QEP RESOURCES, INC. - FORM 10-Q

QEP RESOURCES, INC. - FORM 10-Q - April 28, 2011

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file	filename
EX-31.1 - SECTION 302 CEO CERTIFICATION - QEP RESOURCES, INC.	dex311.htm
EX-12.1 - RATIO OF EARNINGS TO FIXED CHARGES - QEP RESOURCES, INC.	dex121.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - QEP RESOURCES, INC.	dex312.htm
EX-32.1 - SECTION 906 CEO AND CFO CERTIFICATION - QEP RESOURCES, INC.	dex321.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarter ended March 31, 2011

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

For the transition period from to

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)

STATE OF DELAWARE

001-34778

87-0287750

(State or other jurisdiction of

incorporation or organization

(Commission

File Number)

(I.R.S. Employer

Identification No.)

1050 17^thStreet, Suite 500, Denver, Colorado 80265

(Address of principal executive offices)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

At March 31, 2011, there were 176,757,765 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended March 31, 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		14

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		29

	ITEM 4.	CONTROLS AND PROCEDURES		31

PART II. OTHER INFORMATION				31

	ITEM 1.	LEGAL PROCEEDINGS		31

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		32

	ITEM 3.	EXHIBITS		32

SIGNATURES				33

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended March 31,
	2011			2010
	(in millions, except per share amounts)
REVENUES
Natural gas sales	$	271.0		$	264.6
Oil and NGL sales		79.5			54.0
Gathering, processing and other		97.9			81.9
Marketing sales		147.8			179.7

Total Revenues		596.2			580.2

OPERATING EXPENSES
Marketing purchases		146.7			177.9
Lease operating expense		32.8			28.3
Gathering, processing and other		25.2			23.5
General and administrative		31.7			25.2
Production and property taxes		23.7			22.9
Depreciation, depletion and amortization		190.8			147.4
Exploration expenses		2.8			3.6
Abandonment and impairment		5.4			7.6

Total Operating Expenses		459.1			436.4
Net loss from asset sales		—			(0.9	)

OPERATING INCOME		137.1			142.9
Interest and other income		0.6			0.8
Income from unconsolidated affiliates		0.9			0.8
Interest expense		(22.1	)		(19.9	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		116.5			124.6
Income taxes		(42.7	)		(45.9	)

INCOME FROM CONTINUING OPERATIONS		73.8			78.7
Discontinued operations, net of income tax		—			21.2

NET INCOME		73.8			99.9
Net income attributable to noncontrolling interest		(0.6	)		(0.6	)

NET INCOME ATTRIBUTABLE TO QEP	$	73.2		$	99.3

Earnings Per Common Share Attributable to QEP
Basic from continuing operations	$	0.42		$	0.45
Basic from discontinued operations		—			0.12

Basic total	$	0.42		$	0.57

Diluted from continuing operations	$	0.41		$	0.44
Diluted from discontinued operations		—			0.12

Diluted total	$	0.41		$	0.56

Weighted-average common shares outstanding
Used in basic calculation		176.2			174.9
Used in diluted calculation		178.3			177.2
Dividends per common share	$	0.02		$	—

See notes accompanying the condensed consolidated financial statements

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2011		December 31, 2010
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	—	$	—
Accounts receivable, net		262.9		269.9
Fair value of derivative contracts		201.1		257.3
Inventories, at lower of average cost
Gas and oil storage		7.5		16.4
Materials and supplies		72.4		65.4
Prepaid expenses and other		36.6		45.2

Total Current Assets		580.5		654.2

Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties		7,156.7		6,874.3
Unproved properties, not being depleted		331.5		322.0
Midstream field services		1,377.9		1,360.5
Marketing and other		45.0		44.5

Total Property, Plant and Equipment		8,911.1		8,601.3

Less Accumulated Depreciation, Depletion and Amortization
Exploration and production		2,629.8		2,454.4
Midstream field services		257.3		244.6
Marketing and other		12.7		12.3

Total Depreciation, Depletion and Amortization		2,899.8		2,711.3

Net Property, Plant and Equipment		6,011.3		5,890.0

Investment in unconsolidated affiliates		44.0		44.5
Goodwill		59.6		59.6
Fair value of derivative contracts		102.1		120.8
Other noncurrent assets		21.0		16.2

TOTAL ASSETS	$	6,818.5	$	6,785.3

LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	25.5	$	19.5
Accounts payable and accrued expenses		306.4		332.2
Production and property taxes		23.1		18.9
Interest payable		6.9		28.1
Fair value of derivative contracts		108.2		139.3
Deferred income taxes		6.9		27.8
Current portion of long-term debt		—		58.5

Total Current Liabilities		477.0		624.3

Long-term debt, less current portion		1,572.5		1,472.3
Deferred income taxes		1,410.4		1,377.7
Asset retirement obligations		152.4		148.3
Fair value of derivative contracts		1.7		0.3
Other long-term liabilities		113.2		99.3
EQUITY
Common stock		1.8		1.8
Additional paid-in capital		401.1		394.2
Retained earnings		2,490.0		2,420.0
Accumulated other comprehensive income		146.5		194.3

Total Common Shareholders’ Equity		3,039.4		3,010.3
Noncontrolling interests		51.9		52.8

Total Equity		3,091.3		3,063.1

TOTAL LIABILITIES AND EQUITY	$	6,818.5	$	6,785.3

See notes accompanying the condensed consolidated financial statements

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
	2011			2010
	(in millions)
OPERATING ACTIVITIES
Net income	$	73.8		$	99.9
Discontinued operations, net of income tax		—			(21.2	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		191.6			147.7
Deferred income taxes		40.0			42.8
Abandonment and impairment		5.4			7.6
Share-based compensation		7.4			3.6
Dry exploratory well expense		0.6			—
Net loss from asset sales		—			0.9
Income from unconsolidated affiliates		(0.9	)		(0.8	)
Distributions from unconsolidated affiliates and other		1.8			0.9
Unrealized gain on basis-only swaps		(31.2	)		(34.7	)
Changes in operating assets and liabilities		10.9			(24.7	)

Net Cash Provided by Operating Activities of Continuing Operations		299.4			222.0

INVESTING ACTIVITIES
Property, plant and equipment, including dry exploratory well expense		(342.5	)		(288.4	)
Proceeds from disposition of assets		0.9			—
Change in notes receivable		—			25.0

Net Cash Used in Investing Activities of Continuing Operations		(341.6	)		(263.4	)

FINANCING ACTIVITIES
Checks outstanding in excess of cash balances		5.9			9.6
Long-term debt issued		200.0			—
Current portion long-term debt repaid		(58.5	)		—
Change in notes payable		—			13.7
Long-term debt repaid		(100.0	)		—
Other capital contributions		(0.4	)		—
Dividends paid		(3.5	)		—
Distribution from Questar		0.2			—
Distribution to noncontrolling interest		(1.5	)		(1.2	)

Net Cash Provided from Financing Activities of Continuing Operations		42.2			22.1

CASH USED IN CONTINUING OPERATIONS		—			(19.3	)

Cash provided by operating activities of discontinued operations		—			46.8
Cash used in investing activities of discontinued operations		—			(17.5	)
Cash used in financing activities of discontinued operations		—			(27.5	)
Effect of change in cash and cash equivalents of discontinued operations		—			(1.8	)

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

Ending cash and cash equivalents	$	—		$	—

See notes accompanying the condensed consolidated financial statements

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Nature of Business

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

•

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

•

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

•

QEP Marketing Company (QEP Marketing) markets equity 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 Rocky Mountain and Midcontinent regions of the United States. Headquarters are in Denver, Colorado. Shares of QEP common stock trade on the New York Stock Exchange (NYSE:QEP).

Note 2 – Basis of Presentation of Interim Consolidated Financial Statements

The interim condensed consolidated financial statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) and with the instructions for quarterly reports on Form 10-Q and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.

The condensed consolidated financial statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

The preparation of the condensed consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three months ended March 31, 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 consolidated financial statements.

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 March, 31
	2011		2010
	(in millions, except per share amounts)
Revenues	$	—	$	66.7

Income before income taxes		—		33.1
Income taxes		—		(11.9	)

Discontinued operations, net of income taxes	$	—	$	21.2

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

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 under-funded 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 periodically adjusting historical balances to fair value. Comprehensive income attributable to QEP is shown below:


	Three Months Ended March 31,
	2011			2010
Net income	$	73.8		$	99.9
Other comprehensive income (loss)
Net unrealized income (loss) on derivatives		(76.1	)		299.2
Other		—			0.1
Income taxes		28.3			(111.3	)

Net other comprehensive income (loss)		(47.8	)		188.0

Comprehensive income		26.0			287.9
Comprehensive income attributable to noncontrolling interest		(0.6	)		(0.6	)

Comprehensive income attributable to QEP	$	25.4		$	287.3

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


	March 31, 2011			December 31, 2010			Change
	(in millions)
Net unrealized gain on derivatives	$	176.0		$	223.8		$	(47.8	)
Pension and postretirement liabilities		(29.5	)		(29.5	)		—

Accumulated other comprehensive income	$	146.5		$	194.3		$	(47.8	)

Note 5 – Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income attributable to QEP by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. Because of the pro rata nature of the share distribution arising from the Spin-off, historical share counts have been recast to be identical to those of Questar for the corresponding periods.

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 March 31,
	2011		2010
	(in millions)
Weighted-average basic common shares outstanding		176.2		174.9
Potential number of shares issuable under the Long-term Stock Incentive Plan		2.1		2.3

Average diluted common shares outstanding		178.3		177.2

Note 6 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. The Company’s ARO liability applies primarily to abandonment costs associated with gas and oil wells, production facilities and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Income or expense resulting from the settlement of ARO liabilities is included in net gain or (loss) from asset sales in the Consolidated Statements of Income. Changes in ARO were as follows:


	2011			2010
	(in millions)
ARO liability at January 1,	$	148.3		$	124.7
Accretion		2.3			2.0
Liabilities incurred		2.0			11.4
Revisions		—			0.5
Liabilities settled		(0.2	)		(0.1	)

ARO liability at March 31,	$	152.4		$	138.5

Note 7 – Capitalized Exploratory Well Costs

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


	2011			2010
	(in millions)
Balance at January 1,	$	13.6		$	51.7
Additions to capitalized exploratory well costs pending the determination of proved reserves		—			12.4
Reclassifications to property, plant and equipment after the determination of proved reserves		(5.5	)		(33.0	)

Balance at March 31,	$	8.1		$	31.1

Note 8 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures”. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements, but does not change existing guidance as to whether or not an instrument is carried at fair value. ASC 820 also establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. The Level 2 fair value of derivative contracts (see Note 9) is based on market prices posted on the NYMEX on the last trading day of the reporting period and industry-standard discounted cash flow models. The Level 3 fair value of derivative contracts is based on NYMEX market prices in combination with unobservable volatility inputs and industry-standard option pricing models.

QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique.

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

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

Fair Value Measurements
March 31, 2011

Level 2

Level 3

Netting
Adjustments

Total

(in millions)

Assets

Derivative contracts - short term

293.1

27.3

(119.3

)

201.1

Derivative contracts - long term

102.4

—

(0.3

)

102.1

Total assets

395.5

27.3

(119.6

)

303.2

Liabilities

Derivative contracts - short term

223.5

4.1

(119.4

)

108.2

Derivative contracts - long term

1.9

—

(0.2

)

1.7

Total liabilities

225.4

4.1

(119.6

)

109.9

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


	Derivative Contracts 2011
	(in millions)
Balance at January 1,	$	36.3
Realized gains and losses included in revenues		17.9
Unrealized gains and losses included in other comprehensive income		(13.1	)
Settlements		(17.9	)

Balance at March 31,	$	23.2

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


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

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

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

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

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


	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	March 31, 2011				December 31, 2010
	(in millions)
Financial assets
Cash and cash equivalents	$	—	$	—	$	—	$	—
Financial liabilities
Checks outstanding in excess of cash balances		25.5		25.5		19.5		19.5
Long-term debt		1,572.5		1,634.9		1,530.8		1,575.8

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

Note 9 – Derivative Contracts

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

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

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

QEP enters into derivative instruments that do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. Derivative contract counterparties are normally financial institutions and energy-trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and by transacting with multiple counterparties.

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


	Three Months Ended March 31,
	2011			2010
	(in millions)
*Effect of derivative instruments designated as cash flow hedges*
Gains (losses) recognized in AOCI for the effective portion of hedges	$	0.2		$	344.2
*Gains (losses) reclassified from AOCI into income for the effective portion of hedges*
Natural gas sales		73.1			45.6
Oil and NGL sales		—			(2.0	)
Marketing sales		—			—
Marketing purchases		3.4			1.8
*Loss recognized in income for the ineffective portion of hedges*
Interest and other income		(0.2	)		(0.4	)
*Effect of derivative instruments not designated as hedges*
Unrealized gain on basis-only swaps		31.2			34.7
Realized loss on basis-only swaps		(31.2	)		(34.7	)

Based on prices as of March 31, 2011, it is estimated that $112.9 million will be settled and reclassified from AOCI to the Consolidated Statements of Income during the next 12 months.

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


	March 31, 2011		December 31, 2010
	(in millions)
*Assets*
Fixed-price swaps	$	293.1	$	374.6
Price collars		27.3		37.9

Fair value of derivative instruments - short term	$	320.4	$	412.5

Fixed-price swaps	$	102.4	$	121.1
Price collars		—		—

Fair value of derivative instruments - long term	$	102.4	$	121.1

*Liabilities*
Fixed-price swaps	$	136.9	$	175.2
Price collars		4.1		1.6
Basis-only swaps		86.6		117.7

Fair value of derivative instruments - short term	$	227.6	$	294.5

Fixed-price swaps	$	1.9	$	0.6
Price collars		—		—
Basis-only swaps		—		—

Fair value of derivative instruments - long term	$	1.9	$	0.6

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 March 31, 2011:

QEP Energy Production


Year	Time Period	Quantity	Average Hedge Price per Mcf or Bbl, Net to the Well⁽¹⁾
			(estimated)
Gas Fixed-price Swaps (Bcf)
2011	9 months	82.4	$4.78
2012	12 months	71.5	5.06
2013	12 months	50.3	5.51

Gas Price Collars (Bcf)
			Floor-Ceiling
2011	9 months	21.1	$4.36-$6.36

Oil Fixed-price Swaps (Mbbl)
2012	12 months	732	$93.13

Oil Price Collars (Mbbl)
			Floor-Ceiling
2011	9 months	825	$51.73-$102.10

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

QEP 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 March 31, 2011:

QEP Marketing Transactions


Year	Time Period	Quantity	Average Hedged Price per MMBtu
Gas Sales Fixed-price Swaps (millions of MMBtu)
2011	9 months	4.0	$4.37
2012	12 months	0.3	4.73

Gas Purchases Fixed-price Swaps (millions of MMBtu)
2011	9 months	2.1	$4.08
2012	12 months	—	—

Note 10 – Debt

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


	March 31, 2011			December 31, 2010
	(in millions)
Revolving Credit Facility	$	500.0		$	400.0
7.50% Senior Notes due 2011		—			58.5
6.05% Senior Notes due 2016		176.8			176.8
6.80% Senior Notes due 2018		138.6			138.6
6.80% Senior Notes due 2020		138.0			138.0
6.875% Senior Notes due 2021		625.0			625.0

Total principal amount of debt		1,578.4			1,536.9

Less unamortized discount		(5.9	)		(6.1	)

Total long-term debt outstanding	$	1,572.5		$	1,530.8

Long-term debt maturing during the five years following March 31, 2011, is the $500.0 million outstanding under the revolving credit facility that matures in March 2013 (described below).

Credit Arrangements

QEP has a revolving credit facility which provides for loan commitments of $1.0 billion from a syndicate of financial institutions. The facility matures March 2013. The credit facility has restrictive covenants that limit the amount of funded indebtedness that QEP may incur. At March 31, 2011, QEP was in compliance with all of its debt covenants.

Senior Notes

The Company has $1,078.4 million principal amount of senior notes outstanding with maturities ranging from September 2016 to March 2021 and coupons ranging from 6.05% to 6.875%. The senior notes pay interest semi-annually, are unsecured and senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indenture governing QEP’s senior notes contains customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

Note 11 – Share-Based Compensation

QEP issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP recognizes expense over time as the stock options or restricted shares vest. Share-based compensation expense amounted to $7.4 million in the first quarter of 2011 compared to $3.6 million for the first quarter of 2010. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 14.2 million shares available for future grants at March 31, 2011.

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model was 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 Three Months Ended March 31, 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		(70,834	)	7.78 - 23.98		13.76
Forfeited		—		—		—

Balance at March 31, 2011		2,046,323		7.78 - 39.07		21.19


Options Outstanding						Options Exercisable				Unvested Options
Range of Exercise Prices	Number Outstanding at March 31, 2011		Weighted- Average Remaining Term in Years	Weighted- Average Exercise Price		Number Exercisable at March 31, 2011		Weighted- Average Exercise Price		Number Unvested at March 31, 2011		Weighted- Average Exercise Price
$7.78 – $11.89		598,124	1.4	$	8.65		598,124	$	8.65		—		—
19.37 – 27.84		1,245,964	4.5		24.30		260,000		26.53		985,964	$	23.72
39.07		202,235	6.9		39.07		—		—		202,235		39.07

		2,046,323	3.8		21.19		858,124		14.07		1,188,199		26.33

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 March 31, 2011, was 24 months. Transactions involving restricted shares under the terms of the LTSIP are summarized below:


	Unvested Restricted Shares			Price Range	Weighted- Average Price
Balance at January 1, 2011		966,961		$17.03 – $47.28	$	29.05
Granted		377,330		32.29 – 40.64		39.00
Distributed		(206,214	)	19.86 – 38.95		29.11
Forfeited		(384	)	39.07		39.07

Balance at March 31, 2011		1,137,693		17.03 – 47.28		32.33

Note 12 – 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 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 three months ended March 31, 2011, the Company made contributions of $0.7 million to its retirement plans which increase plan assets. During the remainder of 2011, the Company expects to contribute $11.2 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 March 31, 2011
	Pension			Post Retirement Benefits
	(in millions)
Service cost	$	0.7		$	—
Interest cost		1.1			0.1
Expected return on plan assets		(0.6	)		—
Amortization of prior service costs		1.3			0.1
Recognized net actuarial loss		—			—

Periodic expense	$	2.5		$	0.2

Note 13 – Operations by Line of Business

QEP’s lines of business include gas and oil exploration and production (QEP Energy), midstream field services (QEP Field Services) and marketing (QEP Marketing). The lines of business are managed separately and therefore the financial information is presented separately due to the distinct differences in the nature of operations of each line of business, among other factors. Following is a summary of operating results by line of business:


	Three Months Ended March 31,
	2011		2010
	(in millions)
Revenues from Unaffiliated Customers
QEP Energy	$	352.7	$	319.7
QEP Field Services		95.1		80.3
QEP Marketing and other		148.4		180.2

Total	$	596.2	$	580.2

Revenues from Affiliated Companies
QEP Field Services	$	0.6	$	0.6
QEP Marketing and other		133.1		143.3

Total	$	133.7	$	143.9

Operating Income
QEP Energy	$	87.9	$	103.8
QEP Field Services		47.3		37.1
QEP Marketing and other		1.9		2.0

Total	$	137.1	$	142.9

Net Income from Continuing Operations Attributable to QEP
QEP Energy	$	43.1	$	53.8
QEP Field Services		28.0		23.2
QEP Marketing and other		2.1		1.1

Total	$	73.2	$	78.1

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 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 month periods ended March 31, 2011 and March 31, 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 four principal operating areas: Midcontinent in Oklahoma, Arkansas, Texas and Louisiana; the Pinedale Anticline in Wyoming; the Uinta Basin in Utah; and the Rockies Legacy properties in Wyoming and North Dakota;

•

QEP Marketing Company (QEP Marketing) markets equity and third-party natural gas and oil on markets 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.

Outlook

The Company has substantial acreage positions and operations in some of North America’s most economic resource plays including the Bakken/Three Forks, Pinedale, Haynesville, Woodford “Cana” Shale and Granite Wash/Atoka Wash plays. These resource plays are characterized by unconventional oil or natural gas accumulations in continuous tight sands or shales that underlie broad geographic areas. The lateral continuity of such resource plays means that aside from wells abandoned due to mechanical issues, the Company does not expect to drill many unsuccessful wells. Resource plays allow the Company the opportunity to gain considerable operational efficiencies through high density and repeatable drilling and completion operations. The Company has a large inventory of lower-risk, predictable development drilling locations across its acreage holdings in the onshore United States that provide a solid base for consistent organic production and reserve growth. QEP also has one of the lowest cash cost structures among its exploration and production company peers.

While predominantly a natural gas producer, the Company has increased its focus on growing the relative proportion of crude oil and NGL production in its exploration and production business. Oil and NGL production increased by approximately 33% in the first quarter of 2011 compared with the first quarter of 2010 and oil and NGL revenue accounted for approximately 25% of net natural gas and oil revenues (including realized losses on basis-only swaps) in the first quarter of 2011 compared to 19% in the first quarter of 2010. The Company has allocated over 40% of its forecasted 2011 capital expenditures to oil and liquids-rich natural gas projects.

The Company also owns and operates gathering and transmission pipelines and natural gas processing and treatment facilities in its core producing areas, which allows the Company to promptly connect its wells, better control its costs, and generate a significant revenue stream by providing transportation and processing services to third parties in addition to QEP Energy. Net income from QEP’s midstream business accounted for approximately 38% of the Company’s total income from continuing operations during the first quarter of 2011 compared with 30% for the first quarter of 2010.

While QEP believes that it can grow 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 Midcontinent and Rocky Mountain regions, combined with its low-cost operating structure and financial strength, enhance its ability to pursue acquisition opportunities in those geographic areas.

Highlights of Three Months Ended March 31, 2011

In the first quarter of 2011, QEP reported production of 65.9 Bcfe compared to 51.5 Bcfe in the 2010 first quarter. In the first quarter of 2011, the Midcontinent region contributed 59% of total equivalent production. The production growth was driven by good results from development activities in the Haynesville Shale play in northwest Louisiana, continued development of the Granite Wash/Atoka Wash play in the Texas Panhandle, and in the Woodford “Cana” Shale horizontal gas play in the Anadarko Basin of western Oklahoma.

QEP Energy continues to drive down the controllable cash cost of production per Mcfe. The Company defines the cash cost of production as the sum of lease operating expense, general and administrative expense, allocated interest and production taxes. Cash operating costs decreased to $1.50 per Mcfe in the first quarter of 2011 compared to $1.72 per Mcfe in the first quarter of 2010.

QEP Field Services reported gathering system throughput of 1.3 million MMBtu per day for the March 31, 2011 quarter, 5% higher than the 2010 first quarter. The increased volumes were primarily in northwest Louisiana. QEP Field Services also reported a 12% increase in NGL sales volumes to a total of 27.8 million gallons. The increase in NGL sales volumes along with a 6% increase in the per unit NGL margin (NGL revenue less fuel and shrinkage) resulted in a 19% increase to the keep-whole processing margin.

Factors Affecting Results of Operations

Oil and Natural Gas Prices

Historically, prices received for QEP’s natural gas, NGL and crude oil production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, natural gas supply has grown faster than natural gas demand, driven by advances in technology – horizontal drilling and hydraulic fracturing – that has allowed producers to extract increasing amounts of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supply has put downward pressure on natural gas prices, while unrest in the Middle East and other factors have caused the price of crude oil to increase. Changes in the market prices for crude oil and natural gas directly impact many aspects of QEP’s business, including its financial condition, revenues, results of operations, liquidity, rate of growth, costs of goods and services required to drill and complete wells, the carrying value of its oil and natural gas properties and borrowing capacity under its revolving credit facility. For example, despite a 28% increase in natural gas production in the first quarter of 2011 compared to the first quarter of 2010, natural gas revenues increased only 2% due to significantly lower net realized natural gas prices.

QEP uses commodity derivatives to reduce the variability of the prices QEP receives for its production and provide a minimum revenue stream. As of March 31, 2011, assuming 2011 annual production of 265.0 Bcfe, QEP had approximately 54% of its remaining forecast 2011 natural gas, oil and NGL production covered with fixed-price swaps or price collars. See “Quantitative and Qualitative Disclosures about Market Risk—Commodity Derivative Transactions” for further details concerning its commodity derivatives transactions. In addition, as a result of the continued spread between oil and natural gas prices, QEP has allocated over 40% of its forecasted 2011 capital expenditure budget to crude oil and liquids-rich natural gas projects in its portfolio and reduced the overall allocation of capital expenditures directed to the development of dry natural gas plays.

Unrealized Derivative Gains and Losses

Unrealized gains and losses 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.

Strategies

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

•

Allocate capital to the projects that generate the best returns

•

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

•

Be in the best parts of the best plays

•

Build contiguous acreage positions to drive efficiencies

•

Be the operator of our assets whenever possible

•

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

•

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

•

Build gas processing plants to extract liquids from our gas streams

•

Gather, compress and treat our production to drive down costs

•

Actively market our equity production to maximize value

•

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

•

Operate in a safe and environmentally responsible manner

•

Attract and retain the best people

•

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

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 consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles. The preparation of 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 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, 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 March 31,
	2011		2010		Change
QEP Energy	$	242.0	$	215.4	$	26.6
QEP Field Services		61.4		50.4		11.0
QEP Marketing and other		2.4		2.7		(0.3	)

Total Adjusted EBITDA	$	305.8	$	268.5	$	37.3

Adjusted EBITDA increased 14% to $305.8 million for the first quarter of 2011 compared to $268.5 million in the 2010 period, despite an 18% decrease in net realized natural gas prices. The impact of lower natural gas prices was offset by a 28% increase in production and higher net realized crude oil and NGL prices in QEP Energy, along with increased gathering and processing margins in QEP Field Services.

A reconciliation of Adjusted EBITDA to net income follows:


	Three Months Ended December 31,
	2011			2010
	(in millions)
Net income attributable to QEP Resources	$	73.2		$	99.3
Net income attributable to non-controlling interest		0.6			0.6

Net Income		73.8			99.9
Discontinued operations, net of tax		—			(21.2	)

Income from continuing operations		73.8			78.7
Unrealized gain on basis-only swaps		(31.2	)		(34.7	)
Net loss from asset sales		—			0.9
Interest and other income		(0.6	)		(0.8	)
Income taxes		42.7			45.9
Interest expense		22.1			19.9
Depreciation, depletion and amortization		190.8			147.4
Abandonment and impairment		5.4			7.6
Exploration expenses		2.8			3.6

Adjusted EBITDA	$	305.8		$	268.5

Net Income

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


	Three Months Ended March 31,
	2011		2010		Change
QEP Energy	$	43.1	$	53.8	$	(10.7	)
QEP Field Services		28.0		23.2		4.8
QEP Marketing and other		2.1		1.1		1.0

Net Income from continuing operations attributable to QEP	$	73.2	$	78.1	$	(4.9	)

Earnings per diluted share from continuing operations	$	0.41	$	0.44	$	(0.03	)
Average diluted shares		178.3		177.2		1.1

Revenue, Volumes and Prices


	Three Months Ended March 31,
	2011		2010		Change
*Revenues*
Natural gas sales	$	271.0	$	264.6	$	6.4
Oil and NGL sales		79.5		54.0		25.5
Gathering, processing and other		97.9		81.9		16.0
Marketing sales		147.8		179.7		(31.9	)

Total Revenues	$	596.2	$	580.2	$	16.0

QEP Energy’s revenues for the three months ended March 31, 2011 related to 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 March 31,
	Natural Gas			Oil and NGLS		Total
*QEP Energy Revenues*
2010 revenues	$	264.6		$	54.0	$	318.6
Changes associated with volumes ⁽¹⁾		73.0			17.1		90.1
Changes associated with prices ⁽²⁾		(66.6	)		8.4		(58.2	)

2011 revenues	$	271.0		$	79.5	$	350.5

Gathering, processing and other revenues also increased for the three months ended March 31, 2011 as a result of higher volumes and improved processing and gathering fees.


	Three Months Ended March 31,
	Gathering and Processing		Other		Total
*QEP Field Services Revenues*
2010 revenues	$	70.2	$	11.7	$	81.9
Changes associated with volumes ⁽¹⁾		5.3		—		5.3
Changes associated with fees ⁽²⁾		2.5		—		2.5
Changes associated with other factors		—		8.2		8.2

2011 revenues	$	78.0	$	19.9	$	97.9

⁽¹⁾	The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the March 31, 2011, quarter to the March 31, 2010, quarter by the average price or fees for the quarter ended March 31, 2010.

⁽²⁾	The revenue variance attributed to the change in price is calculated by multiplying the change in prices or fees from the March 31, 2011, quarter to the March 31, 2010, quarter by volume for the quarter ended March 31, 2011.

Marketing revenues were lower due to a 5% decrease in the sales volumes for unaffiliated customers coupled with a 24% decrease in the weighted average natural gas sales price obtained for volumes purchased from unaffiliated customers.

Production

QEP Energy reported production of 65.9 Bcfe in the first quarter of 2011 compared to 51.5 Bcfe in the 2010 quarter, a 28% increase, which includes a prior period adjustment of 1.6 Bcfe. On an energy-equivalent basis, crude oil and NGL comprised approximately 10% of QEP Energy’s first quarter 2011 production. A summary of natural gas-equivalent production by major operating area is shown in the following table:


	Three Months Ended March 31,
	2011		2010		Change
*QEP Energy production by operating area (Bcfe)*
Midcontinent		38.8		26.2		12.6
Pinedale Anticline		16.2		15.5		0.7
Uinta Basin		6.4		5.2		1.2
Rockies Legacy		4.5		4.6		(0.1	)

Total QEP Energy		65.9		51.5		14.4

*QEP Energy production volumes*
Natural gas (Bcf)		59.1		46.3		12.8
Oil (MMbbl)		0.8		0.7		0.1
NGL (MMbbl)		0.4		0.2		0.2

Total production (Bcfe)		65.9		51.5		14.4

Average daily production (MMcfe)		732.8		572.3		160.5

Net production in the Midcontinent grew 48% to 38.8 Bcfe in the first quarter of 2011 compared to the first quarter of 2010 and represented 59% of the Company’s total production compared to 51% in the year earlier period. Midcontinent production growth was driven by ongoing development drilling in the Haynesville Shale play in northwest Louisiana, 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 5% to 16.2 Bcfe in the first quarter of 2011 compared to the 2010 first quarter as a result of ongoing development drilling. In the Uinta Basin, production increased 23% to 6.4 Bcfe in the first quarter of 2011 due to an adjustment of QEP’s ownership interest within a federal unit, which resulted in a prior-period positive adjustment to reported production volumes of 1.6 Bcfe. Rockies Legacy net production in the first quarter of 2011 was down by 2.0% to 4.5 Bcfe due to reduced natural gas directed drilling activity and the impact of severe winter conditions on oil sales in North Dakota. Most of QEP’s wells in North Dakota will be connected to oil gathering lines in the first half of 2011 thereby eliminating future weather-related oil sales interruptions. QEP Energy Rockies Legacy properties include all Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.

Pricing

Realized prices for natural gas and NGLs at QEP Energy were lower when compared to the prior quarter, while realized oil prices were higher when compared to the 2010 quarter. A regional comparison of average realized prices, including the impact of hedges, is shown in the following table:


	Three Months Ended March 31,
	2011		2010		Change
*Natural gas average realized prices (per Mcf)*
Midcontinent	$	4.01	$	6.45	$	(2.44	)
Rocky Mountains		5.48		4.91		0.57
Volume-weighted average		4.59		5.72		(1.13	)
*Oil average realized prices (per bbl)*
Midcontinent	$	89.84	$	73.61	$	16.23
Rocky Mountains		79.14		63.49		15.65
Volume-weighted average		81.64		66.26		15.38
*NGL average realized prices (per bbl)*
Midcontinent	$	42.92	$	47.18	$	(4.26	)
Rocky Mountains		52.60		44.08		8.52
Volume-weighted average		44.44		46.31		(1.87	)

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 March 31,
	2011			2010			Change
*Natural gas ($ per Mcf)*
Average field-level natural gas price ($ per Mcf)	$	3.35		$	4.73		$	(1.38	)
Natural gas commodity derivative impact ($ per Mcf)		1.24			0.99			0.25

Average revenue ($ per Mcf)⁽¹⁾		4.59			5.72			(1.13	)
Realized losses on basis-only swaps ($ per Mcf)⁽²⁾		(0.53	)		(0.75	)		0.22

Net realized natural gas price ($ per Mcf)	$	4.06		$	4.97		$	(0.91	)

*Oil ($ per bbl)*
Average field-level oil price ($ per bbl)	$	81.64		$	69.18		$	12.46
Oil commodity derivative impact ($ per bbl)		—			(2.92	)		2.92

Net realized oil price ($ per bbl) ⁽¹⁾	$	81.64		$	66.26		$	15.38

*NGL ($ per bbl)*
Average field-level NGL prices ($ per bbl) ⁽¹⁾	$	44.44		$	46.31		$	(1.87	)

⁽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 its forecasted natural gas and oil production. The impact of QEP’s commodity derivatives transactions on the Company’s financial statements 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 March 31, 2011, are summarized in Note 9 to the consolidated financial statements in Item 1 of Part I in this Quarterly Report on Form 10-Q.


	Three Months Ended March 31,
	2011	2010
*Volumes subject to commodity derivatives as a percent of gas production*
Fixed price swaps	43%		80	%
Price collars	12%		4	%
*Volumes subject to commodity derivatives as a percent of oil production*
Fixed price swaps	—		33	%
Price collars	35%		27	%


	Three Months Ended March 31, 2011
*Impact of commodity derivatives on financial statements (millions)*	2011			2010			Change
Natural gas sales	$	73.1		$	45.6		$	27.5
Oil sales	$	—		$	(2.0	)	$	2.0
*Impact of commodity derivatives that do not qualify for hedge accounting (millions)*
Unrealized gain (loss) on basis-only swaps	$	31.2		$	34.7		$	(3.5	)
Realized (loss) on basis-only swaps	$	(31.2	)	$	(34.7	)	$	3.5

The change in unrealized gains and losses on natural gas basis-only swaps increased first quarter 2011 net income $19.6 million compared to an increase of $21.8 million in the 2010 first quarter. 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 23% increase in gathering margin in the first quarter of 2011, primarily due to an increase in the liquids value received from a short-term third-party gathering and processing arrangement and a 5% increase in gathering system throughput volume to 1.3 million MMBtu per day. The increased volumes were mainly related to the northwest Louisiana gathering system, which accounted for 24% of the total throughput during the first quarter of 2011.

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


	Three Months Ended March 31,
	2011			2010			Change
	(in millions)
*Gathering Margin*
Gathering revenues	$	39.4		$	36.0		$	3.4
Other gathering revenues		17.7			10.7			7.0
Gathering expense		(11.9	)		(9.9	)		(2.0	)

Gathering Margin	$	45.2		$	36.8		$	8.4

*Operating Statistics*
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers		61.1			70.5			(9.4	)
For affiliated customers		57.9			43.2			14.7

Total Gas Gathering Volumes		119.0			113.7			5.3

Average gas gathering revenue (per MMBtu)	$	0.33		$	0.32		$	0.01

Processing

Processing margin increased 24% in the first quarter 2011 compared to 2010 due to increased keep-whole processing margins and increased fee-based processing revenues. The increased keep-whole processing margin was mostly the result of a 12% increase in NGL volumes. Processing fees increased 20% due to a 6% increase in fee-based processing volumes to 57.0 million MMBtu and a 13% increase in the processing fee rate. This was primarily the result of the start-up of the 150 MM per day Iron Horse cryogenic processing plant in eastern Utah during the first quarter of 2011. QEP Field Services also reported higher liquid revenues associated with some short-term third-party gathering and processing arrangements the Company has entered into until the start-up of the Blacks Fork 2 cryogenic processing plant later this year. Approximately 78% of QEP Field Services’ net operating revenue was derived from fee-based gathering and processing contracts in both quarters.

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


	Three Months Ended March 31,
	2011			2010			Change
	(in millions)
*Processing Margin*
NGL sales	$	28.6		$	25.9		$	2.7
Processing (fee based) revenues		10.0			8.3			1.7
Processing (expense)		(2.7	)		(3.0	)		0.3
Processing plant fuel and shrinkage (expense)		(10.2	)		(10.4	)		0.2

Processing Margin	$	25.7		$	20.8		$	4.9

Frac spread (NGL sales – Processing plant fuel and shrinkage)	$	18.4		$	15.5		$	2.9
*Operating Statistics*
Natural gas processing volumes
NGL sales (MMgal)		27.8			24.8			3.0
Average NGL sales price (per gal)	$	1.03		$	1.04		$	(0.01	)
Fee based processing volumes (in millions of MMBtu)
For unaffiliated customers		31.4			28.1			3.3
For affiliated customers		25.6			25.6			—

Total Fee-Based Processing Volumes		57.0			53.7			3.3

Average fee-based processing revenue (per MMBtu)	$	0.17		$	0.15		$	0.02

Operating Expenses

The following table presents QEP’s total operating expenses and the changes from the first quarter of 2010 to the quarter ended March 31, 2011. The narrative below the table explains the significant variances between the two quarters.


	Three Months Ended March 31,
	2011		2010		Change
	(in millions)
Marketing purchases	$	146.7	$	177.9	$	(31.2	)
Lease operating expense		32.8		28.3		4.5
Gathering, processing and other		25.2		23.5		1.7
General and administrative expense		31.7		25.2		6.5
Production and property taxes		23.7		22.9		0.8
Depreciation, depletion and amortization		190.8		147.4		43.4
Exploration expenses		2.8		3.6		(0.8	)
Abandonment and impairment		5.4		7.6		(2.2	)

Total operating expenses	$	459.1	$	436.4	$	22.7

Marketing purchases decreased due to lower volumes purchased from unaffiliated customers and lower weighted average natural gas prices paid to unaffiliated customers in the first quarter of 2011 compared with the 2010 period.

The $4.5 million, or 16% increase in lease operating costs to $32.8 million during the first quarter of 2011 compared to the first quarter of 2010 was driven by the 28% increase in production of natural gas and oil equivalents during the period.

The table below presents certain QEP Energy operating expenses on a per unit of production basis. QEP Energy 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 4% to $4.19 per Mcfe in the first quarter of 2011 compared to $4.34 per Mcfe in 2010.


	Three Months Ended March 31,
	2011		2010		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.69	$	2.62	$	0.07
Lease operating expense		0.51		0.56		(0.05	)
General and administrative expense		0.36		0.37		(0.01	)
Allocated interest expense		0.30		0.37		(0.07	)
Production taxes		0.33		0.42		(0.09	)

Total Production Costs	$	4.19	$	4.34	$	(0.15	)

Depreciation, depletion and amortization (DD&A) expense increased by $.07 per Mcfe increased in 2011. QEP Energy’s DD&A expense increased $42.0, driven by increased investment and a greater proportion of production coming from the Company’s northwest Louisiana properties. The higher DD&A rates in northwest Louisiana reflect significant amortization of leasehold pool costs as a result of the 2008 acquisition of producing properties. Lease operating expense per Mcfe decreased primarily as the result of increased production volumes from new high-rate, low operating cost wells in northwest Louisiana and declining production from higher-cost areas, which reduced average lease operating expense. General and administrative expense per Mcfe decreased in the current year period as the result of increased production in the first quarter of 2011 quarter, offset by higher G&A expenses, which were primarily related to stock based compensation expenses. Allocated interest expense per unit of production decreased in the 2011 period primarily due to higher production volumes. Production taxes per Mcfe decreased in 2011 as a result of lower natural gas field-level sales prices.

Total corporate general and administrative costs increased to $31.7 million for the quarter ended March 31, 2011, compared with $25.2 million during the 2010 first quarter. The increase results from higher non-cash stock based compensation expenses due to the increase in QEP’s stock price, and higher compensation expense related to the issuance of additional shares of restricted stock and stock options during the last half of 2010 and the first quarter of 2011.

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

Overall QEP depreciation expense grew $43.4 million or 29% in the first quarter of 2011 compared with the 2010 quarter as a result of increased production at QEP Energy combined with plant additions at QEP Field Services.

Exploration expenses decreased to $2.8 million in the first quarter of 2011 compared with $3.6 million in the first quarter of 2010 due to reduced seismic acquisition costs of $1.4 million, partially offset by an increase in dry hole cost of $0.6 million.

Abandonment and impairment expenses decreased to $5.4 million in the first quarter of 2011 compared with $7.6 million in the 2010 first quarter primarily due to an increase in the expected level of successful development of the Company’s unproved acreage.

CONSOLIDATED RESULTS BELOW OPERATING INCOME

Interest and other income

Interest and other income is comprised primarily of interest earned on investments, gains and losses on warehouse inventory, hedge ineffectiveness and other miscellaneous income. The slight decrease was primarily due to lower gain on warehouse inventory sales.

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

In the past, the Company has used basis-only swaps to manage the risk of widening basis differentials. Basis-only swaps do not qualify for hedge accounting. As of December 31, 2009, all of the Company’s basis-only swaps had been paired with fixed-price swaps and re-designated as cash flow hedges. Fair value changes occurring prior to re-designation were recorded in the Consolidated Statements of Income. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in AOCI. Realized losses on settlements of basis-only swaps relating to the period prior to re-designation amounted to $31.2 million in the first quarter of 2011 and $34.7 million in the first quarter of 2010. Unrealized gains on basis-only swaps amounted to $31.2 million in the first quarter of 2011 compared to $34.7 million in 2010.

Interest expense

Interest expense rose by 11% to $22.1 million in the first quarter of 2011 compared to a year ago primarily due to March 31, 2011 debt levels that were approximately $170 million higher than average debt levels in the first quarter of 2010.

Income taxes

The effective combined federal and state income tax rate was 36.6% in the first quarter of 2011 compared with 36.9% in the 2010 period.

DISCUSSION BY LINE OF BUSINESS

QEP Energy

QEP Energy reported net income of $43.1 million in the first quarter of 2011 compared with $53.8 million in the 2010 quarter. The primary reason for the decrease was an 18% decline in net realized natural gas prices to $4.06 per Mcfe compared to $4.97 per Mcfe in the first quarter of 2010. The decrease in net realized natural gas prices was partially offset by a 28% increase in natural gas-equivalent production, net of associated increased depreciation, depletion and amortization expense and a 23% increase in net realized oil prices. Changes in unrealized basis-only swaps increased net income $19.6 million in the 2011 quarter compared to an increase of $21.8 million in the first quarter of 2010. Following is a summary of QEP Energy’s financial and operating results:


	Three Months Ended March 31,
	2011			2010			Change
*Operating Income*
Revenues
Natural gas sales	$	271.0		$	264.6		$	6.4
Oil sales		62.3			44.9			17.4
NGL sales		17.2			9.1			8.1
Other		2.2			1.1			1.1

Total Revenues		352.7			319.7			33.0

Operating expenses
Lease operating expense		33.4			28.8			4.6
General and administrative		23.9			19.1			4.8
Production and property taxes		22.2			21.7			0.5
Depreciation, depletion and amortization		177.1			135.1			42.0
Exploration expenses		2.8			3.6			(0.8	)
Abandonment and impairment		5.4			7.6			(2.2	)

Total Operating Expenses		264.8			215.9			48.9

Operating Income		87.9			103.8			(15.9	)
Interest and other income		0.7			0.8			(0.1	)
Interest expense		(19.9	)		(19.0	)		(0.9	)

Income from Continuing Operations before Income Taxes		68.7			85.6			(16.9	)
Income Taxes		(25.6	)		(31.8	)		6.2

Net Income Attributable to QEP	$	43.1		$	53.8		$	(10.7	)

Major QEP Energy Operating Areas

Midcontinent

QEP Energy Midcontinent properties 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, Louisiana, and Texas. With the exception of northwest Louisiana, the Granite Wash play in the Texas Panhandle and the Woodford “Cana” Shale play in western Oklahoma, QEP Energy Midcontinent leasehold interests are relatively fragmented, with no significant concentration of property interests.

QEP Energy has approximately 50,750 net acres of Haynesville Shale lease rights in northwest Louisiana. 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. QEP Energy intends to drill or participate in up to 80 horizontal Haynesville Shale wells in 2011. As of March 31, 2011, QEP Energy had six operated rigs drilling in the project area and operated or had working interests in 730 producing wells in northwest Louisiana compared to 628 at March 31, 2010.

QEP Energy has approximately 75,000 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. QEP Energy intends to drill or participate in up to 79 gross horizontal Woodford Shale wells in 2011. As of March 31, 2011, QEP Energy had three operated rigs drilling in the project area and had working interests in 128 gross producing Woodford Shale wells in western Oklahoma compared to 60 gross wells at March 31, 2010.

QEP Energy has approximately 41,000 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. In the past year, QEP and other operators have drilled a number of successful horizontal wells in the Granite Wash/Atoka Wash play. 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. QEP Energy intends to drill or participate in up to 27 gross horizontal Granite Wash/Atoka Wash wells in 2011.

As of March 31, 2011, QEP Energy had three rigs drilling horizontal Granite Wash/Atoka Wash wells in the Texas Panhandle and had working interests in 71 gross producing horizontal Granite Wash/Atoka Wash wells in the Texas Panhandle and western Oklahoma compared to 22 gross wells at March 31, 2010.

Pinedale Anticline

As of March 31, 2011, QEP Energy had interests in 535 producing wells on the Pinedale Anticline compared to 437 at the end of the first quarter of 2010. Of the 535 producing wells, QEP Energy had working interests in 514 wells and an overriding royalty interest only in an additional 21 wells. As of March 31, 2011, QEP had four rigs drilling on the Pinedale Anticline and expects to complete 90 to 100 well during 2011.

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

Uinta Basin

As of March 31, 2011, QEP Energy had an operating interest in 2,515 producing or shut-in wells in the Uinta Basin of eastern Utah, compared to 2,327 at March 31, 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 289,000 net leasehold acres in the Uinta Basin.

Rockies Legacy

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

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. QEP Energy intends to drill or participate in 53 gross Bakken or Three Forks horizontal wells in 2011. As of March 31, 2011, QEP Energy had two operated rigs drilling in the project area and had working interests in 64 gross producing Bakken or Three Forks wells in North Dakota compared to working interests in 22 gross wells at March 31, 2010.

QEP Field Services

QEP Field Services, which provides gas-gathering and processing services, reported net income of $28.0 million in the first quarter of 2011 compared to $23.2 million in the same period of 2010, a 21% increase. The increase in first quarter net income was the result of higher gathering and processing margins. Following is a summary of QEP Field Services’ financial and operating results:


				Three Months Ended March 31,
	2011			2010			Change
	(in millions)
*Operating Income*
Revenues
NGL sales	$	28.6		$	25.9		$	2.7
Processing (fee based)		10.0			8.3			1.7
Gathering		39.4			36.0			3.4
Other gathering		17.7			10.7			7.0

Total Revenues		95.7			80.9			14.8

Operating expenses
Processing		2.7			3.0			(0.3	)
Processing plant fuel and shrinkage		10.2			10.4			(0.2	)
Gathering		11.9			9.9			2.0
General and administrative		9.0			6.8			2.2
Taxes other than income taxes		1.4			1.1			0.3
Depreciation, depletion and amortization		13.2			11.8			1.4

Total Operating Expenses		48.4			43.0			5.4
Net gain (loss) from asset sales		—			(0.8	)		0.8

Operating Income		47.3			37.1			10.2
Income from unconsolidated affiliates		0.9			0.7			0.2
Interest expense		(3.5	)		(0.7	)		(2.8	)

Income from Continuing Operations before Income Taxes		44.7			37.1			7.6
Income Taxes		(16.1	)		(13.3	)		(2.8	)

Income from Continuing Operations		28.6			23.8			4.8
Net income attributable to noncontrolling interest		(0.6	)		(0.6	)		—

Net Income Attributable to QEP	$	28.0		$	23.2		$	4.8

QEP Marketing

QEP Marketing income from continuing operations was $2.1 million in the first quarter of 2011 compared to $1.1 million in the comparable 2010 quarter as a result of an increase in the storage margin as well as an increase in the revenue from QEP Energy due to higher volumes. The increase in 2011 storage margins was due to an overall increase in natural gas price volatility. Revenues from unaffiliated customers were $148.4 million in the first quarter of 2011 compared to $180.2 million in the first quarter of 2010 This 18% decrease was the result of lower natural gas prices and decreased sales volumes. The weighted-average natural gas sales price for unaffiliated customers decreased 24% in the first quarter of 2011 to $3.60 per MMBtu, compared to $4.73 per MMBtu in the 2010 quarter. The unaffiliated gas sales volumes decreased 4% in 2011 to 26.9 MMBtu compared to 28.1 MMBtu in 2010.

LIQUIDITY AND CAPITAL RESOURCES

QEP funds its operations, capital expenditures and working capital requirements with cash flow from its natural gas and oil operations, borrowings under its credit facility and proceeds from debt offerings. 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 and oil 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 12-24 months. See “Commodity Derivative Impact” above.

Net cash provided from continuing operating activities increased 35% in the first three months of 2011 compared to the first three months of 2010 due to higher noncash adjustments to net income and a source of cash from operating assets and liabilities in 2011 compared with a source of cash in 2010, offset by lower net income. Noncash adjustments to net income consist primarily of depreciation, depletion and amortization; noncash unrealized gains and losses on basis-only swaps and changes in deferred income taxes. Cash sources from operating assets and liabilities were higher in 2011 primarily due to reductions in accounts receivable and prepaid expenses in the March 31, 2011, first quarter compared with the March 31, 2010, first quarter. Net cash provided from continuing operating activities is presented below:


	Three Months Ended March 31,
	2011		2010			Change
	(in millions)
Income from continuing operations	$	73.8	$	78.7		$	(4.9	)
Noncash adjustments to net income		214.7		168.0			46.7
Changes in operating assets and liabilities		10.9		(24.7	)		35.6

Net cash provided from continuing operating activities	$	299.4	$	222.0		$	77.4

Cash Flow from Investing Activities

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


	Three Months Ended March 31,						Forecast 12 Months Ended
	2011			2010			December 31, 2011
	(in millions)
QEP Energy	$	299.5		$	219.9		$	1,050.0
QEP Field Services		42.5			68.5			150.0
QEP Marketing and other		0.5			—			—

Total cash capital expenditures of continuing operations		342.5			288.4			1,200.0
Change in accruals		(27.7	)		(16.6	)		—

Total accrued capital expenditures of continuing operations	$	314.8		$	271.8		$	1,200.0

Cash Flow from Financing Activities

In the first quarter of 2011, net cash used in investing activities of $341.6 million exceeded net cash provided by operating activities of $299.4 million by $42.2 million. Long-term debt (including the current portion of long-term debt) increased by $41.7 million from year-end 2010, primarily due to the semi-annual interest payment on the senior notes. At March 31, 2011, long-term debt consisted of $500.0 million outstanding under QEP’s revolving credit facility and $1,072.5 million in senior notes (including $5.9 million of net original issue discount). At March 31, 2011, combined short-term and long-term debt was 34% and equity was 66% of total capital.

Credit Facility

QEP has a revolving credit facility that provides for loan commitments of $1.0 billion from a syndicate of financial institutions. The facility matures March in 2013. The credit facility has restrictive covenants that limit the amount of funded indebtedness that QEP may incur. At March 31, 2011, QEP was in compliance with all of its debt covenants. At April 22, 2011, QEP had $550.7 million outstanding under its revolving credit facility and $5.6 million of letters of credit issued.

Senior Notes

The Company’s senior notes outstanding as of March 31, 2011, totaled $1,078.4 million principal amount and are comprised of four issues as follows:

•

$176.8 million 6.05% Senior Notes due September 2016

•

$138.6 million 6.80% Senior Notes due April 2018

•

$138.0 million 6.80% Senior Notes due March 2020

•

$625.0 million 6.875% Senior Notes due March 2021

Capital Expenditures

In 2011, QEP intends to fund capital expenditures with cash flow from operating activities and borrowings under its revolving credit facility, if needed . The Company plans to allocate capital to higher return plays and to its core dry gas plays as necessary to generate profitable growth while maintaining a competitive cost structure. As a result of the continued spread between oil and natural gas prices, QEP has allocated over 40% of its forecasted 2011 capital expenditures to oil and liquids-rich natural gas projects in its portfolio and reduced the allocation of its capital expenditures to dry natural gas plays. The Company has budgeted approximately $1,200.0 million for capital expenditures in 2011 (excluding acquisitions), of which it has allocated $1,050.0 million to QEP Energy, with approximately 25% targeted for each of the following: (i) plays in the Rockies, including the Bakken and Three Forks formations in North Dakota, the Sussex play in the Powder River Basin of Wyoming and other Rockies oil and liquids-rich gas plays; (ii) Midcontinent liquid rich gas plays; (iii) the Pinedale Anticline and (iv) the Haynesville shale. QEP plans to invest approximately $150 million in capital expenditures to grow its midstream business, including the completion of its Black Fork 2 cryogenic gas processing plant. The aggregate levels of capital expenditures for 2011 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, natural gas and oil prices, industry conditions, the extent to which properties are acquired, the availability of capital resources to fund the expenditures and changes in management’s business assessments as to where QEP’s capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

During the quarter ended March 31, 2011, capital expenditures increased 16% to $314.8 million, which included $22.0 million for leasehold acquisitions, compared to $271.8 million during the same period of 2010. The increase was driven by higher capital investment in development drilling in the Midcontinent and the Rockies Legacy divisions, partially offset by lower investment at QEP Field Services due to the completion of the Iron Horse processing plant in January 2011.

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 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. As energy prices decline or increase significantly, revenues and cash flow significantly decline or increase. In addition, a non-cash write-down of the Company’s oil and gas properties may be required if future oil and natural gas commodity prices experience a sustained, significant decline. A sensitivity analysis of the Company’s commodity-price-related derivative instruments to changes in the price of the underlying commodities is presented below.

Commodity-Price Risk Management

QEP’s subsidiaries use commodity-price derivative instruments in the normal course of business to reduce the risk of adverse commodity-price movements. However, these same arrangements typically limit future gains from favorable price movements. The Company’s risk-management policies provide for the use of derivative instruments to manage this risk. The types of commodity derivative instruments utilized by the Company include fixed-price swaps, price collars, and basis-only swaps. The volume of commodity derivative instruments utilized by the Company may vary from year to year. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or its counterparties in order to satisfy these margin requirements. The derivative instruments currently utilized by the Company do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates.

As of March 31, 2011, QEP held commodity-price derivative contracts covering about 239.6 million MMBtu of natural gas and 1.6 million barrels of oil. A year earlier, the QEP derivative contracts covered 367.4 million MMBtu of natural gas, 2.3 million barrels of oil. Changes in the fair value of derivative contracts from December 31, 2010 to March 31, 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		(76.5	)		31.1			(45.4	)
Change in gas and oil prices on futures markets		1.9			—			1.9
Contracts added		(1.7	)		—			(1.7	)

Net fair value of gas- and oil-derivative contracts outstanding at March 31, 2011	$	279.9		$	(86.6	)	$	193.3

A table of the net fair value of gas- and oil-derivative contracts as of March 31, 2011, is shown below. Derivatives representing about 64% of the net fair value will settle in the next 12 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 March 31, 2012	$	179.5	$	(86.6	)	$	92.9
Contracts maturing between April 1, 2012 and March 31, 2013		56.8		—			56.8
Contracts maturing between April 1, 2013 and March 31, 2014		43.6		—			43.6
Contracts maturing between April 1, 2014 and March 31, 2015		—		—			—

Net fair value of gas- and oil-derivative contracts outstanding at March 31, 2011	$	279.9	$	(86.6	)	$	193.3

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


	March 31, 2011		December 31, 2010
	(in millions)
Net fair value - asset (liability)	$	193.3	$	238.5
Fair value if market prices of gas and oil and basis differentials decline by 10%		318.5		356.2
Fair value if market prices of gas and oil and basis differentials increase by 10%		83.2		132.1

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $110.1 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $125.2 million. However, a gain or loss would eventually be substantially offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company’s commodity derivative transactions, see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commodity Derivatives Impact under Part I, Item 2 of this Form 10-Q.

Interest-Rate Risk Management

As of March 31, 2011, QEP had $1,078.4 million of fixed-rate long-term debt and $500.0 million of variable-rate long-term debt. QEP had no interest rate derivative instruments at the end of the first quarter of 2011.

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;

•

trends in operations;

•

amount and allocation of forecasted capital expenditures for 2011;

•

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;

•

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 and oil commodity prices;

•

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

•

changes in industry trends;

•

changes in laws or regulations; and

•

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

QEP undertakes no obligation to publicly correct or update the forward-looking statements in this quarterly report, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

ITEM 4.

CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures.

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of March 31, 2011. Based on such evaluation, such officers have concluded that, as of March 31, 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 March 31, 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.

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

Environmental Claims

United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah. The U.S. Environmental Protection Agency (EPA) alleges that QEP Field Services (f/k/a Questar Gas Management) violated the Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for these facilities renders them “major sources” of emissions for criteria and hazardous air pollutants even though controls were installed. Categorization of the facilities as “major sources” affects the particular regulatory program and requirements applicable to those facilities. EPA claims that QEP Field Services failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations for testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed that reduce their actual air emissions below

major source thresholds, rendering them subject to different regulatory requirements applicable to non-major sources. QEP Field Services has vigorously defended EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying Utah’s CAA program or EPA’s prior permitting practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all reasonably possible outcomes; however, management believes the Company has accrued a reasonable loss contingency that is an immaterial amount, for the anticipated most likely outcome. The Ute Indian Tribe and individual members of its Business Committee have now intervened as co-plaintiffs asserting the same CAA claims as the federal government.

QEP Energy v. U.S. Environmental Protection Agency, No. 09-9538, U.S. Court of Appeals for the 10^th Circuit. On July 10, 2009 QEP Energy filed a petition with the U.S. 10^th Circuit Court of Appeals challenging an administrative compliance order dated May 12, 2009 (Order), issued by EPA which asserts that QEP Energy’s Flat Rock 14P well in the Uinta Basin and associated equipment is a major source of hazardous air pollutants and its operation fails to comply with certain regulations of the CAA. The Order required immediate compliance. QEP Energy denies that the drilling and operation of the 14P well and associated equipment violates any provisions of the CAA and intends to vigorously defend this claim.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

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

ITEM 3.

EXHIBITS.

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


Exhibit No.		Exhibits

12.1		Ratio of Earnings to Fixed Charges

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.

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)

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

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


Exhibit No.		Exhibits

12.1		Ratio of Earnings to Fixed Charges

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.

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