10-Q

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, 2012

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

For the transition period from to

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)

STATE OF DELAWARE	001-34778	87-0287750
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

1050 17th Street, Suite 500, Denver, Colorado 80265

(Address of principal executive offices)

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

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

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

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

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

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

At March 31, 2012, there were 178,386,261 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended March 31, 2012

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION			1
	ITEM 1.	FINANCIAL STATEMENTS	1
		CONDENSED CONSOLIDATED STATEMENTS OF INCOME	1
		CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	2
		CONDENSED CONSOLIDATED BALANCE SHEETS	3
		CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	4
		NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	5
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36
	ITEM 4.	CONTROLS AND PROCEDURES	40
PART II. OTHER INFORMATION			40
	ITEM 1.	LEGAL PROCEEDINGS	40
	ITEM 1A.	RISK FACTORS	41
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	41
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	41
	ITEM 4.	MINE SAFETY DISCLOSURES	41
	ITEM 5.	OTHER INFORMATION	41
	ITEM 6.	EXHIBITS	41
SIGNATURES			42

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2012			2011
	(in millions, except per share amounts)
REVENUES
Natural gas sales	$	161.2		$	312.6
Oil sales		110.8			63.0
NGL sales		97.4			47.9
Gathering, processing and other		49.8			46.6
Purchased gas and oil sales		184.0			147.8
Total Revenues		603.2			617.9
OPERATING EXPENSES
Purchased gas and oil expense		188.4			146.7
Lease operating expense		40.1			32.8
Natural gas, oil and NGL transportation and other handling costs		34.5			21.7
Gathering, processing and other		23.7			25.2
General and administrative		36.0			31.7
Production and property taxes		24.7			23.7
Depreciation, depletion and amortization		199.2			190.8
Exploration expenses		2.0			2.8
Abandonment and impairment		6.6			5.4
Total Operating Expenses		555.2			480.8
Net gain from asset sales		1.5			-
OPERATING INCOME		49.5			137.1
Realized and unrealized gains on commodity derivative contracts (See Note 7)		216.3			-
Interest and other income		1.7			0.6
Income from unconsolidated affiliates		1.9			0.9
Interest expense		(24.7	)		(22.1	)
INCOME BEFORE INCOME TAXES		244.7			116.5
Income taxes		(88.7	)		(42.7	)
NET INCOME		156.0			73.8
Net income attributable to noncontrolling interest		(0.8	)		(0.6	)
NET INCOME ATTRIBUTABLE TO QEP	$	155.2		$	73.2
Earnings Per Common Share Attributable to QEP
Basic total	$	0.87		$	0.42
Diluted total	$	0.87		$	0.41
Weighted-average common shares outstanding
Used in basic calculation		177.4			176.2
Used in diluted calculation		178.5			178.3
Dividends per common share	$	0.02		$	0.02

See notes accompanying the condensed consolidated financial statements.

1

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
	2012			2011
	(in millions)
Net income	$	156.0		$	73.8
Other comprehensive income (loss), net of tax:
Reclassification of previously deferred derivative gains and losses to net income (1)		(47.0	)		(47.8	)
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss (2)		0.1			-
Amortization of prior service cost (3)		0.9			-
Total pension and other postretirement plans adjustments		1.0			-
Other comprehensive income		(46.0	)		(47.8	)
Comprehensive income		110.0			26.0
Comprehensive income attributable to noncontrolling interests		(0.8	)		(0.6	)
Comprehensive income attributable to QEP	$	109.2		$	25.4

(1) Presented net of income tax benefit of $27.8 million and $28.3 million during the three months ended March 31, 2012 and 2011, respectively.

(2) Presented net of income tax expense of $0.1 million during the three months ended March 31, 2012.

(3) Presented net of income tax expense of $0.5 million during the three months ended March 31, 2012.

See notes accompanying the condensed consolidated financial statements.

2

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
	2012			2011
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	-		$	-
Accounts receivable, net		303.5			397.4
Fair value of derivative contracts		333.8			273.7
Inventories, at lower of average cost or market
Gas, oil and NGL		10.9			16.2
Materials and supplies		86.6			87.6
Prepaid expenses and other		40.6			43.7
Total Current Assets		775.4			818.6
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties		8,468.3			8,172.4
Unproved properties, not being depleted		316.0			326.8
Midstream field services		1,510.8			1,463.6
Marketing and other		51.6			49.8
Total Property, Plant and Equipment		10,346.7			10,012.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production		3,519.9			3,339.2
Midstream field services		312.2			297.5
Marketing and other		15.5			14.6
Total Accumulated Depreciation, Depletion and Amortization		3,847.6			3,651.3
Net Property, Plant and Equipment		6,499.1			6,361.3
Investment in unconsolidated affiliates		42.6			42.2
Goodwill		59.5			59.5
Fair value of derivative contracts		115.6			123.5
Other noncurrent assets		40.9			37.6
TOTAL ASSETS	$	7,533.1		$	7,442.7
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	58.6		$	29.4
Accounts payable and accrued expenses		380.7			457.3
Production and property taxes		43.5			40.0
Interest payable		8.9			24.4
Fair value of derivative contracts		-			1.3
Deferred income taxes		57.6			85.4
Total Current Liabilities		549.3			637.8
Long-term debt		1,673.5			1,679.4
Deferred income taxes		1,554.5			1,484.7
Asset retirement obligations		167.7			163.9
Fair value of derivative contracts		0.1			-
Other long-term liabilities		130.3			124.8
Commitments and contingencies
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 178.4 million and 177.2 million shares issued, respectively		1.8			1.8
Treasury stock - 0.7 million and 0.4 million shares, respectively		(23.4	)		(13.1	)
Additional paid-in capital		442.6			431.4
Retained earnings		2,825.1			2,673.5
Accumulated other comprehensive income		161.9			207.9
Total Common Shareholders' Equity		3,408.0			3,301.5
Noncontrolling interest		49.7			50.6
Total Equity		3,457.7			3,352.1
TOTAL LIABILITIES AND EQUITY	$	7,533.1		$	7,442.7

See notes accompanying the condensed consolidated financial statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
	2012			2011
	(in millions)
OPERATING ACTIVITIES
Net income	$	156.0		$	73.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		199.2			190.8
Deferred income taxes		69.1			40.0
Abandonment and impairment		6.6			5.4
Share-based compensation		5.7			7.4
Amortization of debt issuance costs and discounts		1.1			0.8
Dry exploratory well expense		0.1			0.6
Net gain from asset sales		(1.5	)		-
Income from unconsolidated affiliates		(1.9	)		(0.9	)
Distributions from unconsolidated affiliates and other		1.6			1.8
Unrealized gain on derivative contracts		(128.3	)		(31.2	)
Changes in operating assets and liabilities		20.8			10.9
Net Cash Provided by Operating Activities		328.5			299.4
INVESTING ACTIVITIES
Property acquisitions		(1.4	)		(22.1	)
Property, plant and equipment, including dry exploratory well expense		(336.5	)		(320.4	)
Proceeds from disposition of assets		3.3			0.9
Net Cash Used in Investing Activities		(334.6	)		(341.6	)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances		29.2			5.9
Long-term debt issued		500.0			-
Long-term debt issuance costs paid		(6.9	)		-
Current portion long-term debt repaid		-			(58.5	)
Proceeds from credit facility		120.0			200.0
Repayments of credit facility		(626.0	)		(100.0	)
Other capital contributions		(6.9	)		(0.8	)
Dividends paid		(3.6	)		(3.5	)
Excess tax benefit on share-based compensation		2.0			0.4
Distribution from Questar		-			0.2
Distribution to noncontrolling interest		(1.7	)		(1.5	)
Net Cash Provided by Financing Activities		6.1			42.2
Change in cash and cash equivalents		-			-
Beginning cash and cash equivalents		-			-
Ending cash and cash equivalents	$	-		$	-
Supplemental Disclosures:
Cash paid for interest	$	39.6		$	44.2
Cash paid (received) for income taxes		(2.6	)		(10.8	)
Increase (decrease) in non-cash capital expenditure accruals		3.5			(27.7	)

See notes accompanying the condensed consolidated financial statements.

4

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Nature of Business

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

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

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

• QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil, provides risk–management services, and owns and operates an underground gas-storage reservoir.

Operations are focused in the Northern Region (Rockies) and Southern Region (primarily Oklahoma, Louisiana, and the Texas Panhandle) of the United States. Company headquarters are located 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 United States Generally Accepted Accounting Principles (GAAP) and with the instructions for quarterly reports on Form 10-Q and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.

The condensed consolidated financial statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

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, 2012, are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

De-designation of commodity derivative contracts

Effective January 1, 2012, QEP elected to discontinue hedge accounting prospectively. Accordingly, all realized and unrealized gains and losses will be recognized in earnings immediately each quarter as derivative contracts are settled and marked-to-market. For the first quarter of 2012 unrealized gains of $128.3 million were included in income that prior to January 1, 2012 would have been deferred in accumulated other comprehensive income under hedge accounting. Refer to Note 7 for additional information.

5

Transportation and other handling costs

In the fourth quarter of 2011, QEP revised its reporting of transportation and handling costs to reflect revenues in accordance with industry practice and GAAP. Transportation and handling costs, previously netted against revenues, have been recast on the Condensed Consolidated Income Statement from revenues to “Natural gas, oil and NGL transportation and other handling costs” for prior periods presented. The impact of this revision is immaterial to the accompanying financial statements and has no effect on income from continuing operations, net income, or earnings per share. The following table details the impact for the three months ended March 31, 2011, on the Condensed Consolidated Income Statement.

	As reported (1)		As revised		Change
	(in millions)
REVENUES
Natural gas sales	$	271.0	$	312.6	$	41.6
Oil sales		62.3		63.0		0.7
NGL sales		45.8		47.9		2.1
Gathering, processing and other		69.3		46.6		(22.7	)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		-		21.7		21.7

(1) In addition to the revision described above, QEP Field Services NGL sales of $28.6 million in the first quarter of 2011 have been reclassified from “Gathering, processing and other” into “NGL sales” in the as reported column to be consistent with current period presentation. QEP reported NGL sales of $17.2 million and Gathering, processing and other of $97.9 million in its first quarter 2011 Form 10-Q. The reclassification is all within Revenues and has no effect on income from continuing operations, net income or earnings per share.

Oil, Natural Gas, and NGL prices

Historically, field-prices received for QEP’s natural gas, NGL, and crude oil production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than natural gas demand, driven by advances in technology, including horizontal drilling combined with multi-stage hydraulic fracturing, which have allowed producers to extract increasing amounts of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supply has put downward pressure on natural gas prices, while concern about the global economy and other factors has created volatility in the price of crude oil. Changes in the market prices for natural gas, crude oil, and NGL directly impact many aspects of QEP’s business, including its financial condition, revenues, results of operations, planned drilling activity and related capital expenditures, liquidity, rate of growth, costs of goods and services required to drill and complete wells, and the carrying value of its oil and natural gas properties.

New accounting pronouncements

In December of 2011, the FASB issued ASU 2011-11, which enhances disclosure requirements regarding an entity’s financial instruments and derivative instruments that are offset or subject to a master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial statements to understand the effect of those arrangements on the entity’s financial position, including the effect of rights of setoff. The amendments are required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. QEP is evaluating the impact of this ASU on its disclosure requirements.

Note 3 – Earnings Per Share

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

Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company’s unvested restricted stock awards contain nonforfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company’s unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company’s unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, the two class method will not have an effect on the Company’s basic earnings per share. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share.

6

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

	Three Months Ended
	March 31,
	2012		2011
	(in millions)
Weighted-average basic common shares outstanding		177.4		176.2
Potential number of shares issuable under the Long-term Stock Incentive Plan		1.1		2.1
Average diluted common shares outstanding		178.5		178.3

Note 4 – 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 from asset sales” in the Condensed Consolidated Statements of Income. Changes in ARO were as follows:

	Asset Retirement Obligations
	2012			2011
	(in millions)
ARO liability at January 1,	$	163.9		$	148.3
Accretion		2.5			2.3
Liabilities incurred		1.6			2.0
Liabilities settled		(0.3	)		(0.2	)
ARO liability at March 31,	$	167.7		$	152.4

Note 5 – Capitalized Exploratory Well Costs

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

	Capitalized Exploratory Well Costs
	2012		2011
	(in millions)
Balance at January 1,	$	5.0	$	13.6
Additions to capitalized exploratory well costs pending the determination of proved reserves		-		-
Reclassifications to property, plant and equipment after the determination of proved reserves		-		(5.5	)
Balance at March 31,	$	5.0	$	8.1

Note 6 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures”. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements, but does not change existing guidance as to whether or not an instrument is carried at fair value. ASC 820 also establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. At March 31, 2012, the Company does not have Level 1 fair value measurements since it uses a broker to access the futures market. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. QEP’s Level 2 fair value measurements consist of fixed-price swaps of natural gas, oil and NGL. Level 3 inputs are unobservable inputs for the asset or liability. QEP’s Level 3 measurements are made up of costless collars for natural gas and oil. The Level 2 fair value of derivative contracts (see Note 7 “Derivative Contracts”) 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 computed by QEP’s risk management group using the Black-Scholes option pricing model with observable inputs from the NYMEX futures prices, LIBOR one year interest rates, credit default swap rates, and unobservable input of volatility computed from historical prices using the Black-Scholes model.

7

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

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

QEP did not have any assets or liabilities measured at fair value on a non-recurring basis, other than ARO’s and property, plant and equipment values for purposes of determining the impairment calculation, at March 31, 2012, or at December 31, 2011. The fair value of financial assets and financial liabilities at March 31, 2012, is shown in the table below:

	Fair Value Measurements
	March 31, 2012
	Level 2		Level 3		Netting Adjustments			Total
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	347.5	$	-	$	(13.7	)	$	333.8
Commodity derivative instruments - long-term		115.8		-		(0.2	)		115.6
Total financial assets	$	463.3	$	-	$	(13.9	)	$	449.4
Financial Liabilities
Commodity derivative instruments - short-term	$	11.6	$	2.1	$	(13.7	)	$	-
Commodity derivative instruments - long-term		0.3		-		(0.2	)		0.1
Total financial liabilities	$	11.9	$	2.1	$	(13.9	)	$	0.1

The change in the fair value of Level 3 commodity derivative instruments assets and liabilities for the three months ended March 31, 2012, is shown below:

	Change in Level 3 Fair Value Measurements
	2012			2011
	(in millions)
Balance at January 1,	$	-		$	36.3
Realized gains and losses		-			17.9
Unrealized gains and losses		(2.1	)		(13.1	)
Settlements		-			(17.9	)
Balance at March 31,	$	(2.1	)	$	23.2

8

The fair value of financial assets and financial liabilities at December 31, 2011, is shown in the table below:

	Fair Value Measurements
	December 31, 2011
	Level 2		Level 3		Netting Adjustments			Total
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	284.1	$	-	$	(10.4	)	$	273.7
Commodity derivative instruments - long-term		123.5		-		-			123.5
Total financial assets	$	407.6	$	-	$	(10.4	)	$	397.2
Financial Liabilities
Commodity derivative instruments - short-term	$	11.7	$	-	$	(10.4	)	$	1.3
Commodity derivative instruments - long-term		-		-		-			-
Total financial liabilities	$	11.7	$	-	$	(10.4	)	$	1.3

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

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	March 31, 2012				December 31, 2011
	(in millions)
Financial assets
Cash and cash equivalents	$	-	$	-	$	-	$	-
Financial liabilities
Checks outstanding in excess of cash balances	$	58.6	$	58.6	$	29.4	$	29.4
Long-term debt		1,673.5		1,770.8		1,679.4		1,754.9

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 7 – Derivative Contracts

QEP uses commodity price derivative instruments in the normal course of business. QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. 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 instruments typically limit future gains from favorable price movements. The volume of production subject to derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into derivative contracts for up to 100% of forecasted production from proved reserves. QEP does not enter into derivative instruments for speculative purposes.

QEP uses derivative instruments known as fixed-price swaps and costless collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Costless collars are combinations of put and call options that have a floor price and a ceiling price and payments are made or received only if the settlement price is outside the range between the floor and ceiling prices. QEP’s derivative instruments do not require the physical delivery of natural gas, crude oil, or NGL between the parties at settlement. Swap and costless collar transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Natural gas price derivative instruments are typically structured as fixed-price swaps at regional price indices. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma. NGL price derivative instruments are typically structured as Mont Belvieu, Texas fixed-price swaps.

QEP enters into derivative transactions that do not have margin requirements or collateral provisions that would require payments prior to the scheduled 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 avoids concentration of credit exposure by transacting with multiple counterparties.

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All derivative instruments are recorded on the Condensed Consolidated Balance Sheets as either assets or liabilities measured at their fair values. Reporting changes in the fair value of derivatives depend upon whether the derivative instrument has been designated as a cash flow hedge and 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. Through December 31, 2011, QEP designated most of its natural gas, oil and NGL derivative contracts as cash flow hedges, whose unrealized fair value gains and losses were recorded to Accumulated Other Comprehensive Income (AOCI). Effective January 1, 2012, QEP elected to de-designate all of its natural gas, oil and NGL derivative contracts that had previously been designated as cash flow hedges and discontinue hedge accounting prospectively. As a result, as of January 1, 2012, QEP will recognize all gains and losses from changes in the fair value of natural gas, oil and NGL derivative contracts immediately in earnings rather than deferring any such amounts in AOCI. At December 31, 2011, AOCI consisted of $395.9 million ($248.6 million after tax) of unrealized gains, representing the mark-to-market value of QEP’s cash flow hedges at December 31, 2011, less any ineffectiveness recognized. As a result of discontinuing hedge accounting on January 1, 2012, the mark-to-market values at December 31, 2011 are frozen in AOCI as of the de-designation date and will be reclassified into the statement of income in future periods as the original hedged transactions occur and effect earnings. QEP expects to reclassify into earnings from AOCI the frozen value related to de-designated natural gas, oil and NGL hedges during the remainder of 2012 and in 2013. In addition, in connection with QEP’s election to discontinue hedge accounting, all realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012 will be presented in the statement of income in “Realized and unrealized gains on commodity derivative contracts” below operating income.

QEP derivative contracts as a percentage of reported production

The following table details the percentage of reported production subject to commodity price derivative contracts for QEP Energy and QEP Field Services.

	Three Months Ended
	March 31,
	2012			2011
QEP Energy
Natural gas derivative volumes as a percent of QEP Energy natural gas production
Fixed price swaps		60	%		43	%
Costless collars		0	%		12	%
Oil derivative volumes as a percent of QEP Energy oil production
Fixed price swaps		37	%		0	%
Costless collars		15	%		35	%
NGL derivative volumes as a percent of QEP Energy NGL production
Fixed price swaps		16	%		0	%
Costless collars		0	%		0	%
QEP Field Services
Ethane derivative volumes as a percent of ethane volumes - QEP Field Services
Fixed price swaps		13	%		0	%
Propane derivative volumes as a percent of propane volumes - QEP Field Services
Fixed price swaps		71	%		0	%

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QEP Energy Outstanding Derivative Contracts

The following table sets forth QEP Energy’s volumes and average prices for its commodity derivative contracts as of March 31, 2012:

					Swaps		Collars
Year	Type of Contract	Index	Total Volumes		Average price per unit		Floor price		Ceiling price
			(in millions)
Natural gas sales			(MMBtu)
2012	Swap	NYMEX		57.8	$	4.72
2012	Swap	IFPEPL (1)		6.1		4.47
2012	Swap	IFNPCR (2)		65.4		4.69
2012	Swap	IFCNPTE (3)		7.7		2.67
2013	Swap	NYMEX		29.2		3.68
2013	Swap	IFNPCR (2)		65.7		5.66
Oil sales			(Bbls)
2012	Swap	NYMEX WTI		1.4	$	97.03
2012	Collar	NYMEX WTI		1.1			$	87.50	$	115.36
2013	Swap	NYMEX WTI		0.2		105.80
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		11.6	$	0.64
2012	Swap	Mt. Belvieu Propane		17.3	$	1.28

(1) Inside FERC monthly settlement index for the Panhandle Eastern Pipeline Company.

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

(3) Inside FERC monthly settlement index for Centerpoint East.

QEP Field Services Outstanding Derivative Contracts

QEP Field Services enters into commodity derivative transactions to manage price risk on extracted NGL volumes. The following table sets forth QEP Field Services’ volumes and swap prices for its commodity derivative contracts as of March 31, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swap price per gallon
			(in millions)
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		11.6	$	0.64
2012	Swap	Mt. Belvieu Propane		9.6	$	1.35

QEP Marketing Outstanding Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage and to lock in a fixed price for some of its customers. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of March 31, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swaps price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2012	Swaps	IFNPCR (1)		1.7	$	4.15
2013	Swaps	IFNPCR (1)		1.2		4.57
Natural gas purchases			(MMBtu)
2012	Swaps	IFNPCR (1)		1.1	$	2.80

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

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

		Gross asset derivative  instruments fair value					Gross liability derivative  instruments fair value
	Balance Sheet line item	March 31, 2012		December 31, 2011		Balance Sheet line item	March 31, 2012		December 31, 2011
		(in millions)					(in millions)
Current
Commodity	Fair value of derivative contracts	$	347.5	$	284.1	Fair value of derivative contracts	$	13.7	$	11.7
Long-term:
Commodity	Fair value of derivative contracts		115.8		123.5	Fair value of derivative contracts		0.3		-
Total commodity derivative instruments		$	463.3	$	407.6		$	14.0	$	11.7

The effects and location of derivative transactions on the Condensed Consolidated Income Statements are summarized in the following tables.

		Three Months Ended March 31,
Derivatives not designated as hedging instruments	Location of gain (loss) recognized in earnings	2012			2011
		(in millions)
Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		$	85.7		$	(31.2	)
Oil derivative contracts			(2.7	)		-
NGL derivative contracts			0.4			-
QEP Field Services
NGL derivative contracts			1.1			-
QEP Marketing
Natural gas derivative contracts			3.5			-
Total realized gain (loss)	Realized and unrealized gains on commodity derivative instruments		88.0			(31.2	)

Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts			132.3			31.2
Oil derivative contracts			(11.5	)		-
NGL derivative contracts			2.9			-
QEP Field Services
NGL derivative contracts			3.0			-
QEP Marketing
Natural gas derivative contracts			1.6			-
Total unrealized gain (loss)	Realized and unrealized gains on commodity derivative instruments		128.3			31.2
Total realized and unrealized gain (loss)	Realized and unrealized gains on commodity derivative instruments	$	216.3		$	-

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		Three Months Ended March 31,
Cash flow hedge derivative instruments	Location of gain (loss) recognized in earnings	2012		2011
Commodity derivatives			(in millions)
Gain (loss) on derivative instruments for the effective portion of hedge recognized in AOCI	Accumulated other comprehensive income (loss)	$	-	$	0.2
Gain (loss) reclassified from AOCI into income for effective portion of hedge	Natural gas sales		-		73.1
Gain (loss) reclassified from AOCI into income for effective portion of hedge	Oil sales		-		-
Gain (loss) reclassified from AOCI into income for effective portion of hedge	NGL sales		-		-
Gain (loss) reclassified from AOCI into income for effective portion of hedge	Marketing purchases		-		3.4
Gain (loss) recognized in income for the ineffective portion of hedges	Interest and other income		-		(0.2	)

It is estimated that derivative contracts that had a fair value at December 31, 2011 of $144.2 million will be settled and reclassified from AOCI to the Condensed Consolidated Statements of Income during the next twelve months.

Note 8 – Restructuring Costs

During the first quarter of 2012, QEP announced the closure of its Oklahoma City office and consolidation of its two division offices in Oklahoma into one regional office in Tulsa. The creation of one office for QEP’s Southern Region will increase QEP’s efficiency, collaboration, and productivity over the long-term. As part of the restructuring plan and closure of the Oklahoma City office, the Company will incur costs associated with the severance and relocation of employees and other exit costs associated with the termination of the operating lease of its Oklahoma City office space. All costs will be incurred by QEP Energy and are reported within QEP Energy’s financial statements. QEP anticipates total restructuring costs to be approximately $5.8 million, with $1.7 million of those costs relating to one-time termination benefits, $3.6 million relating to the retention and relocation of certain employees to the Tulsa office, and the remaining $0.5 million for the termination of the lease for the Oklahoma City office space. During the three months ended March 31, 2012, a total of $2.7 million of restructuring costs were incurred and recorded in “General and administrative” expense on the Condensed Consolidated Income Statement, of which $1.1 million related to one-time termination benefits. The remaining one-time termination benefits will be recognized ratably over the remaining transition period. QEP expects to recognize the remaining costs not yet incurred in the remainder of 2012. The relocation costs and contract termination costs will be recorded in future periods as the costs are incurred. The following is a reconciliation of QEP Energy’s restructuring liability, which is included within “Accounts payable and accrued expenses” on the Condensed Consolidated Balance Sheets.

	Restructuring Costs
	(in millions)
Balance at December 31, 2011	$	-
Costs incurred and charged to expense		2.7
Costs paid or otherwise settled		(2.4	)
Balance at March 31, 2012	$	0.3

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Note 9 – Debt

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

	March 31,			December 31,
	2012			2011
	(in millions)
Revolving Credit Facility	$	100.5		$	606.5
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
5.375% Senior Notes due 2022		500.0			-
Total principal amount of debt		1,678.9			1,684.9
Less unamortized discount		(5.4	)		(5.5	)
Total long-term debt outstanding	$	1,673.5		$	1,679.4

Of the total debt outstanding on March 31, 2012, the $100.5 million drawn under the revolving credit facility (described below) due August 25, 2016, and the 6.05% Senior Notes due September 1, 2016, will mature within the next five years.

Credit Arrangements

QEP’s revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a syndicate of financial institutions. The revolving credit facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The revolving credit agreement also contains provisions that would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for up to two additional one-year periods. During the first quarter of 2012, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.06%. At March 31, 2012, and December 31, 2011, QEP was in compliance with all of its debt covenants. At March 31, 2012 QEP had $100.5 million drawn and $4.1 million in letters of credit outstanding under the credit facility.

Senior Notes

During the first quarter of 2012, the Company issued $500 million of Senior Notes due October 2022, with a coupon of 5.375%. The senior notes were issued at face value. Interest on the senior notes will be paid semi-annually, in April and October of each respective year. The net proceeds of approximately $493.0 million were used to repay indebtedness under QEP Resources’ revolving credit facility. The finance costs incurred of approximately $7.0 million will be deferred and amortized over the life of the senior notes. The amortization of all of the Company’s deferred finance costs is included in “Interest expense” on the Condensed Consolidated Income Statement.

At March 31, 2012, the Company has $1,578.4 million principal amount of senior notes outstanding with maturities ranging from September 2016 to October 2022 and coupons ranging from 5.375% to 6.875%. The senior notes pay interest semi-annually, are unsecured, senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indenture governing QEP’s senior notes contains customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

See Note 14 for additional information regarding the term loan agreement entered into after the balance sheet date.

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Note 10 – Contingencies

QEP is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company’s financial position, results of operations or cash flows. In accordance with ASC 450, 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 or the minimum amount within a range of possible outcomes. The Company believes that the exposure to potential losses from its contingencies deemed as probable is immaterial. For claims deemed reasonably possible the Company does not have a range of potential exposure as an estimate cannot be made because the cases are in their early stages or have a large number of plaintiffs. Disclosures are provided for contingencies reasonably possible to occur which would have a material adverse effect on the Company’s financial position, results of operations or cash flows but have not yet been accrued. Some of the claims involve numerous plaintiffs, 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. The following discussion describes the nature of QEP’s major loss contingencies.

Environmental Claims

United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah filed on February 28, 2008. The U.S. Environmental Protection Agency (EPA) alleges that QEP Field Services (f/k/a Questar Gas Management) violated the Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. Individual members of the Ute Indian Tribe’s Business Committee intervened as co-plaintiffs asserting the same CAA claims as the federal government. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for these facilities renders them “major sources” of emissions for criteria and hazardous air pollutants even though controls were installed and operated by QEP Field Services. Categorization of the facilities as “major sources” affects the particular regulatory program and requirements applicable to those facilities. EPA claims that QEP Field Services failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air pollutant regulations for monitoring, testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed, as part of their operational design, that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements applicable to non-major sources. QEP Field Services has vigorously defended itself against EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying EPA’s prior permitting practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all probable outcomes; however, management believes the Company has accrued an estimated loss contingency that is an immaterial amount, for the anticipated most likely outcome.

Litigation

Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for Oklahoma filed on January 20, 2011. This is a class action filed by a royalty owner on behalf of every QEP Energy royalty owner in the state of Oklahoma since 1988 asserting various claims for damages related to royalty valuation, including breach of contract, breach of fiduciary duty, fraud and conversion, based generally on asserted improper deduction of post-production costs. Because this case is in an early stage prior to full discovery, it is difficult to reasonably estimate potential liability. QEP Energy believes it has properly valued and paid royalty under Oklahoma law and will vigorously defend this claim. Because of the complexities and uncertainties of this legal dispute and the number of plaintiffs, it is difficult to predict all reasonably possible outcomes; however, management believes, at this early litigation stage, the potential loss contingency is an immaterial amount.

Note 11 – Share-Based Compensation

QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance-based share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over time as the stock options, restricted shares, and performance based share units vest. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 13.2 million shares available for future grants under the LTSIP at March 31, 2012. Share-based compensation expense is recognized in “General and administrative” on the Condensed Consolidated Income Statements. During the three months ended March 31, 2012 and 2011, QEP recognized $5.7 million and $7.4 million, respectively, in total compensation expense related to share-based compensation.

15

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for measuring the value of options traded on an exchange. The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:

	Stock Option Variables Three Months Ended March 31, 2012
Fair value of options at grant date	$	14.49
Risk-free interest rate		0.81	%
Expected price volatility		55.9	%
Expected dividend yield		0.26	%
Expected life in years		5.0

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

	Options Outstanding			Weighted- Average Price		Weighted-Average Remaining Contractual Term		Aggregate Intrinsic Value
				(per share)		(in years)		(in millions)
Outstanding at December 31, 2011		2,003,694		$	21.23
Granted		283,029			30.90
Exercised		(313,342	)		8.15
Forfeited		-			-
Outstanding at March 31, 2012		1,973,381		$	24.69		3.8	$	13.3
Options Excercisable at March 31, 2012		1,393,956		$	22.08		3.0	$	12.4
Unvested Options at March 31, 2012		579,425		$	30.97		6.0	$	0.9

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $6.9 million and $1.8 million during the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $5.4 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.6 years.

Restricted Shares

Restricted share grants typically vest in equal installments over a three or four-year period from the grant date. The total fair value of restricted stock that vested was $11.6 million and $7.9 million during the three months ended March 31, 2012 and 2011, respectively. The weighted average grant-date fair value of restricted stock was $30.89 per share and $39.00 per share for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $30.0 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.6 years. Transactions involving restricted shares under the terms of the LTSIP are summarized below:

	Restricted Shares Outstanding			Weighted- Average Price
				(per share)
Unvested balance at December 31, 2011		1,099,752		$	32.80
Granted		659,370			30.89
Vested		(362,743	)		32.85
Forfeited		(31,036	)		32.89
Unvested balance at March 31, 2012		1,365,343		$	31.87

Performance Share Units

Cash payouts are dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units but delivered in cash at the end of the performance period. The weighted average grant-date fair value of the performance share units was $30.90 per share and $39.07 per share for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $4.4 million of unrecognized compensation cost, or the fair market value, related to performance shares granted under the CIP is expected to be recognized over a weighted-average vesting period of 2.6 years. Transactions involving performance shares units under the terms of the CIP are summarized below:

16

	Performance Share Units Outstanding			Weighted- Average Price
Unvested balance at December 31, 2011		115,274		$	39.07
Granted		168,448			30.90
Vested		-			-
Forfeited		(2,707	)		39.07
Unvested balance at March 31, 2012		281,015		$	34.17

Note 12 – Employee Benefits

The Company has both qualified and supplemental plans defined-benefit pension plans. The Company also has postretirement benefits that provide certain health care and life insurance benefits for certain retired employees. During the three months ended March 31, 2012, the Company made contributions of $1.3 million to its funded pension plan, and $1.0 million to its unfunded pension plan. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. During the remainder of 2012, the Company expects to contribute approximately $5.0 million to its funded pension plans, and approximately $0.3 million to its unfunded pension plans. The following table sets forth the Company’s pension and postretirement benefits net period benefit costs:

	Pension						Postretirement benefits
	Three Months Ended March 31,						Three Months Ended March 31,
	2012			2011			2012		2011
	(in millions)
Service cost	$	1.0		$	0.7		$	-	$	-
Interest cost		1.2			1.1			0.1		0.1
Expected return on plan assets		(0.9	)		(0.6	)		-		-
Amortization of prior service costs		1.3			1.3			0.1		0.1
Amortization of actuarial loss		0.2			-			-		-
Periodic expense	$	2.8		$	2.5		$	0.2	$	0.2

Note 13 – Operations by Line of Business

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

17

	Three Months Ended
	March 31,
	2012			2011
	(in millions)
Revenues from unaffiliated customers (1) (2)
QEP Energy	$	396.8		$	396.2
QEP Field Services		93.6			73.3
QEP Marketing and other		112.8			148.4
Total	$	603.2		$	617.9
Revenues from affiliated companies
QEP Field Services	$	26.1		$	23.3
QEP Marketing and other		132.3			133.1
Total	$	158.4		$	156.4
Operating (loss) income (2)
QEP Energy	$	(12.9	)	$	87.9
QEP Field Services		66.0			47.3
QEP Marketing and other		(3.6	)		1.9
Total	$	49.5		$	137.1
Net income attributable to QEP
QEP Energy	$	108.1		$	43.1
QEP Field Services		45.4			28.0
QEP Marketing and other		1.7			2.1
Total	$	155.2		$	73.2

(1) Revenues for the three months ended March 31, 2011 have been recast to reflect QEP’s revised reporting of its transportation and handling costs. See Note 2 “Basis of Presentation of Interim Consolidated Financial Statements” for additional information. In addition, revenues for the three months ended March 31, 2011 reflect the impact of QEP’s settled derivative contracts which during the three months ended March 31, 2012 are reflected below operating income. See Note 7 “Derivative Contracts” for detailed information on derivative contract settlements in the first quarter of 2011.

(2) Operating (loss) income in the first quarter of 2012 excludes the impact of realized commodity derivative contract settlements. During the first quarter of 2012 realized gains and losses from realized commodity derivative contract settlements were included below operating income. Conversely, under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the first quarter of 2011.

(3) Net income attributable to QEP in the first quarter of 2012 includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contract. Conversely, under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the first quarter of 2011.

Note 14 – Subsequent Events

In April 2012, the Company entered into a $300 million senior, unsecured term loan agreement with a group of financial institutions. The term loan agreement provides for borrowings at short-term interest rates and contains covenants, restrictions and interest rates that are substantially the same as the Company’s existing revolving credit agreement. The term loan agreement matures in April of 2017, and the maturity date may be extended one year with the agreement of the lenders. At closing, the Company borrowed $100 million. The Company may borrow the remaining $200 million available under the term loan by June 30, 2012 at which time, any undrawn commitment under the facility will expire.

18

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related notes included in Item 1 of this Quarterly Report on Form 10-Q.

The following information updates the discussion of QEP’s financial condition provided in its 2011 Annual Report on Form 10-K filing and analyzes the changes in the results of operations between the three-month periods ended March 31, 2012 and 2011. 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 2011 Annual Report on Form 10-K.

OVERVIEW

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

• QEP Energy Company (QEP Energy) acquires, explores for, develops and produces natural gas, oil, and natural gas liquids (NGL) in two principal operating regions: the Southern Region of the United States, which includes the Haynesville/Cotton Valley area in northwest Louisiana and the Midcontinent area with properties primarily located in Oklahoma and Texas, and the Northern Region of the United States, which includes the Pinedale Anticline in western Wyoming, the Uinta Basin in eastern Utah, and the Rockies Legacy, which includes the Bakken/Three Forks area in western North Dakota and other properties primarily in Wyoming, Colorado and New Mexico;

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

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

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:

• Operate in a safe and environmentally responsible manner

• 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 plays in which we operate

• Build contiguous acreage positions to drive efficiencies

• Be the operator of our assets whenever possible

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

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

• Build gas processing plants to extract liquids from our gas streams

• Gather, compress and treat our production to drive down costs

• Actively market our QEP Energy production to maximize value

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

• Attract and retain the best people

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

Outlook

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

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While predominantly a natural gas producer, the Company has increased its focus on growing the relative proportion of crude oil and NGL production in its exploration and production business. QEP Energy oil and NGL production increased by approximately 113% in the first quarter of 2012 compared with the first quarter of 2011. In the first quarter of 2012 oil and NGL revenue accounted for approximately 50% of field-level production revenues in the first quarter of 2012 compared to 25% in the first quarter of 2011. The increased NGL volumes in the first quarter of 2012 were the result of the agreement entered into by QEP Energy with QEP Field Services for Pinedale production, effective August 1, 2011, for fee-based processing at the Blacks Fork II plant, and the liquids recovered for QEP Energy by third party processors associated with the development of liquids-rich plays in the Midcontinent and in the Bakken/Three Forks formations. QEP Energy has allocated approximately 89% of its 2012 total forecasted capital expenditure budget to oil and liquids-rich natural gas plays due to depressed current natural gas prices.

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

The Company also owns and operates gathering and transmission pipelines and natural gas processing and treatment facilities in many of its core producing areas, which allows the Company to promptly connect its wells, better control its costs, and generate a significant revenue stream by providing gathering and processing services to third parties. Net income from QEP’s midstream business accounted for 29% of the Company’s total net income during the first quarter of 2012.

Financial and Operating Results

During the first quarter of 2012, QEP had continued growth from QEP Energy, its exploration and production business, and QEP Field Services, its gathering and processing business. Though natural gas and NGL prices decreased in the first quarter of 2012 from the first quarter of 2011, QEP Energy benefitted from higher total production and higher crude oil prices during the three months ended March 31, 2012, as compared to the 2011 period. In the first quarter of 2012, QEP Field Services benefited from attractive gas processing margins, higher NGL volumes from the Blacks Fork II processing plant, which commenced operations in the second half of 2011.

In the first quarter of 2012, QEP Energy reported production of 74.2 Bcfe compared to 65.9 Bcfe in the 2011 first quarter, an increase of 13%. During the three months ended March 31, 2012, the Southern Region contributed 55%, and the Northern Region contributed 45%, respectively, of total equivalent production.

QEP Field Services reported gathering system throughput of 1.4 million MMBtu per day for the three months ended March 31, 2012, up from 1.3 million MMBtu in the first quarter of 2011. During the three months ended March 31, 2012, QEP Field Services reported a 63% increase in NGL sales volumes to a total of 45.2 million gallons. The increase in NGL sales volumes, along with a 23% increase in the per unit NGL margin (NGL revenue less fuel and shrink), resulted in a 61% increase to the keep-whole processing margin during the first quarter of 2012.

In the first quarter of 2012, QEP issued $500 million of Senior Notes due October 2022, with a coupon of 5.375%. The Senior Notes were issued at face value. The net proceeds of approximately $493.0 million were used to repay indebtedness under QEP’s revolving credit facility. Interest on the Senior Notes is payable April 1 and October 1 of each year, with the first interest payment due on October 1, 2012.

Factors Affecting Results of Operations

Oil, Natural Gas, and NGL Prices

Historically, field-prices received for QEP’s natural gas, NGL, and crude oil production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than natural gas demand, driven by advances in technology, including horizontal drilling combined with multi-stage hydraulic fracturing, which have allowed producers to extract increasing amounts of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supply has put downward pressure on natural gas prices, while concern about the global economy and other factors has created volatility in the price of crude oil. Changes in the market prices for natural gas, crude oil, and NGL directly impact many aspects of QEP’s business, including its financial condition, revenues, results of operations, planned drilling activity and related capital expenditures, liquidity, rate of growth, costs of goods and services required to drill and complete wells, and the carrying value of its oil and natural gas properties.

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QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to protect cash flow and returns on invested capital from a drop in commodity prices. In general, QEP plans to hedge approximately 50% of its forecasted production by the end of the first quarter of the current year. As of March 31, 2012, QEP Energy had approximately 66% of its remaining forecasted 2012 natural gas, oil and NGL production covered with fixed-price swaps or costless collars assuming 2012 annual production of 307.5 Bcfe. At March 31, 2012, QEP Energy had approximately 74% of its remaining forecasted 2012 natural gas production covered with fixed-price swaps assuming 2012 annual natural gas production of 242.5 Bcfe. In the first quarter of 2012, QEP has hedged a greater portion of its 2012 natural gas production in light of concerns of oversupply in the natural gas market. See Item 3 “Quantitative and Qualitative Disclosures about Market Risk—Commodity Derivative Transactions” for further details concerning QEP’s commodity derivatives transactions. In addition, as a result of the continued spread between oil and natural gas prices, QEP Energy has allocated approximately 89% of its forecasted 2012 drilling and completion capital expenditure budget to oil and liquids-rich natural gas projects in its portfolio.

Unrealized Derivative Gains and Losses

Unrealized gains and losses that result from changes in the mark-to-market values 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. The Company has elected to discontinue hedge accounting beginning January 1, 2012, and unrealized gains and losses that result from mark-to-market valuations of all derivative positions will be reflected as unrealized commodity derivative gains or losses in the Company’s income statement. See Note 7 - Derivative Contracts to the Condensed Consolidated Financial Statements, in Item 1, Part I of this Quarterly Report on Form 10-Q for additional information regarding the discontinuance of hedge accounting. 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 the 2012 first quarter and prior periods and may continue to incur these types of gains and losses in the future.

Global Economy and the European Debt Crisis

QEP continues to monitor the outlook of the global economy, including the European debt crisis and its potential impact on global economic growth and the banking and financial sectors, the United States federal budget deficit, and commodity prices. QEP expects natural gas prices to remain low in the United States if the natural gas drilling rig count does not decline, natural gas storage levels remain high and natural gas production continues to grow. QEP expects oil prices to remain at or above current levels if the global economy continues its recovery. Disruption to the global oil supply system or other factors could trigger additional oil price volatility with sharp increases in the crude oil price that could be followed by sharp declines in the crude oil price that the Company may receive for its oil production. Because of the global economic outlook and the uncertainty around the commodity pricing environment, QEP continues to plan its capital spending program and financial flexibility appropriately.

Potential for Future Asset Impairments

Natural gas prices in the United States decline in the first quarter of 2012 due to market concerns about growing natural gas production and record high levels of natural gas storage levels after an unusually warm winter. The carrying value of some of the Company’s properties are sensitive to declines in natural gas prices. These assets are at risk of impairment if future prices for natural gas as reflected in the forward curve continue to decline. The cash flow model that the Company uses to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward natural gas prices alone could result in an impairment of properties that are sensitive to declines in natural gas prices. A significant drop in oil prices, though not anticipated, could also trigger impairment. For additional information see Item 1A “Risk Factors” of Part I and see Item 8, Note 1 “Significant Accounting Policies” of Part II of QEP’s 2011 Annual Report on Form 10-K.

Critical Accounting Estimates

QEP’s significant accounting policies are described in Item 7 of Part II of its 2011 Annual Report on Form 10-K. The Company’s Condensed Consolidated Financial Statements are prepared in accordance with United States Generally Accepted Accounting Principles. The preparation of condensed consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP’s accounting policies on gas and oil reserves, successful efforts accounting for gas and oil operations, accounting for derivative contracts and revenue recognition, among others, may involve a higher degree of complexity and judgment on the part of management.

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RESULTS OF OPERATIONS

Net Income

Net income attributable to QEP for the first quarter of 2012 was $155.2 million or $0.87 per diluted share, compared to $73.2 million or $0.41 per diluted share in the first quarter of 2011. The increase in 2012 was due to a 151% increase in QEP Energy’s net income and a 62% increase in QEP Field Services net income. QEP Energy’s net income increased in the first quarter of 2012 due to a $123.7 million gain on unrealized commodity derivative contracts, deferred in accumulated other comprehensive income in the first quarter of 2011, along with significant increases in oil and NGL production and increased oil prices. QEP Field Services’ increase in net income was driven by 75% higher processing margins. Following are comparisons of net income attributable to QEP by line of business:

	Three Months Ended
	March 31,
	2012		2011		Change
	(in millions)
QEP Energy	$	108.1	$	43.1	$	65.0
QEP Field Services		45.4		28.0		17.4
QEP Marketing and other		1.7		2.1		(0.4	)
Net income from continuing operations attributable to QEP	$	155.2	$	73.2	$	82.0
Earnings per diluted share from continuing operations	$	0.87	$	0.41	$	0.46
Average diluted shares		178.5		178.3		0.2

Adjusted EBITDA

Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company’s cash flow and liquidity and its ability to incur and service debt, fund capital expenditures and make distributions to shareholders, and an important measure for comparing the Company’s financial performance to other gas and oil producing companies. In addition, Adjusted EBITDA is part of the Company’s debt covenants under its revolving credit and term loan agreements. Management defines Adjusted EBITDA as net income before the following items: depreciation, depletion and amortization (DD&A), abandonment and impairment, interest and other income, interest expense, income taxes, unrealized gains and losses on derivative contracts, discontinued operations, gains and losses from assets sales, and exploration expense. During the year ended December 31, 2011, QEP revised its reporting of transportation and handling costs to align with industry practice and GAAP. This revised disclosure does not change current or prior period disclosure of net income or Adjusted EBITDA. For additional information, see Note 2 - Basis of Presentation of Interim Consolidated Financial Statements to the Condensed Consolidated Financial Statements, in Item 1, Part I of the Quarterly Report on Form 10-Q, for additional details. Following are comparisons of Adjusted EBITDA by line of business:

	Three Months Ended
	March 31,
	2012		2011		Change
	(in millions)
QEP Energy	$	260.8	$	242.0	$	18.8
QEP Field Services		84.3		61.4		22.9
QEP Marketing and other		0.6		2.4		(1.8	)
Total Adjusted EBITDA	$	345.7	$	305.8	$	39.9

Adjusted EBITDA increased to $345.7 million for the first quarter of 2012 compared to $305.8 million in the 2011 period, despite a 13% decrease in net realized natural gas prices and 13% lower net realized NGL prices. The impact of lower net realized natural gas and NGL prices during the first quarter of 2012 was offset by a 13% increase in total production, 7% higher net realized crude oil prices in QEP Energy, along with increased processing margins in QEP Field Services.

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A reconciliation of Adjusted EBITDA to net income follows:

	Three Months Ended
	March 31,
	2012			2011			Change
	(in millions)
Net income attributable to QEP	$	155.2		$	73.2		$	82.0
Net income attributable to non-controlling interest		0.8			0.6			0.2
Net income		156.0			73.8			82.2
Unrealized (gain) on derivative contracts		(128.3	)		(31.2	)		(97.1	)
Net (gain) from asset sales		(1.5	)		-			(1.5	)
Interest and other income		(1.7	)		(0.6	)		(1.1	)
Income taxes		88.7			42.7			46.0
Interest expense		24.7			22.1			2.6
Depreciation, depletion and amortization		199.2			190.8			8.4
Abandonment and impairment		6.6			5.4			1.2
Exploration expenses		2.0			2.8			(0.8	)
Adjusted EBITDA	$	345.7		$	305.8		$	39.9

Revenue, Volumes and Prices

On January 1, 2012, QEP discontinued hedge accounting. During the first quarter of 2012, commodity derivative realized gains and losses from derivative contract settlements were included below operating income in “Realized and unrealized gains on commodity derivative instruments on the Condensed Consolidated Income Statement. Conversely, during the first quarter of 2011, the commodity derivative realized gains and losses on settlements were included in each respective revenue category in conjunction with hedge accounting and the realization of the underlying contract. For additional information regarding the discontinuance of hedge accounting and impact on the Condensed Consolidated Income Statement, see Note 7 - Derivative Contracts, in Part I, Item 1 of this Quarterly Report on Form 10-Q.

	Three Months Ended
	March 31,
	2012		2011		Change
	(in millions)
QEP Resources Revenues
Natural gas sales	$	161.2	$	312.6	$	(151.4	)
Oil sales		110.8		63.0		47.8
NGL sales		97.4		47.9		49.5
Gathering, processing and other		49.8		46.6		3.2
Purchased gas and oil sales		184.0		147.8		36.2
Total Revenues	$	603.2	$	617.9	$	(14.7	)

QEP Energy’s revenues for the three months ended March 31, 2012, resulting from the sale of natural gas, oil and NGLs increased primarily due to increased production volumes and higher oil prices, offset by lower prices for natural gas and NGL, as follows:

	Three Months Ended March 31,
	Natural Gas			Oil		NGLs			Total
	(in millions)
QEP Energy Revenues
2011 revenues	$	312.6		$	63.0	$	18.4		$	394.0
Changes associated with volumes (1)		2.4			37.9		39.7			80.0
Changes associated with prices (2)		(80.7	)		9.9		(8.2	)		(79.0	)
Changes associated with discontinuance of hedge accounting (3)		(73.1	)		-		-			(73.1	)
2012 revenues	$	161.2		$	110.8	$	49.9		$	321.9

(1) The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three months ended March 31, 2012, to the three months ended March 31, 2011, by the average realized price or fee for the three months ended March 31, 2011.

(2) The revenue variance attributed to the change in price is calculated by multiplying the change in realized prices or fee from the three months ended March 31, 2012, to the three months ended March 31, 2011, by volume for the three months ended March 31, 2012. Pricing changes are driven by changes in the commodity field-level prices excluding impact from commodity derivatives.

(3) During the three months ended March 31, 2011, realized gains and losses on commodity derivative contract settlements were included in natural gas revenues on the Condensed Consolidated Income Statement. Conversely, during the three months ended March 31, 2012 the realized gains and losses on commodity derivative contract settlements are recognized below operating income on the Condensed Consolidated Income Statement.

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QEP Field Services revenues also increased for the three months ended March 31, 2012, as a result of higher gathering and processing volumes and increased processing and gathering fees in the first quarter of 2012 as compared to the first quarter of 2011. Changes associated with other factors decreased gathering revenues by $6.7 million due to the elimination of a short-term, third-party, interruptible processing agreement recorded as other gathering revenues. Changes associated with other factors increased processing revenues by $2.5 million due to charges to customers unrelated to the processing process recorded as other processing fees at QEP Field Services. The following table presents changes in QEP Field Services major revenue categories and the related volume and pricing impact:

	Three Months Ended March 31,
	NGLs			Processing		Gathering			Total
	(in millions)
QEP Field Services
2011 revenues	$	29.5		$	10.0	$	57.1		$	96.6
Changes associated with volumes (1)		18.6			0.5		1.6			20.7
Changes associated with fees (2)		(0.6	)		6.0		1.2			6.6
Changes associated with other factors (3)		-			2.5		(6.7	)		(4.2	)
2012 revenues	$	47.5		$	19.0	$	53.2		$	119.7

(1) The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three months ended March 31, 2012, to the three months ended March 31, 2011, by the average realized price or fee for the three months ended March 31, 2011.

(2) The revenue variance attributed to the change in fees is calculated by multiplying the change in realized prices or fee from the three months ended March 31, 2012, to the three months ended March 31, 2011, by volume for the three months ended March 31, 2012.

(3) The revenue variance attributed to the change associated with other factors represents the changes in other gathering revenues and changes in other processing fees. These other revenues are not included in average gathering revenue per MMBtu or average fee-based processing revenue per MMBtu in QEP Field Services operating statistics and thus have not been included in the price and volume variance analysis presented above.

Purchased gas and oil sales increased by $36.2 million, or 24% during the three months ended March 31, 2012 from 2011. The increase in the first quarter of 2012 was primarily due to additional gas purchases made in northwest Louisiana to utilize firm transportation capacity and the subsequent sale of those gas purchases.

Production

QEP Energy reported production of 74.2 Bcfe in the first quarter of 2012, a 13% increase over the 65.9 Bcfe reported in the 2011 first quarter. On an energy-equivalent basis, crude oil and NGL comprised approximately 20% of QEP Energy’s production for the three month period ended March 31, 2012, up from 10% for the three months ended March 31, 2011. A summary is shown in the following table:

	Three Months Ended March 31,
	2012		2011		Change
QEP Energy Production Volumes
Natural gas (Bcf)		59.5		59.1		0.4
Oil (Mbbl)		1,222.5		763.0		459.5
NGL (Mbbl)		1,221.7		386.3		835.4
Total production (Bcfe)		74.2		65.9		8.3
Average daily production (MMcfe)		815.1		732.8		82.3

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

	Three Months Ended March 31,
	2012		2011		Change
QEP Energy - Natural gas Production (Bcf)
Southern Region
Haynesville/Cotton Valley		27.9		28.2		(0.3	)
Midcontinent		8.2		7.7		0.5
Northern Region
Pinedale Anticline		17.0		15.4		1.6
Uinta Basin		3.3		4.8		(1.5	)
Rockies Legacy		3.1		3.0		0.1
Total production		59.5		59.1		0.4

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

	Three Months Ended March 31,
	2012		2011		Change
QEP Energy - Oil Production (Mbbl)
Southern Region
Haynesville/Cotton Valley		9.4		14.6		(5.2	)
Midcontinent		285.9		163.6		122.3
Northern Region
Pinedale Anticline		152.3		130.6		21.7
Uinta Basin		204.1		225.3		(21.2	)
Rockies Legacy		570.8		228.9		341.9
Total production		1,222.5		763.0		459.5

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

	Three Months Ended March 31,
	2012		2011		Change
QEP Energy - NGL Production (Mbbl)
Southern Region
Haynesville/Cotton Valley		2.4		2.0		0.4
Midcontinent		439.5		323.5		116.0
Northern Region
Pinedale Anticline		717.1		-		717.1
Uinta Basin		21.3		34.3		(13.0	)
Rockies Legacy		41.4		26.5		14.9
Total production		1,221.7		386.3		835.4

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

	Three Months Ended March 31,
	2012		2011		Change
QEP Energy - Total Production (Bcfe)
Southern Region
Haynesville/Cotton Valley		28.0		28.3		(0.3	)
Midcontinent		12.6		10.5		2.1
Northern Region
Pinedale Anticline		22.2		16.2		6.0
Uinta Basin (1)		4.6		6.4		(1.8	)
Rockies Legacy		6.8		4.5		2.3
Total production		74.2		65.9		8.3

(1) During the three months ended March 31, 2011, the Uinta Basin production included a 1.6 Bcfe positive adjustment due to an increase of QEP’s ownership interest within a federal unit.

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Southern Region – Haynesville/Cotton Valley. Net production from the Haynesville Shale and Cotton Valley tight gas plays in northwest Louisiana decreased 1% to 28.0 Bcfe in the first quarter of 2012 compared to the first quarter of 2011. Haynesville/Cotton Valley production comprised 38% of the Company’s total production in the first quarter of 2012, compared to 43% in the year-earlier period. In recent months QEP Energy has significantly reduced the pace of development drilling in the Haynesville shale play in response to depressed natural gas prices.

Southern Region – Midcontinent. Net production in the Midcontinent area grew 20% to 12.6 Bcfe in the first quarter of 2012 compared to the first quarter of 2011 and represented 17% of the Company’s total production for the 2012 first quarter, up from 16% during the 2011 first quarter. Midcontinent production growth was driven by continued development of the Granite Wash/Atoka Wash play in the Texas Panhandle and the Woodford “Cana” Shale horizontal gas play in the Anadarko Basin of western Oklahoma.

Northern Region – Pinedale Anticline. Net production from the Pinedale Anticline in western Wyoming grew 37% to 22.2 Bcfe in the first quarter of 2012 compared to the 2011 first quarter and represented 30% of the Company’s total production. Pinedale production growth was driven by increased drilling activity and the new fee-based processing agreement between QEP Energy and QEP Field Services at Blacks Fork II. As a result of the processing agreement, QEP Energy NGL production at Pinedale for the first quarter of 2012 was 717.1 Mbbl, contrasted with no reportable NGL production in the comparable 2011 period.

Northern Region – Uinta Basin. In the Uinta Basin, production decreased 28% in the first quarter of 2012 due primarily to a first quarter 2011 prior-period adjustment of QEP’s ownership interest within a federal unit, which resulted in a positive adjustment to reported production volumes in 2011 of 1.6 Bcfe. Excluding this prior-period adjustment, QEP Uinta Basin production would have declined by 4% in the first quart of 2012 as a result of lower development drilling activity throughout 2011. QEP expects production increases to be realized later in 2012 as a result of its new drilling program in the Uinta Basin.

Northern Region – Rockies Legacy. Rockies Legacy net production in the first quarter of 2012 increased 51% to 6.8 Bcfe due to increased oil-directed drilling activity in the North Dakota Bakken/Three Forks play. QEP Energy Rockies Legacy properties include all Northern Region properties except the Pinedale Anticline and the Uinta Basin.

Pricing

During the year ended December 31, 2011, QEP revised its reporting of transportation and handling costs. Transportation and handling costs have been recast on the Condensed Consolidated Income Statement from revenues to “Natural gas, oil and NGL transportation and other handling costs” for all periods presented. See Note 2 - Basis of Presentation of Interim Consolidated Financial Statements to the Condensed Consolidated Financial Statements, in Item 1, Part I of this Quarterly Report on Form 10-Q, for additional information. Prior to the recast, transportation and other handling costs were netted against revenue.

The Company enters into commodity derivative instruments to manage its exposure to price fluctuations on a portion of its forecasted natural gas, oil and NGL production. Derivative positions as of March 31, 2012, and December 31, 2011, are summarized in Note 7 – Derivative Contracts to the Condensed Consolidated Financial Statements in Item 1, Part I of this Quarterly Report on Form 10-Q. Field level and realized prices (after the impact of all settled commodity derivatives) for natural gas and NGLs at QEP Energy were lower during the three months ended March 31, 2012, than in the 2011 comparable period, while field-level and realized oil prices were higher when compared to the 2011 first quarter. A regional comparison of average field level prices is shown in the following tables:

	Three Months Ended March 31,
	2012		2011		Change
QEP Energy - Average field-level natural gas price (per Mcf)
Southern Region	$	2.75	$	4.00	$	(1.25	)
Northern Region		2.64		4.14		(1.50	)
Average field-level natural gas price		2.71		4.06		(1.35	)

	Three Months Ended March 31,
	2012		2011		Change
QEP Energy - Average field-level oil price (per bbl)
Southern Region	$	97.89	$	89.87	$	8.02
Northern Region		88.36		80.35		8.01
Average field-level oil price		90.67		82.57		8.10

	Three Months Ended March 31,
	2012		2011		Change
QEP Energy - Average field-level NGL price (per bbl)
Southern Region	$	33.95	$	44.55	$	(10.60	)
Northern Region		44.78		63.58		(18.80	)
Average field-level NGL price		40.87		47.54		(6.67	)

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A comparison of net realized average natural gas, oil and NGL prices, including the realized gains and losses on commodity derivative contracts is shown in the following table:

	Three Months Ended March 31,
	2012 (2)			2011 (1)		Change
Natural gas (per Mcf)
Average field-level price	$	2.71		$	4.06	$	(1.35	)
Commodity derivative impact		1.44			0.71		0.73
Net realized price	$	4.15		$	4.77	$	(0.62	)
Oil (per bbl)
Average field-level price	$	90.67		$	82.57	$	8.10
Commodity derivative impact		(2.20	)		-		(2.20	)
Net realized price	$	88.47		$	82.57	$	5.90
NGL (per bbl)
Average field-level price	$	40.87		$	47.54	$	(6.67	)
Commodity derivative impact		0.34			-		0.34
Net realized price	$	41.21		$	47.54	$	(6.33	)

(1) Commodity derivative impact was reported in “Revenues” in the Condensed Consolidated Income Statement.

(2) Commodity derivative impact was reported below operating income in “Realized and unrealized gains on commodity derivative contracts” beginning January 1, 2012 in the Condensed Consolidated Income Statement.

Gathering

QEP Field Services gathering margins declined 4% in the first quarter of 2012, primarily due to the decreased other gathering revenue related to the elimination of a third-party interruptible processing agreement discussed below. Partially offsetting the gathering margin decrease was a 4% increase in gathering system throughput volume and a 3% increase in the average gathering rate. Gathering system throughput volume was 1.4 million MMBtu per day for the first quarter of 2012, up from 1.3 million MMBtu per day during the first quarter of 2011. The increased volumes were mainly related to the gathering system tied into the Blacks Fork hub and the northwest Louisiana gathering system. The Blacks Fork hub accounted for 50% of the total gathering system throughput during the first quarter of 2012, compared to 49% in the 2011 first quarter, while the Louisiana hub accounted for 24% of the total throughput during the three months ended March 31, 2012 and 2011.

During the first quarter of 2011, QEP Field Services reported "Other gathering revenues" Related to a short-term interruptible gas processing contract with a third-party processor. The short-term processing arrangement was in effect prior to the startup of QEP Field Service’s Blacks Fork II processing plant.

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

	Three Months Ended March 31,
	2012			2011			Change
Gathering Margin	(in millions)
Gathering revenues	$	41.9		$	39.4		$	2.5
Other gathering revenues		11.3			17.7			(6.4	)
Gathering expense		(9.6	)		(11.9	)		2.3
Gathering margin	$	43.6		$	45.2		$	(1.6	)

	Three Months Ended March 31,
	2012		2011		Change
Operating Statistics
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers		61.0		61.1		(0.1	)
For affiliated customers		62.7		57.9		4.8
Total Gas Gathering Volumes		123.7		119.0		4.7
Average gas gathering revenue (per MMBtu)	$	0.34	$	0.33	$	0.01

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Processing

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

QEP Field Services processing margin increased 75% in the first quarter of 2012 compared to the 2011 first quarter, due to a 61% increase in keep-whole processing margins and a 90% increase in fee-based processing revenues. The increased keep-whole processing margin was primarily the result of increased NGL volumes as well as increased fee-based processing revenues. NGL volumes increased 63% in the first quarter of 2012 compared to the 2011 first quarter. The increased NGL volume was primarily the result of the start-up of the Blacks Fork II plant in July 2011. Including the impact of gains on derivative contract settlements, NGL prices increased 1% in the first quarter of 2012 compared to the 2011 first quarter. Though NGL prices increased, the keep-whole processing margin per NGL gallon was $0.66 for the first quarter of 2012, essentially flat compared to the first quarter of 2011. Fee-based processing revenues increased during the first quarter of 2012 due to a 59% increase in the average processing fee rate to $0.27 per MMBtu and a 5% increase in fee-based processing volumes to 59.7 million MMBtu. Approximately 72% of QEP Field Services’ net operating revenue was derived from fee-based gathering and processing agreements in the three months ended March 31, 2012, compared to 78% during the three months ended March 31, 2011. The decline in the relative percentage of fee-based revenues was due primarily to the increase in keep-whole processing margins in 2012.

Keep-whole processing margin as used in the following table is defined as the market value for NGL’s extracted from the natural gas stream less the market value of the Btu-equivalent volume of natural gas required to replace the extracted liquids and the related transportation and handling costs. The following tables are a summary of QEP Field Services’ processing financial and operating results:

	Three Months Ended March 31,
	2012			2011			Change
Processing Margin	(in millions)
NGL sales	$	47.5		$	29.5		$	18.0
Realized gains from commodity derivative contract settlements		1.1			-			1.1
Processing (fee-based) revenues		16.0			10.0			6.0
Other processing fees		3.0			-			3.0
Processing (expense)		(3.7	)		(2.7	)		(1.0	)
Processing plant fuel and shrink (expense)		(10.1	)		(10.2	)		0.1
Natural gas, oil and NGL transportation and other handling costs		(8.8	)		(0.9	)		(7.9	)
Processing margin	$	45.0		$	25.7		$	19.3
Keep-whole processing margin (NGL sales less processing plant fuel and shrinkage less natural gas, oil and NGL transportation and other handling costs)	$	29.7		$	18.4		$	11.3

	Three Months Ended March 31,
	2012		2011		Change
Operating Statistics
Natural gas processing volumes
NGL sales (MMgal)		45.2		27.8		17.4
Average net realized NGL sales price (per gal)	$	1.07	$	1.06	$	0.01
Fee-based processing volumes (in millions of MMBtu)
For unaffiliated customers		28.0		31.4		(3.4	)
For affiliated customers		31.7		25.6		6.1
Total fee-based processing volumes		59.7		57.0		2.7
Average fee-based processing revenue (per MMBtu)	$	0.27	$	0.17	$	0.10

28

Operating Expenses

The following table presents QEP Resources' total operating expenses and the changes from the three months ended March 31, 2011, to the three months ended March 31, 2012. The narrative following the table explains the significant variances between the comparable periods.

	Three Months Ended March 31,
	2012		2011		Change
	(in millions)
Purchased gas and oil expense	$	188.4	$	146.7	$	41.7
Lease operating expense		40.1		32.8		7.3
Natural gas, oil and NGL transportation and other handling costs		34.5		21.7		12.8
Gathering, processing and other		23.7		25.2		(1.5	)
General and administrative		36.0		31.7		4.3
Production and property taxes		24.7		23.7		1.0
Depreciation, depletion and amortization		199.2		190.8		8.4
Exploration expenses		2.0		2.8		(0.8	)
Abandonment and impairment		6.6		5.4		1.2
Total operating expenses	$	555.2	$	480.8	$	74.4

Purchased gas and oil expense increased 28% in the first quarter of 2012, primarily due to QEP Energy gas purchases made in northwest Louisiana to utilize firm transportation capacity. QEP Energy began recording purchased gas expense and related revenue on these contracts during the second quarter of 2011.

Lease operating expense increased $7.3 million, or 22% during the first quarter of 2012 compared to the first quarter of 2011, driven by a 13% increase in production during the first quarter of 2012 and higher water disposal costs and work over costs.

Natural gas, oil and NGL transportation and other handling costs increased $12.8 million, or 59% primarily due a $7.9 million increase at QEP Field Services. The increase at QEP Field Services was primarily due to transportation costs relating to the Blacks Fork II plant which was put into service in the third quarter of 2011. See Note 2 - Basis of Presentation and of Interim Consolidated Financial Statements to the Condensed Consolidated Financial Statements, in Item 1, Part I of this Quarterly Report on Form 10-Q, for a discussion of the recasting of 2011 transportation and other handling costs.

Gathering, processing and other expense decreased by $1.5 million due to lower gathering expenses due to the elimination of a short-term, third-party interruptible processing agreement in which QEP Field Services was required to purchase the shrink gas. The short-term processing arrangement was in effect during the first quarter of 2011 before the expansion of the Blacks Fork processing plant was put into service during the third quarter of 2011. This decrease was partially offset by increased gathering, processing and NGL sales volumes. During the three months ended March 31, 2012, fee-based processing volumes were 5% higher, gathering volumes were 4% higher, and NGL sales volumes were 63% higher than the 2011 first quarter at QEP Field Services.

Total general and administrative (G&A) expense increased to $36.0 million for the quarter ended March 31, 2012, compared with $31.7 million during the 2011 first quarter. The increase in G&A in the 2012 first quarter was primarily due to $2.7 million in restructuring costs associated with the closure of QEP Energy’s Oklahoma City office and $1.5 million higher compensation costs related to increases in employee compensation and benefits.

Production and property taxes increased 4% during the first quarter of 2012, due to higher natural gas, oil and NGL production and higher field-level oil prices, partially offset by lower field-level sales prices for natural gas and NGL during the same period of 2011.

QEP’s total DD&A expense grew $8.4 million, or 4% in the first quarter of 2012 compared with the 2011 first quarter. The increase in DD&A expense was the result of increased production at QEP Energy and a 16% increase in QEP Field Services DD&A due primarily due to the completion of the Blacks Fork II in July 2011.

Exploration expenses were $2.0 million in the first quarter of 2012 compared with $2.8 million in the first quarter of 2011 due to lower dry hole costs.

Abandonment and impairment expenses increased to $6.6 million in the first quarter of 2012 compared with $5.4 million in the 2011 first quarter. The increase of $1.2 million was primarily due to increased leasehold impairments in the Uinta Basin of $0.4 million and increased leasehold impairments in the Rockies Legacy Division of $0.9 million in the first quarter of 2012 compared to the 2011 first quarter. Natural gas prices remain weak due to continued increases in natural gas production relative to demand and historically high storage levels. Certain of the Company’s properties have significant natural gas reserves and therefore are sensitive to declines in natural gas prices. These assets are at risk of impairment if future natural gas prices do not increase or experience further decline.

29

CONSOLIDATED RESULTS BELOW OPERATING INCOME

Realized and unrealized gain on commodity derivative contracts

Effective January 1, 2012, QEP discontinued hedge accounting, thus changes during the first quarter of 2012 and all changes in mark-to-market are recognized in the current period earnings. In 2011, QEP used hedge accounting and changes in mark-to-market were reflected in Accumulated Other Comprehensive Income (AOCI) and ultimately revenues when the derivatives were settled. Gains and losses on commodity derivative instruments during 2012 are comprised of both realized and unrealized gains and losses on QEP’s commodity derivative contracts. During the first quarter of 2012, gains on commodity derivative instruments were $216.3 million, of which $88.0 million was realized and $128.3 million was unrealized.

Interest and other income

Interest and other income are comprised primarily of interest earned on investments, gains and losses on warehouse inventory, and other miscellaneous income. During the three months ended March 31, 2012, interest and other income increased $1.1 million primarily due to variance in inventory valuations of $0.6 million and reduced hedge ineffectiveness of $0.3 million.

Interest expense

Interest expense increased 12% in the first quarter of 2012 compared to the first quarter of 2011. The increase in interest expense was due to average debt levels that were approximately $125 million higher average debt levels in the comparable prior period. In addition, QEP’s issuance of $500 million of Senior Notes in the first quarter of 2012 increased 2012 first quarter interest expense by $2.2 million over the 2011 period.

Income taxes

The effective combined federal and state income tax rate was 36.2% for the three months ended March 31, 2012, lower than the 36.7% in the three months ended March 31, 2011, respectively. The 2012 combined rate was lower due to changes in estimates and subsequent reduction of accruals that are non-deductible for income tax purposes.

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DISCUSSION BY LINE OF BUSINESS

QEP Energy

QEP Energy reported net income of $108.1 million in the first quarter of 2012, an increase of 151% from $43.1 million in the 2011 first quarter. The primary reasons for the increase were a gain from derivative contracts of $207.2 million, a 13% increase in total production and a 7% increase in net realized oil prices. The increases in derivative gains, total production and net realized oil prices were offset by a 13% decrease in net realized natural gas prices and a 13% decrease in net realized NGL prices. Following is a summary of QEP Energy’s financial and operating results:

	Three Months Ended March 31,
	2012			2011			Change
	(in millions)
Revenues
Natural gas sales	$	161.2		$	312.6		$	(151.4	)
Oil sales		110.8			63.0			47.8
NGL sales		49.9			18.4			31.5
Purchased gas and oil sales		72.5			-			72.5
Other		2.4			2.2			0.2
Total Revenues		396.8			396.2			0.6
Operating expenses
Purchased gas and oil expense		72.5			-			72.5
Lease operating expense		40.8			33.4			7.4
Natural gas, oil and NGL transportation and other handling costs		50.4			43.5			6.9
General and administrative		32.9			23.9			9.0
Production and property taxes		22.9			22.2			0.7
Depreciation, depletion and amortization		183.1			177.1			6.0
Exploration expenses		2.0			2.8			(0.8	)
Abandonment and impairment		6.6			5.4			1.2
Total Operating Expenses		411.2			308.3			102.9
Net gain from asset sales		1.5			-			1.5
Operating (Loss) Income		(12.9	)		87.9			(100.8	)
Realized gains on commodity derivative instruments		83.5			(31.2	)		114.7
Unrealized gains on commodity derivative instruments		123.7			31.2			92.5
Interest and other income (loss)		1.7			0.7			1.0
Interest expense		(23.6	)		(19.9	)		(3.7	)
Income before Income Taxes		172.4			68.7			103.7
Income taxes		(64.3	)		(25.6	)		(38.7	)
Net Income Attributable to QEP	$	108.1		$	43.1		$	65.0

Operating expenses per unit

The following table presents certain QEP Energy operating expenses on a per unit of production basis. QEP Energy total operating expenses (the sum of depreciation, depletion and amortization expense, lease operating expense, natural gas, oil and NGL transportation and other handling costs, general and administrative expense, and a portion of total QEP interest expense that is allocated to QEP Energy based on intercompany agreements and production taxes) per Mcfe of production decreased 2% to $4.77 per Mcfe in the first quarter of 2012 compared to $4.85 per Mcfe in the 2011 first quarter.

	Three Months Ended March 31,
	2012		2011		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.47	$	2.69	$	(0.22	)
Lease operating expense		0.55		0.51		0.04
Natural gas, oil and NGL transportation and other handling costs		0.68		0.66		0.02
General and administrative expense		0.44		0.36		0.08
Allocated interest expense		0.32		0.30		0.02
Production taxes		0.31		0.33		(0.02	)
Total Operating Expenses	$	4.77	$	4.85	$	(0.08	)

31

DD&A expense decreased $0.22 per Mcfe in the first quarter of 2012 from the 2011 first quarter. QEP Energy’s DD&A expense increased $6.0 million during the first quarter of 2012 from the 2011 first quarter primarily as the result of booking NGL reserves associated with the fee-based processing agreement entered into between QEP Energy and QEP Field Services for QEP Energy’s Pinedale production, increased percentage of production from the lowest DD&A pools and impairments taken in the fourth quarter of 2011.

Lease operating expense per Mcfe increased $0.04 for the first quarter ended March 31, 2012 from the 2011 first quarter. The 2012 first quarter increase was the result of increased water disposal costs and work over costs on its liquids producing areas.

QEP Energy’s average production costs (lease operating expense) per Mcfe were 8% higher for the three months ended March 31, 2012, compared to the three months ended March 31, 2011. The following table presents average production cost, excluding production taxes for QEP Energy by region on a per unit of production basis.

	Three Months Ended March 31,
	2012		2011		Change
	(per Mcfe)
Southern Region	$	0.53	$	0.45	$	0.08
Northern Region		0.57		0.59		(0.02	)
Average production cost		0.55		0.51		0.04

Natural gas, oil and NGL transportation and other handling costs per Mcfe were 3% higher in the first quarter of 2012 than in the first quarter of 2011. The increase per Mcfe in the first quarter of 2012 was due to a 13% increase in production at QEP Energy.

G&A expense increased $0.08 per Mcfe in the three months ended March 31, 2012, as the result of higher total G&A expenses, which were primarily related to changes in accruals for loss contingencies, restructuring costs and higher employee compensation and benefits in the three months ended March 31, 2012.

Allocated interest expense per unit of production increased $0.02 in the three months ended March 31, 2012, primarily due to higher QEP average debt levels resulting in higher interest expense allocated to QEP Energy.

In most states in which QEP Energy operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Accordingly, production taxes per Mcfe decreased by $0.02 during the three months ended March 31, 2012 because of lower field-level natural gas and NGL prices.

QEP Energy Operating Regions

The following table presents operated and non-operated well activity at March 31, 2012, as well as completions for the three months ended March 31, 2012:

	Operated												Non-operated
	Completions				Drilling				Waiting on completion				Completions				Drilling				Waiting on completion
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Southern Region
Haynesville/Cotton Valley		23		12.0		2		1.0		7		5.7		3		0.5		-		-		3		0.2
Midcontinent		7		5.6		2		1.5		5		3.9		26		2.9		16		1.4		22		3.3
Northern Region
Pinedale		12		9.2		23		15.1		39		28.2		-		-		-		-		-		-
Uinta Basin		10		10.0		1		1.0		3		3.0		65		0.2		-		-		-		-
Rockies Legacy		3		2.8		8		6.8		3		2.8		16		0.6		16		0.6		21		0.7

Southern Region

Haynesville/Cotton Valley

QEP Energy has approximately 50,700 net acres of Haynesville Shale lease rights in northwest Louisiana and additional lease rights that cover the Hosston and Cotton Valley formations. The depth of the top of the Haynesville Shale ranges from approximately 10,500 feet to 12,500 feet across QEP Energy’s leasehold and is below the Hosston and Cotton Valley formations that QEP Energy has been developing in northwest Louisiana since the 1990’s. As of March 31, 2012, QEP Energy had one operated rig drilling in the project area.

32

Midcontinent

QEP Energy’s Midcontinent properties cover all properties in the Southern Region except the Haynesville/Cotton Valley area of northwest Louisiana, and are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas Panhandle.

QEP Energy has approximately 76,600 net acres of Woodford Shale lease rights in western Oklahoma. The true vertical depth to the top of the Woodford Shale ranges from approximately 10,500 feet to 14,500 feet across QEP Energy’s leasehold. As of March 31, 2012, QEP Energy had two operated rigs drilling in the project area.

QEP Energy has approximately 38,700 net acres of Granite Wash/Atoka Wash lease rights in the Texas Panhandle and western Oklahoma and has been drilling vertical Granite Wash/Atoka Wash wells for over a decade. The true vertical depth to the top of the Granite Wash/Atoka Wash interval ranges from approximately 11,100 feet to 15,900 feet across QEP Energy’s leasehold. In the past few years, QEP and other operators have drilled a number of successful horizontal wells in the Granite Wash/Atoka Wash play but have also drilled some wells with disappointing results. As of March 31, 2012, QEP Energy did not have any rigs drilling in the Granite Wash/Atoka Wash. QEP Energy anticipates drilling some operated wells in the play in 2012 and participating in a number of outside-operated well proposals.

Northern Region

Pinedale Anticline

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. 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. On March 13, 2012, the WOGCC approved 5-acre density drilling for Lance Pool wells on an additional approximate 7,200 gross acres. The area approved for increased density corresponds to the currently estimated economic productive limits of QEP Energy core acreage in the field. 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 1,100 additional wells will be required to fully develop its Pinedale acreage on a combination of 5 and 10-acre density. In addition to QEP Energy’s gross producing wells, QEP Energy had an overriding royalty interest only in an additional 21 wells at Pinedale. At March 31, 2012, QEP Energy had seven operated rigs drilling in the Pinedale Anticline (one of which QEP plans to move to the Bakken play in North Dakota during the second quarter of 2012).

Uinta Basin

The majority of Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at depths of 4,500 feet to deeper than 18,000 feet. QEP Energy owns interests in approximately 255,200 net leasehold acres in the Uinta Basin. QEP Energy had two operated rigs drilling in the Uinta Basin at March 31, 2012 targeting the 32,300 net acre Mesaverde Formation productive fairway in the Redwash Unit.

Rockies Legacy

The remainder of QEP Energy Northern Region leasehold interests, productive wells and proved reserves are distributed over a number of fields and properties managed as the Rockies Legacy division. Exploration and development activity in the first quarter of 2012 includes wells in the Greater Green River Basin in Wyoming and the Williston Basin in North Dakota.

QEP Energy has approximately 90,000 net acres of lease rights in the Williston Basin in western North Dakota, where the Company is targeting the Bakken and Three Forks formations. The true vertical depth to the top of the Bakken Formation ranges from approximately 9,500 feet to 10,000 feet across QEP Energy’s leasehold. The Three Forks Formation lies approximately 60 to 70 feet below the Middle Bakken Formation and is also a target for horizontal drilling. As of March 31, 2012, QEP Energy had three operated rigs drilling in the project area.

QEP Field Services

QEP Field Services, which provides gas gathering and processing services, generated net income of $45.4 million in the first quarter of 2012 compared to $28.0 million in the same period of 2011, a 62% increase. The increase in net income in the 2012 first quarter was the result of higher processing margins and increased gathering throughput volumes, partially offset by lower gathering margins resulting from decreased other gathering revenue due to the elimination of a short-term, third-party interruptible processing agreement. The short-term processing arrangement was in effect during the first quarter of 2011 before the expansion of the Blacks Fork processing plant was put into service during the third quarter of 2011. Following is a summary of QEP Field Services’ financial and operating results:

33

	Three Months Ended March 31,
	2012			2011			Change
	(in millions)
Revenues
NGL sales	$	47.5		$	29.5		$	18.0
Processing (fee based)		16.0			10.0			6.0
Other processing fees		3.0			-			3.0
Gathering		41.9			39.4			2.5
Other gathering		11.3			17.7			(6.4	)
Total Revenues		119.7			96.6			23.1
Operating expenses
Processing		3.7			2.7			1.0
Processing plant fuel and shrinkage		10.1			10.2			(0.1	)
Gathering		9.6			11.9			(2.3	)
Natural gas, oil and NGL transportation and other handling costs		8.8			0.9			7.9
General and administrative		4.5			9.0			(4.5	)
Taxes other than income taxes		1.7			1.4			0.3
Depreciation, depletion and amortization		15.3			13.2			2.1
Total Operating Expenses		53.7			49.3			4.4
Operating Income		66.0			47.3			18.7
Income from unconsolidated affiliates		1.9			0.9			1.0
Realized gains on commodity derivative instruments		1.1			-			1.1
Unrealized gains on commodity derivative instruments		3.0			-			3.0
Interest expense		(2.3	)		(3.5	)		1.2
Income before Income Taxes		69.7			44.7			25.0
Income taxes		(23.5	)		(16.1	)		(7.4	)
Net income		46.2			28.6			17.6
Net income attributable to noncontrolling interest		(0.8	)		(0.6	)		(0.2	)
Net Income Attributable to QEP	$	45.4		$	28.0		$	17.4

Natural gas, oil and NGL transportation and other handling costs increased $7.9 million during the first quarter of 2012, primarily due to transportation costs relating to the Blacks Fork II plant which was put into service in the third quarter of 2011.

General and administrative expenses decreased by $4.5 million during the first quarter of 2012 driven primarily by a $4.3 million reduction in accruals for loss contingencies.

See “Gathering” and “Processing” sections, as appeared earlier, for additional discussion of the significant changes in QEP Field Services comparative financial statements.

QEP Marketing

QEP Marketing, which markets affiliate and third-party natural gas and oil, and owns and operates a gas storage facility, generated net income of $1.7 million in the three months ended March 31, 2012, compared with $2.1 million in the three months ended March 31, 2011. The decrease in the first quarter of 2012 was due primarily to lower marketing margins

LIQUIDITY AND CAPITAL RESOURCES

QEP funds its operations, capital expenditures and working capital requirements with cash flow from its operating activities, borrowings under its credit facility and, periodically, proceeds from debt offerings and asset sales. The Company believes cash flow from operations and availability under its credit facility will be sufficient to fund the Company’s planned capital expenditures and operating expenses over the next 12 months. To the extent actual operating results differ from the Company’s estimates, its liquidity could be adversely affected.

Cash Flow from Operating Activities

Cash flows from operations are primarily affected by natural gas, oil and NGL production volumes and commodity prices (including the effects of settlements of the Company’s derivative contracts) and by changes in working capital. QEP enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future gas, oil and NGL production for the next 12 to 24 months.

34

Net cash provided by operating activities increased 10% in the first quarter of 2012 compared to the first quarter of 2011 due to higher net income, offset by lower noncash adjustments to net income and an increase in the source of cash from operating assets and liabilities in 2012 from the 2011 period. Noncash adjustments to net income consisted primarily of depreciation, depletion and amortization; noncash unrealized gains and losses on derivative contracts; and changes in deferred income taxes. Operating assets and liabilities were a source of cash in the first quarter of 2012 primarily due to a decrease in accounts receivable offset by a decrease in accounts payable. Operating assets and liabilities driving a source of cash in the first quarter of 2011 were increases in accounts payable. Net cash provided from operating activities is presented below:

	Three Months Ended March 31,
	2012		2011		Change
	(in millions)
Net income	$	156.0	$	73.8	$	82.2
Noncash adjustments to net income		151.7		214.7		(63.0	)
Changes in operating assets and liabilities		20.8		10.9		9.9
Net cash provided from operating activities	$	328.5	$	299.4	$	29.1

Cash Flow from Investing Activities

A comparison of capital expenditures for the first three months of 2012 and 2011 and a forecast for calendar year 2012 are presented in the table below:

	Three Months Ended March 31,								Current Forecast Twelve Months Ended (2)		Prior Forecast  Twelve Months  Ended (1)
	2012			2011		Change			December 31, 2012		December 31, 2012
	(in millions)
QEP Energy	$	293.0		$	298.2	$	(5.2	)	$	1,315.0	$	1,280.0
QEP Field Services		47.2			16.1		31.1			170.0		170.0
QEP Marketing		0.2			0.1		0.1			1.0		-
Corporate		1.0			0.4		0.6			14.0		-
Total accrued capital expenditures		341.4			314.8		26.6			1,500.0		1,450.0
Change in accruals		(3.5	)		27.7		(31.2	)		-		-
Total cash capital expenditures	$	337.9		$	342.5	$	(4.6	)	$	1,500.0	$	1,450.0

(1) Forecast as reported in the 2011 Annual Report on Form 10-K.

(2) Represents the upper end of the most recent guidance.

During the first three months of 2012, capital expenditures on a cash basis decreased 1% to $337.9 million, compared to $342.5 million during the first three months of 2011. The decrease was driven by reduced development drilling in the the Haynesville/Cotton Valley, partially offset by higher capital investment in liquids-rich development drilling in the Pinedale Anticline and Uinta Basin. Approximately $306.0 million was invested in QEP Energy, including $291.6 million in drilling and completion and other expenditures and $1.4 million in property acquisition costs. QEP Field Services first quarter of 2012 capital expenditures of $30.7 million were invested to expand capacity at the Company’s gathering, processing and treating facilities, including the construction of a new 150 MMcfpd fee-based cryogenic gas processing plant in the Uinta Basin.

QEP Energy capital investment in the first quarter of 2012 decreased $5.2 million on an accrual basis over the 2011 first quarter due to lower lease acquisition capital expenditures in the Midcontinent (approximately 93% lower) and approximately 45% lower capital expenditures in the Haynesville play due to the reduced drilling program. Offsetting these reductions in the first quarter of 2012 were increased capital expenditures in the Rockies Legacy Division (approximately 94% higher) and in the Uinta Basin (approximately 24% higher) as capital is allocated out of the dry-gas Haynesville play into these oil and liquids-rich natural gas drilling programs.

QEP Field Services capital investment increased $31.1 million on an accrual basis in the first quarter of 2012 compared to the 2011 first quarter due to the projects directed to grow the midstream business including the construction of a new 150 MMcfpd fee-based cryogenic gas processing plant in the Uinta Basin.

At March 31, 2012, QEP’s upper range of forecasted capital investments for 2012 is expected to be $1,500 million, comprised of $1,315 million at QEP Energy, $170 million at QEP Field Services, and $15 million for QEP Resources and QEP Marketing. For the remainder of 2012, QEP intends to fund capital expenditures with cash flow from operating activities and, if needed, borrowings under its revolving credit facility. As a result of the continued spread between oil and natural gas prices, in the remainder of 2012 QEP plans to decrease capital expenditures for the Haynesville Shale and other dry-gas development areas and increase capital expenditures for higher return projects, including Pinedale, Uinta Basin Red Wash Mesaverde, and oil-directed horizontal drilling in the Bakken, Powder River Basin and Midcontinent. QEP Energy has allocated approximately 89% of its forecasted 2012 drilling and completion capital expenditure budget to oil and liquids-rich natural gas projects in its portfolio. QEP plans to invest approximately $170 million in capital expenditures to grow its midstream business, including construction of a new 150 MMcfpd fee-based cryogenic gas processing plant in the Uinta Basin as well as a new 10,000 Bblpd expansion to the NGL fractionators located at the Blacks Fork processing complex. QEP Resources plans to invest approximately $14 million in capital expenditures related to corporate activities primarily the implementation of a new ERP system. The aggregate levels of capital expenditures for 2012 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, natural gas and oil prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management’s business assessments as to where QEP’s capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

35

Cash Flow from Financing Activities

In the first quarter of 2012, net cash used in investing activities of $334.6 million exceeded net cash provided by operating activities of $328.5 million by $6.1 million. Net cash used in investing activities during the first quarter of 2011 was $341.6 million, which exceeded net cash provided by operating activities of $299.4 million by $42.2 million. Long-term debt decreased by $5.9 million from December 31, 2011. At March 31, 2012, long-term debt consisted of $100.5 million outstanding under QEP’s revolving credit facility and $1,573.0 million in senior notes (including $5.4 million of net original issue discount). At March 31, 2012, long-term debt was 33% and equity was 67% of total capital.

Credit Facility

QEP’s revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a syndicate of financial institutions. The revolving credit facility provides for borrowings at short-term interest rates. The revolving credit facility agreement also contains provisions which would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for two additional one-year periods. QEP reduced its borrowings under its credit facility from $606.5 million as of December 31, 2011 to $100.5 million at March 31, 2012. QEP’s weighted-average interest rate on borrowings from its credit facilities was 2.06% during the first quarter of 2012. The credit agreement includes financial covenants (i) limiting the ratio of the consolidated funded debt of the Company to the sum of consolidated funded debt plus shareholders’ equity to not more than 0.6 to 1, (ii) limiting the ratio of the consolidated funded debt of the Company to the Company’s consolidated EBITDA to not more than 3.5 to 1, and (iii) if the Company’s debt ratings fall below a certain level, limiting the Company’s total consolidated funded debt to a specified aggregate amount. At March 31, 2012, QEP was in compliance with all of its debt covenants. At April 20, 2012, QEP had $15 million outstanding under its revolving credit facility and $4.1 million of letters of credit issued.

Senior Notes

During the first quarter of 2012, the Company issued $500.0 million 5.375% Senior Notes due October 2022. The proceeds from the Senior Notes were used to pay down the Company’s revolving credit facility. The Company’s senior notes outstanding as of March 31, 2012, totaled $1,578.4 million principal amount and are comprised of five issuances 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

• $500.0 million 5.375% Senior Notes due October 2022

Term Loan

In April 2012, the Company entered into a $300 million senior, unsecured term loan agreement with a group of financial institutions. The term loan agreement provides for borrowings at short-term interest rates and contains covenants, restrictions and interest rates that are substantially the same as the Company’s existing revolving credit agreement. The term loan agreement matures in April of 2017, and the maturity date may be extended one year with the agreement of the lenders. At closing, the Company borrowed $100 million. The Company may borrow the remaining $200 million available under the term loan by June 30, 2012 at which time, any undrawn commitment under the facility will expire.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

QEP’s primary market-risk exposure arises from changes in the market price for natural gas, oil and NGL, and to a lesser extent, volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. QEP Energy and QEP Marketing have long-term contracts for pipeline capacity and are obligated to pay for transportation services with no guarantee that QEP will be able to fully utilize the contractual capacity of these transportation commitments. If energy prices decline or increase significantly, revenues and cash flow may significantly decline or increase. In addition, a non-cash write-down of the Company’s oil and gas properties may be required if future oil and natural gas commodity prices experience a sustained, significant decline. A sensitivity analysis of the Company’s commodity price related derivative instruments to changes in the price of the underlying commodities is presented below.

36

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 and costless collars. 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, 2012, QEP held commodity price derivative contracts totaling 235.9 million MMBtu of natural gas, 2.7 million barrels of oil, and 50.1 million gallons of NGL. At December 31, 2011, the QEP derivative contracts covered 213.0 million MMBtu of natural gas, 2.0 million barrels of oil, and 53.9 million gallons of NGL. Changes in the fair value of derivative contracts from December 31, 2011 to March 31, 2012, are presented below:

	Commodity derivative contracts
	(in millions)
Net fair value of gas and oil derivative contracts outstanding at Dec. 31, 2011	$	395.9
Contracts settled		(88.0	)
Change in gas and oil prices on futures markets		131.3
Contracts added		10.1
Net fair value of gas, oil and NGL derivative contracts outstanding at March 31, 2012	$	449.3

A table of the net fair value of gas, oil and NGL derivative contracts that are scheduled to settle over the next two years as of March 31, 2012, is shown below. Derivatives representing approximately 74% of the March 31, 2012 net fair value will settle in the next twelve months:

	Commodity derivative contracts
	(in millions)
Contracts maturing by March 31, 2013	$	333.8
Contracts maturing between April 1, 2013 and March 31, 2014		115.5
Net fair value of gas, oil and NGL derivative contracts outstanding at March 31, 2012	$	449.3

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

	March 31, 2012		December 31, 2011
	(in millions)
Net fair value - asset (liability)	$	449.3	$	395.9
Fair value if market prices of gas, oil and NGL and basis differentials decline by 10%		536.1		490.3
Fair value if market prices of gas, oil and NGL and basis differentials increase by 10%		366.8		301.4

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $82.5 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $86.8 million. However, a gain or loss eventually would be substantially offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company’s commodity derivative transactions, see Note 7 – Derivative Contracts under Part I, Item 1 of this Form 10-Q.

37

Interest-Rate Risk Management

The Company’s ability to borrow and the rates quoted by lenders can be adversely affected by the illiquid credit markets as described in the risk factors in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011. The Company’s credit facility has floating interest rates and as such, exposes QEP to interest rate risk. If interest rates were to increase 10% over their three months ended March 31, 2012 and 2011 average levels and at our average level of borrowing for those same periods, our interest expense would increase by $0.2 million and $0.3  million for the three months ended March 31, 2012 and 2011, respectively, or less than 2% in each period.

38

Forward-Looking Statements

This quarterly report contains information that includes or is based upon “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:

• QEP’s growth strategies;

• plans to drill or participate in wells;

• future expenses and operating costs;

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

• the outcome of contingencies such as legal proceedings;

• expected contributions to the Company’s retirement plans;

• results from planned drilling operations and production operations;

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

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

• expected mix of revenues from the Company’s gathering business;

• impact on earnings from discontinuing hedge accounting;

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

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

• QEP’s ability to develop reserves and grow production as necessary to satisfy delivery commitments and its ability to purchase natural gas, crude oil and NGLs in the market to cover any shortfalls;

• payment of dividends;

• plans to hedge a portion of forecasted production; and

• acquisition plans.

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, 2011;

• changes in natural gas, oil and NGL prices;

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

• drilling results;

• shortages of oilfield equipment, services and personnel;

• operating risks such as unexpected drilling conditions;

• weather conditions;

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

• the availability and cost of debt financing;

• changes in laws or regulations, including the implementation of the Dodd-Frank Act;

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

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

39

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, 2012. Based on such evaluation, such officers have concluded that, as of March 31, 2012, the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company’s  reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information is accumulated and communicated to the Company’s management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating the Company’s disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company’s controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Controls.

There were no changes in the Company’s internal controls over financial reporting during the quarter ended March 31, 2012, that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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.

Environmental Claims

United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah filed on February 28, 2008. The U.S. Environmental Protection Agency (EPA) alleges that QEP Field Services (f/k/a Questar Gas Management) violated the Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. Individual members of the Ute Indian Tribe’s Business Committee intervened as co-plaintiffs asserting the same CAA claims as the federal government. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for these facilities renders them “major sources” of emissions for criteria and hazardous air pollutants even though controls were installed and operated by QEP Field Services. Categorization of the facilities as “major sources” affects the particular regulatory program and requirements applicable to those facilities. EPA claims that QEP Field Services failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air pollutant regulations for monitoring, testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed, as part of their operational design, that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements applicable to non-major sources. QEP Field Services has vigorously defended itself against EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying EPA’s prior permitting practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all probable outcomes; however, management believes the Company has accrued an estimated loss contingency that is an immaterial amount, for the anticipated most likely outcome.

Litigation

Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for Oklahoma filed on January 20, 2011. This is a class action filed by a royalty owner on behalf of every QEP Energy royalty owner in the state of Oklahoma since 1988 asserting various claims for damages related to royalty valuation, including breach of contract, breach of fiduciary duty, fraud and conversion, based generally on asserted improper deduction of post-production costs. Because this case is in an early stage prior to full discovery, it is difficult to reasonably estimate potential liability. QEP Energy believes it has properly valued and paid royalty under Oklahoma law and will vigorously defend this claim.

40

ITEM 1A. RISK FACTORS.

Risk factors relating to the Company are set forth in its Annual Report on Form 10-K for the year ended December 31, 2011. No material changes to such risk factors has occurred during the three months ended March 31, 2012.

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

QEP had no unregistered sales of equity during the first quarter of 2012.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

None.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

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

Exhibit No.	Exhibits
31.1	Certification signed by C. B. Stanley, QEP Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification signed by Richard J. Doleshek, QEP Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification signed by C. B. Stanley and Richard J. Doleshek, QEP Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document
101.SCH	XBRL Schema Document
101.CAL	XBRL Calculation Linkbase Document
101.LAB	XBRL Label Linkbase Document
101.PRE	XBRL Presentation Linkbase Document
101.DEF	XBRL Definition Linkbase Document

41

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 26, 2012	/s/ C. B. Stanley
	C. B. Stanley,
	President and Chief Executive Officer
April 26, 2012	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President,
	Chief Financial Officer and Treasurer

42

Exhibit Index

Exhibit No.	Exhibits
31.1	Certification signed by C. B. Stanley, QEP Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification signed by Richard J. Doleshek, QEP Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification signed by C. B. Stanley and Richard J. Doleshek, QEP Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document
101.SCH	XBRL Schema Document
101.CAL	XBRL Calculation Linkbase Document
101.LAB	XBRL Label Linkbase Document
101.PRE	XBRL Presentation Linkbase Document
101.DEF	XBRL Definition Linkbase Document

43

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Charles B. Stanley, certify that:

1. I have reviewed this Form 10-Q of QEP Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

April 26, 2012

/s/ Charles B. Stanley

Charles B. Stanley

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard J. Doleshek, certify that:

1. I have reviewed this Form 10-Q of QEP Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

April 26, 2012

/s/ Richard J. Doleshek

Richard J. Doleshek

Executive Vice President, Chief Financial Officer and Treasurer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of QEP Resources, Inc. (the Company) on Form 10-Q for the period ended March 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the Report), C. B. Stanley, President and Chief Executive Officer of the Company, and Richard J. Doleshek, Executive Vice President, Chief Financial Officer and Treasurer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	QEP RESOURCES, INC.
April 26, 2012
	/s/ C. B. Stanley
	C. B. Stanley
	President and Chief Executive Officer
April 26, 2012
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President,
	Chief Financial Officer and Treasurer

XML

Restructuring Costs (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Restructuring Costs [Abstract]
Number of division offices to be consolidated	2
Number of regional offices created	1
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	$ 5.8
Restructuring costs incurred to date	2.7
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2011	0
Costs incurred and charged to expense	2.7
Costs paid or otherwise settled	(2.4)
Balance at March 31, 2012	0.3
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	1.7
Restructuring costs incurred to date	1.1
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.6
Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	$ 0.5

XML

Basis of Presentation of Interim Consolidated Financial Statements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
REVENUES
Natural gas sales	$ 161.2	$ 312.6
Oil sales	110.8	63.0
NGL sales	97.4	47.9
Gathering, processing and other	49.8	46.6
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs	33.9	21.7
Prior periods presentation of revenues
REVENUES
Natural gas sales		271.0	[1]
Oil sales		62.3	[1]
NGL sales		45.8	[1]
Gathering, processing and other		69.3	[1]
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		0	[1]
Restatement Adjustment [Member]
REVENUES
Natural gas sales		41.6
Oil sales		0.7
NGL sales		2.1
Gathering, processing and other		(22.7)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		$ 21.7

[1] In addition to the revision described above, QEP Field Services NGL sales of $28.6 million in the first quarter of 2011 have been reclassified from "Gathering, processing and other" into "NGL sales" in the as reported column to be consistent with current period presentation. QEP reported NGL sales of $17.2 million and Gathering, processing and other of $97.9 million in its first quarter 2011 Form 10-Q. The reclassification is all within Revenues and has no effect on income from continuing operations, net income or earnings per share.

XML

Capitalized Exploratory Well Costs (Tables)

3 Months Ended

Mar. 31, 2012

Capitalized Exploratory Well Costs (Tables) [Abstract]

Capitalized exploratory well costs

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

	Capitalized Exploratory Well Costs
	2012		2011
	(in millions)
Balance at January 1,	$	5.0	$	13.6
Additions to capitalized exploratory well costs pending the determination of proved reserves		-		-
Reclassifications to property, plant and equipment after the determination of proved reserves		-		(5.5	)
Balance at March 31,	$	5.0	$	8.1

XML

Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 1.0	$ 0.7
Interest cost	1.2	1.1
Expected return on plan assets	(0.9)	(0.6)
Amortization of prior service costs	1.3	1.3
Amortization of actuarial loss	0.2	0
Periodic expense	2.8	2.5
Pension Benefits [Member] | Funded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to unfunded pension plan	1.3
Expected to contribute to unfunded pension plans	5.0
Pension Benefits [Member] | Unfunded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to unfunded pension plan	1.0
Expected to contribute to unfunded pension plans	0.3
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0	0
Interest cost	0.1	0.1
Expected return on plan assets	0	0
Amortization of prior service costs	0.1	0.1
Amortization of actuarial loss	0	0
Periodic expense	$ 0.2	$ 0.2

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011	Dec. 31, 2010
Financial liabilities
Commodity derivative instruments - long-term	$ 0.1	$ 0
Fair Value, Measurements, Recurring [Member]
Financial Assets
Commodity derivative instruments - short-term	333.8	273.7
Commodity derivative instruments - long-term	115.6	123.5
Total financial assets	449.4	397.2
Financial liabilities
Commodity derivative instruments - short-term	0	1.3
Commodity derivative instruments - long-term	0.1	0
Total financial liabilities	0.1	1.3
Fair Value, Measurements, Recurring [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Financial Assets
Cash and cash equivalents	0	0
Financial liabilities
Checks outstanding in excess of cash balances	58.6	29.4
Long-term debt	1,673.5	1,679.4
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Financial Assets
Cash and cash equivalents	0	0
Financial liabilities
Checks outstanding in excess of cash balances	58.6	29.4
Long-term debt	1,770.8	1,754.9
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Financial Assets
Commodity derivative instruments - short-term	347.5	284.1
Commodity derivative instruments - long-term	115.8	123.5
Total financial assets	463.3	407.6
Financial liabilities
Commodity derivative instruments - short-term	11.6	11.7
Commodity derivative instruments - long-term	0.3	0
Total financial liabilities	11.9	11.7
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial Assets
Commodity derivative instruments - short-term	0	0
Commodity derivative instruments - long-term	0	0
Total financial assets	0	0
Financial liabilities
Commodity derivative instruments - short-term	2.1	0
Commodity derivative instruments - long-term	0	0
Total financial liabilities	2.1	0
Level 3 Unobservable input reconciliation [Roll Forward]
Balance at January 1,	(2.1)	0	23.2	36.3
Realized gains and losses	0	17.9
Unrealized gains and losses	(2.1)	(13.1)
Settlements	0	(17.9)
Balance at March 31,	(2.1)	0	23.2	36.3
Fair Value, Measurements, Recurring [Member] | Netting and Collateral [Member]
Financial Assets
Commodity derivative instruments - short-term	(13.7)	(10.4)
Commodity derivative instruments - long-term	(0.2)	0
Total financial assets	(13.9)	(10.4)
Financial liabilities
Commodity derivative instruments - short-term	(13.7)	(10.4)
Commodity derivative instruments - long-term	(0.2)	0
Total financial liabilities	$ (13.9)	$ (10.4)

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Earnings Per Share

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

Earnings Per Share

Note 3 – Earnings Per Share

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

Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company's unvested restricted stock awards contain nonforfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, the two class method will not have an effect on the Company's basic earnings per share. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share.

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

	Three Months Ended
	March 31,
	2012		2011
	(in millions)
Weighted-average basic common shares outstanding		177.4		176.2
Potential number of shares issuable under the Long-term Stock Incentive Plan		1.1		2.1
Average diluted common shares outstanding		178.5		178.3

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Operations by Line of Business (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Segment Reporting Information [Line Items]
Revenues from unaffiliated customers	$ 603.2	[1],[2]	$ 617.9	[1]
Revenues from affiliated companies	158.4		156.4
Operating (loss) income	49.5	[3]	137.1	[3]
Net income attributable to QEP	155.2		73.2
QEP Energy [Member]
Segment Reporting Information [Line Items]
Revenues from unaffiliated customers	396.8	[1],[2]	396.2	[1],[2]
Operating (loss) income	(12.9)	[3]	87.9	[3]
Net income attributable to QEP	108.1		43.1
QEP Field Services [Member]
Segment Reporting Information [Line Items]
Revenues from unaffiliated customers	93.6	[1],[2]	73.3	[1],[2]
Revenues from affiliated companies	26.1		23.3
Operating (loss) income	66.0	[3]	47.3	[3]
Net income attributable to QEP	45.4		28.0
QEP Marketing and Other [Member]
Segment Reporting Information [Line Items]
Revenues from unaffiliated customers	112.8	[1],[2]	148.4	[1],[2]
Revenues from affiliated companies	132.3		133.1
Operating (loss) income	(3.6)	[3]	1.9	[3]
Net income attributable to QEP	$ 1.7		$ 2.1

[1] Operating (loss) income in the first quarter of 2012 excludes the impact of realized commodity derivative contract settlements. During the first quarter of 2012 realized gains and losses from realized commodity derivative contract settlements were included below operating income. Conversely, under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the first quarter of 2011.

[2] Revenues for the three months ended March 31, 2011 have been recast to reflect QEP's revised reporting of its transportation and handling costs. See Note 2 "Basis of Presentation of Interim Consolidated Financial Statements" for additional information. In addition, revenues for the three months ended March 31, 2011 reflect the impact of QEP's settled derivative contracts which during the three months ended March 31, 2012 are reflected below operating income. See Note 7 "Derivative Contracts" for detailed information on derivative contract settlements in the first quarter of 2011.

[3] Net income attributable to QEP in the first quarter of 2012 includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contract. Conversely, under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the first quarter of 2011.

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Debt (Tables)

3 Months Ended

Mar. 31, 2012

Debt Disclosure [Abstract]

Debt Outstanding

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

	March 31,			December 31,
	2012			2011
	(in millions)
Revolving Credit Facility	$	100.5		$	606.5
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
5.375% Senior Notes due 2022		500.0			-
Total principal amount of debt		1,678.9			1,684.9
Less unamortized discount		(5.4	)		(5.5	)
Total long-term debt outstanding	$	1,673.5		$	1,679.4

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Restructuring Costs (Tables)

3 Months Ended

Mar. 31, 2012

Restructuring Costs [Abstract]

Reconciliation of QEP Energy's restructuring liability

The following is a reconciliation of QEP Energy's restructuring liability, which is included within “Accounts payable and accrued expenses” on the Condensed Consolidated Balance Sheets.

	Restructuring Costs
	(in millions)
Balance at December 31, 2011	$	-
Costs incurred and charged to expense		2.7
Costs paid or otherwise settled		(2.4	)
Balance at March 31, 2012	$	0.3

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Subsequent Events (Details) (Senior term loan [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Senior term loan [Member]
Subsequent Event [Line Items]
Senior term loan agreement amount	$ 300
Senior loan maturing date	Apr. 30, 2017
Extension period (in years)	1
Amount borrowed at closing	100
Senior term loan remaining availability	$ 200

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Share-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2012

Share-Based Compensation [Abstract]

Schedule of calculated fair value of options granted and major assumptions used

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, 2012
Fair value of options at grant date	$	14.49
Risk-free interest rate		0.81	%
Expected price volatility		55.9	%
Expected dividend yield		0.26	%
Expected life in years		5.0

Summary of stock option transactions under the terms of LTSIP

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

	Options Outstanding			Weighted- Average Price		Weighted-Average Remaining Contractual Term		Aggregate Intrinsic Value
				(per share)		(in years)		(in millions)
Outstanding at December 31, 2011		2,003,694		$	21.23
Granted		283,029			30.90
Exercised		(313,342	)		8.15
Forfeited		-			-
Outstanding at March 31, 2012		1,973,381		$	24.69		3.8	$	13.3
Options Excercisable at March 31, 2012		1,393,956		$	22.08		3.0	$	12.4
Unvested Options at March 31, 2012		579,425		$	30.97		6.0	$	0.9

Restricted Shares and Performance Share Units Activity

Transactions involving restricted shares under the terms of the LTSIP are summarized below:

	Restricted Shares Outstanding			Weighted- Average Price
				(per share)
Unvested balance at December 31, 2011		1,099,752		$	32.80
Granted		659,370			30.89
Vested		(362,743	)		32.85
Forfeited		(31,036	)		32.89
Unvested balance at March 31, 2012		1,365,343		$	31.87

Performance Share Units

Cash payouts are dependent upon the Company's total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units but delivered in cash at the end of the performance period. The weighted average grant-date fair value of the performance share units was $30.90 per share and $39.07 per share for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $4.4 million of unrecognized compensation cost, or the fair market value, related to performance shares granted under the CIP is expected to be recognized over a weighted-average vesting period of 2.6 years. Transactions involving performance shares units under the terms of the CIP are summarized below:

	Performance Share Units Outstanding			Weighted- Average Price
Unvested balance at December 31, 2011		115,274		$	39.07
Granted		168,448			30.90
Vested		-			-
Forfeited		(2,707	)		39.07
Unvested balance at March 31, 2012		281,015		$	34.17

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Employee Benefits (Tables)

3 Months Ended

Mar. 31, 2012

Employee Benefits [Abstract]

Pension and Other Postretirement Benefit Costs

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

	Pension						Postretirement benefits
	Three Months Ended March 31,						Three Months Ended March 31,
	2012			2011			2012		2011
	(in millions)
Service cost	$	1.0		$	0.7		$	-	$	-
Interest cost		1.2			1.1			0.1		0.1
Expected return on plan assets		(0.9	)		(0.6	)		-		-
Amortization of prior service costs		1.3			1.3			0.1		0.1
Amortization of actuarial loss		0.2			-			-		-
Periodic expense	$	2.8		$	2.5		$	0.2	$	0.2

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Basis of Presentation of Interim Consolidated Financial Statements

3 Months Ended

Mar. 31, 2012

Basis of Presentation of Interim Consolidated Financial Statements [Abstract]

Basis of Presentation of Interim Consolidated Financial Statements

Note 2 – Basis of Presentation of Interim Consolidated Financial Statements

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

The condensed consolidated financial statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

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, 2012, are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

De-designation of commodity derivative contracts

Effective January 1, 2012, QEP elected to discontinue hedge accounting prospectively. Accordingly, all realized and unrealized gains and losses will be recognized in earnings immediately each quarter as derivative contracts are settled and marked-to-market. For the first quarter of 2012 unrealized gains of $128.3 million were included in income that prior to January 1, 2012 would have been deferred in accumulated other comprehensive income under hedge accounting. Refer to Note 7 for additional information.

Transportation and other handling costs

In the fourth quarter of 2011, QEP revised its reporting of transportation and handling costs to reflect revenues in accordance with industry practice and GAAP. Transportation and handling costs, previously netted against revenues, have been recast on the Condensed Consolidated Income Statement from revenues to “Natural gas, oil and NGL transportation and other handling costs” for prior periods presented. The impact of this revision is immaterial to the accompanying financial statements and has no effect on income from continuing operations, net income, or earnings per share. The following table details the impact for the three months ended March 31, 2011, on the Condensed Consolidated Income Statement.

	As reported (1)		As revised		Change
	(in millions)
REVENUES
Natural gas sales	$	271.0	$	312.6	$	41.6
Oil sales		62.3		63.0		0.7
NGL sales		45.8		47.9		2.1
Gathering, processing and other		69.3		46.6		(22.7	)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		-		21.7		21.7

(1) In addition to the revision described above, QEP Field Services NGL sales of $28.6 million in the first quarter of 2011 have been reclassified from “Gathering, processing and other” into “NGL sales” in the as reported column to be consistent with current period presentation. QEP reported NGL sales of $17.2 million and Gathering, processing and other of $97.9 million in its first quarter 2011 Form 10-Q. The reclassification is all within Revenues and has no effect on income from continuing operations, net income or earnings per share.

Oil, Natural Gas, and NGL prices

Historically, field-prices received for QEP's natural gas, NGL, and crude oil production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than natural gas demand, driven by advances in technology, including horizontal drilling combined with multi-stage hydraulic fracturing, which have allowed producers to extract increasing amounts of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supply has put downward pressure on natural gas prices, while concern about the global economy and other factors has created volatility in the price of crude oil. Changes in the market prices for natural gas, crude oil, and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling activity and related capital expenditures, liquidity, rate of growth, costs of goods and services required to drill and complete wells, and the carrying value of its oil and natural gas properties.

New accounting pronouncements

In December of 2011, the FASB issued ASU 2011-11, which enhances disclosure requirements regarding an entity's financial instruments and derivative instruments that are offset or subject to a master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial statements to understand the effect of those arrangements on the entity's financial position, including the effect of rights of setoff. The amendments are required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. QEP is evaluating the impact of this ASU on its disclosure requirements.

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Operations by Line of Business (Tables)

3 Months Ended

Mar. 31, 2012

Operations by Line of Business [Abstract]

Summary of operating results by line of business

The following table is a summary of operating results by line of business:

	Three Months Ended
	March 31,
	2012			2011
	(in millions)
Revenues from unaffiliated customers (1) (2)
QEP Energy	$	396.8		$	396.2
QEP Field Services		93.6			73.3
QEP Marketing and other		112.8			148.4
Total	$	603.2		$	617.9
Revenues from affiliated companies
QEP Field Services	$	26.1		$	23.3
QEP Marketing and other		132.3			133.1
Total	$	158.4		$	156.4
Operating (loss) income (2)
QEP Energy	$	(12.9	)	$	87.9
QEP Field Services		66.0			47.3
QEP Marketing and other		(3.6	)		1.9
Total	$	49.5		$	137.1
Net income attributable to QEP
QEP Energy	$	108.1		$	43.1
QEP Field Services		45.4			28.0
QEP Marketing and other		1.7			2.1
Total	$	155.2		$	73.2

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Debt (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Total principal amount of debt	$ 1,678,900,000	$ 1,684,900,000
Less unamortized discount	(5,400,000)	(5,500,000)
Total long-term debt outstanding	1,673,500,000	1,679,400,000
Principal amount of senior notes outstanding	1,578,400,000
Senior Notes, stated interest rate, minimum (in hundredths)	5.375%
Senior Notes, stated interest rate, maximim (in hundredths)	6.875%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Total principal amount of debt	100,500,000	606,500,000
Maturity date of long-term debt	Aug. 25, 2016
Borrowing capacity	1,500,000,000
Potential increased borrowing capacity	2,000,000,000
Weighted-average interest rate (in hundredths)	2.06%
Number of maturity date extentions	2
Amount outstanding	100,500,000
Letters of credit outstanding	4,100,000
Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	176,800,000	176,800,000
Long-term debt, interest rate (in hundredths)	6.05%
Maturity date of long-term debt	Sep. 01, 2016
Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	138,600,000	138,600,000
Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	138,000,000	138,000,000
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	625,000,000	625,000,000
Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	500,000,000	0
Long-term debt, interest rate (in hundredths)	5.375%
Proceeds from issuance of debt	493,000,000
Debt issuance costs	$ 7,000,000

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
REVENUES
Natural gas sales	$ 161.2		$ 312.6
Oil sales	110.8		63.0
NGL sales	97.4		47.9
Gathering, processing and other	49.8		46.6
Purchased gas and oil sales	184.0		147.8
Total Revenues	603.2	[1],[2]	617.9	[1]
OPERATING EXPENSES
Purchased gas and oil expense	188.4		146.7
Lease operating expense	34.5		32.8
Natural gas, oil and NGL transportation and other handling costs	33.9		21.7
Gathering, processing and other	23.7		25.2
General and administrative	36.0		31.7
Production and property taxes	24.7		23.7
Depreciation, depletion and amortization	199.2		190.8
Exploration expenses	2.0		2.8
Abandonment and impairment	6.6		5.4
Total Operating Expenses	555.2		480.8
Net gain from asset sales	1.5		0
OPERATING INCOME	49.5	[3]	137.1	[3]
Realized and unrealized gains on commodity derivative instruments (see Note 7)	216.3		0
Interest and other income	1.7		0.6
Income from unconsolidated affiliates	1.9		0.9
Interest expense	(24.7)		(22.1)
INCOME BEFORE INCOME TAXES	244.7		116.5
Income taxes	(88.7)		(42.7)
NET INCOME	156.0		73.8
Net income attributable to noncontrolling interest	(0.8)		(0.6)
NET INCOME ATTRIBUTABLE TO QEP	$ 155.2		$ 73.2
Earnings Per Common Share Attributable to QEP
Basic total	$ 0.87		$ 0.42
Diluted total	$ 0.87		$ 0.41
Weighted-average common shares outstanding
Used in basic calculation	177.4		176.2
Used in diluted calculation	178.5		178.3
Dividends per common share	$ 0.02		$ 0.02

[1] Operating (loss) income in the first quarter of 2012 excludes the impact of realized commodity derivative contract settlements. During the first quarter of 2012 realized gains and losses from realized commodity derivative contract settlements were included below operating income. Conversely, under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the first quarter of 2011.

[2] Revenues for the three months ended March 31, 2011 have been recast to reflect QEP's revised reporting of its transportation and handling costs. See Note 2 "Basis of Presentation of Interim Consolidated Financial Statements" for additional information. In addition, revenues for the three months ended March 31, 2011 reflect the impact of QEP's settled derivative contracts which during the three months ended March 31, 2012 are reflected below operating income. See Note 7 "Derivative Contracts" for detailed information on derivative contract settlements in the first quarter of 2011.

[3] Net income attributable to QEP in the first quarter of 2012 includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contract. Conversely, under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the first quarter of 2011.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
OPERATING ACTIVITIES
Net income	$ 156.0	$ 73.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	199.2	190.8
Deferred income taxes	69.1	40.0
Abandonment and impairment	6.6	5.4
Share-based compensation	5.7	7.4
Amortization of debt issuance costs and discounts	1.1	0.8
Dry exploratory well expense	0.1	0.6
Net gain from asset sales	(1.5)	0
Income from unconsolidated affiliates	(1.9)	(0.9)
Distributions from unconsolidated affiliates and other	1.6	1.8
Unrealized gain on derivative contracts	(128.3)	(31.2)
Changes in operating assets and liabilities	20.8	10.9
Net Cash Provided by Operating Activities	328.5	299.4
INVESTING ACTIVITIES
Property acquisitions	(1.4)	(22.1)
Property, plant and equipment, including dry exploratory well expense	(336.5)	(320.4)
Proceeds from disposition of assets	3.3	0.9
Net Cash Used in Investing Activities	(334.6)	(341.6)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	29.2	5.9
Long-term debt issued	500.0	0
Long-term debt issuance costs paid	(6.9)	0
Current portion long-term debt repaid	0	(58.5)
Proceeds from credit facility	120.0	200.0
Repayments of credit facility	(626.0)	(100.0)
Other capital contributions	(6.9)	(0.8)
Dividends paid	(3.6)	(3.5)
Excess tax benefit on share-based compensation	2.0	0.4
Distribution from Questar	0	0.2
Distribution to noncontrolling interest	(1.7)	(1.5)
Net Cash Provided by Financing Activities	6.1	42.2
Change in cash and cash equivalents	0	0
Beginning cash and cash equivalents	0	0
Ending cash and cash equivalents	0	0
Supplemental Disclosures:
Cash paid for interest	39.6	44.2
Cash paid (received) for income taxes	(2.6)	(10.8)
Increase (decrease) in non-cash capital expenditure accruals	$ 3.5	$ (27.7)

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011	Dec. 31, 2010
ARO Liability [Roll Forward]
ARO liability at January 1,	$ 167.7	$ 152.4	$ 163.9	$ 148.3
Accretion	2.5	2.3
Liabilities incurred	1.6	2.0
Liabilities settled	(0.3)	(0.2)
ARO liability at March 31,	$ 167.7	$ 152.4	$ 163.9	$ 148.3

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Basis of Presentation of Interim Consolidated Financial Statements (Tables)

3 Months Ended

Mar. 31, 2012

Basis of Presentation of Interim Consolidated Financial Statements [Abstract]

Impact of change in transportation and other handling costs

The following table details the impact for the three months ended March 31, 2011, on the Condensed Consolidated Income Statement.

	As reported (1)		As revised		Change
	(in millions)
REVENUES
Natural gas sales	$	271.0	$	312.6	$	41.6
Oil sales		62.3		63.0		0.7
NGL sales		45.8		47.9		2.1
Gathering, processing and other		69.3		46.6		(22.7	)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		-		21.7		21.7

(1) In addition to the revision described above, QEP Field Services NGL sales of $28.6 million in the first quarter of 2011 have been reclassified from “Gathering, processing and other” into “NGL sales” in the as reported column to be consistent with current period presentation. QEP reported NGL sales of $17.2 million and Gathering, processing and other of $97.9 million in its first quarter 2011 Form 10-Q. The reclassification is all within Revenues and has no effect on income from continuing operations, net income or earnings per share.

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Capitalized Exploratory Well Costs (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011	Dec. 31, 2010
Capitalized exploratory well costs [Roll Forward]
Balance at January 1,	$ 5.0	$ 8.1	$ 5.0	$ 13.6
Additions to capitalized exploratory well costs pending the determination of proved reserves	0	0
Reclassifications to property, plant and equipment after the determination of proved reserves	0	(5.5)
Balance at March 31,	$ 5.0	$ 8.1	$ 5.0	$ 13.6

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2012

Asset Retirement Obligations [Abstract]

Asset retirement obligations roll forward

Changes in ARO were as follows:

	Asset Retirement Obligations
	2012			2011
	(in millions)
ARO liability at January 1,	$	163.9		$	148.3
Accretion		2.5			2.3
Liabilities incurred		1.6			2.0
Liabilities settled		(0.3	)		(0.2	)
ARO liability at March 31,	$	167.7		$	152.4

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Nature of Business

3 Months Ended

Mar. 31, 2012

Nature Of Business [Abstract]

Nature of Business

Note 1 – Nature of Business

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

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

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

• QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil, provides risk–management services, and owns and operates an underground gas-storage reservoir.

Operations are focused in the Northern Region (Rockies) and Southern Region (primarily Oklahoma, Louisiana, and the Texas Panhandle) of the United States. Company headquarters are located in Denver, Colorado. Shares of QEP common stock trade on the New York Stock Exchange (NYSE:QEP).

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Net income	$ 156.0		$ 73.8
Other comprehensive income (loss), net of tax:
Reclassification of previously deferred derivative gains and losses to net income	(47.0)	[1]	(47.8)	[1]
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss	0.1	[2]	0
Amortization of prior service cost	0.9	[3]	0
Total pension and other postretirement plans adjustments	1.0		0
Other comprehensive income	(46.0)		(47.8)
Comprehensive income	110.0		26.0
Comprehensive income attributable to noncontrolling interests	(0.8)		(0.6)
Comprehensive income attributable to QEP	109.2		25.4
Income tax benefit of reclassification of derivative gains and losses	27.8		28.3
Income tax expense of amortization of net actuarial loss	0.1
Income tax expense of amortization of prior service cost	$ 0.5

[1] Presented net of income tax benefit of $27.8 million and $28.3 million during the three months ended March 31, 2012 and 2011, respectively.

[2] Presented net of income tax expense of $0.1 million during the three months ended March 31, 2012.

[3] Presented net of income tax expense of $0.5 million during the three months ended March 31, 2012.

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Share-Based Compensation

3 Months Ended

Mar. 31, 2012

Share-Based Compensation [Abstract]

Share-Based Compensation

Note 11 – Share-Based Compensation

QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance-based share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over time as the stock options, restricted shares, and performance based share units vest. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 13.2 million shares available for future grants under the LTSIP at March 31, 2012. Share-based compensation expense is recognized in “General and administrative” on the Condensed Consolidated Income Statements. During the three months ended March 31, 2012 and 2011, QEP recognized $5.7 million and $7.4 million, respectively, in total compensation expense related to share-based compensation.

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for measuring the value of options traded on an exchange. The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:

	Stock Option Variables Three Months Ended March 31, 2012
Fair value of options at grant date	$	14.49
Risk-free interest rate		0.81	%
Expected price volatility		55.9	%
Expected dividend yield		0.26	%
Expected life in years		5.0

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

	Options Outstanding			Weighted- Average Price		Weighted-Average Remaining Contractual Term		Aggregate Intrinsic Value
				(per share)		(in years)		(in millions)
Outstanding at December 31, 2011		2,003,694		$	21.23
Granted		283,029			30.90
Exercised		(313,342	)		8.15
Forfeited		-			-
Outstanding at March 31, 2012		1,973,381		$	24.69		3.8	$	13.3
Options Excercisable at March 31, 2012		1,393,956		$	22.08		3.0	$	12.4
Unvested Options at March 31, 2012		579,425		$	30.97		6.0	$	0.9

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $6.9 million and $1.8 million during the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $5.4 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.6 years.

Restricted Shares

Restricted share grants typically vest in equal installments over a three or four-year period from the grant date. The total fair value of restricted stock that vested was $11.6 million and $7.9 million during the three months ended March 31, 2012 and 2011, respectively. The weighted average grant-date fair value of restricted stock was $30.89 per share and $39.00 per share for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $30.0 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.6 years. Transactions involving restricted shares under the terms of the LTSIP are summarized below:

	Restricted Shares Outstanding			Weighted- Average Price
				(per share)
Unvested balance at December 31, 2011		1,099,752		$	32.80
Granted		659,370			30.89
Vested		(362,743	)		32.85
Forfeited		(31,036	)		32.89
Unvested balance at March 31, 2012		1,365,343		$	31.87

Performance Share Units

Cash payouts are dependent upon the Company's total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units but delivered in cash at the end of the performance period. The weighted average grant-date fair value of the performance share units was $30.90 per share and $39.07 per share for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, $4.4 million of unrecognized compensation cost, or the fair market value, related to performance shares granted under the CIP is expected to be recognized over a weighted-average vesting period of 2.6 years. Transactions involving performance shares units under the terms of the CIP are summarized below:

	Performance Share Units Outstanding			Weighted- Average Price
Unvested balance at December 31, 2011		115,274		$	39.07
Granted		168,448			30.90
Vested		-			-
Forfeited		(2,707	)		39.07
Unvested balance at March 31, 2012		281,015		$	34.17

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Document And Entity Information (USD $) In Billions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Jun. 30, 2011
Entity Registrant Name	QEP RESOURCES, INC.
Entity Central Index Key	0001108827
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 7,399,937,572
Entity Common Stock, Shares Outstanding	178,386,261
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2012

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Employee Benefits

3 Months Ended

Mar. 31, 2012

Employee Benefits [Abstract]

Employee Benefits

Note 12 – Employee Benefits

The Company has both qualified and supplemental plans defined-benefit pension plans. The Company also has postretirement benefits that provide certain health care and life insurance benefits for certain retired employees. During the three months ended March 31, 2012, the Company made contributions of $1.3 million to its funded pension plan, and $1.0 million to its unfunded pension plan. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. During the remainder of 2012, the Company expects to contribute approximately $5.0 million to its funded pension plans, and approximately $0.3 million to its unfunded pension plans. The following table sets forth the Company's pension and postretirement benefits net period benefit costs:

	Pension						Postretirement benefits
	Three Months Ended March 31,						Three Months Ended March 31,
	2012			2011			2012		2011
	(in millions)
Service cost	$	1.0		$	0.7		$	-	$	-
Interest cost		1.2			1.1			0.1		0.1
Expected return on plan assets		(0.9	)		(0.6	)		-		-
Amortization of prior service costs		1.3			1.3			0.1		0.1
Amortization of actuarial loss		0.2			-			-		-
Periodic expense	$	2.8		$	2.5		$	0.2	$	0.2

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 0	$ 0
Accounts receivable, net	303.5	397.4
Fair value of derivative contracts	333.8	273.7
Inventories, at lower of average cost or market
Gas, oil and NGL	10.9	16.2
Materials and supplies	86.6	87.6
Prepaid expenses and other	40.6	43.7
Total Current Assets	775.4	818.6
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	8,468.3	8,172.4
Unproved properties, not being depleted	316.0	326.8
Midstream field services	1,510.8	1,463.6
Marketing and other	51.6	49.8
Total Property, Plant and Equipment	10,346.7	10,012.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	3,519.9	3,339.2
Midstream field services	312.2	297.5
Marketing and other	15.5	14.6
Total Accumulated Depreciation, Depletion and Amortization	3,847.6	3,651.3
Net Property, Plant and Equipment	6,499.1	6,361.3
Investment in unconsolidated affiliates	42.6	42.2
Goodwill	59.5	59.5
Fair value of derivative contracts	115.6	123.5
Other noncurrent assets	40.9	37.6
TOTAL ASSETS	7,533.1	7,442.7
Current Liabilities
Checks outstanding in excess of cash balances	58.6	29.4
Accounts payable and accrued expenses	380.7	457.3
Production and property taxes	43.5	40.0
Interest payable	8.9	24.4
Fair value of derivative contracts	0	1.3
Deferred income taxes	57.6	85.4
Total Current Liabilities	549.3	637.8
Long-term debt	1,673.5	1,679.4
Deferred income taxes	1,554.5	1,484.7
Asset retirement obligations	167.7	163.9
Fair value of derivative contracts	0.1	0
Other long-term liabilities	130.3	124.8
Commitments and contingencies
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized 178.4 million and 177.2 million shares issued, respectively	1.8	1.8
Treasury stock - 0.7 million and 0.4 million shares, respectively	(23.4)	(13.1)
Additional paid-in capital	442.6	431.4
Retained earnings	2,825.1	2,673.5
Accumulated other comprehensive income	161.9	207.9
Total Common Shareholders' Equity	3,408.0	3,301.5
Noncontrolling interest	49.7	50.6
Total Equity	3,457.7	3,352.1
TOTAL LIABILITIES AND EQUITY	$ 7,533.1	$ 7,442.7

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Fair Value Measurements

3 Months Ended

Mar. 31, 2012

Fair Value Measurements [Abstract]

Fair Value Measurements

Note 6 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures”. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements, but does not change existing guidance as to whether or not an instrument is carried at fair value. ASC 820 also establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. At March 31, 2012, the Company does not have Level 1 fair value measurements since it uses a broker to access the futures market. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. QEP's Level 2 fair value measurements consist of fixed-price swaps of natural gas, oil and NGL. Level 3 inputs are unobservable inputs for the asset or liability. QEP's Level 3 measurements are made up of costless collars for natural gas and oil. The Level 2 fair value of derivative contracts (see Note 7 “Derivative Contracts”) 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 computed by QEP's risk management group using the Black-Scholes option pricing model with observable inputs from the NYMEX futures prices, LIBOR one year interest rates, credit default swap rates, and unobservable input of volatility computed from historical prices using the Black-Scholes model.

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

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

QEP did not have any assets or liabilities measured at fair value on a non-recurring basis, other than ARO's and property, plant and equipment values for purposes of determining the impairment calculation, at March 31, 2012, or at December 31, 2011. The fair value of financial assets and financial liabilities at March 31, 2012, is shown in the table below:

	Fair Value Measurements
	March 31, 2012
	Level 2		Level 3		Netting Adjustments			Total
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	347.5	$	-	$	(13.7	)	$	333.8
Commodity derivative instruments - long-term		115.8		-		(0.2	)		115.6
Total financial assets	$	463.3	$	-	$	(13.9	)	$	449.4
Financial Liabilities
Commodity derivative instruments - short-term	$	11.6	$	2.1	$	(13.7	)	$	-
Commodity derivative instruments - long-term		0.3		-		(0.2	)		0.1
Total financial liabilities	$	11.9	$	2.1	$	(13.9	)	$	0.1

The change in the fair value of Level 3 commodity derivative instruments assets and liabilities for the three months ended March 31, 2012, is shown below:

	Change in Level 3 Fair Value Measurements
	2012			2011
	(in millions)
Balance at January 1,	$	-		$	36.3
Realized gains and losses		-			17.9
Unrealized gains and losses		(2.1	)		(13.1	)
Settlements		-			(17.9	)
Balance at March 31,	$	(2.1	)	$	23.2

The fair value of financial assets and financial liabilities at December 31, 2011, is shown in the table below:

	Fair Value Measurements
	December 31, 2011
	Level 2		Level 3		Netting Adjustments			Total
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	284.1	$	-	$	(10.4	)	$	273.7
Commodity derivative instruments - long-term		123.5		-		-			123.5
Total financial assets	$	407.6	$	-	$	(10.4	)	$	397.2
Financial Liabilities
Commodity derivative instruments - short-term	$	11.7	$	-	$	(10.4	)	$	1.3
Commodity derivative instruments - long-term		-		-		-			-
Total financial liabilities	$	11.7	$	-	$	(10.4	)	$	1.3

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

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	March 31, 2012				December 31, 2011
	(in millions)
Financial assets
Cash and cash equivalents	$	-	$	-	$	-	$	-
Financial liabilities
Checks outstanding in excess of cash balances	$	58.6	$	58.6	$	29.4	$	29.4
Long-term debt		1,673.5		1,770.8		1,679.4		1,754.9

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.

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Capitalized Exploratory Well Costs

3 Months Ended

Mar. 31, 2012

Capitalized Exploratory Well Costs (Tables) [Abstract]

Capitalized Exploratory Well Costs

Note 5 – Capitalized Exploratory Well Costs

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

	Capitalized Exploratory Well Costs
	2012		2011
	(in millions)
Balance at January 1,	$	5.0	$	13.6
Additions to capitalized exploratory well costs pending the determination of proved reserves		-		-
Reclassifications to property, plant and equipment after the determination of proved reserves		-		(5.5	)
Balance at March 31,	$	5.0	$	8.1

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

Components of basic and diluted shares used in EPS

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

	Three Months Ended
	March 31,
	2012		2011
	(in millions)
Weighted-average basic common shares outstanding		177.4		176.2
Potential number of shares issuable under the Long-term Stock Incentive Plan		1.1		2.1
Average diluted common shares outstanding		178.5		178.3

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Operations by Line of Business

3 Months Ended

Mar. 31, 2012

Operations by Line of Business [Abstract]

Operations by Line of Business

Note 13 – Operations by Line of Business

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

	Three Months Ended
	March 31,
	2012			2011
	(in millions)
Revenues from unaffiliated customers (1) (2)
QEP Energy	$	396.8		$	396.2
QEP Field Services		93.6			73.3
QEP Marketing and other		112.8			148.4
Total	$	603.2		$	617.9
Revenues from affiliated companies
QEP Field Services	$	26.1		$	23.3
QEP Marketing and other		132.3			133.1
Total	$	158.4		$	156.4
Operating (loss) income (2)
QEP Energy	$	(12.9	)	$	87.9
QEP Field Services		66.0			47.3
QEP Marketing and other		(3.6	)		1.9
Total	$	49.5		$	137.1
Net income attributable to QEP
QEP Energy	$	108.1		$	43.1
QEP Field Services		45.4			28.0
QEP Marketing and other		1.7			2.1
Total	$	155.2		$	73.2

(1) Revenues for the three months ended March 31, 2011 have been recast to reflect QEP's revised reporting of its transportation and handling costs. See Note 2 “Basis of Presentation of Interim Consolidated Financial Statements” for additional information. In addition, revenues for the three months ended March 31, 2011 reflect the impact of QEP's settled derivative contracts which during the three months ended March 31, 2012 are reflected below operating income. See Note 7 “Derivative Contracts” for detailed information on derivative contract settlements in the first quarter of 2011.

(2) Operating (loss) income in the first quarter of 2012 excludes the impact of realized commodity derivative contract settlements. During the first quarter of 2012 realized gains and losses from realized commodity derivative contract settlements were included below operating income. Conversely, under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the first quarter of 2011.

(3) Net income attributable to QEP in the first quarter of 2012 includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contract. Conversely, under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the first quarter of 2011.

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Debt

3 Months Ended

Mar. 31, 2012

Debt Disclosure [Abstract]

Debt

Note 9 – Debt

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

	March 31,			December 31,
	2012			2011
	(in millions)
Revolving Credit Facility	$	100.5		$	606.5
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
5.375% Senior Notes due 2022		500.0			-
Total principal amount of debt		1,678.9			1,684.9
Less unamortized discount		(5.4	)		(5.5	)
Total long-term debt outstanding	$	1,673.5		$	1,679.4

Of the total debt outstanding on March 31, 2012, the $100.5 million drawn under the revolving credit facility (described below) due August 25, 2016, and the 6.05% Senior Notes due September 1, 2016, will mature within the next five years.

Credit Arrangements

QEP's revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a syndicate of financial institutions. The revolving credit facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The revolving credit agreement also contains provisions that would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for up to two additional one-year periods. During the first quarter of 2012, QEP's weighted-average interest rate on borrowings from its credit facility was 2.06%. At March 31, 2012, and December 31, 2011, QEP was in compliance with all of its debt covenants. At March 31, 2012 QEP had $100.5 million drawn and $4.1 million in letters of credit outstanding under the credit facility.

Senior Notes

During the first quarter of 2012, the Company issued $500 million of Senior Notes due October 2022, with a coupon of 5.375%. The senior notes were issued at face value. Interest on the senior notes will be paid semi-annually, in April and October of each respective year. The net proceeds of approximately $493.0 million were used to repay indebtedness under QEP Resources' revolving credit facility. The finance costs incurred of approximately $7.0 million will be deferred and amortized over the life of the senior notes. The amortization of all of the Company's deferred finance costs is included in “Interest expense” on the Condensed Consolidated Income Statement.

At March 31, 2012, the Company has $1,578.4 million principal amount of senior notes outstanding with maturities ranging from September 2016 to October 2022 and coupons ranging from 5.375% to 6.875%. The senior notes pay interest semi-annually, are unsecured, senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indenture governing QEP's senior notes contains customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets.

See Note 14 for additional information regarding the term loan agreement entered into after the balance sheet date.

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Derivative Contracts

3 Months Ended

Mar. 31, 2012

Derivative Contracts [Abstract]

Derivative Contracts

Note 7 – Derivative Contracts

QEP uses commodity price derivative instruments in the normal course of business. QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. 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 instruments typically limit future gains from favorable price movements. The volume of production subject to derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into derivative contracts for up to 100% of forecasted production from proved reserves. QEP does not enter into derivative instruments for speculative purposes.

QEP uses derivative instruments known as fixed-price swaps and costless collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Costless collars are combinations of put and call options that have a floor price and a ceiling price and payments are made or received only if the settlement price is outside the range between the floor and ceiling prices. QEP's derivative instruments do not require the physical delivery of natural gas, crude oil, or NGL between the parties at settlement. Swap and costless collar transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Natural gas price derivative instruments are typically structured as fixed-price swaps at regional price indices. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma. NGL price derivative instruments are typically structured as Mont Belvieu, Texas fixed-price swaps.

QEP enters into derivative transactions that do not have margin requirements or collateral provisions that would require payments prior to the scheduled 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 avoids concentration of credit exposure by transacting with multiple counterparties.

All derivative instruments are recorded on the Condensed Consolidated Balance Sheets as either assets or liabilities measured at their fair values. Reporting changes in the fair value of derivatives depend upon whether the derivative instrument has been designated as a cash flow hedge and 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. Through December 31, 2011, QEP designated most of its natural gas, oil and NGL derivative contracts as cash flow hedges, whose unrealized fair value gains and losses were recorded to Accumulated Other Comprehensive Income (AOCI). Effective January 1, 2012, QEP elected to de-designate all of its natural gas, oil and NGL derivative contracts that had previously been designated as cash flow hedges and discontinue hedge accounting prospectively. As a result, as of January 1, 2012, QEP will recognize all gains and losses from changes in the fair value of natural gas, oil and NGL derivative contracts immediately in earnings rather than deferring any such amounts in AOCI. At December 31, 2011, AOCI consisted of $395.9 million ($248.6 million after tax) of unrealized gains, representing the mark-to-market value of QEP's cash flow hedges at December 31, 2011, less any ineffectiveness recognized. As a result of discontinuing hedge accounting on January 1, 2012, the mark-to-market values at December 31, 2011 are frozen in AOCI as of the de-designation date and will be reclassified into the statement of income in future periods as the original hedged transactions occur and effect earnings. QEP expects to reclassify into earnings from AOCI the frozen value related to de-designated natural gas, oil and NGL hedges during the remainder of 2012 and in 2013. In addition, in connection with QEP's election to discontinue hedge accounting, all realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012 will be presented in the statement of income in “Realized and unrealized gains on commodity derivative contracts” below operating income.

QEP derivative contracts as a percentage of reported production

The following table details the percentage of reported production subject to commodity price derivative contracts for QEP Energy and QEP Field Services.

	Three Months Ended
	March 31,
	2012			2011
QEP Energy
Natural gas derivative volumes as a percent of QEP Energy natural gas production
Fixed price swaps		60	%		43	%
Costless collars		0	%		12	%
Oil derivative volumes as a percent of QEP Energy oil production
Fixed price swaps		37	%		0	%
Costless collars		15	%		35	%
NGL derivative volumes as a percent of QEP Energy NGL production
Fixed price swaps		16	%		0	%
Costless collars		0	%		0	%
QEP Field Services
Ethane derivative volumes as a percent of ethane volumes - QEP Field Services
Fixed price swaps		13	%		0	%
Propane derivative volumes as a percent of propane volumes - QEP Field Services
Fixed price swaps		71	%		0	%

QEP Energy Outstanding Derivative Contracts

The following table sets forth QEP Energy's volumes and average prices for its commodity derivative contracts as of March 31, 2012:

					Swaps		Collars
Year	Type of Contract	Index	Total Volumes		Average price per unit		Floor price		Ceiling price
			(in millions)
Natural gas sales			(MMBtu)
2012	Swap	NYMEX		57.8	$	4.72
2012	Swap	IFPEPL (1)		6.1		4.47
2012	Swap	IFNPCR (2)		65.4		4.69
2012	Swap	IFCNPTE (3)		7.7		2.67
2013	Swap	NYMEX		29.2		3.68
2013	Swap	IFNPCR (2)		65.7		5.66
Oil sales			(Bbls)
2012	Swap	NYMEX WTI		1.4	$	97.03
2012	Collar	NYMEX WTI		1.1			$	87.50	$	115.36
2013	Swap	NYMEX WTI		0.2		105.80
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		11.6	$	0.64
2012	Swap	Mt. Belvieu Propane		17.3	$	1.28

(1) Inside FERC monthly settlement index for the Panhandle Eastern Pipeline Company.

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

(3) Inside FERC monthly settlement index for Centerpoint East.

QEP Field Services Outstanding Derivative Contracts

QEP Field Services enters into commodity derivative transactions to manage price risk on extracted NGL volumes. The following table sets forth QEP Field Services' volumes and swap prices for its commodity derivative contracts as of March 31, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swap price per gallon
			(in millions)
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		11.6	$	0.64
2012	Swap	Mt. Belvieu Propane		9.6	$	1.35

QEP Marketing Outstanding Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage and to lock in a fixed price for some of its customers. The following table sets forth QEP Marketing's volumes and swap prices for its commodity derivative contracts as of March 31, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swaps price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2012	Swaps	IFNPCR (1)		1.7	$	4.15
2013	Swaps	IFNPCR (1)		1.2		4.57
Natural gas purchases			(MMBtu)
2012	Swaps	IFNPCR (1)		1.1	$	2.80

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

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

		Gross asset derivative  instruments fair value					Gross liability derivative  instruments fair value
	Balance Sheet line item	March 31, 2012		December 31, 2011		Balance Sheet line item	March 31, 2012		December 31, 2011
		(in millions)					(in millions)
Current
Commodity	Fair value of derivative contracts	$	347.5	$	284.1	Fair value of derivative contracts	$	13.7	$	11.7
Long-term:
Commodity	Fair value of derivative contracts		115.8		123.5	Fair value of derivative contracts		0.3		-
Total commodity derivative instruments		$	463.3	$	407.6		$	14.0	$	11.7

The effects and location of derivative transactions on the Condensed Consolidated Income Statements are summarized in the following tables.

		Three Months Ended March 31,
Derivatives not designated as hedging instruments	Location of gain (loss) recognized in earnings	2012			2011
		(in millions)
Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		$	85.7		$	(31.2	)
Oil derivative contracts			(2.7	)		-
NGL derivative contracts			0.4			-
QEP Field Services
NGL derivative contracts			1.1			-
QEP Marketing
Natural gas derivative contracts			3.5			-
Total realized gain (loss)	Realized and unrealized gains on commodity derivative instruments		88.0			(31.2	)

Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts			132.3			31.2
Oil derivative contracts			(11.5	)		-
NGL derivative contracts			2.9			-
QEP Field Services
NGL derivative contracts			3.0			-
QEP Marketing
Natural gas derivative contracts			1.6			-
Total unrealized gain (loss)	Realized and unrealized gains on commodity derivative instruments		128.3			31.2
Total realized and unrealized gain (loss)	Realized and unrealized gains on commodity derivative instruments	$	216.3		$	-

		Three Months Ended March 31,
Cash flow hedge derivative instruments	Location of gain (loss) recognized in earnings	2012		2011
Commodity derivatives			(in millions)
Gain (loss) on derivative instruments for the effective portion of hedge recognized in AOCI	Accumulated other comprehensive income (loss)	$	-	$	0.2
Gain (loss) reclassified from AOCI into income for effective portion of hedge	Natural gas sales		-		73.1
Gain (loss) reclassified from AOCI into income for effective portion of hedge	Oil sales		-		-
Gain (loss) reclassified from AOCI into income for effective portion of hedge	NGL sales		-		-
Gain (loss) reclassified from AOCI into income for effective portion of hedge	Marketing purchases		-		3.4
Gain (loss) recognized in income for the ineffective portion of hedges	Interest and other income		-		(0.2	)

It is estimated that derivative contracts that had a fair value at December 31, 2011 of $144.2 million will be settled and reclassified from AOCI to the Condensed Consolidated Statements of Income during the next twelve months.

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Restructuring Costs

3 Months Ended

Mar. 31, 2012

Restructuring Costs [Abstract]

Restructuring Costs

Note 8 – Restructuring Costs

During the first quarter of 2012, QEP announced the closure of its Oklahoma City office and consolidation of its two division offices in Oklahoma into one regional office in Tulsa. The creation of one office for QEP's Southern Region will increase QEP's efficiency, collaboration, and productivity over the long-term. As part of the restructuring plan and closure of the Oklahoma City office, the Company will incur costs associated with the severance and relocation of employees and other exit costs associated with the termination of the operating lease of its Oklahoma City office space. All costs will be incurred by QEP Energy and are reported within QEP Energy's financial statements. QEP anticipates total restructuring costs to be approximately $5.8 million, with $1.7 million of those costs relating to one-time termination benefits, $3.6 million relating to the retention and relocation of certain employees to the Tulsa office, and the remaining $0.5 million for the termination of the lease for the Oklahoma City office space. During the three months ended March 31, 2012, a total of $2.7 million of restructuring costs were incurred and recorded in “General and administrative” expense on the Condensed Consolidated Income Statement, of which $1.1 million related to one-time termination benefits. The remaining one-time termination benefits will be recognized ratably over the remaining transition period. QEP expects to recognize the remaining costs not yet incurred in the remainder of 2012. The relocation costs and contract termination costs will be recorded in future periods as the costs are incurred. The following is a reconciliation of QEP Energy's restructuring liability, which is included within “Accounts payable and accrued expenses” on the Condensed Consolidated Balance Sheets.

	Restructuring Costs
	(in millions)
Balance at December 31, 2011	$	-
Costs incurred and charged to expense		2.7
Costs paid or otherwise settled		(2.4	)
Balance at March 31, 2012	$	0.3

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Contingencies

3 Months Ended

Mar. 31, 2012

Contingencies [Abstract]

Contingencies

Note 10 – Contingencies

QEP is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company's financial position, results of operations or cash flows. In accordance with ASC 450, 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 or the minimum amount within a range of possible outcomes. The Company believes that the exposure to potential losses from its contingencies deemed as probable is immaterial. For claims deemed reasonably possible the Company does not have a range of potential exposure as an estimate cannot be made because the cases are in their early stages or have a large number of plaintiffs. Disclosures are provided for contingencies reasonably possible to occur which would have a material adverse effect on the Company's financial position, results of operations or cash flows but have not yet been accrued. Some of the claims involve numerous plaintiffs, 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. The following discussion describes the nature of QEP's major loss contingencies.

Environmental Claims

United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah filed on February 28, 2008. The U.S. Environmental Protection Agency (EPA) alleges that QEP Field Services (f/k/a Questar Gas Management) violated the Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. Individual members of the Ute Indian Tribe's Business Committee intervened as co-plaintiffs asserting the same CAA claims as the federal government. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for these facilities renders them “major sources” of emissions for criteria and hazardous air pollutants even though controls were installed and operated by QEP Field Services. Categorization of the facilities as “major sources” affects the particular regulatory program and requirements applicable to those facilities. EPA claims that QEP Field Services failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air pollutant regulations for monitoring, testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed, as part of their operational design, that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements applicable to non-major sources. QEP Field Services has vigorously defended itself against EPA's claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying EPA's prior permitting practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all probable outcomes; however, management believes the Company has accrued an estimated loss contingency that is an immaterial amount, for the anticipated most likely outcome.

Litigation

Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for Oklahoma filed on January 20, 2011. This is a class action filed by a royalty owner on behalf of every QEP Energy royalty owner in the state of Oklahoma since 1988 asserting various claims for damages related to royalty valuation, including breach of contract, breach of fiduciary duty, fraud and conversion, based generally on asserted improper deduction of post-production costs. Because this case is in an early stage prior to full discovery, it is difficult to reasonably estimate potential liability. QEP Energy believes it has properly valued and paid royalty under Oklahoma law and will vigorously defend this claim. Because of the complexities and uncertainties of this legal dispute and the number of plaintiffs, it is difficult to predict all reasonably possible outcomes; however, management believes, at this early litigation stage, the potential loss contingency is an immaterial amount.

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Earnings Per Share (Details) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Earnings Per Share [Abstract]
Weighted-average basic common shares outstanding	177.4	176.2
Potential number of shares issuable under the Long-term Stock Incentive Plan	1.1	2.1
Average diluted common shares outstanding	178.5	178.3

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Basis of Presentation of Interim Consolidated Financial Statements (Policies)

3 Months Ended

Mar. 31, 2012

Basis of Presentation of Interim Consolidated Financial Statements [Abstract]

De-designation of commodity derivative contracts

De-designation of commodity derivative contracts

Effective January 1, 2012, QEP elected to discontinue hedge accounting prospectively. Accordingly, all realized and unrealized gains and losses will be recognized in earnings immediately each quarter as derivative contracts are settled and marked-to-market. For the first quarter of 2012 unrealized gains of $128.3 million were included in income that prior to January 1, 2012 would have been deferred in accumulated other comprehensive income under hedge accounting. Refer to Note 7 for additional information

Transportation and other handling costs

Transportation and other handling costs

In the fourth quarter of 2011, QEP revised its reporting of transportation and handling costs to reflect revenues in accordance with industry practice and GAAP. Transportation and handling costs, previously netted against revenues, have been recast on the Condensed Consolidated Income Statement from revenues to “Natural gas, oil and NGL transportation and other handling costs” for prior periods presented. The impact of this revision is immaterial to the accompanying financial statements and has no effect on income from continuing operations, net income, or earnings per share. The following table details the impact for the three months ended March 31, 2011, on the Condensed Consolidated Income Statement.

	As reported (1)		As revised		Change
	(in millions)
REVENUES
Natural gas sales	$	271.0	$	312.6	$	41.6
Oil sales		62.3		63.0		0.7
NGL sales		45.8		47.9		2.1
Gathering, processing and other		69.3		46.6		(22.7	)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		-		21.7		21.7

(1) In addition to the revision described above, QEP Field Services NGL sales of $28.6 million in the first quarter of 2011 have been reclassified from “Gathering, processing and other” into “NGL sales” in the as reported column to be consistent with current period presentation. QEP reported NGL sales of $17.2 million and Gathering, processing and other of $97.9 million in its first quarter 2011 Form 10-Q. The reclassification is all within Revenues and has no effect on income from continuing operations, net income or earnings per share.

New accounting pronouncements

New accounting pronouncements

In December of 2011, the FASB issued ASU 2011-11, which enhances disclosure requirements regarding an entity's financial instruments and derivative instruments that are offset or subject to a master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial statements to understand the effect of those arrangements on the entity's financial position, including the effect of rights of setoff. The amendments are required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. QEP is evaluating the impact of this ASU on its disclosure requirements.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value Measurements [Abstract]

Fair value of financial assets and liabilities

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

	Fair Value Measurements
	March 31, 2012
	Level 2		Level 3		Netting Adjustments			Total
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	347.5	$	-	$	(13.7	)	$	333.8
Commodity derivative instruments - long-term		115.8		-		(0.2	)		115.6
Total financial assets	$	463.3	$	-	$	(13.9	)	$	449.4
Financial Liabilities
Commodity derivative instruments - short-term	$	11.6	$	2.1	$	(13.7	)	$	-
Commodity derivative instruments - long-term		0.3		-		(0.2	)		0.1
Total financial liabilities	$	11.9	$	2.1	$	(13.9	)	$	0.1

The fair value of financial assets and financial liabilities at December 31, 2011, is shown in the table below:

	Fair Value Measurements
	December 31, 2011
	Level 2		Level 3		Netting Adjustments			Total
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	284.1	$	-	$	(10.4	)	$	273.7
Commodity derivative instruments - long-term		123.5		-		-			123.5
Total financial assets	$	407.6	$	-	$	(10.4	)	$	397.2
Financial Liabilities
Commodity derivative instruments - short-term	$	11.7	$	-	$	(10.4	)	$	1.3
Commodity derivative instruments - long-term		-		-		-			-
Total financial liabilities	$	11.7	$	-	$	(10.4	)	$	1.3

Change in fair value of Level 3 assets and liabilities

The change in the fair value of Level 3 commodity derivative instruments assets and liabilities for the three months ended March 31, 2012, is shown below:

	Change in Level 3 Fair Value Measurements
	2012			2011
	(in millions)
Balance at January 1,	$	-		$	36.3
Realized gains and losses		-			17.9
Unrealized gains and losses		(2.1	)		(13.1	)
Settlements		-			(17.9	)
Balance at March 31,	$	(2.1	)	$	23.2

Fair value and related carrying amount of certain financial instruments

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

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	March 31, 2012				December 31, 2011
	(in millions)
Financial assets
Cash and cash equivalents	$	-	$	-	$	-	$	-
Financial liabilities
Checks outstanding in excess of cash balances	$	58.6	$	58.6	$	29.4	$	29.4
Long-term debt		1,673.5		1,770.8		1,679.4		1,754.9

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Share-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Share-Based Compensation [Abstract]
Shares available for future grants	13,200,000
Total compensation expense related to share-based compensation	$ 5.7	$ 7.4
Stock Options [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Fair value of options at grant date	$ 14.49
Risk-free interest rate	81.00%
Expected price volatility	55.90%
Expected dividend yield	0.26%
Expected life in years	5.0
Options Outstanding [RollForward]
Outstanding at December 31, 2011 (in shares)	2,003,694
Granted (in shares)	283,029
Exercised (in shares)	(313,342)
Forfeited (in shares)	0
Outstanding at March 31, 2012 (in shares)	1,973,381
Options Excercisable (in shares)	1,393,956
Unvested Options (in shares)	579,425
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning (in dollars per share)	$ 21.23
Weighted-Average Price, Granted (in dollars per share)	$ 30.90
Weighted-Average Price, Exercised (in dollars per share)	$ 8.15
Weighted-Average Price, Forfeited (in dollars per share)	$ 0
Weighted-Average Price, Ending (in dollars per share)	$ 24.69
Weighted-Average Price, Options Excercisable	$ 22.08
Weighted-Average Price, Unvested Options	$ 30.97
Weighted-Average Remaining Contractual Term, Outstanding (in years)	3.8
Aggregate Intrinsic Value, Outstanding	13.3
Weighted-Average Remaining Contractual Term, Options Excercisable (in years)	3.0
Aggregate Intrinsic Value, Options Excercisable	12.4
Weighted-Average Remaining Contractual Term, Unvested Options (in years)	6.0
Aggregate Intrinsic Value, Unvested Options	0.9
Intrinsic value of options exercised	6.9	1.8
Unrecognized compensation cost	5.4
Weighted-average period for recognition of compensation costs (in years)	2.6
Restricted Stock [Member]
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning balance (in dollars per share)	$ 32.80
Weighted-Average Price, Granted (in dollars per share)	$ 30.89	$ 39.00
Weighted-Average Price, Vested (in dollars per share)	$ 32.85
Weighted-Average Price, Forfeited (in dollars per share)	$ 32.89
Weighted-Average Price, Ending Balance (in dollars per share)	$ 31.87
Unrecognized compensation cost	30.0
Weighted-average period for recognition of compensation costs (in years)	2.6
Vesting period minimum (in years)	3Y
Vesting period maximum (in years)	4Y
Total fair value of stock that vested	11.6	7.9
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)	1,099,752
Granted (in shares)	659,633
Vested (in shares)	(362,743)
Forfeited (in shares)	(31,036)
Balance, Ending (in shares)	1,365,606
Performance Share Units [Member]
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning balance (in dollars per share)	$ 39.07
Weighted-Average Price, Granted (in dollars per share)	$ 30.90	$ 39.07
Weighted-Average Price, Vested (in dollars per share)	$ 0
Weighted-Average Price, Forfeited (in dollars per share)	$ 39.07
Weighted-Average Price, Ending Balance (in dollars per share)	$ 34.17
Unrecognized compensation cost	$ 4.4
Weighted-average period for recognition of compensation costs (in years)	2.6
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)	115,274
Granted (in shares)	168,448
Vested (in shares)	0
Forfeited (in shares)	(2,707)
Balance, Ending (in shares)	281,015

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
CONDENSED CONSOLIDATED BALANCE SHEETS [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500.0	500.0
Common stock, shares issued (in shares)	178.4	177.2
Treasury stock (in shares)	0.7	0.4

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2012

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

Note 4 – 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 from asset sales” in the Condensed Consolidated Statements of Income. Changes in ARO were as follows:

	Asset Retirement Obligations
	2012			2011
	(in millions)
ARO liability at January 1,	$	163.9		$	148.3
Accretion		2.5			2.3
Liabilities incurred		1.6			2.0
Liabilities settled		(0.3	)		(0.2	)
ARO liability at March 31,	$	167.7		$	152.4

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Derivative Contracts (Tables)

3 Months Ended

Mar. 31, 2012

Derivative Contracts [Abstract]

Commodity Derivatives as a Percentage of Reported Production

The following table details the percentage of reported production subject to commodity price derivative contracts for QEP Energy and QEP Field Services.

	Three Months Ended
	March 31,
	2012			2011
QEP Energy
Natural gas derivative volumes as a percent of QEP Energy natural gas production
Fixed price swaps		60	%		43	%
Costless collars		0	%		12	%
Oil derivative volumes as a percent of QEP Energy oil production
Fixed price swaps		37	%		0	%
Costless collars		15	%		35	%
NGL derivative volumes as a percent of QEP Energy NGL production
Fixed price swaps		16	%		0	%
Costless collars		0	%		0	%
QEP Field Services
Ethane derivative volumes as a percent of ethane volumes - QEP Field Services
Fixed price swaps		13	%		0	%
Propane derivative volumes as a percent of propane volumes - QEP Field Services
Fixed price swaps		71	%		0	%

Derivative Volumes and Average Prices

The following table sets forth QEP Energy's volumes and average prices for its commodity derivative contracts as of March 31, 2012:

					Swaps		Collars
Year	Type of Contract	Index	Total Volumes		Average price per unit		Floor price		Ceiling price
			(in millions)
Natural gas sales			(MMBtu)
2012	Swap	NYMEX		57.8	$	4.72
2012	Swap	IFPEPL (1)		6.1		4.47
2012	Swap	IFNPCR (2)		65.4		4.69
2012	Swap	IFCNPTE (3)		7.7		2.67
2013	Swap	NYMEX		29.2		3.68
2013	Swap	IFNPCR (2)		65.7		5.66
Oil sales			(Bbls)
2012	Swap	NYMEX WTI		1.4	$	97.03
2012	Collar	NYMEX WTI		1.1			$	87.50	$	115.36
2013	Swap	NYMEX WTI		0.2		105.80
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		11.6	$	0.64
2012	Swap	Mt. Belvieu Propane		17.3	$	1.28

(1) Inside FERC monthly settlement index for the Panhandle Eastern Pipeline Company.

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

(3) Inside FERC monthly settlement index for Centerpoint East.

QEP Field Services Outstanding Derivative Contracts

QEP Field Services enters into commodity derivative transactions to manage price risk on extracted NGL volumes. The following table sets forth QEP Field Services' volumes and swap prices for its commodity derivative contracts as of March 31, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swap price per gallon
			(in millions)
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		11.6	$	0.64
2012	Swap	Mt. Belvieu Propane		9.6	$	1.35

QEP Marketing Outstanding Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage and to lock in a fixed price for some of its customers. The following table sets forth QEP Marketing's volumes and swap prices for its commodity derivative contracts as of March 31, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swaps price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2012	Swaps	IFNPCR (1)		1.7	$	4.15
2013	Swaps	IFNPCR (1)		1.2		4.57
Natural gas purchases			(MMBtu)
2012	Swaps	IFNPCR (1)		1.1	$	2.80

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

Fair values of Derivatives by Balance Sheet Location

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

		Gross asset derivative  instruments fair value					Gross liability derivative  instruments fair value
	Balance Sheet line item	March 31, 2012		December 31, 2011		Balance Sheet line item	March 31, 2012		December 31, 2011
		(in millions)					(in millions)
Current
Commodity	Fair value of derivative contracts	$	347.5	$	284.1	Fair value of derivative contracts	$	13.7	$	11.7
Long-term:
Commodity	Fair value of derivative contracts		115.8		123.5	Fair value of derivative contracts		0.3		-
Total commodity derivative instruments		$	463.3	$	407.6		$	14.0	$	11.7

Effects of Derivative Transactions

The effects and location of derivative transactions on the Condensed Consolidated Income Statements are summarized in the following tables.

		Three Months Ended March 31,
Derivatives not designated as hedging instruments	Location of gain (loss) recognized in earnings	2012			2011
		(in millions)
Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		$	85.7		$	(31.2	)
Oil derivative contracts			(2.7	)		-
NGL derivative contracts			0.4			-
QEP Field Services
NGL derivative contracts			1.1			-
QEP Marketing
Natural gas derivative contracts			3.5			-
Total realized gain (loss)	Realized and unrealized gains on commodity derivative instruments		88.0			(31.2	)

Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts			132.3			31.2
Oil derivative contracts			(11.5	)		-
NGL derivative contracts			2.9			-
QEP Field Services
NGL derivative contracts			3.0			-
QEP Marketing
Natural gas derivative contracts			1.6			-
Total unrealized gain (loss)	Realized and unrealized gains on commodity derivative instruments		128.3			31.2
Total realized and unrealized gain (loss)	Realized and unrealized gains on commodity derivative instruments	$	216.3		$	-

		Three Months Ended March 31,
Cash flow hedge derivative instruments	Location of gain (loss) recognized in earnings	2012		2011
Commodity derivatives			(in millions)
Gain (loss) on derivative instruments for the effective portion of hedge recognized in AOCI	Accumulated other comprehensive income (loss)	$	-	$	0.2
Gain (loss) reclassified from AOCI into income for effective portion of hedge	Natural gas sales		-		73.1
Gain (loss) reclassified from AOCI into income for effective portion of hedge	Oil sales		-		-
Gain (loss) reclassified from AOCI into income for effective portion of hedge	NGL sales		-		-
Gain (loss) reclassified from AOCI into income for effective portion of hedge	Marketing purchases		-		3.4
Gain (loss) recognized in income for the ineffective portion of hedges	Interest and other income		-		(0.2	)

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Derivative Contracts (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended																																													3 Months Ended
	Mar. 31, 2012	Mar. 31, 2012 QEP Energy [Member] Natural gas derivative contracts [Member]	Mar. 31, 2011 QEP Energy [Member] Natural gas derivative contracts [Member]	Mar. 31, 2012 QEP Energy [Member] Oil derivative contracts [Member]	Mar. 31, 2011 QEP Energy [Member] Oil derivative contracts [Member]	Mar. 31, 2012 QEP Energy [Member] NGL derivative contracts [Member]	Mar. 31, 2011 QEP Energy [Member] NGL derivative contracts [Member]	Mar. 31, 2012 QEP Field Services [Member] NGL derivative contracts [Member]	Mar. 31, 2011 QEP Field Services [Member] NGL derivative contracts [Member]	Mar. 31, 2012 QEP Marketing [Member] Natural gas derivative contracts [Member]	Mar. 31, 2011 QEP Marketing [Member] Natural gas derivative contracts [Member]	Mar. 31, 2012 Realized and unrealized gains on commodity derivative instruments [Member]	Mar. 31, 2011 Realized and unrealized gains on commodity derivative instruments [Member]	Mar. 31, 2012 Accumulated other comprehensive income (loss) [Member]	Mar. 31, 2011 Accumulated other comprehensive income (loss) [Member]	Mar. 31, 2012 Natural Gas Sales [Member]	Mar. 31, 2011 Natural Gas Sales [Member]	Mar. 31, 2012 Oil Sales [Member]	Mar. 31, 2011 Oil Sales [Member]	Mar. 31, 2012 NGL Sales [Member]	Mar. 31, 2011 NGL Sales [Member]	Mar. 31, 2012 Marketing Purchases [Member]	Mar. 31, 2011 Marketing Purchases [Member]	Mar. 31, 2012 Interest and Other Income [Member]	Mar. 31, 2011 Interest and Other Income [Member]	Mar. 31, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2012 [Member] NYMEX [Member] Bcf	Mar. 31, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2012 [Member] IFPEPL [Member] MMBTU	Mar. 31, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2012 [Member] IFNPCR [Member] MMBTU	Mar. 31, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2012 [Member] IFCNPTE [Member] MMBTU	Mar. 31, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2013 [Member] NYMEX [Member] Bcf	Mar. 31, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2013 [Member] IFNPCR [Member] MMBTU	Mar. 31, 2012 Swap [Member] Oil Sales (Bbls) [Member] 2012 [Member] NYMEX WTI [Member] MMBbls	Mar. 31, 2012 Swap [Member] NGL Sales [Member] 2012 [Member] Mt. Belvieu Ethane [Member] gal	Mar. 31, 2012 Swap [Member] NGL Sales [Member] 2012 [Member] Mt. Belvieu Propane [Member] gal	Mar. 31, 2012 Swap [Member] QEP Field Services [Member] 2012 [Member] Mt. Belvieu Ethane [Member] gal	Mar. 31, 2012 Swap [Member] QEP Field Services [Member] 2012 [Member] Mt. Belvieu Propane [Member] gal	Mar. 31, 2012 Swap [Member] QEP Marketing [Member] 2012 [Member] IFNPCR [Member] MMBTU	Mar. 31, 2012 Swap [Member] QEP Marketing [Member] 2013 [Member] IFNPCR [Member] MMBTU	Mar. 31, 2012 Swap [Member] Purchased Gas and Oil Expense [Member] 2012 [Member] IFNPCR [Member] MMBTU	Mar. 31, 2012 Costless Collars [Member]	Dec. 31, 2011 Costless Collars [Member]	Mar. 31, 2012 Costless Collars [Member] Short-term [Member]	Dec. 31, 2011 Costless Collars [Member] Short-term [Member]	Mar. 31, 2012 Costless Collars [Member] Long-term [Member]	Dec. 31, 2011 Costless Collars [Member] Long-term [Member]	Mar. 31, 2012 Costless Collars [Member] Oil Sales (Bbls) [Member] 2012 [Member] NYMEX WTI [Member] MMBbls	Mar. 31, 2012 Costless Collars [Member] Oil Sales (Bbls) [Member] 2013 [Member] NYMEX WTI [Member] MMBbls	Mar. 31, 2012 QEP Energy [Member] Fixed-price swaps [Member] Natural Gas Sales (MMbtu) [Member]	Mar. 31, 2011 QEP Energy [Member] Fixed-price swaps [Member] Natural Gas Sales (MMbtu) [Member]	Mar. 31, 2012 QEP Energy [Member] Fixed-price swaps [Member] Oil Sales (Bbls) [Member]	Mar. 31, 2011 QEP Energy [Member] Fixed-price swaps [Member] Oil Sales (Bbls) [Member]	Mar. 31, 2012 QEP Energy [Member] Fixed-price swaps [Member] NGL Sales [Member]	Mar. 31, 2011 QEP Energy [Member] Fixed-price swaps [Member] NGL Sales [Member]	Mar. 31, 2012 QEP Energy [Member] Costless Collars [Member] Natural Gas Sales (MMbtu) [Member]	Mar. 31, 2011 QEP Energy [Member] Costless Collars [Member] Natural Gas Sales (MMbtu) [Member]	Mar. 31, 2012 QEP Energy [Member] Costless Collars [Member] Oil Sales (Bbls) [Member]	Mar. 31, 2011 QEP Energy [Member] Costless Collars [Member] Oil Sales (Bbls) [Member]	Mar. 31, 2012 QEP Energy [Member] Costless Collars [Member] NGL Sales [Member]	Mar. 31, 2011 QEP Energy [Member] Costless Collars [Member] NGL Sales [Member]	Mar. 31, 2012 QEP Field Services [Member] Fixed-price swaps [Member] Ethane Sales (Gals) [Member]	Mar. 31, 2011 QEP Field Services [Member] Fixed-price swaps [Member] Ethane Sales (Gals) [Member]	Mar. 31, 2012 QEP Field Services [Member] Fixed-price swaps [Member] Propane Sales (Gals) [Member]	Mar. 31, 2011 QEP Field Services [Member] Fixed-price swaps [Member] Propane Sales (Gals) [Member]
Derivative Contracts [Abstract]
Forecasted production from proved reserves (in hundredths)	100.00%
Unrealized gains on derivative contracts	$ 395.9
Unrealized gains on derivative contracts, net of tax	248.6
Derivative [Line Items]
Derivative volumes as a percent of production (in hundredths)																																																60.00%	43.00%	37.00%	0.00%	16.00%	0.00%	0.00%	12.00%	15.00%	35.00%	0.00%	0.00%	32.00%	0.00%	88.00%	0.00%
Derivatives, Fair Value [Line Items]
Derivative, Index																										NYMEX	IFPEPL	IFNPCR	IFCNPTE	NYMEX	IFNPCR	NYMEX WTI	Mt. Belvieu Ethane	Mt. Belvieu Propane	Mt. Belvieu Ethane	Mt. Belvieu Propane	IFNPCR	IFNPCR	IFNPCR							NYMEX WTI	NYMEX WTI
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)																										57.8	6.1	65.4	7.7	29.2	65.7	1.4	11.6	17.3	11.6	9.6	1.7	1.2	1.1							1.1	0.2
Average Swap price per unit ($ per unit)																										4.72	4.47	4.69	2.67	3.68	5.66	97.03	0.64	1.28	0.64	1.35	4.15	4.57	2.80								105.80
Collars Floor Price ($ per unit)																																														$ 87.50
Collars Ceiling Price ($ per unit)																																														$ 115
Derivative - Contract Year																										2012	2012	2012	2012	2013	2013	2012	2012	2012	2012	2012	2012	2013	2012							2012	2013
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross																																								463.3	407.6	347.5	284.1	115.8	123.5
Derivative Liability, Fair Value, Gross																																								14.0	11.7	13.7	11.7	0.3	0
Amount that will be settled and reclassified from AOCI to Consolidated Statement of Income during the next twelve months	144.2
Derivatives not designated as hedging instruments - Commodity derivatives [Abstract]
Realized gain (loss) on commodity derivative contracts		85.7	(31.2)	(2.7)	0	0.4	0	1.1	0	3.5	0	88.0	(31.2)
Unrealized gain (loss) on commodity derivative contracts		132.3	31.2	(11.5)	0	2.9	0	3.0	0	1.6	0	128.3	31.2
Total gain (loss) on commodity derivative instruments												216.3	0
Gain (loss) on derivative instruments for the effective portion of hedge recognized in AOCI [Abstract]
Gain (loss) on derivative instruments for the effective portion of hedge recognized in AOCI														0	0.2	0	73.1	0	0	0	0	0	3.4
Gain (loss) recognized in income for the ineffective portion of hedges [Abstract]
Interest and other income																								$ 0	$ (0.2)

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Subsequent Events

3 Months Ended

Mar. 31, 2012

Subsequent Events [Abstract]

Subsequent Events

Note 14 – Subsequent Events

In April 2012, the Company entered into a $300 million senior, unsecured term loan agreement with a group of financial institutions. The term loan agreement provides for borrowings at short-term interest rates and contains covenants, restrictions and interest rates that are substantially the same as the Company's existing revolving credit agreement. The term loan agreement matures in April of 2017, and the maturity date may be extended one year with the agreement of the lenders. At closing, the Company borrowed $100 million. The Company may borrow the remaining $200 million available under the term loan by June 30, 2012 at which time, any undrawn commitment under the facility will expire.