
Changes associated with fees (2)		22.3		-		22.3		37.8		-		37.8
Changes associated with other factors		-		12.1		12.1		-		38.6		38.6
2011 revenues	$	98.9	$	19.8	$	118.7	$	272.9	$	67.2	$	340.1

________________________

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

Purchased gas and oil sales, which include QEP Energy purchased gas sales, were $211.0 million and $350.2 higher in the three and nine months ended September 30, 2011, respectively. These increases were due to $211.2 million and $367.2 in purchased gas sales recorded at QEP Energy during the three and nine months ended September 30, 2011. The purchased gas sales increase primarily related to gas purchases made in northwest Louisiana to fulfill pipeline shipping commitments.

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Production

QEP Energy reported production of 70.7 Bcfe in the third quarter of 2011 compared to 61.7 Bcfe in the 2010 third quarter, a 15% increase. During the first three quarters of 2011, QEP Energy reported production of 201.3 Bcfe, a 21% increase over the 166.9 Bcfe reported in the first three quarters of 2010. On an energy-equivalent basis, crude oil and NGL comprised approximately 15% and 13%, respectively, of QEP Energy’s production for the three and nine month periods ended September 30, 2011. A summary of production is shown in the following table:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011		2010		Change		2011		2010		Change
QEP Energy production volumes
Natural gas (Bcf)		59.8		55.0		4.8		175.9		149.2		26.7
Oil (Mbbl)		922.6		790.1		132.5		2,559.2		2,149.5		409.7
NGL (Mbbl)		894.4		310.7		583.7		1,675.0		786.9		888.1
Total production (Bcfe)		70.7		61.7		9.0		201.3		166.9		34.4
Average daily production (MMcfe)		767.7		670.3		97.4		737.2		611.2		126.0

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
QEP Energy - Natural gas (Bcf)
Southern Region
Haynesville/Cotton Valley		26.6		21.9		4.7			80.2		56.4		23.8
Midcontinent		8.9		8.8		0.1			24.7		23.6		1.1
Northern Region
Pinedale Anticline		17.8		17.1		0.7			50.2		47.5		2.7
Uinta Basin		3.6		3.8		(0.2	)		11.8		11.2		0.6
Rockies Legacy		2.9		3.4		(0.5	)		9.0		10.5		(1.5	)
Total production		59.8		55.0		4.8			175.9		149.2		26.7

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
QEP Energy - Oil (Mbbl)
Southern Region
Haynesville/Cotton Valley		8.8		13.8		(5.0	)		32.8		49.8		(17.0	)
Midcontinent		187.0		163.4		23.6			543.5		488.3		55.2
Northern Region
Pinedale Anticline		149.2		147.1		2.1			419.0		401.9		17.1
Uinta Basin		198.6		236.5		(37.9	)		657.3		706.5		(49.2	)
Rockies Legacy		379.0		229.3		149.7			906.6		503.0		403.6
Total production		922.6		790.1		132.5			2,559.2		2,149.5		409.7

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
QEP Energy - NGL (Mbbl)
Southern Region
Haynesville/Cotton Valley		-		-		-			-		-		-
Midcontinent		348.3		252.3		96.0			1,013.1		622.7		390.4
Northern Region
Pinedale Anticline		489.0		-		489.0			489.0		-		489.0
Uinta Basin		23.6		31.6		(8.0	)		83.1		89.3		(6.2	)
Rockies Legacy		33.5		26.8		6.7			89.8		74.9		14.9
Total production		894.4		310.7		583.7			1,675.0		786.9		888.1

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
QEP Energy - Total Production (Bcfe)
Southern Region
Haynesville/Cotton Valley		26.6		22.0		4.6			80.4		56.7		23.7
Midcontinent		12.1		11.4		0.7			34.0		30.4		3.6
Northern Region
Pinedale Anticline		21.6		17.9		3.7			55.6		49.9		5.7
Uinta Basin		4.8		5.3		(0.5	)		16.2		15.9		0.3
Rockies Legacy		5.6		5.1		0.5			15.1		14.0		1.1
Total production		70.7		61.7		9.0			201.3		166.9		34.4

Net production in the Haynesville/Cotton Valley area grew 21% to 26.6 Bcfe in the third quarter of 2011 compared to the third quarter of 2010 and represented 38% of the Company’s total production compared to 36% in the year earlier period. During the nine months ended September 30, 2011, net production from the Haynesville/Cotton Valley area was 80.4 Bcfe compared to 56.7 Bcfe in the comparable period, which represented 40% of the Company’s first three quarters of 2011 total production compared to 34% 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 6% to 12.1 Bcfe in the third quarter of 2011 compared to the third quarter of 2010 and represented 17% of the Company’s total production for the 2011 third quarter, down from 18% during the 2010 third quarter. During the first three quarters of 2011, net production in the Midcontinent was 34.0 Bcfe compared to 30.4 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 21% to 21.6 Bcfe in the third quarter of 2011 compared to the 2010 third quarter as a result of ongoing development drilling. The Pinedale Anticline net production during the first three quarters of 2011 increased 11% to 55.6 Bcfe from the comparable period in 2010. As a result of a new fee-based processing agreement between QEP Energy and QEP Field Services at Blacks Fork II, NGL production at Pinedale for the third quarter was 489 Mbbl. The fee-based processing agreement was effective August 1, 2011, therefore the reported NGL volumes for the third quarter were for only a portion of the quarter.

In the Uinta Basin, production decreased 0.5 Bcfe in the third quarter of 2011 but increased 0.3 Bcfe in the first nine 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 third quarter of 2011 increased to 5.6 Bcfe due to increased oil directed drilling activity in the North Dakota Bakken/Three Forks play. During the first three quarters of 2011, Rockies Legacy net production increased by 8% to 15.1 Bcfe from the first three quarters of 2010. Most of QEP’s wells in North Dakota have been connected to oil gathering lines during the first three quarters 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 at QEP Energy were lower than the prior year comparative period, while realized oil and NGL prices were higher when compared to the 2010 prior-year. A regional comparison of average field level prices is shown in the following tables:

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
QEP Energy - Average field-level natural gas price ($ per Mcf)
Southern Region	$	3.28	$	3.63	$	(0.35	)	$	3.36	$	3.99	$	(0.63	)
Northern Region		3.25		3.04		0.21			3.30		3.59		(0.29	)
Average field-level natural gas price		3.27		3.37		(0.10	)		3.34		3.80		(0.46	)

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2011		2010		Change		2011		2010		Change
QEP Energy - Average field-level oil price ($ per bbl)
Southern Region	$	88.44	$	71.81	$	16.63	$	90.83	$	73.71	$	17.12
Northern Region		79.67		62.84		16.83		83.24		65.18		18.06
Average field-level oil price		81.53		64.85		16.68		84.95		67.31		17.64

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
QEP Energy - Average field-level NGL price ($ per bbl)
Southern Region	$	44.19	$	27.85	$	16.34		$	42.38	$	33.48	$	8.90
Northern Region		34.33		39.64		(5.31	)		37.56		39.91		(2.35	)
Average field-level NGL price		38.17		30.07		8.10			40.48		34.83		5.65

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 September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
Natural gas ($ per Mcf)
Average field-level natural gas price	$	3.27		$	3.37		$	(0.10	)	$	3.34		$	3.80		$	(0.46	)
Natural gas commodity derivative impact		1.20			1.77			(0.57	)		1.19			1.62			(0.43	)
Average revenue (1)		4.47			5.14			(0.67	)		4.53			5.42			(0.89	)
Realized losses on basis-only swaps (2)		(0.47	)		(0.50	)		0.03			(0.50	)		(0.61	)		0.11
Net realized natural gas price	$	4.00		$	4.64		$	(0.64	)	$	4.03		$	4.81		$	(0.78	)
Oil ($ per bbl)
Average field-level oil price	$	81.53		$	64.85		$	16.68		$	84.95		$	67.31		$	17.64
Oil commodity derivative impact		0.91			(1.80	)		2.71			0.38			(2.42	)		2.80
Net realized oil price	$	82.44		$	63.05		$	19.39		$	85.33		$	64.89		$	20.44
NGL ($ per bbl)
Average field-level NGL price	$	38.17		$	30.07		$	8.10		$	40.48		$	34.83		$	5.65

____________________

(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 September 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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Volumes subject to commodity derivatives as a percent of gas production - QEP Energy
Fixed price swaps		56	%		70	%		48	%		76	%
Costless collars		12	%		3	%		12	%		3	%
Volumes subject to commodity derivatives as a percent of oil production - QEP Energy
Fixed price swaps		5	%		29	%		3	%		32	%
Costless collars		30	%		23	%		32	%		25	%
Volumes subject to commodity derivatives as a percent of propane production - QEP Field Services
Fixed price swaps		42	%		-			16	%		-

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	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
Impact of settled commodity derivatives on financial statements (millions)
Natural gas sales	$	71.6		$	97.6		$	(26.0	)	$	209.1		$	240.7		$	(31.6	)
Oil sales	$	0.9		$	(1.4	)	$	2.3		$	1.0		$	(5.2	)	$	6.2
Impact of settled commodity derivatives that do not qualify for hedge accounting (millions)
Unrealized gain (loss) on basis-only swaps	$	27.9		$	27.9		$	-		$	86.7		$	90.0		$	(3.3	)
Realized (loss) on basis-only swaps	$	(27.9	)	$	(27.9	)	$	-		$	(86.7	)	$	(90.0	)	$	3.3

The change in unrealized gains and losses on natural gas basis-only swaps increased the third quarter 2011 net income $17.6 million compared to an increase of $17.5 million in the third quarter of 2010. During the first three quarters of 2011, net income increased $54.5 million from the impact of unrealized gains and losses on natural gas basis-only swaps compared to an increase of $56.6 million in the first three quarters 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 26% increase in gathering margin in the third quarter of 2011 and a 29% increase for the first nine months of 2011, primarily due to an increase in the liquids value received from a short-term, third-party processing arrangement for certain volumes in the Northern Region and a 6% and 3% increase in the average gathering rate for the comparable periods. Gathering system throughput volume was 1.4 million MMBtu per day for both the third quarters of 2011 and 2010. For the nine months ended September 30, 2011 and 2010, gathering system throughput volume was 1.3 million MMBtu per day. The increased volumes were mainly related to the northwest Louisiana gathering system, which accounted for 39% and 54% of the total throughput during the third quarter and first three quarters of 2011.

During the first nine months of 2011, QEP directed 200 million cubic feet per day of gas to a third-party cryogenic processing plant on an interruptible basis, reported in QEP Field Services as "Other gathering revenues." QEP expects other gathering revenue to diminish and to be replaced by keep-whole processing revenues in QEP Field Services and NGL revenues in QEP Energy.

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
Gathering Margin
Gathering revenues	$	41.9		$	38.9		$	3.0		$	120.0		$	113.3		$	6.7
Other gathering revenues		16.5			7.1			9.4			59.2			25.7			33.5
Gathering expense		(11.0	)		(8.5	)		(2.5	)		(35.3	)		(27.1	)		(8.2	)
Gathering margin	$	47.4		$	37.5		$	9.9		$	143.9		$	111.9		$	32.0
Operating Statistics
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers		66.3			74.3			(8.0	)		193.4			210.0			(16.6	)
For affiliated customers		60.6			52.3			8.3			173.6			144.5			29.1
Total Gas Gathering Volumes		126.9			126.6			0.3			367.0			354.5			12.5
Average gas gathering revenue (per MMBtu)	$	0.33		$	0.31		$	0.02		$	0.33		$	0.32		$	0.01

Processing

Although a significant portion of the Company’s gas processing services are performed for a volumetric-based fee, a portion of its gas processing agreements are commodity-based with commodity price exposure. Such agreements are referred to as “keep-whole” processing agreements whereby the Company has the right to extract NGLs recovered at its processing plants, and the obligation to replace the Btu equivalent value of those NGLs (the “shrink”). Under these agreements, the Company is exposed to the spread between NGL prices and natural gas prices.

Processing margin increased 127% in the third quarter 2011 and 80% in the first three quarters of 2011 compared to the 2010 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 52% in the third quarter and 29% in the first three quarters of 2011 compared to the 2010 periods. NGL volumes increased 32% in the third quarter and 27% in the first three quarters of 2011 compared to the 2010 periods. Fee-based processing revenues increased 73% during the third quarter 2011 when compared to the third quarter 2010, due to an 11% increase in fee-based processing volumes to 63.8 million MMBtu and a 50% increase in the average processing fee rate. During the first three quarters of 2011 fee-based processing revenues increased 44% over the 2010 comparable period, due to an 8% increase in fee-based processing volumes to 181.1 million MMBtu and a 31% increase in the processing fee rate. The increased processing volume was primarily the result of the start-up of the 150 MMcf per day Iron Horse cryogenic processing plant in the Uinta Basin of eastern Utah during the first quarter of 2011 and the start-up of the Blacks Fork II plant in July 2011. Approximately 72% and 73% of QEP Field Services’ net operating revenue was derived from fee-based gathering and processing agreements in the three and nine months ended September 30, 2011, compared to 81% and 79% during the three and nine months ended September 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.

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Frac spread as used in the following table is defined as the difference between the market value for NGL extracted from the natural gas stream and the market value of the Btu-equivalent volume of natural gas required to replace the extracted liquids. Following is a summary of QEP Field Services’ processing financial and operating results:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
Processing Margin
NGL sales	$	41.6		$	20.9		$	20.7		$	115.3		$	70.6		$	44.7
Processing (fee-based) revenues		15.4			8.9			6.5			37.6			26.2			11.4
Other processing fees		1.7			-			1.7			1.7			-			1.7
Processing (expense)		(3.1	)		(2.8	)		(0.3	)		(8.9	)		(8.8	)		(0.1	)
Processing plant fuel and shrinkage (expense)		(12.5	)		(8.0	)		(4.5	)		(34.1	)		(25.9	)		(8.2	)
Processing margin	$	43.1		$	19.0		$	24.1		$	111.6		$	62.1		$	49.5
Frac spread (NGL sales less processing plant fuel and shrinkage)	$	29.1		$	12.9		$	16.2		$	81.2		$	44.7		$	36.5
Operating Statistics
Natural gas processing volumes
NGL sales (MMgal)		34.0			25.8			8.2			98.2			77.3			20.9
Average NGL sales price (per gal)	$	1.23		$	0.81		$	0.42		$	1.17		$	0.91		$	0.26
Fee-based processing volumes (in millions of MMBtu)
For unaffiliated customers		31.9			29.4			2.5			96.4			87.9			8.5
For affiliated customers		31.9			28.2			3.7			84.7			80.5			4.2
Total fee-based processing volumes		63.8			57.6			6.2			181.1			168.4			12.7
Average fee-based processing revenue (per MMBtu)	$	0.24		$	0.16		$	0.08		$	0.21		$	0.16		$	0.05

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Operating Expenses

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
	(in millions)
Purchased gas and oil sales	$	352.7	$	143.6	$	209.1		$	803.3	$	455.4	$	347.9
Lease operating expense		37.0		32.8		4.2			104.1		89.7		14.4
Gathering, processing and other		27.0		19.5		7.5			79.4		62.6		16.8
General and administrative		28.7		24.7		4.0			89.1		75.6		13.5
Separation costs		-		0.2		(0.2	)		-		14.2		(14.2	)
Production and property taxes		27.7		19.7		8.0			78.5		61.6		16.9
Depreciation, depletion and amortization		189.0		170.5		18.5			566.4		469.5		96.9
Exploration expenses		2.4		2.9		(0.5	)		7.5		9.2		(1.7	)
Abandonment and impairment		5.7		12.2		(6.5	)		16.4		29.1		(12.7	)
Total operating expenses	$	670.2	$	426.1	$	244.1		$	1,744.7	$	1,266.9	$	477.8

Purchased gas and oil expense, which includes QEP Energy purchased gas expense, increased due to increased purchased gas expense at QEP Energy of $208.1 million and $362.8 million during the three and nine months ended September 30, 2011. The increased purchased gas expense at QEP Energy relates to gas purchases made in northwest Louisiana to utilize firm transportation capacity.

Lease operating expense increased $4.2 million, or 13% to $37.0 million during the third quarter of 2011 compared to the third quarter of 2010, driven by a 15% increase in production of natural gas and oil equivalents during the period. Lease operating expense increased 16% to $104.1 million during the first three quarters of 2011 compared to the first three quarters of 2010, due to a 21% increase in production of natural gas and oil equivalents. Gathering, processing and other expense increased due to higher gathering and processing volumes in the third quarter and first three quarters of 2011 when compared with the 2010 periods.

Total corporate general and administrative (G&A) expense increased to $28.7 million for the quarter ended September 30, 2011, compared with $24.7 million during the 2010 third quarter. During the first three quarters of 2011, corporate general and administrative costs increased $13.5 million from the first three quarters of 2010. The increases in 2011 resulted from employee benefit plan related expenses, increased legal and outside professional services and higher insurance costs.

During the three and nine months ended September 30, 2010, QEP reported separation costs of $0.2 million and $14.2 million, respectively, 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. There were no separation costs in the three and nine months ended September 30, 2011.

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, depletion and amortization expense grew $18.5 million or 11% in the third quarter of 2011 compared with the 2010 third quarter, and increased $96.9 million or 21% in the first three quarters of 2011 compared to the first three quarters of 2010, as a result of increased production at QEP Energy combined with plant additions at QEP Field Services.

Exploration expenses were $2.4 million in the third quarter of 2011 compared with $2.9 million in the third quarter of 2010 due to reduced seismic acquisition costs of $0.6 million. Exploration expenses decreased $1.7 million during the first three quarters of 2011, when compared to the first three quarters of 2010 due to lower seismic acquisition costs of $2.3 million, offset by an increase in dry hole costs of $0.5 million.

Abandonment and impairment expenses decreased to $5.7 million in the third quarter of 2011 compared with $12.2 million in the 2010 third quarter, and decreased to $16.4 million in the first three quarters of 2011 compared to $29.1 million in the first three quarters of 2010, primarily due to increases in the expected level of successful development of the Company’s unproved acreage.

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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 nine month periods ended September 30, 2011, was primarily due to lower gains on warehouse inventory sales.

Loss from early extinguishment of debt

The loss from early extinguishment of debt was $0.7 million in the three and nine month periods ended September 30, 2011 compared to $13.3 million in the 2010 periods. The $0.7 million related to replacing the previous $1.0 billion revolver with a new $1.5 billion revolver in August 2011. The $13.3 million was the result of the August 2010 purchase of $638.0 million principal amount of senior notes and the termination of a $500 million term loan relating to the Spin-off from Questar.

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 Accumulated Other Comprehensive Income. Realized losses on settlements of basis-only swaps relating to the period prior to re-designation amounted to $27.9 million in the third quarter of 2011 and $27.9 million in the third quarter of 2010. Unrealized gains on basis-only swaps amounted to $27.9 million in the third quarter of 2011 compared to $27.9 million in 2010. Realized losses on settlements of basis-only swaps relating to the period prior to re-designation amounted to $86.7 million in the first three quarters of 2011 and $90.0 million in the first three quarters of 2010. Unrealized gains on basis-only swaps amounted to $86.7 million in the first three quarters of 2011 compared to $90.0 million in 2010.

Interest expense

Interest expense increased 1% in the third quarter of 2011 and 7% in the first three quarters of 2011 compared to a year ago primarily due to September 30, 2011, debt levels that were approximately $205 million higher than average debt levels in the comparable prior period.

Income taxes

The effective combined federal and state income tax rate was 36.6% for both the three and nine months ended September 30, 2011, slightly lower than the 38.1% and 37.2% in the three and nine months ended September 30, 2010, respectively.

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DISCUSSION BY LINE OF BUSINESS

QEP Energy

QEP Energy reported net income of $58.3 million in the third quarter of 2011 compared with $58.6 million in the 2010 third quarter. Net income for the first three quarters of 2011 decreased 10% to $148.2 million compared to $165.0 million a year earlier. The primary reason for the decrease was a 14% decline in net realized natural gas prices to $4.00 per Mcfe in the third quarter of 2011, compared to $4.64 per Mcfe in the third quarter of 2010. Net realized natural gas prices decreased to $4.03 per Mcfe in the first three quarters of 2011 compared to $4.81 per Mcfe in the comparable 2010 period. The decrease in net realized natural gas prices was partially offset by a 15% and 21% increase in natural gas-equivalent total production, and a 31% increase in net realized oil prices in both the three and nine months ended September 30, 2011. Changes in unrealized basis-only swaps increased net income $17.6 million in the 2011 third quarter compared to an increase of $17.5 million in the third quarter of 2010 and increased net income $54.5 million in the first three quarters of 2011 compared to an increase of $56.6 million in the first three quarters of 2010. Following is a summary of QEP Energy’s financial and operating results:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
	(in millions)
Operating Income
Revenues
Natural gas sales	$	266.7		$	283.2		$	(16.5	)	$	795.8		$	808.4		$	(12.6	)
Oil sales		76.1			49.9			26.2			218.4			139.5			78.9
NGL sales		34.1			9.3			24.8			67.8			27.4			40.4
Purchased gas sales		211.2			-			211.2			367.2			-			367.2
Other		2.5			1.1			1.4			7.3			3.7			3.6
Total Revenues		590.6			343.5			247.1			1,456.5			979.0			477.5
Operating expenses
Purchased gas expense		208.1			-			208.1			362.8			-			362.8
Lease operating expense		38.0			33.1			4.9			106.4			91.2			15.2
General and administrative		23.0			17.9			5.1			69.8			55.9			13.9
Production and property taxes		26.3			18.6			7.7			73.9			58.2			15.7
Depreciation, depletion and amortization		174.4			157.8			16.6			524.0			432.1			91.9
Exploration expenses		2.4			2.9			(0.5	)		7.5			9.2			(1.7	)
Abandonment and impairment		5.7			12.2			(6.5	)		16.4			29.1			(12.7	)
Total Operating Expenses		477.9			242.5			235.4			1,160.8			675.7			485.1
Net gain from asset sales		1.2			11.2			(10.0	)		1.4			13.7			(12.3	)
Operating Income		113.9			112.2			1.7			297.1			317.0			(19.9	)
Interest and other income (loss)		(0.7	)		1.6			(2.3	)		(0.5	)		4.3			(4.8	)
Income from unconsolidated affiliates		-			-			-			0.1			0.1			-
Interest expense		(20.5	)		(21.1	)		0.6			(60.8	)		(59.1	)		(1.7	)
Income from Continuing Operations before Income Taxes		92.7			92.7			-			235.9			262.3			(26.4	)
Income taxes		(34.4	)		(34.1	)		(0.3	)		(87.7	)		(97.3	)		9.6
Net Income Attributable to QEP	$	58.3		$	58.6		$	(0.3	)	$	148.2		$	165.0		$	(16.8	)

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Operating expenses per unit

The following table 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 decreased 1% to $4.00 per Mcfe in the third quarter of 2011 compared to $4.03 per Mcfe in 2010. During the first three quarters of 2011 total production costs per Mcfe decreased less than 1% compared to the 2010 period.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.47	$	2.56	$	(0.09	)	$	2.60	$	2.59	$	0.01
Lease operating expense		0.54		0.54		-			0.53		0.55		(0.02	)
General and administrative expense		0.33		0.29		0.04			0.35		0.33		0.02
Allocated interest expense		0.29		0.34		(0.05	)		0.30		0.35		(0.05	)
Production taxes		0.37		0.30		0.07			0.37		0.35		0.02
Total Production Costs	$	4.00	$	4.03	$	(0.03	)	$	4.15	$	4.17	$	(0.02	)

Depreciation, depletion and amortization (DD&A) expense decreased $0.09 per Mcfe in third quarter 2011 from the 2010 third quarter, but increased by $0.01 per Mcfe during the first three quarters of 2011 from the first three quarters of 2010. QEP Energy’s DD&A expense increased $16.6 million during the third quarter 2011 from the 2010 third quarter and increased $91.9 million during the first three quarters of 2011 from the 2010 first three quarters. Though QEP Energy’s total DD&A increased, the lower per unit amount in the third quarter 2011 was the result of booking NGL reserves associated with the fee-based processing agreement entered into between QEP Energy and QEP Field Services for QEP’s Pinedale production and growing production volumes.

Lease operating expense per Mcfe was flat for the quarter ended September 30, 2011 from the prior year quarter, but decreased during the first three quarters of 2011 from the 2010 first three quarters as the result of increased production volumes in lower cost areas. Growing production from new high-rate, low-operating cost wells in the Haynesville/Cotton Valley area and in the Pinedale Anticline coupled with declining production from older higher cost areas is reducing average per Mcfe lease operating expense.

General and administrative (G&A) expense per Mcfe increased in the three and nine months ended September 30, 2011, as the result of higher G&A expenses, which were primarily related to employee benefit plan related expenses, increased legal and outside professional services and higher insurance costs, which were partially offset by increased production in the three and nine months ended September 30, 2011. Allocated interest expense per unit of production decreased in the three and nine months ended September 30, 2011, primarily due to higher production volumes. Production taxes per Mcfe increased during the three and nine months ended September 30, of 2011 because of higher field level oil and NGL prices.

QEP Energy’s average production costs (lease operating expense) per Mcfe were lower for the nine months ended September 30, 2011, but flat in the third quarter when compared to the prior year periods in 2010. The decrease for the first nine months of 2011 was a result of growing production in lower cost operating areas such as Haynesville/Cotton Valley and Pinedale, coupled with declining production in higher cost areas. The following table presents average production cost, excluding production taxes for QEP Energy by region on a per unit of production basis.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
	(per Mcfe)
Southern Region	$	0.51	$	0.52	$	(0.01	)	$	0.48	$	0.54	$	(0.06	)
Northern Region		0.57		0.56		0.01			0.59		0.56		0.03
Average production cost		0.54		0.54		-			0.53		0.55		(0.02	)

Major QEP Energy Operating Regions

Southern Region

Haynesville/Cotton Valley

QEP Energy has approximately 50,640 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 September 30, 2011, QEP Energy had six operated rigs drilling in the project area. QEP Energy operated or had working interests in 793 gross (467 net) producing wells in northwest Louisiana compared to 670 gross (421 net) wells at September 30, 2010. In the Haynesville/Cotton Valley area, QEP Energy completed 8 gross (6.8 net) and 33 gross (25.6 net) operated wells during the three and nine months ended September 30, 2011. QEP Energy has 11 gross (7.0 net) operated wells waiting on completion or being completed and has an interest in 14 gross (1.0 net) outside-operated Haynesville/Cotton Valley wells that are waiting on completions and 6 gross (3.4 net) 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.

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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.

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 September 30, 2011, QEP Energy had two operated rigs drilling in the project area and had working interests in 189 gross (33 net) producing Woodford Shale wells in western Oklahoma compared to 81 gross (16 net) wells at September 30, 2010. QEP completed 4 gross (2.2 net) operated wells during the third quarter of 2011 and 10 gross (6.0 net) operated wells in the first three quarters of 2011 in the Woodford Shale play. QEP Energy has interests in 8 gross (0.6 net) wells being drilled and 17 gross (1.2 net) wells waiting on completion that are operated by others. QEP Energy intends to drill or participate in up to 114 gross (17.8 net) horizontal Woodford Shale wells in 2011.

QEP Energy has approximately 38,900 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 September 30, 2011, QEP Energy did not have any rigs drilling in the Granite Wash/Atoka Wash, but did have three rigs drilling in other parts of the region, specifically, in western Oklahoma. QEP Energy had working interests in 89 gross (22 net) producing horizontal Granite Wash/Atoka Wash wells in the Texas Panhandle and western Oklahoma compared to 45 gross (10 net) wells at September 30, 2010. In the Granite Wash/Atoka Wash play, QEP completed 5 gross (4.5 net) and 8 gross (7.3 net) operated wells during the three and nine months ended September 30, 2011. QEP Energy has 4 gross (2.6 net) operated wells waiting on completion and is participating in 4 gross (0.1 net) outside-operated wells being drilled. QEP Energy intends to drill or participate in up to 48 gross (14.3 net) horizontal Granite Wash/Atoka Wash wells in 2011.

Northern Region

Pinedale Anticline

As of September 30, 2011, QEP Energy had interests in 608 gross (360 net) producing wells on the Pinedale Anticline compared to 507 gross (291 net) wells at the end of the third quarter of 2010. Of the 608 gross producing wells, QEP Energy had working interests in 587 gross (360 net) wells and an overriding royalty interest only in an additional 21 wells. QEP completed 37 gross (23.9 net) operated wells during the third quarter of 2011 and 79 gross (54.3 net) operated wells in the first three quarters of 2011 on the Pinedale Anticline. QEP Energy has 26 gross (17.4 net) operated wells drilled and cased waiting on completion. As of September 30, 2011, QEP had four rigs drilling on the Pinedale Anticline and expects to complete 100 to 105 gross (67 to 71 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 1,200 additional wells will be required to fully develop its Pinedale acreage on a combination of 5 and 10 acre density.

Uinta Basin

As of September 30, 2011, QEP Energy had an operating interest in 2,603 gross (776 net) producing or shut-in wells in the Uinta Basin of eastern Utah, compared to 2,171 gross (690 net) at September 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 256,000 net leasehold acres in the Uinta Basin. In the Uinta Basin, QEP completed 1 gross (0.5 net) and 6 gross (4.9 net) operated wells during the three and nine months ended September 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.

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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 September 30, 2011, QEP Energy had three operated rigs drilling in the project area and had working interests in 96 gross (19 net) producing Bakken/Three Forks wells in North Dakota compared to working interests in 56 gross (10 net) wells at September 30, 2010. QEP completed 3 gross (2.9 net) operated wells during the third quarter of 2011 and 8 gross (7.2 net) operated wells in the first three quarters of 2011 in the Bakken/Three Forks play. QEP Energy also has interests in 3 gross (2.9 net) operated wells being drilled, 9 gross (7.8 net) operated wells waiting on completion, 11 gross (0.2 net) outside-operated wells being drilled and 8 gross (0.1 net) outside-operated wells waiting on completion. QEP Energy intends to drill or participate in 57 gross (20 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 $42.0 million in the third quarter of 2011 compared to $21.0 million in the same period of 2010, a 100% increase. Net income was $114.2 million in the first three quarters of 2011 compared to $68.5 million in the first three quarters 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 September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
	(in millions)
Operating Income
Revenues
NGL sales	$	41.6		$	20.9		$	20.7		$	115.3		$	70.6		$	44.7
Processing (fee based)		15.4			8.9			6.5			37.6			26.2			11.4
Other processing fees		1.7			-			1.7			1.7			-			1.7
Gathering		41.9			38.9			3.0			120.0			113.3			6.7
Other gathering		16.5			7.1			9.4			59.2			25.7			33.5
Total Revenues		117.1			75.8			41.3			333.8			235.8			98.0
Operating expenses
Processing		3.1			2.8			0.3			8.9			8.8			0.1
Processing plant fuel and shrinkage		12.5			8.0			4.5			34.1			25.9			8.2
Gathering		11.0			8.5			2.5			35.3			27.1			8.2
General and administrative		6.6			7.6			(1.0	)		22.4			21.6			0.8
Taxes other than income taxes		1.4			1.2			0.2			4.4			3.3			1.1
Depreciation, depletion and amortization		14.0			12.3			1.7			40.7			36.0			4.7
Total Operating Expenses		48.6			40.4			8.2			145.8			122.7			23.1
Net gain (loss) from asset sales		(0.1	)		(0.1	)		-			-			(1.2	)		1.2
Operating Income		68.4			35.3			33.1			188.0			111.9			76.1
Interest and other income		-			0.1			(0.1	)		-			0.1			(0.1	)
Income from unconsolidated affiliates		2.3			1.0			1.3			4.4			2.3			2.1
Interest expense		(3.8	)		(2.4	)		(1.4	)		(10.4	)		(4.3	)		(6.1	)
Income from Continuing Operations before Income Taxes		66.9			34.0			32.9			182.0			110.0			72.0
Income taxes		(24.0	)		(12.2	)		(11.8	)		(65.6	)		(39.4	)		(26.2	)
Income from Continuing Operations		42.9			21.8			21.1			116.4			70.6			45.8
Net income attributable to noncontrolling interest		(0.9	)		(0.8	)		(0.1	)		(2.2	)		(2.1	)		(0.1	)
Net Income Attributable to QEP	$	42.0		$	21.0		$	21.0		$	114.2		$	68.5		$	45.7

QEP Marketing

QEP Marketing, which markets affiliate and third-party natural gas and oil, generated net income from continuing operations of $1.6 million in the three months ended September 30, 2011, compared with $2.0 million in the three months ended September 30, 2010. The decrease in the third quarter of 2011 was due to a 49% decrease in marketing margins and a 5% decrease in marketing sales volumes. During the nine months ended September 30, 2011, QEP Marketing and other net income from continuing operations increased to $5.5 million from $3.6 million in the comparable 2010 period. The increase in the first nine months of 2011 was due to a $2.6 million increase in interest income, partially offset by a 41% decrease in marketing margins and a 2% decrease in marketing sales volumes.

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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.

During the third quarter and nine months ended September 30, 2011, QEP had strong production growth. Net cash provided from continuing operating activities increased 24% in the first three quarters of 2011 compared to the first three quarters of 2010 due to higher net income, higher noncash adjustments to net income and a source of cash from operating assets and liabilities in 2011 compared with a use of cash in 2010 period. 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 nine months ended September 30, 2011, compared with the same period ended September 30, 2010. Net cash provided from continuing operating activities is presented below:

	Nine Months Ended September 30,
	2011		2010			Change
	(in millions)
Income from continuing operations	$	269.7	$	220.1		$	49.6
Noncash adjustments to net income		673.8		628.6			45.2
Changes in operating assets and liabilities		12.2		(80.7	)		92.9
Net cash provided from continuing operating activities	$	955.7	$	768.0		$	187.7

Cash Flow from Investing Activities

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

	Nine Months Ended September 30,									Current Forecast Twelve Months Ended		Prior Forecast Twelve Months Ended (1)
	2011			2010			Change			December 31, 2011		December 31, 2011
	(in millions)
QEP Energy	$	939.4		$	876.9		$	62.5		$	1,250.0	$	1,173.0
QEP Field Services		68.1			178.9			(110.8	)		95.0		125.0
QEP Marketing and other		3.4			1.0			2.4			5.0		2.0
Total accrued capital expenditures of continuing operations		1,010.9			1,056.8			(45.9	)		1,350.0		1,300.0
Change in accruals		(12.5	)		(20.9	)		8.4			-		-
Total cash capital expenditures of continuing operations	$	998.4		$	1,035.9		$	(37.5	)	$	1,350.0	$	1,300.0

_____________________

(1) Forecast as reported in the second quarter 2011 quarterly report.

QEP Energy capital investment in the first nine months of 2011 increased $62.5 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 $110.8 million in the first nine months of 2011 compared to the 2010 period due to completion of major capital projects in eastern Utah and northwest Louisiana in late 2010 and completion of the Blacks Fork II plant early in the third quarter of 2011. At September 30, 2011, QEP forecasted capital investments for 2011 total $1,350 million, comprised of $1,250 million in QEP Energy, $95 million in QEP Field Services, and $5 million in QEP Marketing and other. The $77 million increase in forecasted capital investment in QEP Energy for 2011 from June 30, 2011, to September 30, 2011, is due to; 1) an increase in the number of projected net completed Pinedale and Haynesville Shale wells by year-end due to continued drilling/completion efficiency gains; 2) increased completed well costs associated with non-operated Haynesville wells; 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) an increase in lease acquisition spending. Forecasted capital investment in QEP Field Services declined $30 million compared to the prior forecast due to actual costs associated with new plants being less than forecast, and a change in timing of expenditures on certain other gathering and processing projects.

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Cash Flow from Financing Activities

In the first nine months of 2011, net cash used in investing activities of $991.0 million exceeded net cash provided by operating activities of $955.7 million by $35.3 million. Net cash used in investing activities during the first nine months of 2010 was $957.6 million, which exceeded net cash provided by operating activities of $768.0 million by $189.6 million. Long-term debt (including the current portion of long-term debt) increased by $51.9 million from year-end 2010, primarily due to the semi-annual interest payments on the senior notes. At September 30, 2011, long-term debt consisted of $510.0 million outstanding under QEP’s revolving credit facility and $1,072.7 million in senior notes (including $5.7 million of net original issue discount). At September 30, 2011, combined short-term and long-term debt was 33% and equity was 67% of total capital.

Credit Facility

During the third quarter of 2011, QEP entered into a new revolving credit facility, which matures in August 2016 and replaced the previous $1.0 billion credit facility. Proceeds from borrowings under the credit facility were used to refinance outstanding amounts under the Company’s previous credit facility and will be used for general corporate purposes, including working capital and capital expenditures. The terms of the new credit facility provide for loan commitments of $1.5 billion from a syndicate of financial institutions. The new credit facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The agreement also contains the provisions which would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for two additional one-year periods. At September 30, 2011, QEP was in compliance with all of its debt covenants. At October 25, 2011, QEP had $520.0 million outstanding under its revolving credit facility and $4.1 million of letters of credit issued.

Senior Notes

The Company’s senior notes outstanding as of September 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

For the remainder of 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 primarily to higher return plays and also to its core Haynesville dry gas play 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 approximately 65% of its forecasted 2011 drilling and completion capital expenditure budget to oil and liquids-rich natural gas projects in its portfolio. The Company has budgeted approximately $1,350.0 million for capital expenditures in 2011 (including leasehold acquisitions), of which it has allocated $1,250.0 million to QEP Energy. QEP plans to invest approximately $95.0 million in capital expenditures to grow its midstream business, including the Blacks Fork II cryogenic gas processing plant which was completed in July 2011. 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 or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management’s business assessments as to where QEP’s capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

During the first nine months of 2011, capital expenditures decreased 4% to $998.4 million, which included $40.7 million for property acquisitions, compared to $1,035.9 million during the same period of 2010. The decrease was driven by reduced development drilling in the Haynesville/Cotton Valley and Pinedale Anticline, partially offset by higher capital investment in development drilling in the Midcontinent and the Rockies Legacy divisions

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.

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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, costless 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 September 30, 2011, QEP held commodity price derivative contracts covering about 214.1 million MMBtu of natural gas, 1.4 million barrels of oil, and 11.5 million NGL gallons. A year earlier, the QEP derivative contracts covered 284.1 million MMBtu of natural gas and 1.5 million barrels of oil. Changes in the fair value of derivative contracts from December 31, 2010 to September 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		(214.0	)		86.7			(127.3	)
Change in gas and oil prices on futures markets		108.2			-			108.2
Contracts added		82.6			-			82.6
Net fair value of gas, oil and NGL derivative contracts outstanding at September 30, 2011	$	333.0		$	(31.0	)	$	302.0

A table of the net fair value of gas, oil and NGL derivative contracts as of September 30, 2011, is shown below. Derivatives representing approximately 65% 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 September 30, 2012	$	216.6	$	(31.0	)	$	185.6
Contracts maturing between October 1, 2012 and September 30, 2013		98.0		-			98.0
Contracts maturing between October 1, 2013 and September 30, 2014		18.4		-			18.4
Contracts maturing between October 1, 2014 and September 30, 2015		-		-			-
Net fair value of gas, oil and NGL derivative contracts outstanding at September 30, 2011	$	333.0	$	(31.0	)	$	302.0

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:

	September 30, 2011		December 31, 2010
	(in millions)
Net fair value - asset (liability)	$	302.0	$	238.5
Fair value if market prices of gas, oil and NGL and basis differentials decline by 10%		404.4		356.2
Fair value if market prices of gas, oil and NGL and basis differentials increase by 10%		210.6		132.1

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $91.4 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $102.4 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 and see Note 9 – Derivative Contracts under Part I, Item 1of this Form 10-Q.

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Interest-Rate Risk Management

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 nine month ended September 30, 2011 and 2010 average levels and at our average level of borrowing for those same periods, our interest expense would increase by $1.0 million and $0.2 million for the nine months ended September 30, 2011 and 2010, respectively, or less than 2% in either year.

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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 plans;

●

trends in operations;

●

amount and allocation of forecasted capital expenditures for 2011;

●

impact of recently issued accounting pronouncements;

●

the amount and timing of the settlement of derivative contracts;

●

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, crude oil 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;

●

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.

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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 September 30, 2011. Based on such evaluation, such officers have concluded that, as of September 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 September 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 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.

The following repurchases of QEP shares were made by an affiliated purchaser, QEP Resources Education Foundation, during the third quarter of 2011:

Period	Total number of shares purchased (1)		Weighted-average price paid per share		Total number of shares purchased as part of publicly announced plans or programs		Maximum number of shares that may yet be repurchased under the plans or programs
July 1, 2011 - July 31, 2011		-	$	-		-		-
August 1, 2011 - August 31, 2011		-	$	-		-		-
September 1, 2011 - September 30, 2011		6,950	$	28.4269		-		-
		6,950	$	28.4269		-		-

(1) QEP Resources Education Foundation, an affiliated purchaser, purchased the shares in open-market transactions. These purchases were not made pursuant to a publicly announced plan or program.

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 September 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010, (ii) Condensed Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, (iii) Condensed Consolidated Statements of Cash Flows for the nine months ended September 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.

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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)

October 28, 2011	/s/ C. B. Stanley
	C. B. Stanley,
	President and Chief Executive Officer

October 28, 2011	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President,
	Chief Financial Officer and Treasurer

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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 September 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010, (ii) Condensed Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, (iii) Condensed Consolidated Statements of Cash Flows for the nine months ended September 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.