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 June 30, 2012

o 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	(Commission	(I.R.S. Employer
incorporation or organization	File Number)	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  o

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

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

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

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

At June 30, 2012, there were 177,769,238 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2012

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION			2
	ITEM 1.	FINANCIAL STATEMENTS	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2012 AND 2011	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2012 AND 2011	3
		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT JUNE 30, 2012 AND DECEMBER 31, 2011	4
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2012 AND 2011	5
		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	48
	ITEM 4.	CONTROLS AND PROCEDURES	51
PART II. OTHER INFORMATION			51
	ITEM 1.	LEGAL PROCEEDINGS	51
	ITEM 1A.	RISK FACTORS	52
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	52
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	52
	ITEM 4.	MINE SAFETY DISCLOSURES	52
	ITEM 5.	OTHER INFORMATION	52
	ITEM 6.	EXHIBITS	52
SIGNATURES			53

1

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions, except per share amounts)
REVENUES
Natural gas sales	$	138.9		$	298.7		$	300.1		$	611.3
Oil sales		107.2			80.7			218.0			143.7
NGL sales		82.1			63.8			179.5			111.7
Gathering, processing and other		45.8			58.9			95.6			105.5
Purchased gas, oil and NGL sales		125.3			306.0			309.3			453.8
Total Revenues		499.3			808.1			1,102.5			1,426.0
OPERATING EXPENSES
Purchased gas, oil and NGL expense		124.9			303.9			313.3			450.6
Lease operating expense		40.5			34.3			80.6			67.1
Natural gas, oil and NGL transportation and other handling costs		40.7			24.0			75.2			45.7
Gathering, processing and other		20.6			27.2			44.3			52.4
General and administrative		36.8			28.7			72.8			60.4
Production and property taxes		19.4			27.1			44.1			50.8
Depreciation, depletion and amortization		214.1			186.6			413.3			377.4
Exploration expenses		2.1			2.3			4.1			5.1
Abandonment and impairment		55.7			5.3			62.3			10.7
Total Operating Expenses		554.8			639.4			1,110.0			1,120.2
Net gain from asset sales		-			0.2			1.5			0.2
OPERATING (LOSS) INCOME		(55.5	)		168.9			(6.0	)		306.0
Realized and unrealized gains on derivative contracts (See Note 6)		82.3			-			298.6			-
Interest and other income (loss)		0.9			(0.4	)		2.6			0.2
Income from unconsolidated affiliates		1.4			1.3			3.3			2.2
Loss from early extinguishment of debt		(0.6	)		-			(0.6	)		-
Interest expense		(28.2	)		(22.1	)		(52.9	)		(44.2	)
INCOME BEFORE INCOME TAXES		0.3			147.7			245.0			264.2
Income taxes		(0.1	)		(54.2	)		(88.8	)		(96.9	)
NET INCOME		0.2			93.5			156.2			167.3
Net income attributable to noncontrolling interest		(0.9	)		(0.7	)		(1.7	)		(1.3	)
NET (LOSS) INCOME ATTRIBUTABLE TO QEP	$	(0.7	)	$	92.8		$	154.5		$	166.0
Earnings Per Common Share Attributable to QEP
Basic total	$	-		$	0.52		$	0.87		$	0.94
Diluted total	$	-		$	0.52		$	0.87		$	0.93
Weighted-average common shares outstanding
Used in basic calculation		177.7			176.6			177.6			176.4
Used in diluted calculation		177.7			178.6			178.5			178.5
Dividends per common share	$	0.02		$	0.02		$	0.04		$	0.04

See notes accompanying the condensed consolidated financial statements.

2

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Net income	$	0.2		$	93.5		$	156.2		$	167.3
Other comprehensive (loss) income, net of tax:
Reclassification of previously deferred derivative gains(1)		(44.7	)		(2.5	)		(91.7	)		(50.3	)
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss (2)		0.1			-			0.2			-
Amortization of prior service cost (3)		0.8			1.7			1.7			1.7
Total pension and other postretirement plans adjustments		0.9			1.7			1.9			1.7
Other comprehensive loss		(43.8	)		(0.8	)		(89.8	)		(48.6	)
Comprehensive (loss) income		(43.6	)		92.7			66.4			118.7
Comprehensive income attributable to noncontrolling interests		(0.9	)		(0.7	)		(1.7	)		(1.3	)
Comprehensive (loss) income attributable to QEP	$	(44.5	)	$	92.0		$	64.7		$	117.4

(1) Presented net of income tax benefit of $26.5 million and $54.3 million during the three and six months ended June 30, 2012, respectively, and net of income tax benefit of $1.5 million and $29.8 million during the three and six months ended June 30, 2011, respectively.

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

(3) Presented net of income tax expense of $0.5 million and $1.1 million during the three and six months ended June 30, 2012, respectively, and net of income tax expense of $1.1 million during the three and six months ended June 30, 2011, respectively.

See notes accompanying the condensed consolidated financial statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
	2012			2011
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	146.4		$	-
Accounts receivable, net		236.9			397.4
Fair value of derivative contracts		268.2			273.7
Inventories, at lower of average cost or market
Gas, oil and NGL		11.6			16.2
Materials and supplies		90.0			87.6
Prepaid expenses and other		42.5			43.7
Total Current Assets		795.6			818.6
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties		8,822.3			8,172.4
Unproved properties		305.4			326.8
Midstream field services		1,550.1			1,463.6
Marketing and other		53.6			49.8
Total Property, Plant and Equipment		10,731.4			10,012.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production		3,763.7			3,339.2
Midstream field services		327.8			297.5
Marketing and other		16.3			14.6
Total Accumulated Depreciation, Depletion and Amortization		4,107.8			3,651.3
Net Property, Plant and Equipment		6,623.6			6,361.3
Investment in unconsolidated affiliates		41.9			42.2
Goodwill		59.5			59.5
Fair value of derivative contracts		76.2			123.5
Other noncurrent assets		40.8			37.6
TOTAL ASSETS	$	7,637.6		$	7,442.7
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	-		$	29.4
Accounts payable and accrued expenses		373.8			457.3
Production and property taxes		47.2			40.0
Interest payable		33.0			24.4
Fair value of derivative contracts		2.3			1.3
Deferred income taxes		31.0			85.4
Total Current Liabilities		487.3			637.8
Long-term debt		1,866.6			1,679.4
Deferred income taxes		1,563.1			1,484.7
Asset retirement obligations		172.2			163.9
Fair value of derivative contracts		2.4			-
Other long-term liabilities		129.8			124.8
Commitments and contingencies
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 178.5 million and 177.2 million shares issued, respectively		1.8			1.8
Treasury stock - 0.7 million and 0.4 million shares, respectively		(24.0	)		(13.1	)
Additional paid-in capital		450.4			431.4
Retained earnings		2,820.7			2,673.5
Accumulated other comprehensive income		118.1			207.9
Total Common Shareholders' Equity		3,367.0			3,301.5
Noncontrolling interest		49.2			50.6
Total Equity		3,416.2			3,352.1
TOTAL LIABILITIES AND EQUITY	$	7,637.6		$	7,442.7

See notes accompanying the condensed consolidated financial statements.

4

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2012			2011
	(in millions)
OPERATING ACTIVITIES
Net income	$	156.2		$	167.3
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		413.3			377.4
Deferred income taxes		77.1			95.7
Abandonment and impairment		62.3			10.7
Share-based compensation		12.3			10.8
Amortization of debt issuance costs and discounts		2.4			1.5
Dry exploratory well expense		0.1			0.5
Net gain from asset sales		(1.5	)		(0.2	)
Income from unconsolidated affiliates		(3.3	)		(2.2	)
Distributions from unconsolidated affiliates and other		3.5			2.6
Non-cash loss on early extinguishment of debt		0.1			-
Unrealized gain on derivative contracts		(89.9	)		(58.8	)
Changes in operating assets and liabilities		61.7			23.3
Net Cash Provided by Operating Activities		694.3			628.6
INVESTING ACTIVITIES
Property acquisitions		(4.0	)		(29.8	)
Property, plant and equipment, including dry exploratory well expense		(681.5	)		(632.0	)
Proceeds from disposition of assets		3.6			1.6
Net Cash Used in Investing Activities		(681.9	)		(660.2	)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances		(29.4	)		(1.5	)
Long-term debt issued		800.0			-
Long-term debt issuance costs paid		(8.8	)		-
Long-term debt repaid		(6.7	)		(58.5	)
Proceeds from credit facility		194.5			200.0
Repayments of credit facility		(801.0	)		(100.0	)
Other capital contributions		(6.4	)		(0.4	)
Dividends paid		(7.1	)		(7.1	)
Excess tax benefit on share-based compensation		2.0			1.4
Distribution from Questar		-			0.2
Distribution to noncontrolling interest		(3.1	)		(2.5	)
Net Cash Provided by Financing Activities		134.0			31.6
Change in cash and cash equivalents		146.4			-
Beginning cash and cash equivalents		-			-
Ending cash and cash equivalents	$	146.4		$	-
Supplemental Disclosures:
Cash paid for interest	$	42.7		$	64.6
Cash paid (received) for income taxes		8.0			(7.2	)
Non-cash investing activities
Change in capital expenditure accrual balance	$	45.3		$	12.3

See notes accompanying the condensed consolidated financial statements.

5

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Nature of Business

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

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

§ QEP Field Services Company (QEP Field Services) provides midstream field services; including natural gas gathering, processing, compression, and treating services, for affiliates and third parties; 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 two major regions, the Northern Region (primarily in the Rockies) and the Southern Region (primarily Oklahoma, Louisiana, and the Texas Panhandle) of the United States. QEP’s corporate headquarters are located in Denver, Colorado.

Shares of QEP Resources’ common stock trade on the New York Stock Exchange under the ticker symbol “QEP”.

Note 2 – Basis of Presentation of Interim Consolidated Financial Statements

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

The condensed consolidated financial statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 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 and six months ended June 30, 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 for all of its derivative instruments. 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 three and six months ended June 30, 2012, unrealized losses of $38.4 million and unrealized gains of $89.9 million were included in income that, prior to January 1, 2012, would have been deferred in Accumulated Other Comprehensive Income (AOCI) under hedge accounting. Refer to Note 6 – Derivative Contracts 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, were recast on the Condensed Consolidated Statement of Income from “Revenues” to “Natural gas, oil and NGL transportation and other handling costs” for prior periods presented. The impact of this revision was immaterial to the accompanying financial statements and had no effect on income from continuing operations, net income, or earnings per share.

6

The following table details the impact for the three and six months ended June 30, 2011, on the Condensed Consolidated Statement of Income.

	Three Months Ended June 30, 2011							Six Months Ended June 30, 2011
	As reported (1)		As revised		Change			As reported (1)		As revised		Change
	(in millions)							(in millions)
REVENUES
Natural gas sales	$	258.1	$	298.7	$	40.6		$	529.1	$	611.3	$	82.2
Oil sales		80.0		80.7		0.7			142.3		143.7		1.4
NGL sales		61.6		63.8		2.2			107.4		111.7		4.3
Gathering, processing and other		78.4		58.9		(19.5	)		147.7		105.5		(42.2	)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		-		24.0		24.0			-		45.7		45.7

(1) The “As reported” numbers reflect QEP Field Services NGL sales of $45.1 million and $73.7 million for the three and six months ended June 30, 2011, which were reclassified from “Gathering, processing and other” into “NGL sales” for consistency with current period presentation. In its second quarter 2011 Form 10-Q, QEP reported “NGL sales” of $16.5 million and $33.7 million, and “Gathering, processing and other” of $123.5 million and $221.4 million for the three and six months ended June 30, 2011, respectively. The QEP Field Services NGL reclassification is all within “Revenues” and has no effect on income from continuing operations, net income or earnings per share.

Impairment of long-lived assets

Proved gas and oil properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value. Triggering events could include, but are not limited to, an impairment of gas and oil reserves caused by mechanical problems, faster-than-expected decline of reserves, lease-ownership issues, other-than-temporary decline in natural gas, NGL and crude oil prices and changes in the utilization of midstream gathering and processing assets. If impairment is indicated, fair value is calculated using a discounted-cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating costs, and estimates of probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors. During the three and six months ended June 30, 2012, QEP Energy recorded non-cash, price-related impairment charges of $48.9 million and $49.3 million, respectively, on some of its proved properties. The impairment charges are related to the reduced value of certain fields resulting from lower natural gas, crude oil and NGL prices. The assets were written down to their estimated fair values. Of the $49.3 million impairment charge during the six months ended June 30, 2012, $48.9 million is related to proved properties in the Southern Region and $0.4 million is related to proved properties in the Northern Region.

The Company also performs periodic assessments of unproved gas and oil properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired the Company considers numerous factors including current development and exploration plans, results of development or exploration activity on adjacent leaseholds, technical personnel evaluations of the properties, and the remaining lease term. During the three and six months ended June 30, 2012, QEP recorded non-cash impairment charges of $6.1 million and $12.1 million, respectively, on some of its unproved properties relating to the various factors described. Of the $6.1 million and $12.1 million impairment charges during the three and six months ended June 30, 2012, $3.1 million and $6.1 million, respectively, related to unproved properties in the Southern Region and $3.0 million and $6.0 million, respectively, related to unproved properties in the Northern Region.

Natural gas, NGL and crude oil prices

Historically, field-level prices received for QEP’s natural gas, NGL, and crude oil production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than natural gas demand, driven by advances in drilling and completion technologies, including horizontal drilling and multi-stage hydraulic fracturing, which have allowed producers to extract increased quantities of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas and NGL drilling and supplies have resulted in downward pressure on natural gas and NGL 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 may impact the carrying value of its oil and natural gas properties.

7

New accounting pronouncements

In May of 2011, the FASB issued ASU 2011-04, which develops common measurement and disclosure requirements regarding an entity’s fair value measurements and aligns GAAP and International Financial Reporting Standards. The amendments are required for interim and annual reporting periods beginning after December 15, 2011. The adoption of these requirements did not have a material impact on the financial statements of QEP.

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

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. QEP’s unvested restricted shares are included in weighted-average basic common shares outstanding because once the shares are granted, the restricted shares are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company’s unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company’s unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company’s unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. During the three months ended June 30, 2012, 0.9 million shares were not included in diluted common shares outstanding as they were anti-dilutive due to QEP’s net loss. There were no anti-dilutive shares during the six months ended June 30, 2012 and during the three and six months ended June 30, 2011.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(in millions)
Weighted-average basic common shares outstanding		177.7		176.6		177.6		176.4
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan		-		2.0		0.9		2.1
Average diluted common shares outstanding		177.7		178.6		178.5		178.5

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.

8

The following is a reconciliation of the changes in the asset retirement obligation from January 1, 2012 and 2011 to June 30, 2012 and 2011, respectively:

	Asset Retirement Obligations
	2012			2011
	(in millions)
ARO liability at January 1,	$	163.9		$	148.3
Accretion		5.1			4.8
Liabilities incurred		3.6			2.9
Liabilities settled		(0.4	)		(0.3	)
ARO liability at June 30,	$	172.2		$	155.7

Note 5 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures”. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements, but does not change existing guidance as to whether or not an instrument is carried at fair value. ASC 820 also establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.

QEP has determined its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (see Note 6 - 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. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company’s policy is to recognize significant transfers between levels at the end of the reporting period.

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

In addition, QEP has Level 2 interest rate swaps. The fair values of the interest rate swaps are determined using the market standard methodology of discounting the future expected cash flows that would occur under the contractual terms of the swap. The variable interest rates used in the calculation of projected cash flows are based on an expectation of future interest rates derived from observable market interest rate curves. QEP incorporates credit valuation adjustments to reflect both its nonperformance risk and the respective counterparty’s nonperformance risk in the fair value measurements. While the credit valuation adjustments are not observable inputs, they are not significant to the overall valuation and the other inputs used to value the interest rate swaps are observable Level 2 inputs.

As of June 30, 2012 and December 31, 2011, the Company did not have assets or liabilities classified as Level 1 or Level 3 within the fair value hierarchy.

9

The fair value of financial assets and liabilities at June 30, 2012 is shown in the table below:

	Fair Value Measurements
	June 30, 2012
	Level 1		Level 2		Level 3		Netting Adjustments			Total
			(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	-	$	272.2	$	-	$	(4.0	)	$	268.2
Commodity derivative instruments - long-term		-		77.5		-		(1.3	)		76.2
Total financial assets	$	-	$	349.7	$	-	$	(5.3	)	$	344.4
Financial Liabilities
Commodity derivative instruments - short-term	$	-	$	4.0			$	(4.0	)	$	-
Interest rate swaps - short-term		-		2.3				-			2.3
Commodity derivative instruments - long-term		-		1.7				(1.3	)		0.4
Interest rate swaps - long-term		-		2.0		-					2.0
Total financial liabilities	$	-	$	10.0	$	-	$	(5.3	)	$	4.7

Fair values related to the Company’s crude oil costless collars were transferred from Level 3 to Level 2 in the second quarter of 2012, due to the enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. There were no other significant transfers in or out of Levels 1, 2 or 3 for the periods presented herein. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.

The change in the fair value of Level 3 commodity derivative instruments assets and liabilities for the six months ended June 30, 2012, is shown below:

	Change in Level 3 Fair Value Measurements
	2012
	(in millions)
Balance at January 1,	$	-
Realized gains and losses		0.6
Unrealized gains and losses		3.8
Settlements		(0.6	)
Transfers out of Level 3		(3.8	)
Balance at June 30,	$	-

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

	Fair Value Measurements
	December 31, 2011
	Level 1		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

10

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

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	June 30, 2012				December 31, 2011
	(in millions)
Financial assets
Cash and cash equivalents	$	146.4	$	146.4	$	-	$	-
Financial liabilities
Checks outstanding in excess of cash balances	$	-	$	-	$	29.4	$	29.4
Long-term debt	$	1,866.6	$	1,967.2	$	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.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company’s asset retirement obligations is presented in Note 4 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company’s nonrecurring, non-financial measurements.  The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the first half of 2012 and through the period ended December 31, 2011, the Company recorded impairments on certain oil & gas property resulting in a write down of the associated carrying value to fair value. The fair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flow models. Given the unobservable nature of the inputs, proved oil and gas property impairments would be considered Level 3 within the fair value hierarchy.

The following table summarizes the non-financial assets and liabilities measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition and their associated impairment:

	Level 3 Fair Value		Impairment		Level 3 Fair Value		Impairment
	June 30, 2012				December 31, 2011
	(in millions)
Proved Property	$	5,058.6	$	49.3	$	4,833.2	$	195.5

Note 6 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity 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 gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production from proved reserves. In addition, QEP may enter into commodity derivative contracts on a portion of its extracted NGL volumes in its midstream business and may enter into commodity derivative contracts on natural gas sales and purchases for marketing transactions. QEP does not enter into commodity derivative instruments for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps 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 commodity 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.

11

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

Through December 31, 2011, QEP designated the majority of its natural gas, oil and NGL derivative contracts as cash flow hedges, whose unrealized fair value gains and losses were recorded to AOCI. Effective January 1, 2012, QEP elected to de-designate all of its natural gas, crude oil and NGL derivative contracts that were previously designated as cash flow hedges and discontinue hedge accounting prospectively. As a result of discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were frozen in AOCI as of the de-designation date and are being reclassified into the Consolidated Statement of Income as the transactions settle and affect earnings. At June 30, 2012, AOCI consisted of $249.8 million ($156.9 million after tax) of unrealized gains. QEP expects to reclassify into earnings from AOCI the frozen value related to de-designated natural gas, oil and NGL hedges over the remainder of 2012 and 2013. Currently, QEP recognizes all gains and losses from changes in the fair value of natural gas, oil and NGL derivative contracts immediately in earnings rather than deferring any such amounts in AOCI. All commodity derivative instruments are recorded on the Consolidated Balance Sheets as either assets or liabilities measured at their fair values and  all realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012, are presented in the Consolidated Statement of Income in “Realized and unrealized gains on derivative contracts” below operating income.

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

QEP 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						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
QEP Energy
Natural gas derivative volumes as a percent of QEP Energy natural gas production
Fixed price swaps		67	%		46	%		63	%		44	%
Costless collars		0	%		12	%		0	%		12	%
Oil derivative volumes as a percent of QEP Energy oil production
Fixed price swaps		35	%		3	%		36	%		2	%
Costless collars		28	%		31	%		22	%		33	%
NGL derivative volumes as a percent of QEP Energy NGL production
Fixed price swaps		18	%		0	%		17	%		0	%
QEP Field Services
Ethane derivative volumes as a percent of ethane volumes - QEP Field Services
Fixed price swaps		15	%		0	%		27	%		0	%
Propane derivative volumes as a percent of propane volumes - QEP Field Services
Fixed price swaps		59	%		0	%		76	%		0	%

12

QEP Energy Derivative Contracts

The following table sets forth QEP Energy’s volumes and average prices for its commodity derivative contracts as of June 30, 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		39.9	$	4.66
2012	Swap	IFPEPL (1)		4.9	$	4.14
2012	Swap	IFNPCR (2)		45.4	$	4.61
2012	Swap	IFCNPTE (3)		5.5	$	2.66
2013	Swap	NYMEX		29.2	$	3.68
2013	Swap	IFNPCR (2)		65.7	$	5.66
Oil sales			(Bbls)
2012	Swap	NYMEX WTI		0.9	$	97.03
2012	Collar	NYMEX WTI		0.7			$	87.50	$	115.36
2013	Swap	NYMEX WTI		0.9	$	104.12
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		7.7	$	0.64
2012	Swap	Mt. Belvieu Propane		11.6	$	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 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 June 30, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swap price per gallon
			(in millions)
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		7.7	$	0.64
2012	Swap	Mt. Belvieu Propane		3.9	$	1.28

QEP Marketing Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage and for marketing transactions in which QEP Marketing is required to deliver gas volumes at a fixed price. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of June 30, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swaps price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2012	Swap	IFNPCR (1)		1.8	$	4.06
2013	Swap	IFNPCR (1)		1.2	$	4.57
Natural gas purchases			(MMBtu)
2012	Swap	IFNPCR (1)		0.7	$	2.97
2013	Swap	IFNPCR (1)		0.1	$	2.59

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

13

QEP Resources Derivative Contracts

In the second quarter of 2012, QEP Resources entered into interest rate swap agreements to effectively lock in a fixed interest rate on debt outstanding under its Term Loan.

The following table sets forth QEP Resources’ notional amounts and interest rates for its interest rate swaps outstanding as of June 30, 2012:

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

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

		Gross asset derivative instruments fair value					Gross liability derivative instruments fair value
	Balance Sheet line item	June 30, 2012		December 31, 2011		Balance Sheet line item	June 30, 2012		December 31, 2011
		(in millions)					(in millions)
Current:
Commodity	Fair value of derivative contracts	$	272.2	$	284.1	Fair value of derivative contracts	$	4.0	$	11.7
Interest rate swaps	Fair value of derivative contracts		-		-	Fair value of derivative contracts		2.3		-
Long-term:
Commodity	Fair value of derivative contracts		77.5		123.5	Fair value of derivative contracts		1.7		-
Interest rate swaps	Fair value of derivative contracts		-		-	Fair value of derivative contracts		2.0		-
Total derivative    instruments		$	349.7	$	407.6		$	10.0	$	11.7

14

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

		Three Months Ended						Six Months Ended
Derivative instruments not designated	Location of gain (loss)	June 30,						June 30,
as cash flow hedges	recognized in earnings	2012			2011			2012			2011
		(in millions)
Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		$	111.9		$	(27.6	)	$	197.6		$	(58.8	)
Oil derivative contracts			2.2			-			(0.5	)		-
NGL derivative contracts			2.7			-			3.1			-
QEP Field Services
NGL derivative contracts			3.3			-			4.4			-
QEP Marketing
Natural gas derivative contracts			0.6			-			4.1			-
Total realized gain (loss) on commodity derivative contracts			120.7			(27.6	)		208.7			(58.8	)
Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts			(78.4	)		27.6			53.9			58.8
Oil derivative contracts			38.6			-			27.1			-
NGL derivative contracts			4.9			-			7.8			-
QEP Field Services
NGL derivative contracts			1.5			-			4.5			-
QEP Marketing
Natural gas derivative contracts			(0.7	)		-			0.9			-
Total unrealized (loss) gain on commodity derivative contracts			(34.1	)		27.6			94.2			58.8
Total realized and unrealized gain on commodity derivative contracts	Realized and unrealized gains on derivative contracts	$	86.6		$	-		$	302.9		$	-
Unrealized gain (loss) on interest rate swaps
Unrealized loss on interest rate swaps	Realized and unrealized gains on derivative contracts	$	(4.3	)	$	-		$	(4.3	)	$	-

		Three Months Ended					Six Months Ended
Derivative instruments classified	Location of gain (loss)	June 30,					June 30,
as cash flow hedges	recognized in earnings	2012			2011		2012		2011
Commodity derivatives			(in millions)
Gain on derivative instruments for the effective  portion of hedge recognized in AOCI	Accumulated other comprehensive income	$	-	$	61.3	$	-	$	61.5
Gain reclassified from AOCI into income for effective portion of hedge	Natural gas sales		-		64.4		-		137.5
Gain reclassified from AOCI into income for effective portion of hedge	Oil sales		-		0.1		-		0.1
Gain reclassified from AOCI into income for effective portion of hedge	Marketing purchases		-		0.5		-		3.9
Gain recognized in income for the ineffective portion of hedges	Interest and other income		-		0.3		-		0.1

The Company estimates that derivative contracts that were outstanding and frozen in AOCI at June 30, 2012, having a frozen fair value of $120.0 million will be settled and reclassified from AOCI to the Condensed Consolidated Statements of Income during the next twelve months.

15

Note 7 – Restructuring Costs

During the first quarter 2012, QEP announced the closure of its Oklahoma City office and the subsequent consolidation of its Southern Region operations into a single regional office located in Tulsa. The creation of one office for QEP’s Southern Region is intended to increase regional efficiency, team-based collaboration and organizational productivity, over the long-term. As part of this restructuring plan and office closure, QEP 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. In addition, QEP has incurred costs from other restructuring and reorganization activities in an effort to centralize and gain efficiencies. 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 $6.0 million, consisting of $2.1 million in one-time termination benefits, $3.4 million in retention and relocation expenses for certain employees relocating to the Tulsa office, and $0.5 million for the termination of the QEP’s Oklahoma City office space lease. During the three and six months ended June 30, 2012, a total of $2.3 million and $5.0 million, respectively, of restructuring costs were incurred and recorded in “General and administrative” expense on the Condensed Consolidated Statement of Income, of which $0.8 million and $1.9 million, respectively, 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 Liability
	(in millions)
Balance at December 31, 2011	$	-
Costs incurred and charged to expense		5.0
Costs paid or otherwise settled		(4.6	)
Balance at June 30, 2012	$	0.4

Note 8 – Debt

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

	June 30,			December 31,
	2012			2011
	(in millions)
Revolving Credit Facility due 2016	$	-		$	606.5
Term Loan due 2017		300.0			-
6.05% Senior Notes due 2016		176.8			176.8
6.80% Senior Notes due 2018		134.0			138.6
6.80% Senior Notes due 2020		136.0			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		1,871.8			1,684.9
Less unamortized discount		(5.2	)		(5.5	)
Total long-term debt outstanding	$	1,866.6		$	1,679.4

Of the total debt outstanding on June 30, 2012, only the revolving credit facility, due August 25, 2016, the Term Loan due April 18, 2017, and the 6.05% Senior Notes, due September 1, 2016, will mature within the next five years.

Credit Arrangements

QEP’s revolving credit facility agreement (Credit Facility), which matures in August 2016, provides for loan commitments of $1.5 billion from a group of financial institutions. The Credit Facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The revolving credit agreement also contains an accordion provision that would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for up to two additional one-year periods.

During the first half of 2012, QEP’s weighted-average interest rate on borrowings from its Credit Facility was 2.05%. At June 30, 2012 and December 31, 2011, QEP was in compliance with the covenants under the credit agreement. At June 30, 2012, there were no borrowings outstanding and QEP had $4.1 million in letters of credit outstanding under the Credit Facility.

16

Term Loan

During the second quarter of 2012, QEP entered into a $300.0 million senior, unsecured term loan agreement (Term Loan) with a group of financial institutions. The Term Loan 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 Credit Facility. The Term Loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. The proceeds from the Term Loan were used to pay down the Credit Facility and for general corporate purposes. During the second quarter of 2012, QEP’s weighted-average interest rate on borrowings from the Term Loan was 2.02%. At June 30, 2012, QEP was in compliance with the covenants under the credit agreement.

Senior Notes

During the first quarter of 2012, QEP completed a public offering for $500.0 million in aggregate principal amount of 5.375% senior notes due in October 2022 (2022 Senior Notes). The 2022 Senior Notes were issued at face value. Interest on the 2022 Senior Notes will be paid semi-annually, in April and October of each respective year. The net proceeds of $493.1 million were used to repay indebtedness under QEP’s Credit Facility. The finance costs incurred of $6.9 million were deferred and are being amortized over the life of the notes. The amortization of all of the Company’s deferred finance costs is included in “Interest expense” on the Condensed Consolidated Statement of Income.

During the second quarter of 2012, QEP repurchased $6.7 million of its senior notes outstanding. QEP recognized a loss on extinguishment of debt from those repurchases and associated write-offs of debt issuance costs, discounts and premiums paid of $0.6 million. At June 30, 2012, the Company had $1,571.8 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.

Note 9 – 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. QEP’s estimates are based on information known about the claims, experience in contesting, litigating and settling similar claims. Although actual amounts could differ from management’s estimates, QEP believes that the exposure to potential losses, in excess of the amount which has been accrued, from its probable contingencies 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. As previously disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2011, and its Quarterly Report on Form 10-Q for the three months ended March 31, 2012, 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. On May 16, 2012, QEP Field Services settled this matter through the parties’ execution of a consent decree which was subsequently approved by court order. The civil penalty payable to the government is $3.7 million. A contribution of $0.4 million will be payable to a non-profit corporation or trust to be created by the Ute Indian Tribe of the Uintah and Ouray Reservation for the implementation of environmental programs for the benefit of tribal members. The settlement also requires the company to reduce its emissions by removing certain equipment, installing additional pollution controls and replacing the natural gas powered instrument control systems with compressed air control systems, all of which will require capital expenditures of approximately $2.4 million, of which $0.5 million had be spent at June 30, 2012. QEP Field Services will have continuing operational compliance obligations under the consent decree at the affected facilities.

17

Litigation

Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for Oklahoma. 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, including the early stage of discovery and the number of plaintiffs, it is difficult to predict all reasonably possible outcomes.

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services’ former affiliate Questar Gas Company (QGC) filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, for an accounting and declaratory judgment related to a 1993 gathering agreement (1993 Agreement) entered when the parties were affiliates. Under the 1993 Agreement, QEP Field Services provides gathering services for producing properties developed by former affiliate Wexpro Company on behalf of QGC’s utility ratepayers. The core dispute pertains to the annual recalculation of the gathering rate which is based on a cost of service concept expressed in the 1993 Agreement and in a 1998 amendment. The annual gathering rate has been calculated in the same manner under the contract since it was amended in 1998, without any prior objection or challenge by QGC. Specific monetary damages are not asserted. Because of the complexities and uncertainties of this legal dispute in its early stages, it is difficult to predict all reasonably possible outcomes. Also, on May 1, 2012, QEP Field Services Company filed a legal action against Questar Gas entitled QEP Field Services Company v. Questar Gas Company, in the Second District Court in Denver County, Colorado, seeking declaratory judgment relating to its gathering service and charges under the same agreement. While QEP Field Services intends to defend itself against QGC’s claims and vigorously pursue its legal rights, the claims involve complex legal issues and uncertainties that make it difficult to predict the outcome of the cases and therefore management cannot determine at this time whether this litigation may have an adverse material effect on its financial position, results of operations or cash flows.

Note 10 – 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 13.1 million shares available for future grants under the LTSIP at June 30, 2012. Share-based compensation expense is recognized in “General and administrative” on the Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2012, QEP recognized $6.6 million and $12.3 million, respectively, in total compensation expense related to share-based compensation compared to $3.4 million and $10.8 million during the three and six months ended June 30, 2011.

Stock Options

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

The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:

	Stock Option Variables Six Months Ended June 30, 2012
Fair value of options at grant date	$	14.46
Risk-free interest rate		0.81	%
Expected price volatility		55.9	%
Expected dividend yield		0.26	%
Expected life in years		5.0

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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		291,143			30.83
Exercised		(313,342	)		8.15
Forfeited		-			-		-
Outstanding at June 30, 2012		1,981,495		$	24.71		3.6	$	12.5
Options Exercisable at June 30, 2012		1,500,192		$	22.19		2.8	$	12.3
Unvested Options at June 30, 2012		481,303		$	32.56		6.1	$	0.2

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 $2.6 million during the six months ended June 30, 2012 and 2011, respectively. As of June 30, 2012, $4.6 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.4 years.

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 during the six months ended June 30, 2012 and 2011, was $12.6 million and $9.9 million, respectively. The weighted average grant-date fair value of restricted stock was $30.74 per share and $39.14 per share for the six months ended June 30, 2012 and 2011, respectively. As of June 30, 2012, $25.3 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.4 years.

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

	Restricted Shares Outstanding			Weighted- Average Price
				(per share)
Unvested balance at December 31, 2011		1,099,752		$	32.80
Granted		706,221			30.74
Vested		(397,204	)		32.31
Forfeited		(49,209	)		32.71
Unvested balance at June 30, 2012		1,359,560		$	31.88

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 six months ended June 30, 2012 and 2011, respectively. As of June 30, 2012, $5.3 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 2.4 years.

Transactions involving performance share 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		171,954			30.90
Vested		-			-
Forfeited		(4,148	)		39.07
Unvested balance at June 30, 2012		283,080		$	34.11

Note 11 – Employee Benefits

The Company has a funded qualified defined benefit pension plan and an unfunded supplemental defined benefit pension plan. The Company also has unfunded postretirement benefits that provide certain health care and life insurance benefits for certain retired employees. During the six months ended June 30, 2012, the Company made contributions of $2.7 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 $3.6 million to its funded pension plans, and approximately $0.3 million to its unfunded pension plans. In July 2012, Congress passed the Moving Ahead for Progress in the 21st Century Act, which included pension funding stabilization provisions. The measure, which is designed to stabilize the discount rate used to determine funding requirements from the effects of interest rate volatility, may reduce the Company’s United States Pension Plan contributions during 2012 from the planned amounts.

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

	Pension
	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Service cost	$	0.9		$	0.7		$	1.9		$	1.4
Interest cost		1.2			1.1			2.4			2.2
Expected return on plan assets		(0.9	)		(0.6	)		(1.8	)		(1.2	)
Amortization of prior service costs		1.3			1.3			2.6			2.6
Amortization of actuarial loss		0.2			-			0.4			-
Periodic expense	$	2.7		$	2.5		$	5.5		$	5.0

	Postretirement benefits
	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)
Service cost	$	-	$	-	$	-	$	-
Interest cost		0.1		0.1		0.2		0.2
Expected return on plan assets		-		-		-		-
Amortization of prior service costs		0.1		0.1		0.2		0.2
Recognized net actuarial loss		-		-		-		-
Periodic expense	$	0.2	$	0.2	$	0.4	$	0.4

Note 12 – 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.

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

	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
For the three months ended June 30, 2012	(in millions)
Revenues (1)
From unaffiliated customers	$	335.5		$	83.4		$	80.4		$	-		$	499.3
From affiliated customers		-			30.2			118.2			(148.4	)		-
Total Revenues		335.5			113.6			198.6			(148.4	)		499.3
Operating expenses
Purchased gas, oil and NGL expense		40.6			4.1			197.4			(117.2	)		124.9
Lease operating expense		41.4			-			-			(0.9	)		40.5
Natural gas, oil and NGL transportation and other handling costs		57.2			12.0			-			(28.5	)		40.7
Gathering, processing and other		-			20.4			0.5			(0.3	)		20.6
General and administrative		29.2			9.0			0.1			(1.5	)		36.8
Production and property taxes		18.2			1.2			-			-			19.4
Depreciation, depletion and amortization		197.2			16.1			0.8			-			214.1
Other operating expenses		57.8			-			-			-			57.8
Total operating expenses		441.6			62.8			198.8			(148.4	)		554.8
Operating (loss) income (2)		(106.1	)		50.8			(0.2	)		-			(55.5	)
Realized and unrealized gains (losses) on derivative contracts		81.8			4.8			(4.3	)		-			82.3
Interest and other income		0.7			0.1			26.8			(26.7	)		0.9
Income from unconsolidated affiliates		0.1			1.3			-			-			1.4
Loss on early extinguishment of debt		-			-			(0.6	)		-			(0.6	)
Interest expense		(23.4	)		(3.6	)		(27.9	)		26.7			(28.2	)
(Loss) income before income taxes		(46.9	)		53.4			(6.2	)		-			0.3
Income taxes		16.6			(19.2	)		2.5			-			(0.1	)
Net (loss) income		(30.3	)		34.2			(3.7	)		-			0.2
Net income attributable to noncontrolling interest		-			(0.9	)		-			-			(0.9	)
Net (loss) income attributable to QEP (3)	$	(30.3	)	$	33.3		$	(3.7	)	$	-		$	(0.7	)

(1) The impact of QEP’s settled derivative contracts, for the three months ended June 30, 2012, are reflected below operating (loss) income.

(2) Operating (loss) income for the three months ended June 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the three months ended June 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.

(3) Net income (loss) attributable to QEP for the three months ended June 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

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	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
For the three months ended June 30, 2011	(in millions)
Revenues (1)
From unaffiliated customers	$	555.5		$	102.0		$	150.6		$	-		$	808.1
From affiliated customers		-			20.2			145.2			(165.4	)		-
Total Revenues		555.5			122.2			295.8			(165.4	)		808.1
Operating expenses
Purchased gas, oil and NGL expenses		154.7			-			292.5			(143.3	)		303.9
Lease operating expense		35.0			-			-			(0.7	)		34.3
Natural gas, oil and NGL transportation and other handling costs		42.3			1.2			-			(19.5	)		24.0
Gathering, processing and other		-			26.9			0.4			(0.1	)		27.2
General and administrative		22.9			6.8			0.8			(1.8	)		28.7
Production and property taxes		25.4			1.6			0.1			-			27.1
Depreciation, depletion and amortization		172.5			13.5			0.6			-			186.6
Other operating expenses		7.6			-			-			-			7.6
Total operating expenses		460.4			50.0			294.4			(165.4	)		639.4
Net gain (loss) from asset sales		0.2			0.1			(0.1	)		-			0.2
Operating income (2)		95.3			72.3			1.3			-			168.9
Interest and other (loss) income		(0.5	)		-			24.8			(24.7	)		(0.4	)
Income from unconsolidated affiliates		0.1			1.2			-			-			1.3
Interest expense		(20.4	)		(3.1	)		(23.3	)		24.7			(22.1	)
Income before income taxes		74.5			70.4			2.8			-			147.7
Income taxes		(27.7	)		(25.5	)		(1.0	)		-			(54.2	)
Net income		46.8			44.9			1.8			-			93.5
Net income attributable to noncontrolling interest		-			(0.7	)		-			-			(0.7	)
Net income attributable to QEP (3)	$	46.8		$	44.2		$	1.8		$	-		$	92.8

(1) Revenues for the three months ended June 30, 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 June 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the three months ended June 30, 2011.

(2) Under hedge accounting, gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three months ended June 30, 2011.

(3) Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three months ended June 30, 2011.

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	QEP Energy			QEP Field Services			QEP Marketing  & Other			Eliminations			QEP Consolidated
For the six months ended June 30, 2012	(in millions)
Revenues (1)
From unaffiliated customers	$	732.3		$	177.0		$	193.2		$	-		$	1,102.5
From affiliated customers		-			56.3			250.5			(306.8	)		-
Total Revenues		732.3			233.3			443.7			(306.8	)		1,102.5
Operating expenses
Purchased gas, oil and NGL expense		113.1			4.1			445.0			(248.9	)		313.3
Lease operating expense		82.2			-			-			(1.6	)		80.6
Natural gas, oil and NGL transportation and other handling costs		107.6			20.8			-			(53.2	)		75.2
Gathering, processing and other		-			43.8			0.7			(0.2	)		44.3
General and administrative		62.1			13.5			0.1			(2.9	)		72.8
Production and property taxes		41.1			2.9			0.1			-			44.1
Depreciation, depletion and amortization		380.3			31.4			1.6			-			413.3
Other operating expenses		66.4			-			-			-			66.4
Total operating expenses		852.8			116.5			447.5			(306.8	)		1,110.0
Net gain from asset sales		1.5			-			-			-			1.5
Operating (loss) income (2)		(119.0	)		116.8			(3.8	)		-			(6.0	)
Realized and unrealized gains on derivative contracts		289.0			8.9			0.7			-			298.6
Interest and other income		2.4			0.1			52.7			(52.6	)		2.6
Income from unconsolidated affiliates		0.1			3.2			-			-			3.3
Loss on early extinguishment of debt		-			-			(0.6	)		-			(0.6	)
Interest expense		(47.0	)		(5.9	)		(52.6	)		52.6			(52.9	)
Income (loss) before income taxes		125.5			123.1			(3.6	)		-			245.0
Income taxes		(47.7	)		(42.7	)		1.6			-			(88.8	)
Net income (loss)		77.8			80.4			(2.0	)		-			156.2
Net income attributable to noncontrolling interest		-			(1.7	)		-			-			(1.7	)
Net income (loss) attributable to QEP (3)	$	77.8		$	78.7		$	(2.0	)	$	-		$	154.5

(1) The impact of QEP’s settled derivative contracts, for the six months ended June 30, 2012, are reflected below operating (loss) income.

(2) Operating (loss) income for the six months ended June 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the six months ended June 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.

(3) Net (loss) income attributable to QEP for the six months ended June 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

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	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
For the six months ended June 30, 2011	(in millions)
Revenues (1)
From unaffiliated customers	$	951.7		$	175.3		$	299.0		$	-		$	1,426.0
From affiliated customers		-			43.5			278.3			(321.8	)		-
Total Revenues		951.7			218.8			577.3			(321.8	)		1,426.0
Operating expenses
Purchased gas, oil and NGL expense		154.7			-			570.4			(274.5	)		450.6
Lease operating expense		68.4			-			-			(1.3	)		67.1
Natural gas, oil and NGL transportation and other handling costs		85.8			2.1			-			(42.2	)		45.7
Gathering, processing and other		-			51.7			0.7			-			52.4
General and administrative		46.8			15.8			1.6			(3.8	)		60.4
Production and property taxes		47.6			3.0			0.2			-			50.8
Depreciation, depletion and amortization		349.6			26.7			1.1			-			377.4
Other operating expenses		15.8			-			-			-			15.8
Total operating expenses		768.7			99.3			574.0			(321.8	)		1,120.2
Net gain (loss) from asset sales		0.2			0.1			(0.1	)		-			0.2
Operating income (2)		183.2			119.6			3.2			-			306.0
Interest and other income		0.2			-			49.2			(49.2	)		0.2
Income from unconsolidated affiliates		0.1			2.1			-			-			2.2
Interest expense		(40.3	)		(6.6	)		(46.5	)		49.2			(44.2	)
Income before income taxes		143.2			115.1			5.9			-			264.2
Income taxes		(53.3	)		(41.6	)		(2.0	)		-			(96.9	)
Net income		89.9			73.5			3.9			-			167.3
Net income attributable to noncontrolling interest		-			(1.3	)		-			-			(1.3	)
Net income attributable to QEP (3)	$	89.9		$	72.2		$	3.9		$	-		$	166.0

(1) Revenues for the six months ended June 30, 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 six months ended June 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the six months ended June 30, 2011.

(2) Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three and six months ended June 30, 2011.

(3) Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three and six months ended June 30, 2011.

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

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

The following information updates the discussion of QEP’s financial condition provided in its 2011 Annual Report on Form 10-K filing and analyzes the changes in the results of operations between the three and six-month periods ended June 30, 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 – natural gas and crude oil exploration and production; midstream field services; and energy marketing. These businesses are conducted through the Company’s three principal subsidiaries:

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

§ QEP Field Services Company (QEP Field Services) provides midstream field services in the Northern Region and northwest Louisiana, 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 a returns-focused investment, superior operational execution, and a low-cost business model. To achieve these objectives we strive to:

§ Operate in a safe and environmentally responsible manner;

§ Allocate capital to those projects that generate optimal returns;

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

§ Be in the highest-potential areas of the resource plays in which we operate;

§ Build contiguous acreage positions to drive operating efficiencies;

§ Be the operator of our assets, whenever possible;

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

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

§ Build gas processing plants to extract liquids from our natural gas streams;

§ Gather, compress and treat our production to drive down costs;

§ Actively market our QEP Energy production to maximize value;

§ Utilize derivative contracts to mitigate the impact of natural gas, crude oil or NGL price volatility, while locking acceptable cash flows required to support future capital expenditures;

§ Attract and retain the best people; and

§ Maintain a capital structure that allows us the necessary financial flexibility with which to invest in organic growth and potential acquisition opportunities, as they may arise.

Outlook

The Company has substantial acreage positions and operations in some of the most prolific hydrocarbon resource plays in the continental United States, including the 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 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 growth in organic production and reserves. QEP believes that it has one of the lowest cash operating structures among its exploration and production company peers. However, in certain of its resource plays, QEP, like its peers, has experienced rising drilling and completion 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 106% in the second quarter of 2012 compared with the second quarter of 2011. During the six months ended June 30, 2012, QEP Energy oil and NGL production increased 109% compared with the six months ended June 30, 2011. In the second quarter of 2012 oil and NGL revenue accounted for approximately 52% of QEP Energy’s field-level production revenues compared to 30% in the second quarter of 2011. During the first half of 2012, oil and NGL revenue accounted for approximately 51% of QEP Energy’s field-level production revenues compared to 27% during the first half of 2011. The increased NGL volumes in the second quarter and first half of 2012, were primarily the result of the agreement entered into by QEP Energy with QEP Field Services for Pinedale production, in August of 2011, for fee-based processing at the Blacks Fork II plant, liquids recovered for QEP Energy by QEP Field Services in the Uinta Basin and the liquids recovered for QEP Energy by third party processors associated with the development of liquids-rich plays in the Midcontinent and Bakken/Three Forks areas. QEP Energy has allocated approximately 90% of its 2012 total forecasted capital expenditure budget to oil and liquids-rich natural gas plays due to depressed natural gas prices.

While QEP believes that it can grow production and reserves from an 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 model and financial strength, enhance its ability to pursue acquisition opportunities.

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

Financial and Operating Results

During the three and six months ended June 30, 2012, the Company had substantial production growth at QEP Energy, as well as increased processing and gathering volumes at QEP Field Services. In the second quarter of 2012, QEP Energy reported production of 79.6 Bcfe compared to 64.7 Bcfe in the second quarter of 2011, an increase of 23%. During the first half of 2012, QEP Energy reported total equivalent production of 153.8 Bcfe, 18% higher than the first half of 2011. During both the three and six months ended June 30, 2012, the Southern Region contributed 55% of total equivalent production, and the Northern Region contributed 45% of total equivalent production. QEP Field Services gathering throughput volumes during the three and six months ended June 30, 2012, were 11% and 7% higher than the 2011 comparable periods. QEP Field Services reported gathering system throughput of 1.5 million MMBtu per day for the second quarter of 2012, up from 1.3 million MMBtu per day in the second quarter of 2011. During the first half of 2012, QEP Field Services gathering system throughput was 1.4 million MMBtu per day compared to 1.3 million MMBtu per day in the first half of 2011. During the three and six months ended June 30, 2012, QEP Field Services reported 14% and 35% increases in NGL sales volumes, respectively. QEP Field Services fee-based processing volumes were 7% and 6% higher in the three and six months of 2012, respectively, when compared to the prior year periods.

The increases in production at QEP Energy and system throughput at QEP Field Services were offset by decreased commodity prices at both QEP Energy and QEP Field Services. For the three and six months ended June 30, 2012, QEP Energy’s average total net realized equivalent price was $5.13 per Mcfe and $5.29 per Mcfe compared to $5.71 per Mcfe and $5.60 per Mcfe during the three and six months ended June 30, 2011, respectively. In addition, at QEP Field Services, the increase in NGL sales volumes was more than offset by a 21% decrease in the per unit NGL margin (NGL revenue, including realized derivative gains, less fuel and shrink), resulting in a 43% decrease to the keep-whole processing margin during the second quarter of 2012. QEP Field Services’ increased NGL sales volumes during the first half of 2012 were more than offset by a 5% decrease in the per unit NGL margin, resulting in a 6% decrease to the keep-whole processing margin when compared the same period last year.

In the first quarter of 2012, QEP completed a public offering for $500.0 million in aggregate principal amount of 5.375% senior notes due in October 2022 (2022 Senior Notes). The 2022 Senior Notes were issued at face value. The net proceeds of $493.1 million were used to repay indebtedness under QEP’s revolving credit facility. Interest on the 2022 Senior Notes is payable April 1 and October 1 of each year, with the first interest payment due on October 1, 2012.

During the second quarter of 2012, QEP entered into a $300.0 million senior unsecured term loan agreement (Term Loan) with a group of financial institutions. The Term Loan 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 matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. In conjunction with the Term Loan, QEP entered into interest rate swap contracts with an aggregate notional amount of $300.0 million that effectively locks in a fixed rate that QEP will pay over the duration of the Term Loan.

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Factors Affecting Results of Operations

Oil, Natural Gas, and NGL Prices

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

QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% of its forecasted annual production by the end of the first quarter of each fiscal year. As of June 30, 2012, QEP Energy had approximately 70% 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, including 79% of its remaining forecasted 2012 natural gas production covered with fixed-price swaps assuming 2012 annual natural gas production of 242.5 Bcfe. During the first half of 2012, QEP entered into commodity derivative contracts for 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 90% 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

The Company elected to discontinue hedge accounting beginning January 1, 2012, and unrealized gains and losses from mark-to-market valuations of all derivative positions are reflected as unrealized derivative gains or losses in the Company’s income statement. See Note 6 - 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 first half of 2012 and in prior periods and may continue to incur these types of gains and losses in the future.

Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the outlook of the global economy, including the European debt crisis and its potential impact on global economic growth and the banking and financial sectors, political unrest in the Middle East, the United States federal budget deficit, changes in regulatory oversight policy and commodity price volatility. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on natural gas, NGL and crude oil supply, demand and prices.

Supply, Demand and Other Market Risk Factors

While the U.S. natural gas directed drilling rig count peaked in late 2011, the inventory of drilled gas wells waiting on completion caused the decreased natural gas production response to lag the downturn in the natural gas rig count. As a result of the lag, U.S. natural gas production eventually began to decline during the second quarter of 2012. The U.S. natural gas market entered the storage injection season with record high inventory levels. However, the combination of strong natural gas demand from electric power generation, combined with recent declines in U.S. natural gas production, has led to a decrease in natural gas inventories, resulting in a general firming of natural gas prices at the end of the second quarter of 2012. Despite increased stability in natural gas prices at the end of the second quarter of 2012, QEP expects U.S. natural gas prices to remain volatile and well below the five year average price over the next 12 to 18 months. Continued low natural gas prices have caused U.S. E&P companies, including QEP, to shift capital investments away from predominantly dry gas areas towards fields that are known to have liquids-rich natural gas and crude oil deposits. This shift in focus has caused domestic NGL production to increase dramatically. The increased NGL supplies, the warmer than average winter of 2011-2012, and price dislocations from infrastructure bottlenecks in certain regions, have all contributed to a weakening in domestic NGL prices. QEP expects NGL prices to remain volatile for the foreseeable future. QEP anticipates global crude oil prices to remain near current levels, assuming the global economy and socio-political backdrops remain relatively stable. Disruption to the global oil supply system, political and/or economic instability, and/or other factors could trigger additional volatility in crude oil prices. In addition, transportation, refining, or other infrastructure constraints could introduce significant price differentials between regional markets where QEP sells its crude oil production and national (NYMEX or Cushing) and global (Brent or U.S. Gulf Coast) markets. Because of the global and regional price volatility and the uncertainty around the commodity price environment, QEP continues to manage its capital spending program and financial flexibility accordingly.

27

Potential for Future Asset Impairments

During the second quarter and first half of 2012, QEP recorded non-cash, price-related impairment charges of $48.9 million and $49.3 million, respectively, on some of its proved properties. The impairment charges related to the reduced value of certain fields resulting from lower natural gas, crude oil and NGL prices. The assets were written down to their estimated fair values. Of the $49.3 million impairment charge during the six months ended June 30, 2012, $48.9 million related to proved properties in the Southern Region and $0.4 million related to proved properties in the Northern Region.

During the first half of 2012, U.S. natural gas prices were lower than in the first half of 2011, due to market concerns about growing natural gas production and record high levels of natural gas storage after an unusually warm winter season. The carrying values of some of the Company’s properties are sensitive to declines in natural gas, crude oil and NGL prices. These assets are at risk of impairment if future prices for natural gas, crude oil or NGL prices decline. The cash flow model that the Company uses to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future oil 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, crude oil and NGL prices alone could result in an impairment of properties. 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.

Impact of Dodd-Frank Act

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), was passed by Congress and signed into law in July 2010, establishing the Commodity Futures Trading Commission (CFTC).  The Dodd-Frank Act is designed to provide a comprehensive framework for the regulation of the over-the-counter derivatives market with the intent to provide greater transparency and reduction of risk between counterparties. The Dodd-Frank Act subjects swap dealers and major swap participants to capital and margin requirements and requires many derivative transactions to be cleared on exchanges. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users.  QEP is currently evaluating the CFTC's final rules and assessing the impact on the Company’s risk management program. In its initial evaluation, QEP believes it will meet the requirements for the commercial end-user clearing exception and be able to continue to execute derivative transactions and not be required to meet the mandated clearing requirements. The CFTC's final rules are expected to have an impact on many of QEP's derivatives counterparties which may result in additional costs that may be passed on to the Company, thereby potentially decreasing the relative effectiveness of our derivatives and potential profitability.

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 (GAAP). The preparation of the Company’s Condensed Consolidated Financial Statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP’s accounting policies on gas and oil reserves, successful efforts accounting for gas and oil operations, impairment of gas and oil properties, asset retirement obligations, accounting for derivative contracts, revenue recognition, environmental obligations and other contingencies, benefit plan obligations, share-based compensation, and income taxes, among others, may involve a high degree of complexity and judgment on the part of management.

RESULTS OF OPERATIONS

Net Income (Loss)

QEP Resources’ net loss was $0.7 million, or $0.00 per diluted share, in the second quarter of 2012, compared to net income of $92.8 million, or $0.52 per diluted share, in the second quarter of 2011. The decline in net income during the second quarter of 2012 was attributable to a 165% decrease in QEP Energy’s net income and a 25% decrease in QEP Field Services net income. QEP Energy’s net income decreased in the second quarter of 2012 due to a $34.9 million loss on unrealized derivative contracts and a $48.9 million commodity price-related impairment charge on some of its proved properties, partially offset by increased production volumes. The decrease in QEP Field Services’ second quarter 2012 net income was driven by a 9% decline in gathering margins and a 23% decline in processing margins. Net income attributable to QEP for the first half of 2012 was $154.5 million, or $0.87 per diluted share, compared to $166.0 million, or $0.93 per diluted share in the first half of 2011. The decrease in the six month period of 2012 was due to a 13% decrease in QEP Energy’s net income, partially offset by a 9% increase in QEP Field Services net income. QEP Energy’s net income decreased during the first half of 2012 due to a commodity price-related impairment charges on proved properties of $49.3 million and 6% lower total equivalent commodity prices, offset partially by an $88.8 million gain on unrealized commodity derivative contracts, deferred in AOCI in the first half of 2011 and increased production volumes. QEP Field Services’ increase in net income during the six months ended June 30, 2012 was driven by 14% higher processing margins.

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

	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2012			2011		Change			2012			2011		Change
	(in millions)
QEP Energy	$	(30.3	)	$	46.8	$	(77.1	)	$	77.8		$	89.9	$	(12.1	)
QEP Field Services		33.3			44.2		(10.9	)		78.7			72.2		6.5
QEP Marketing and other		(3.7	)		1.8		(5.5	)		(2.0	)		3.9		(5.9	)
Net (loss) income attributable to QEP	$	(0.7	)	$	92.8	$	(93.5	)	$	154.5		$	166.0	$	(11.5	)
Earnings per diluted share	$	-		$	0.52	$	(0.52	)	$	0.87		$	0.93	$	(0.06	)
Average diluted shares		177.7			178.6		(0.9	)		178.5			178.5		-

Adjusted EBITDA

Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company’s cash flow, liquidity, and ability to incur and service debt, fund capital expenditures and make distributions to shareholders. The use of this measure allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. It is also an important measure for comparing the Company’s financial performance to other gas and oil producing companies. In addition, Adjusted EBITDA is a measure used in the Company’s debt covenants under its revolving credit agreement and Term Loan.

Consistent with such debt covenants, 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, losses on early extinguishment of debt, 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 better 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.

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

	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2012		2011		Change			2012		2011		Change
	(in millions)
QEP Energy	$	265.7	$	247.7	$	18.0		$	526.5	$	489.7	$	36.8
QEP Field Services		71.5		86.9		(15.4	)		155.8		148.3		7.5
QEP Marketing and other		1.3		2.0		(0.7	)		1.9		4.4		(2.5	)
Adjusted EBITDA	$	338.5	$	336.6	$	1.9		$	684.2	$	642.4	$	41.8

Adjusted EBITDA increased to $338.5 million during the second quarter of 2012, compared to $336.6 million in the second quarter of 2011, despite a 17% decline in net realized natural gas prices, 10% lower net realized crude oil prices and 16% lower net realized NGL prices. The impact of lower net realized prices during the second quarter of 2012 was more than offset by a 23% increase in total production in QEP Energy. During the six months ended June 30, 2012, Adjusted EBITDA increased to $684.2 million from $642.4 million in the six months ended June 30, 2011, despite 15% lower net realized natural gas, 2% lower net realized crude oil prices and 15% lower net realized NGL prices. The impact of lower net realized prices during the first half of 2012 was more than offset by an 18% increase in total production at QEP Energy, and increased processing margins at QEP Field Services.

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The following table is a reconciliation of Adjusted EBITDA to net income, the most comparable GAAP financial measure of this non-GAAP financial measure:

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2012			2011			Change			2012			2011			Change
	(in millions)
Net (loss) income attributable to QEP Resources	$	(0.7	)	$	92.8		$	(93.5	)	$	154.5		$	166.0		$	(11.5	)
Net income attributable to non-controlling interest		0.9			0.7			0.2			1.7			1.3			0.4
Net income		0.2			93.5			(93.3	)		156.2			167.3			(11.1	)
Unrealized loss (gain) on derivative contracts		38.4			(27.6	)		66.0			(89.9	)		(58.8	)		(31.1	)
Net gain from asset sales		-			(0.2	)		0.2			(1.5	)		(0.2	)		(1.3	)
Interest and other (income) loss		(0.9	)		0.4			(1.3	)		(2.6	)		(0.2	)		(2.4	)
Income taxes		0.1			54.2			(54.1	)		88.8			96.9			(8.1	)
Interest expense		28.2			22.1			6.1			52.9			44.2			8.7
Loss on early extinguishment of debt		0.6			-			0.6			0.6			-			0.6
Depreciation, depletion and amortization		214.1			186.6			27.5			413.3			377.4			35.9
Abandonment and impairment		55.7			5.3			50.4			62.3			10.7			51.6
Exploration expenses		2.1			2.3			(0.2	)		4.1			5.1			(1.0	)
Adjusted EBITDA	$	338.5		$	336.6		$	1.9		$	684.2		$	642.4		$	41.8

The following table is a reconciliation of QEP Energy Adjusted EBITDA to net income:

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2012			2011			Change			2012			2011			Change
	(in millions)
Net income (loss) attributable to QEP Energy	$	(30.3	)	$	46.8		$	(77.1	)	$	77.8		$	89.9		$	(12.1	)
Unrealized loss (gain) on derivative contracts		34.9			(27.6	)		62.5			(88.8	)		(58.8	)		(30.0	)
Net gain from asset sales		-			(0.2	)		0.2			(1.5	)		(0.2	)		(1.3	)
Interest and other (income) loss		(0.7	)		0.5			(1.2	)		(2.4	)		(0.2	)		(2.2	)
Income taxes		(16.6	)		27.7			(44.3	)		47.7			53.3			(5.6	)
Interest expense		23.4			20.4			3.0			47.0			40.3			6.7
Depreciation, depletion and amortization		197.2			172.5			24.7			380.3			349.6			30.7
Abandonment and impairment		55.7			5.3			50.4			62.3			10.7			51.6
Exploration expenses		2.1			2.3			(0.2	)		4.1			5.1			(1.0	)
Adjusted EBITDA	$	265.7		$	247.7		$	18.0		$	526.5		$	489.7		$	36.8

The following table is a reconciliation of QEP Field Services Adjusted EBITDA to net income:

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2012			2011			Change			2012			2011			Change
	(in millions)
Net income attributable to QEP Field Services	$	33.3		$	44.2		$	(10.9	)	$	78.7		$	72.2		$	6.5
Net income attributable to non-controlling interest		0.9			0.7			0.2			1.7			1.3			0.4
Net income		34.2			44.9			(10.7	)		80.4			73.5			6.9
Unrealized (gain) on derivative contracts		(1.5	)		-			(1.5	)		(4.5	)		-			(4.5	)
Net gain from asset sales		-			(0.1	)		0.1			-			(0.1	)		0.1
Interest and other income		(0.1	)		-			(0.1	)		(0.1	)		-			(0.1	)
Income taxes		19.2			25.5			(6.3	)		42.7			41.6			1.1
Interest expense		3.6			3.1			0.5			5.9			6.6			(0.7	)
Depreciation, depletion and amortization		16.1			13.5			2.6			31.4			26.7			4.7
Adjusted EBITDA	$	71.5		$	86.9		$	(15.4	)	$	155.8		$	148.3		$	7.5

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The following table is a reconciliation of QEP Marketing and other Adjusted EBITDA to net income:

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2012			2011			Change			2012			2011			Change
	(in millions)
Net income (loss) attributable to QEP Marketing and other	$	(3.7	)	$	1.8		$	(5.5	)	$	(2.0	)	$	3.9		$	(5.9	)
Unrealized loss on derivative contracts		5.0			-			5.0			3.4			-			3.4
Net gain from asset sales		-			0.1			(0.1	)		-			0.1			(0.1	)
Interest and other income		(0.1	)		(0.1	)		-			(0.1	)		-			(0.1	)
Income taxes		(2.5	)		1.0			(3.5	)		(1.6	)		2.0			(3.6	)
Interest expense		1.2			(1.4	)		2.6			-			(2.7	)		2.7
Loss on early extinguishment of debt		0.6			-			0.6			0.6			-			0.6
Depreciation, depletion and amortization		0.8			0.6			0.2			1.6			1.1			0.5
Adjusted EBITDA	$	1.3		$	2.0		$	(0.7	)	$	1.9		$	4.4		$	(2.5	)

Production

QEP Energy reported production of 79.6 Bcfe in the second quarter of 2012, a 23% increase when compared to the 64.7 Bcfe reported in the second quarter of 2011. On an energy-equivalent basis, crude oil and NGL comprised approximately 20% of QEP Energy’s production during the three month period ended June 30, 2012, up from 12% for the three months ended June 30, 2011. QEP Energy reported production of 153.8 Bcfe in the first half of 2012, an 18% increase over the 130.6 Bcfe reported during the first half of 2011. On an energy-equivalent basis, crude oil and NGL comprised approximately 20% of QEP Energy’s production for the six months ended June 30, 2012, up from 11% for the six months ended June 30, 2011.

A summary of QEP Energy production is shown in the following table:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012		2011		Change		2012		2011		Change
QEP Energy Production Volumes
Natural gas (Bcf)		64.0		57.0		7.0		123.5		116.1		7.4
Oil (Mbbl)		1,308.0		873.6		434.4		2,530.5		1,636.6		893.9
NGL (Mbbl)		1,297.8		394.3		903.5		2,519.5		780.6		1,738.9
Total production (Bcfe)		79.6		64.7		14.9		153.8		130.6		23.2
Average daily production (MMcfe)		875.1		710.8		164.3		845.1		721.7		123.4

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

	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
QEP Energy - Natural gas Production (Bcf)
Northern Region
Pinedale		18.2		17.0		1.2			35.2		32.4		2.8
Uinta Basin		4.0		3.4		0.6			7.3		8.2		(0.9	)
Legacy		2.9		3.1		(0.2	)		6.0		6.1		(0.1	)
Southern Region
Haynesville/Cotton Valley		30.9		25.7		5.2			58.8		53.9		4.9
Midcontinent		8.0		7.8		0.2			16.2		15.5		0.7
Total production		64.0		57.0		7.0			123.5		116.1		7.4

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

	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
QEP Energy - Oil Production (Mbbl)
Northern Region
Pinedale		153.8		139.2		14.6			306.1		269.8		36.3
Uinta Basin		216.2		233.4		(17.2	)		420.3		458.7		(38.4	)
Legacy		575.2		298.7		276.5			1,146.0		527.6		618.4
Southern Region
Haynesville/Cotton Valley		13.0		11.7		1.3			22.4		26.3		(3.9	)
Midcontinent		349.8		190.6		159.2			635.7		354.2		281.5
Total production		1,308.0		873.6		434.4			2,530.5		1,636.6		893.9

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012		2011		Change		2012		2011		Change
QEP Energy - NGL Production (Mbbl)
Northern Region
Pinedale		748.8		-		748.8		1,465.9		-		1,465.9
Uinta Basin		86.6		25.2		61.4		107.9		59.5		48.4
Legacy		48.2		29.8		18.4		89.6		56.3		33.3
Southern Region
Haynesville/Cotton Valley		2.0		2.0		-		4.4		4.0		0.4
Midcontinent		412.2		337.3		74.9		851.7		660.8		190.9
Total production		1,297.8		394.3		903.5		2,519.5		780.6		1,738.9

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012		2011		Change		2012		2011		Change
QEP Energy - Total Production (Bcfe)
Northern Region
Pinedale		23.7		17.8		5.9		45.9		34.0		11.9
Uinta Basin (1)		5.9		5.0		0.9		10.5		11.4		(0.9	)
Legacy		6.5		5.0		1.5		13.3		9.5		3.8
Southern Region
Haynesville/Cotton Valley		30.9		25.8		5.1		58.9		54.1		4.8
Midcontinent		12.6		11.1		1.5		25.2		21.6		3.6
Total production		79.6		64.7		14.9		153.8		130.6		23.2

(1) During the six months ended June 30, 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.

Northern Region – Pinedale Division. Net production from Pinedale in western Wyoming grew 33% to 23.7 Bcfe in the second quarter of 2012 compared to the second quarter of 2011. Net production from Pinedale grew 35% to 45.9 Bcfe in the first half of 2012 compared to the first half of 2011. Pinedale production growth was driven by increased drilling activity and the fee-based processing agreement at Blacks Fork II entered into in the third quarter of 2011 between QEP Energy and QEP Field Services. As a result of the processing agreement, QEP Energy NGL production at Pinedale for the three and six months ended June 30, 2012, was 748.8 Mbbl and 1,465.9 Mbbl, contrasted with no reportable NGL production in the comparable 2011 periods. During the three and six months ended June 30, 2012, the Pinedale Division represented 30% of QEP Energy’s total production compared to 28% and 26% during the three and six months ended June 30, 2011, respectively.

Northern Region – Uinta Basin Division. In the Uinta Basin, production increased 18% to 5.9 Bcfe in the second quarter of 2012 from the second quarter of 2011 due to increased drilling activity as a result of its new drilling program targeting the Lower Mesaverde Formation in the Red Wash Unit. NGL production increased 244% to 86.6 Mbbl in the second quarter of 2012 compared to the second quarter of 2011 as a result of QEP Energy executing a fee-based processing agreement with QEP Field Services that resulted in the NGLs recovered from QEP Energy production being credited to QEP Energy. During the first half of 2012, Uinta Basin production decreased 8% 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 the first half of 2011 of 1.6 Bcfe. Excluding this prior-period adjustment, QEP Uinta Basin production increased by 7% in the first half of 2012 as a result of its new drilling program targeting the Lower Mesaverde Formation. During the three and six months ended June 30, 2012, the Uinta Basin Division production represented 7% of QEP Energy’s total production compared to 8% and 9% during the three and six months ended June 30, 2011, respectively.

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Northern Region –Legacy Division. Legacy Division net production during the second quarter of 2012 increased 30% to 6.5 Bcfe, driven by a 93% increase in crude oil production and a 62% increase in NGL production. During the first half of 2012, net production in the Legacy Division increased 40% to 13.3 Bcfe due to a 117% increase in crude oil production and a 59% increase in NGL production. The increased production in the three and six months ended June 30, 2012, was due to increased oil-directed drilling activity in the North Dakota Bakken/Three Forks play. QEP Energy Legacy Division properties include all Northern Region Rockies properties except the Pinedale Anticline and the Uinta Basin. During the three and six months ended June 30, 2012, the Legacy Division production represented 8% and 9% of QEP Energy’s total production, respectively, compared to 8% and 7% during the three and six months ended June 30, 2011, respectively.

Southern Region – Haynesville/Cotton Valley Division. Net production from the Haynesville Shale and Cotton Valley tight gas plays in northwest Louisiana increased 20% to 30.9 Bcfe in the second quarter of 2012, when compared to the second quarter of 2011. During the first half of 2012, net production from the Haynesville Shale and Cotton Valley plays increased 9% to 58.9 Bcfe. The increases during the three and six months ended June 30, 2012, were due to the completion of several high-rate wells in 2012 that were drilled during the latter half of 2011. QEP Energy has significantly reduced the pace of development drilling in the Haynesville shale play in response to depressed natural gas prices and expects production to decline as the final operated rig was released in July of 2012 and the completion of five wells that have been drilled and cased in 2012 are currently planned to be deferred until early 2013. During the three and six months ended June 30, 2012, Haynesville/Cotton Valley production comprised 39% and 38% of QEP Energy’s total production, respectively, compared to 40% and 41% in the three and six months ended June 30, 2011, respectively.

Southern Region – Midcontinent Division. Net production in the Midcontinent grew 14% to 12.6 Bcfe in the second quarter of 2012 when compared to the second quarter of 2011 due to an 84% increase in crude oil production and a 22% increase in NGL production. During the first half of 2012, net production in the Midcontinent grew 17% to 25.2 Bcfe compared to the first half of 2011, driven by a 79% increase in crude oil production and a 29% increase in NGL production. Midcontinent production growth was driven by continued development of the Granite Wash/Marmaton/Tonkawa plays in Texas and western Oklahoma and the Woodford “Cana” Shale liquids-rich gas play in the Anadarko Basin of western Oklahoma. During the three and six months ended June 30, 2012, the Midcontinent Division represented 16% of QEP Energy’s total production, down from 17% during the second quarter and first half of 2011.

Pricing

During the year ended December 31, 2011, QEP revised its reporting of natural gas, oil and NGL transportation and handling costs. Transportation and handling costs have been recast on the Condensed Consolidated Statement of Income from revenues to “Natural gas, oil and NGL transportation and other handling costs” for all periods presented. Prior to the recast, transportation and other handling costs were netted against revenue and were reflected in field-level prices. 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.

In addition, QEP Energy’s field-level and realized prices (after the impact of all settled commodity derivatives) for natural gas, oil and NGLs were lower during the three and six months ended June 30, 2012, than in the 2011 comparable periods. A regional comparison of average field level prices is shown in the following tables:

	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
QEP Energy - Average field-level natural gas price (per Mcf)
Northern Region	$	2.07	$	3.95	$	(1.88	)	$	2.35	$	4.05	$	(1.70	)
Southern Region		2.23		4.21		(1.98	)		2.48		4.10		(1.62	)
Average field-level natural gas price		2.17		4.11		(1.94	)		2.43		4.08		(1.65	)
QEP Energy - Average field-level oil price (per bbl)
Northern Region	$	78.12	$	91.67	$	(13.55	)	$	83.19	$	86.40	$	(3.21	)
Southern Region		91.76		94.11		(2.35	)		94.51		92.12		2.39
Average field-level oil price		81.90		92.24		(10.34	)		86.14		87.73		(1.59	)
QEP Energy - Average field-level NGL price (per bbl)
Northern Region	$	36.76	$	63.22	$	(26.46	)	$	40.52	$	63.41	$	(22.89	)
Southern Region		32.11		41.14		(9.03	)		33.06		42.81		(9.75	)
Average field-level NGL price		35.27		44.22		(8.95	)		37.98		45.86		(7.88	)

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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 June 30,							Six Months Ended June 30,
	2012 (1)		2011 (2)		Change			2012 (1)			2011 (2)		Change
Natural gas (per Mcf)
Average field-level price	$	2.17	$	4.11	$	(1.94	)	$	2.43		$	4.08	$	(1.65	)
Commodity derivative impact		1.75		0.64		1.11			1.60			0.68		0.92
Net realized price	$	3.92	$	4.75	$	(0.83	)	$	4.03		$	4.76	$	(0.73	)
Oil (per bbl)
Average field-level price	$	81.90	$	92.24	$	(10.34	)	$	86.14		$	87.73	$	(1.59	)
Commodity derivative impact		1.70		0.14		1.56			(0.19	)		0.08		(0.27	)
Net realized price	$	83.60	$	92.38	$	(8.78	)	$	85.95		$	87.81	$	(1.86	)
NGL (per bbl)
Average field-level price	$	35.27	$	44.22	$	(8.95	)	$	37.98		$	45.86	$	(7.88	)
Commodity derivative impact		2.04		-		2.04			1.23			-		1.23
Net realized price	$	37.31	$	44.22	$	(6.91	)	$	39.21		$	45.86	$	(6.65	)

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

(2) The impact of settled commodity derivatives that qualified for hedge accounting was reported in “Revenues” in the Condensed Consolidated Statement of Income.

Gathering

During the three and six months ended June 30, 2012 QEP Field Services gathering margins declined 9% and 6%, respectively, due mainly to a decrease in other gathering revenue and related margin from the elimination of a third-party interruptible processing agreement. Partially offsetting the decline in gathering margin was an 11% and a 7% increase in gathering system throughput volume and a 6% and 3% increase in the average gathering rate during the three and six months ended June 30, 2012, respectively. Gathering system throughput volume was 1.5 million MMBtu per day and 1.4 million MMBtu per day for the three and six months ended June 30, 2012, respectively, up from 1.3 million MMBtu per day during the three and six months ended June 30, 2011. The increased volumes were mainly related to the gathering system tied into the Blacks Fork hub, which were 11% and 8% higher in the three and six months ended June 30, 2012, respectively, and the northwest Louisiana gathering system, which were 37% and 20% higher in the three and six months June 30, 2012, respectively. The Blacks Fork hub accounted for 49% of the total gathering system throughput during the three and six months ended June 30, 2012, and in the three and six months ended June 30, 2011, while the Louisiana hub accounted for 25% of the total throughput during the three and six months ended June 30, 2012, compared to 20% and 22% during the three and six months ended June 30, 2011, respectively.

During the three and six months ended June 30, 2011, QEP Field Services reported other gathering revenues and related gathering expense 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. Of the $15.7 million and $22.1 million decrease in other gathering revenues, $15.0 million and $23.4 million of the decrease related to the elimination of this contract. In addition, gathering expenses related to the elimination of this contract were $4.5 million and $7.6 million lower during the three and six months ended June 30, 2011.

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

	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Change			2012			2011			Change
Gathering Margin				(in millions)						(in millions)
Gathering revenues	$	45.8		$	38.7		$	7.1		$	87.7		$	78.1		$	9.6
Other gathering revenues		9.3			25.0			(15.7	)		20.6			42.7			(22.1	)
Gathering expense		(8.3	)		(12.4	)		4.1			(17.9	)		(24.3	)		6.4
Gathering margin	$	46.8		$	51.3		$	(4.5	)	$	90.4		$	96.5		$	(6.1	)

Operating Statistics
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers		63.2		66.0		(2.8	)		124.2		127.1		(2.9	)
For affiliated customers		70.7		55.1		15.6			133.4		113.0		20.4
Total Gas Gathering Volumes		133.9		121.1		12.8			257.6		240.1		17.5
Average gas gathering revenue (per MMBtu)	$	0.34	$	0.32	$	0.02		$	0.34	$	0.33	$	0.01

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. 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 amount of natural gas to the customer. Keep-whole processing exposes the Company to the “frac” spread. The frac spread is the difference between the market value of NGLs extracted at the processing plant and the market value of an energy-equivalent volume of natural gas.

QEP Field Services processing margin decreased 23% during the second quarter of 2012, but increased 14% during the first half of 2012. The decrease in the processing margin during the second quarter of 2012 was due to a 43% decline in keep-whole processing margins, partially offset by a 44% increase in fee-based processing revenues. The increase in the processing margin during the first half of 2012 was due to a 5% increase in the frac spread per NGL gallon and a 51% increase in fee-based processing revenues, offset slightly by a 6% decrease in the keep-whole processing margin. During the second quarter and first half of 2012, keep-whole processing margins decreased due to a decrease in the net realized NGL sales price per gallon, offset by increased NGL sales volumes. NGL sales volumes increased 14% and 35% in the three and six months ended June 30, 2012, respectively, compared to the 2011 periods. The increased NGL sales volumes in the second quarter and first half of 2012 were primarily the result of the Blacks Fork II plant which commenced operations in July 2011, partially offset by the execution, in the second quarter of 2012, of a fee-based processing agreement with QEP Energy in the Uinta Basin that effectively transferred NGL gallons from QEP Field Services to QEP Energy.

Including the impact of gains on derivative contract settlements, NGL prices decreased 24% and 14% in the three and six months ended June 30, 2012, respectively, compared to the three and six months ended June 30, 2011, which caused a corresponding decrease in the keep-whole processing margin per NGL gallon. During the three and six months ended June 30, 2012, the keep-whole processing margin per NGL gallon was $0.46 and $0.56, respectively, compared to $0.93 and $0.81 during the three and six months ended June 30, 2011, respectively.

Fee-based processing revenues increased during the second quarter of 2012 due to a 29% increase in the average processing fee rate to $0.27 per MMBtu and a 7% increase in fee-based processing volumes to 64.5 million MMBtu. During the first half of 2012, the increase in fee-based processing revenues was the result of a 42% increase in the average processing fee rate and a 6% increase in fee-based processing volumes. Approximately 78% and 75% of QEP Field Services’ net operating revenue was derived from fee-based gathering and processing agreements in the three and six months ended June 30, 2012, respectively, compared to 69% and 73% during the three and six months ended June 30, 2011, respectively.

Keep-whole processing margin, as reflected in the table below, 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 (including fractionation) costs. Transportation and handling costs were up $10.8 million and $18.7 million during the three and six months ended June 30, 2012, respectively, primarily the result of additional transportation costs relating to NGL sale agreements that provide for transportation and fractionation of NGL’s at Mont Belvieu, Texas, and the 2012 operation of the Blacks Fork II plant, which was put into service in July of 2011.

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

	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Change			2012			2011			Change
Processing Margin										(in millions)
NGL sales (1)	$	36.3		$	46.3		$	(10.0	)	$	83.8		$	75.8		$	8.0
Realized gains from commodity derivative contract settlements		3.3			-			3.3			4.4			-			4.4
Processing (fee-based) revenues		17.6			12.2			5.4			33.6			22.2			11.4
Other processing fees		-			-			-			3.0			-			3.0
Processing (expense)		(3.7	)		(3.1	)		(0.6	)		(7.4	)		(5.8	)		(1.6	)
Processing plant fuel and shrink (expense)		(8.4	)		(11.4	)		3.0			(18.5	)		(21.6	)		3.1
Natural gas, oil and NGL transportation and other handling costs		(12.0	)		(1.2	)		(10.8	)		(20.8	)		(2.1	)		(18.7	)
Processing margin	$	33.1		$	42.8		$	(9.7	)	$	78.1		$	68.5		$	9.6
Keep-whole processing margin	$	19.2		$	33.7		$	(14.5	)	$	48.9		$	52.1		$	(3.2	)

Operating Statistics
Natural gas processing volumes
NGL sales (MMgal)		41.4		36.4		5.0			86.6		64.2		22.4
Average net realized NGL sales price (per gal)	$	0.96	$	1.27	$	(0.31	)	$	1.02	$	1.18	$	(0.16	)
Fee-based processing volumes (in millions of MMBtu)
For unaffiliated customers		29.7		33.1		(3.4	)		57.7		64.5		(6.8	)
For affiliated customers		34.8		27.2		7.6			66.5		52.8		13.7
Total fee-based processing volumes		64.5		60.3		4.2			124.2		117.3		6.9
Average fee-based processing revenue (per MMBtu)	$	0.27	$	0.21	$	0.06		$	0.27	$	0.19	$	0.08

(1) NGL sales for the three and six months ended June 30, 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 and six months ended June 30, 2011, reflect the impact of QEP’s settled derivative contracts which during the three and six months ended June 30, 2012, are reflected below operating (loss) income. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the three and six months ended June 30, 2011.

Revenue, Volume and Price Variance Analysis

On January 1, 2012, QEP discontinued hedge accounting. During the three and six months ended June 30, 2012, commodity derivative realized gains and losses from derivative contract settlements were included below operating (loss) income in “Realized and unrealized gains on derivative contracts” on the Condensed Consolidated Statement of Income. Conversely, during the three and six months ended June 30, 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 Statement of Income, see Note 6 - Derivative Contracts, in Part I, Item 1 of this Quarterly Report on Form 10-Q.

	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2011		2010		Change			2012		2011		Change
	(in millions)
QEP Resources Revenues
Natural gas sales	$	138.9	$	298.7	$	(159.8	)	$	300.1	$	611.3	$	(311.2	)
Oil sales		107.2		80.7		26.5			218.0		143.7		74.3
NGL sales		82.1		63.8		18.3			179.5		111.7		67.8
Gathering, processing and other		45.8		58.9		(13.1	)		95.6		105.5		(9.9	)
Purchased gas and oil sales		125.3		306.0		(180.7	)		309.3		453.8		(144.5	)
Total Revenues	$	499.3	$	808.1	$	(308.8	)	$	1,102.5	$	1,426.0	$	(323.5	)

QEP Energy’s revenues for the three and six months ended June 30, 2012, generated from the sale of natural gas, oil and NGLs, decreased primarily due to lower prices for natural gas, crude oil and NGL, partially offset by higher production volumes, as follows:

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	Natural Gas			Oil			NGLs			Total
	(in millions)
QEP Energy Revenues
Three months ended June 30, 2011 Revenues	$	298.7		$	80.7		$	17.5		$	396.9
Changes associated with volumes (1)		27.7			40.5			40.0			108.2
Changes associated with prices (2)		(123.1	)		(13.9	)		(11.7	)		(148.7	)
Changes associated with discontinuance of hedge accounting (3)		(64.4	)		(0.1	)		-			(64.5	)
Three months ended June 30, 2012 Revenues	$	138.9		$	107.2		$	45.8		$	291.9
	Natural Gas			Oil			NGLs			Total
	(in millions)
QEP Energy Revenues
Six months ended June 30, 2011 Revenues	$	611.3		$	143.7		$	35.9		$	790.9
Changes associated with volumes (1)		30.1			78.4			79.7			188.2
Changes associated with prices (2)		(203.8	)		(4.0	)		(19.9	)		(227.7	)
Changes associated with discontinuance of hedge accounting (3)		(137.5	)		(0.1	)		-			(137.6	)
Six months ended June 30, 2012 Revenues	$	300.1		$	218.0		$	95.7		$	613.8

(1) The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and six months ended June 30, 2012, to the three and six months ended June 30, 2011, by the average field-level price for the three and six months ended June 30, 2011.

(2) The revenue variance attributed to the change in price is calculated by multiplying the change in field-level prices or fee from the three and six months ended June 30, 2012, to the three and six months ended June 30, 2011, by volume for the three and six months ended June 30, 2012. Pricing changes are driven by changes in the commodity field-level prices excluding impact from commodity derivatives.

(3) During the three and six months ended June 30, 2011, realized gains and losses on commodity derivative contract settlements were included in natural gas revenues on the Condensed Consolidated Statement of Income. Conversely, during the three and six months ended June 30, 2012, the realized gains and losses on commodity derivative contract settlements are recognized below operating (loss) income on the Condensed Consolidated Statement of Income.

QEP Field Services revenues decreased during the second quarter of 2012 compared to the 2011 second quarter but increased during the first half of 2012. During the three and six months ended June 30, 2012, various factors decreased gathering revenues including the elimination of a short-term, third-party, interruptible processing agreement recorded as other gathering revenues and reflected as a change associated with other factors. Changes associated with other factors increased processing revenues by $0.5 million and $3.0 million during the three and six months ended June 30, 2012, respectively, due to charges to customers 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 June 30,
	NGLs			Processing		Gathering			Total
	(in millions)
QEP Field Services
Three months ended June 30, 2011 Revenues	$	46.3		$	12.2	$	63.7		$	122.2
Changes associated with volumes (1)		7.9			0.9		4.1			12.9
Changes associated with prices/fees (2)		(17.9	)		4.0		2.7			(11.2	)
Changes associated with other factors (3)		-			0.5		(15.4	)		(14.9	)
Three months ended June 30, 2012 Revenues	$	36.3		$	17.6	$	55.1		$	109.0
	Six Months Ended June 30,
	NGLs			Processing		Gathering			Total
	(in millions)
QEP Field Services
Six months ended June 30, 2011 Revenues	$	75.8		$	22.2	$	120.8		$	218.8
Changes associated with volumes (1)		26.5			1.4		5.7			33.6
Changes associated with prices/fees (2)		(18.5	)		10.0		3.9			(4.6	)
Changes associated with other factors (3)		-			3.0		(22.1	)		(19.1	)
Six months ended June 30, 2012 Revenues	$	83.8		$	36.6	$	108.3		$	228.7

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(1) The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and six months ended June 30, 2012, to the three and six months ended June 30, 2011, by the average price or fee for the three and six months ended June 30, 2011.

(2) The revenue variance attributed to the change in fees is calculated by multiplying the change in prices or fees from the three and six months ended June 30, 2012, to the three and six months ended June 30, 2011, by volume for the three and six months ended June 30, 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, oil and NGL sales decreased by $180.7 million and $144.5 million, or 59% and 32%, during the three and six months ended June 30, 2012, respectively, from 2011. The decreases in the three and six months ended June 30, 2012, were due to decreased resale natural gas volumes and prices. Resale natural gas volumes were 40% and 2% lower during the three and six months ended June 30, 2012, while resale natural gas prices were 55% and 44% lower during the three and six months ended June 30, 2012, respectively.

Operating Expenses

The following table presents QEP Resources’ total operating expenses and the changes from the three and six months ended June 30, 2012, to the three and six months ended June 30, 2011. The narrative following the table explains the significant variances between the comparable periods.

	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
	(in millions)
Purchased gas and oil expense	$	124.9	$	303.9	$	(179.0	)	$	313.3	$	450.6	$	(137.3	)
Lease operating expense		40.5		34.3		6.2			80.6		67.1		13.5
Natural gas, oil and NGL transportation and other handling costs		40.7		24.0		16.7			75.2		45.7		29.5
Gathering, processing and other		20.6		27.2		(6.6	)		44.3		52.4		(8.1	)
General and administrative		36.8		28.7		8.1			72.8		60.4		12.4
Production and property taxes		19.4		27.1		(7.7	)		44.1		50.8		(6.7	)
Depreciation, depletion and amortization		214.1		186.6		27.5			413.3		377.4		35.9
Exploration expenses		2.1		2.3		(0.2	)		4.1		5.1		(1.0	)
Abandonment and impairment		55.7		5.3		50.4			62.3		10.7		51.6
Total operating expenses	$	554.8	$	639.4	$	(84.6	)	$	1,110.0	$	1,120.2	$	(10.2	)

Purchased gas, oil and NGL expense decreased 59% and 30% in the three and six months ended June 30, 2012, respectively. The decreases during both periods were primarily due to lower natural gas and crude oil prices.

Lease operating expense increased 18% and 20% during the three and six months ended June 30, 2012, respectively, due to higher water disposal costs, increased trucking, labor and pumper costs, and higher maintenance, repairs and work over costs. Water disposal costs increased $2.8 million and $5.5 million during the three and six months ended June 30, 2012, respectively, primarily in the Northern Region due to increased drilling activity and liquids production. During the three and six months ended June 30, 2012, trucking, labor and pumper costs increased $1.4 million and $4.6 million, respectively, in both the Southern and Northern Regions due to increased activity and liquids production. Maintenance, repairs and work over costs increased $0.8 million and $2.5 million during the three and six months ended June 30, 2012, primarily in the Southern Region.

For the three and six months ended June 30, 2012, natural gas, oil and NGL transportation and other handling costs increased $16.7 million and $29.5 million, respectively, when compared to the corresponding period in 2011. The increases during the three and six months ended June 30, 2012, are primarily due to transportation costs relating to NGL sale agreements that provide for transportation and fractionation of NGL’s at Mont Belvieu, Texas and the 2012 operation of 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 $6.6 million and $8.1 million for the three and six months ended June 30, 2012, respectively, due to lower gathering expenses from 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 half of 2011 before the expansion of the Blacks Fork processing plant was put into service during the third quarter of 2011.

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For the second quarter of 2012, general and administrative (G&A) expense increased $8.1 million to $36.8 million, compared to the same period in 2011. The increase in G&A during the second quarter of 2012 was primarily due to a $5.5 million increase in costs from increased headcount and the annual compensation program, and $2.3 million attributable to restructuring costs (see Note 7 – Restructuring Costs of this Form 10-Q for additional information on the restructuring costs). G&A expense increased $12.4 million, or 21%, during the first half of 2012 when compared to the first half of 2011. The increase in G&A in the first half of 2012 was primarily due to $5.0 million in restructuring costs, $2.7 million increase in outside services and $2.9 million in higher costs due to increased headcount and the annual compensation program.

Production and property taxes decreased 28% for the second quarter of 2012 and 13% during the first half of 2012. The decrease in the three and six months ended June 30, 2012 was due to a 29% and a 20% decrease, respectively, in field-level equivalent sales prices which are used as the basis for production taxes in most states where QEP operates.

For the three months and six months ended June 30, 2012, QEP’s total DD&A expense grew $27.5 million, or 15%, and $35.9 million, or 10%, respectively, as compared to the same periods in 2011. The second quarter 2012 and first half 2012 increases in DD&A expense were the result of increased production at QEP Energy and increased DD&A at QEP Field Services due primarily to the completion of the Blacks Fork II plant in July 2011.

Exploration expenses decreased $0.2 million, or 9%, during the second quarter of 2012 and decreased $1.0 million, or 20%, in the first half of 2012 compared with 2011 periods. The first half 2012 decrease primarily related to a decrease of $0.4 million in dry hole expense.

Abandonment and impairment expenses increased $50.4 million in the second quarter of 2012 compared with the second quarter of 2011. The majority of the second quarter 2012 increase related to a non-cash impairment of certain of QEP Energy’s proved properties in its Southern Region of $48.9 million. The impairment change in the second quarter of 2012 related to the reduced value of certain fields resulting from lower natural gas, crude oil and NGL prices. In addition, during the second quarter of 2012, QEP Energy impairments on unproved properties were $1.1 million higher than the second quarter of 2011 due to numerous factors including, current development and exploration plans, results of development or exploration activity on adjacent leaseholds, technical personnel evaluations of the properties and the remaining lease term. During the first half of 2012, abandonment and impairment expenses increased $51.6 million from the first half of 2011. The increase in the first half of 2012 was primarily due to the $48.9 million impairment of proved properties in the Southern Region combined with $1.9 million higher write-offs of certain unproved properties due to the numerous factors listed previously. The Company’s proved properties have significant reserves and are sensitive to declines in natural gas, crude oil and NGL prices. These assets are at risk of impairment if future natural gas, crude oil or NGL prices experience significant declines.

CONSOLIDATED RESULTS BELOW OPERATING (LOSS) INCOME

Realized and unrealized gain on derivative contracts

Effective January 1, 2012, QEP discontinued hedge accounting, thus changes during the three and six months ended June 30, 2012, and all changes in mark-to-market are recognized in the current period earnings. In 2011, QEP used hedge accounting and changes in the mark-to-market value of the commodity derivative contracts were reflected in AOCI and ultimately revenues when the commodity derivatives were settled. Gains and losses on derivative instruments during 2012 are comprised of both realized and unrealized gains and losses on QEP’s commodity derivative contracts and interest rate swaps. During the second quarter of 2012, gains on commodity derivative instruments were $86.6 million, of which $120.7 million was realized, partially offset by a $34.1 million unrealized loss on commodity derivative instruments. During the first half of 2012, gains on commodity derivative instruments were $302.9 million, of which $208.7 million was realized and $94.2 million was unrealized. Additionally, during the three and six months ended June 30, 2012, QEP recognized an unrealized loss of $4.3 million from the mark-to-market value of its interest rate swaps.

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 and six months ended June 30, 2012, interest and other income increased $1.3 million and $2.4 million, respectively. The increases were primarily due to variances in warehouse inventory sales and valuations of $1.3 million and $1.9 million for the three and six months ended June 30, 2012, when compared to the prior year periods.

Loss from early extinguishment of debt

During the second quarter of 2012, QEP recorded a loss from early extinguishment of debt of $0.6 million from the retirement of a portion of QEP’s Senior Notes.

Interest expense

Interest expense increased $6.1 million, or 28%, during the second quarter of 2012 when compared to the second quarter of 2011. The increase in second quarter 2012 interest expense was attributable to average debt levels that were approximately $198 million higher than average debt levels in the second quarter of 2011. During the first half of 2012, interest expense increased $8.7 million, or 20%, when compared to the first half of 2011. The increase in interest expense during the first half of 2012 was due to average debt levels that were approximately $221 million higher than average debt levels in the first half of 2011. The increase in average debt levels is mostly related to the issuance of QEP’s 2022 Senior Notes and Term Loan in the first half of 2012.

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Income taxes

QEP’s effective combined federal and state income tax rate was 33.3% for the three months ended June 30, 2012, lower than the 36.7% in the three months ended June 30, 2011. The second quarter of 2012 combined rate was lower due primarily to lower net income and the related tax effect from the realization of permanent tax items or adjustments. The effective combined federal and state income tax rate was 36.2% for the six months ended June 30, 2012, lower than the 36.7% in the six months ended June 30, 2011. The 2012 first half combined rate was lower due to a lower tax rate in the first quarter of 2012, resulting from changes in estimates and subsequent reduction of accruals that are non-deductible for income tax purposes.

DISCUSSION BY LINE OF BUSINESS

QEP Energy

QEP Energy reported a net loss of $30.3 million in the second quarter of 2012, a decrease of $77.1 million from the $46.8 million net income reported in the second quarter of 2011. The decline in second quarter of 2012 net income was due to a non-cash impairment charge of $48.9 million on certain of its Southern Region proved properties, an unrealized loss from commodity derivative instruments of $34.9 million combined with 10% lower average total equivalent net realized prices. During the first half of 2012, QEP Energy reported net income of $77.8 million, a 13% decrease from the $89.9 million in the first half of 2011. The primary reasons for the decrease in the first half of 2012 were a $49.3 million non-cash impairment on proved properties and 6% lower average total equivalent net realized prices, partially offset by an unrealized gain from commodity derivative contracts of $88.8 million and increased production.

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

	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Change			2012			2011			Change
	(in millions)
Revenues
Natural gas sales	$	138.9		$	298.7		$	(159.8	)	$	300.1		$	611.3		$	(311.2	)
Oil sales		107.2			80.7			26.5			218.0			143.7			74.3
NGL sales		45.8			17.5			28.3			95.7			35.9			59.8
Purchased gas, oil and NGL sales		41.3			156.0			(114.7	)		113.8			156.0			(42.2	)
Other		2.3			2.6			(0.3	)		4.7			4.8			(0.1	)
Total Revenues		335.5			555.5			(220.0	)		732.3			951.7			(219.4	)
Operating expenses
Purchased gas, oil and NGL expense		40.6			154.7			(114.1	)		113.1			154.7			(41.6	)
Lease operating expense		41.4			35.0			6.4			82.2			68.4			13.8
Natural gas, oil and NGL transportation and other handling costs		57.2			42.3			14.9			107.6			85.8			21.8
General and administrative		29.2			22.9			6.3			62.1			46.8			15.3
Production and property taxes		18.2			25.4			(7.2	)		41.1			47.6			(6.5	)
Depreciation, depletion and amortization		197.2			172.5			24.7			380.3			349.6			30.7
Exploration expenses		2.1			2.3			(0.2	)		4.1			5.1			(1.0	)
Abandonment and impairment		55.7			5.3			50.4			62.3			10.7			51.6
Total Operating Expenses		441.6			460.4			(18.8	)		852.8			768.7			84.1
Net gain from asset sales		-			0.2			(0.2	)		1.5			0.2			1.3
Operating (Loss) Income		(106.1	)		95.3			(201.4	)		(119.0	)		183.2			(302.2	)
Realized gain (loss) on derivative instruments		116.7			(27.6	)		144.3			200.2			(58.8	)		259.0
Unrealized (loss) gain on derivative instruments		(34.9	)		27.6			(62.5	)		88.8			58.8			30.0
Interest and other income (loss)		0.7			(0.5	)		1.2			2.4			0.2			2.2
Income from unconsolidated affiliates		0.1			0.1			-			0.1			0.1			-
Interest expense		(23.4	)		(20.4	)		(3.0	)		(47.0	)		(40.3	)		(6.7	)
(Loss) Income before Income Taxes		(46.9	)		74.5			(121.4	)		125.5			143.2			(17.7	)
Income taxes		16.6			(27.7	)		44.3			(47.7	)		(53.3	)		5.6
Net (Loss) Income Attributable to QEP	$	(30.3	)	$	46.8		$	(77.1	)	$	77.8		$	89.9		$	(12.1	)

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Operating expenses per unit

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 6% to $4.61 per Mcfe in the second quarter of 2012 compared to $4.92 per Mcfe in the second quarter of 2011. Total operating expenses per Mcfe decreased 4% to $4.68 per Mcfe in the first half of 2012 compared to $4.90 per Mcfe in the first half of 2011. The following table presents certain QEP Energy operating expenses on a units of production basis.

	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.48	$	2.67	$	(0.19	)	$	2.47	$	2.68	$	(0.21	)
Lease operating expense		0.52		0.54		(0.02	)		0.53		0.52		0.01
Natural gas, oil and NGL transportation and other handling costs		0.72		0.65		0.07			0.70		0.66		0.04
General and administrative expense		0.37		0.35		0.02			0.40		0.36		0.04
Allocated interest expense		0.29		0.32		(0.03	)		0.31		0.31		-
Production taxes		0.23		0.39		(0.16	)		0.27		0.37		(0.10	)
Total Operating Expenses	$	4.61	$	4.92	$	(0.31	)	$	4.68	$	4.90	$	(0.22	)

DD&A expense decreased $0.19 per Mcfe in the second quarter of 2012 when compared to the second quarter of 2011. DD&A expense decreased $0.21 per Mcfe in the first half of 2012, when compared to the first half of 2011. During the second quarter 2012 and first half of 2012 the DD&A expense per Mcfe decline was the result of booking NGL reserves associated with the fee-based processing agreement entered into between QEP Energy and QEP Field Services for QEP Energy’s Pinedale production, increased percentage of production from the lower cost DD&A pools and impairments taken in the fourth quarter of 2011.

Lease operating expense per Mcfe decreased $0.02 during the second quarter ended June 30, 2012, when compared to the second quarter of 2011. The decrease in the second quarter of 2012 lease operating expense is primarily due to a $0.02 per Mcfe decrease in both the Southern and Northern Regions. The Southern Region decrease was a result of an 18% increase in production, partially offset by a 12% increase in lease operating expenses. The Northern Region decrease was driven by a 30% increase in production, while lease operating expenses only increased 25%. Lease operating expense per Mcfe increased $0.01 for the first half of 2012 from the 2011 first half. The increase in lease operation expense per Mcfe in the first half of 2012 is due to a $0.03 per Mcfe increase in the Southern Region. The Southern Region increase was the result of an 18% increase in lease operating expenses, partially offset by a 11% increase in production. The decrease in lease operating expense per Mcfe in the Northern Region was primarily the result of a 27% increase in production, which was partially offset by a 22% increase in lease operating expenses in the Northern Region. For additional information regarding the variances in production and lease operating expenses, see “Production” and “Operating Expenses” discussions earlier in this Form 10-Q.

QEP Energy’s average production costs (lease operating expense) per Mcfe were 4% lower in the second quarter of 2012 compared to the second quarter of 2011. During the first half of 2012, average production costs per Mcfe were 2% higher than in the first half of 2011. The following table presents average production cost, excluding production taxes for QEP Energy by region on a units of production basis:

	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
	(per Mcfe)
Northern Region	$	0.60	$	0.62	$	(0.02	)	$	0.59	$	0.61	$	(0.02	)
Southern Region		0.46		0.48		(0.02	)		0.49		0.46		0.03
Average production cost		0.52		0.54		(0.02	)		0.53		0.52		0.01

Natural gas, oil and NGL transportation and other handling costs per Mcfe were 11% higher in the second quarter of 2012 than in the second quarter of 2011. During the first half of 2012, natural gas, oil and NGL transportation and other handling costs per Mcfe were 6% higher than in the first half of 2011. The per Mcfe increase in both the three and six months ended June 30, 2012, relates to NGL sale agreements at Mont Belvieu, Texas, and the related transportation and processing of NGL’s, which were effective beginning with the startup of the Blacks Fork II plant in the third quarter of 2011. In addition, natural gas processing costs from the Blacks Fork II plant in 2012 compared to 2011 are contributing to the increase.

G&A expense increased $0.02 per Mcfe in the three months ended June 30, 2012, and increased $0.04 per Mcfe in the six months ended June 30, 2012. The per Mcfe increases in the three and six months ended June 30, 2012, were the result of higher total G&A expenses, which were primarily related to restructuring costs and higher compensation costs from increased headcount in the three and six months ended June 30, 2012, partially offset by increased production during the same periods. See Note 7 – “Restructuring Costs” of this form 10-Q for additional information regarding restructuring costs.

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Allocated interest expense per Mcfe decreased $0.03 in the three months ended June 30, 2012, but was flat in the six months ended June 30, 2012. The decrease in the three months ended June 30, 2012, was primarily due to increases in production outpacing increases in allocated interest expense.

In most states in which QEP Energy operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production taxes per Mcfe decreased by $0.16 and $0.10 during the three and six months ended June 30, 2012, because of lower field-level natural gas, oil and NGL prices.

QEP Energy Operating Regions

The following table presents operated and non-operated well completions for the three and six months ended June 30, 2012:

	Operated Completions								Non-operated Completions
	Three Months Ended June 30, 2012				Six Months Ended June 30, 2012				Three Months Ended June 30, 2012				Six Months Ended June 30, 2012
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Northern Region
Pinedale		39		27.2		51		36.4		-		-		-		-
Uinta Basin		16		14.3		26		24.3		67		0.2		132		0.4
Legacy		6		4.5		9		7.3		33		1.7		49		2.3
Southern Region
Haynesville/Cotton Valley		6		4.7		29		16.7		3		0.2		6		0.7
Midcontinent		6		4.3		13		9.9		35		4.0		61		6.9

The following table presents operated and non-operated wells drilling and waiting on completion at June 30, 2012:

	Operated								Non-operated
	Drilling				Waiting on completion				Drilling				Waiting on completion
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Northern Region
Pinedale		22		14.1		42		31.5		-		-		-		-
Uinta Basin		2		1.6		2		2.0		-		-		-		-
Legacy		6		5.0		7		5.9		12		0.6		14		0.3
Southern Region
Haynesville/Cotton Valley		-		-		5		2.4		1		0.1		-		-
Midcontinent		4		4.0		6		5.2		11		1.1		34		3.1

Northern Region

Pinedale Division

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 17,900 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 approximately 7,200 additional 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 1,050 additional wells will be required to fully develop its Pinedale acreage on a combination of 5 and 10-acre density. At June 30, 2012, QEP Energy had six operated rigs drilling in the Pinedale Anticline.

Uinta Basin Division

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 253,800 net leasehold acres in the Uinta Basin. QEP Energy had three operated rigs drilling in the Uinta Basin at June 30, 2012, two of which are targeting the Lower Mesaverde Formation productive fairway in the Redwash Unit, in which QEP holds 32,300 net acres, and one is drilling various vertical and horizontal oil targets.

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Legacy Division

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 Legacy Division. Exploration and development activity in the three and six months ended June 30, 2012, includes wells in the Greater Green River and Powder River Basins in Wyoming and the Williston Basin in North Dakota.

QEP Energy has approximately 90,000 net acres of leasehold rights in the Williston Basin in western North Dakota, where the Company is targeting the Bakken and Three Forks formations. The true vertical depth to the top of the Bakken Formation ranges from approximately 9,500 feet to 10,000 feet across QEP Energy’s leasehold. The Three Forks Formation lies approximately 60 to 70 feet below the Middle Bakken Formation and is also a target for horizontal drilling. As of June 30, 2012, QEP Energy had four operated rigs drilling in the project area.

Southern Region

Haynesville/Cotton Valley Division

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 June 30, 2012, QEP Energy had one operated rig drilling in the project area, which has since been released.

Midcontinent Division

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 western Oklahoma and the Texas Panhandle.

QEP Energy has approximately 75,600 net acres of Woodford Shale lease rights in western Oklahoma. The true vertical depth to the top of the Woodford Shale ranges from approximately 10,500 feet to 14,500 feet across QEP Energy’s leasehold. As of June 30, 2012, QEP Energy had three operated rigs drilling in the Woodford/Cana play.

QEP Energy has approximately 35,000 net acres of Granite Wash/Atoka Wash lease rights in the Texas Panhandle and western Oklahoma and has been drilling vertical Granite Wash/Atoka Wash wells for over a decade. 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 June 30, 2012, QEP Energy had one rig drilling in oil plays in western Oklahoma that is also being utilized to drill wells in the Texas Panhandle.

QEP Field Services

QEP Field Services, which provides gas gathering and processing services, generated net income of $33.3 million in the second quarter of 2012, compared to $44.2 million in the same period of 2011. Conversely, during the first half of 2012 QEP Field Services net income increased 9% to $78.7 million compared to $72.2 million in the first half of 2011. The decrease in net income during the second quarter of 2012 was the result of lower processing and gathering margins, however, during the first half of 2012, the processing margin increase resulted in higher net income for QEP Field Services. Gathering margins were lower during the second quarter and first half of 2012 as the result of 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 second quarter and first half of 2011, before the expansion of the Blacks Fork processing plant was put into service during the third quarter of 2011. Processing margins were lower in the second quarter of 2012 because of lower keep-whole processing margins, which, conversely, during the first half of 2012 were higher than the first half of 2011.

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

	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Change			2012			2011			Change
	(in millions)
Revenues
NGL sales	$	36.3		$	46.3		$	(10.0	)	$	83.8		$	75.8		$	8.0
Processing (fee based)		17.6			12.2			5.4			33.6			22.2			11.4
Other processing fees		-			-			-			3.0			-			3.0
Gathering		45.8			38.7			7.1			87.7			78.1			9.6
Other gathering		9.3			25.0			(15.7	)		20.6			42.7			(22.1	)
Purchased gas, oil and NGL sales		4.6			-			4.6			4.6			-			4.6
Total Revenues		113.6			122.2			(8.6	)		233.3			218.8			14.5
Operating expenses
Purchased gas, oil and NGL expense		4.1			-			4.1			4.1			-			4.1
Processing		3.7			3.1			0.6			7.4			5.8			1.6
Processing plant fuel and shrinkage		8.4			11.4			(3.0	)		18.5			21.6			(3.1	)
Gathering		8.3			12.4			(4.1	)		17.9			24.3			(6.4	)
Natural gas, oil and NGL transportation and other handling costs		12.0			1.2			10.8			20.8			2.1			18.7
General and administrative		9.0			6.8			2.2			13.5			15.8			(2.3	)
Taxes other than income taxes		1.2			1.6			(0.4	)		2.9			3.0			(0.1	)
Depreciation, depletion and amortization		16.1			13.5			2.6			31.4			26.7			4.7
Total Operating Expenses		62.8			50.0			12.8			116.5			99.3			17.2
Net gain from asset sales		-			0.1			(0.1	)		-			0.1			(0.1	)
Operating Income		50.8			72.3			(21.5	)		116.8			119.6			(2.8	)
Interest and other income		0.1			-			0.1			0.1			-			0.1
Income from unconsolidated affiliates		1.3			1.2			0.1			3.2			2.1			1.1
Realized gains on derivative instruments		3.3			-			3.3			4.4			-			4.4
Unrealized gains on derivative instruments		1.5			-			1.5			4.5			-			4.5
Interest expense		(3.6	)		(3.1	)		(0.5	)		(5.9	)		(6.6	)		0.7
Income before Income Taxes		53.4			70.4			(17.0	)		123.1			115.1			8.0
Income taxes		(19.2	)		(25.5	)		6.3			(42.7	)		(41.6	)		(1.1	)
Net income		34.2			44.9			(10.7	)		80.4			73.5			6.9
Net income attributable to noncontrolling interest		(0.9	)		(0.7	)		(0.2	)		(1.7	)		(1.3	)		(0.4	)
Net Income Attributable to QEP	$	33.3		$	44.2		$	(10.9	)	$	78.7		$	72.2		$	6.5

Natural gas, oil and NGL transportation and other handling costs increased $10.8 million and $18.7 million during the three and six months ended June 30, 2012, respectively. The increases in both periods were primarily due to transportation costs relating to the Blacks Fork II plant, placed into service in the third quarter of 2011, and the related transportation and ultimate sale of additional NGL’s at Mont Belvieu, Texas.

General and administrative expenses increased by $2.2 million during the second quarter of 2012, but decreased $2.3 million during the first half of 2012. The increase in the second quarter of 2012 related to increased compensation costs from increased headcount when compared to the second quarter of 2011. The decrease in the first half of 2012 compared to the first half of 2011 was primarily due to a $4.3 million reduction in accruals for loss contingencies, offset by increased compensation costs.

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

QEP Marketing and Other

QEP Marketing, which markets affiliate and third-party natural gas and oil, and owns and operates a gas storage facility, and Other generated a net loss of $3.7 million in the three months ended June 30, 2012, a $5.5 million decrease over the $1.8 million of income in the three months ended June 30, 2011. The decrease in the second quarter of 2012 was due primarily to lower marketing volumes and margins. During the six months ended June 30, 2012, net income decreased $5.9 million due primarily to lower marketing margins.

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

	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Change			2012			2011			Change
	(in millions)
Revenues
Purchased gas, oil and NGL sales	$	196.6		$	293.2		$	(96.6	)	$	439.8		$	572.2		$	(132.4	)
Other		2.0			2.6			(0.6	)		3.9			5.1			(1.2	)
Total Revenues		198.6			295.8			(97.2	)		443.7			577.3			(133.6	)
Operating expenses
Purchased gas, oil and NGL expense		197.4			292.5			(95.1	)		445.0			570.4			(125.4	)
Gathering, processing and other		0.5			0.4			0.1			0.7			0.7			-
General and administrative		0.1			0.8			(0.7	)		0.1			1.6			(1.5	)
Production and property taxes		-			0.1			(0.1	)		0.1			0.2			(0.1	)
Depreciation, depletion and amortization		0.8			0.6			0.2			1.6			1.1			0.5
Total Operating Expenses		198.8			294.4			(95.6	)		447.5			574.0			(126.5	)
Net loss from asset sales		-			(0.1	)		0.1			-			(0.1	)		0.1
Operating (Loss) Income		(0.2	)		1.3			(1.5	)		(3.8	)		3.2			(7.0	)
Realized gain on derivative instruments		0.7			-			0.7			4.1			-			4.1
Unrealized loss on derivative instruments		(5.0	)		-			(5.0	)		(3.4	)		-			(3.4	)
Interest and other income		26.8			24.8			2.0			52.7			49.2			3.5
Loss on extinguishment of debt		(0.6	)		-			(0.6	)		(0.6	)		-			(0.6	)
Interest expense		(27.9	)		(23.3	)		(4.6	)		(52.6	)		(46.5	)		(6.1	)
(Loss) Income before Income Taxes		(6.2	)		2.8			(9.0	)		(3.6	)		5.9			(9.5	)
Income taxes		2.5			(1.0	)		3.5			1.6			(2.0	)		3.6
Net (Loss) Income Attributable to QEP	$	(3.7	)	$	1.8		$	(5.5	)	$	(2.0	)	$	3.9		$	(5.9	)

LIQUIDITY AND CAPITAL RESOURCES

QEP seeks to fund its development projects by employing a capital structure and financing strategy to provide sufficient liquidity to withstand commodity price swings. As part of this strategy QEP funds long-term capital intensive development projects while maintaining the ability to employ an exploration program and execute acquisitions while maintaining an appropriate debt rating in conjunction with these objectives. In addition, QEP maintains a commodity price derivative strategy to reduce commodity price volatility and to provide certainty to cash flows and operations.

QEP funds its operations, capital expenditures and working capital requirements with cash flow from its operating activities, borrowings under its credit facilities. Periodically, QEP’s access to debt and capital markets and sales of non-strategic properties will provide additional liquidity. The Company believes cash flow from operations, cash-on-hand and availability under its Credit Facility will be sufficient to fund the Company’s planned capital expenditures and operating expenses during the next 12 months. To the extent actual operating results differ from the Company’s estimates, its liquidity could be adversely affected.

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

	June 30, 2012			December 31, 2011
	(in millions, except %)
Cash and cash equivalents	$	146.4		$	-
Amount available under the credit facility (1)		1,495.9			893.5
Total liquidity	$	1,642.3		$	893.5
Total debt (2)	$	1,866.6		$	1,679.4
Total common shareholders' equity		3,367.0			3,301.5
Ratio of debt to total capital (3)		36	%		34	%

(1) See discussion of Credit Facility below. Includes outstanding letters of credit of $4.1 million.

(2) Includes all outstanding long-term debt which is discussed in detail below.

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

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Credit Facility

QEP’s revolving credit facility agreement (Credit Facility), which matures in August 2016, provides for loan commitments of $1.5 billion from a syndicate of financial institutions. The Credit Facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The 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’s weighted-average interest rate on borrowings from its Credit Facility was 2.05% during the first half of 2012. At June 30, 2012, QEP was in compliance with the debt covenants under the credit agreement. QEP reduced its borrowings under its credit facility from $606.5 million as of December 31, 2011, to no borrowings outstanding at June 30, 2012, as a result of the issuance of the 2022 Senior Notes and Term Loan. At July 27, 2012, QEP had no borrowings outstanding under its revolving credit facility and $4.1 million of letters of credit issued.

Term Loan

During the second quarter of 2012, the Company entered into a $300.0 million Term Loan 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 Credit Facility. The term loan agreement matures in April of 2017, and the maturity date may be extended one year with the agreement of the lenders. The proceeds from the term loan were used to pay down the Company’s revolving credit facility and general corporate purposes. During the second quarter of 2012, QEP’s weighted-average interest rate on the term loan was 2.02%. In conjunction with the Term Loan, QEP entered into interest rate swap contracts with a combined notional principal amount of $300.0 million which will mature in March 2017.  Under the swap contracts, QEP pays 1.07% for the life of the swaps and receives one-month LIBOR.  The current interest rate under the Term Loan is one-month LIBOR, plus 1.75% (the Applicable Margin) which , when combined with the fixed interest rate swaps, results in an effective rate of 2.82% for borrowings under the Term Loan.  To the extent that the Applicable Margin under the Term Loan changes, the effective fixed rate paid for borrowings under the Term Loan will change.

Senior Notes

During the first quarter of 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 5.375% senior notes due in October 2022. The proceeds from the 2022 Senior Notes were used to pay down the Company’s revolving credit facility. In the second quarter of 2012, the Company purchased $6.7 million of its Senior Notes outstanding. The Company’s senior notes outstanding as of June 30, 2012, totaled $1,571.8 million principal amount and are comprised of five issuances as follows:

• $176.8 million 6.05% Senior Notes due September 2016

• $134.0 million 6.80% Senior Notes due April 2018

• $136.0 million 6.80% Senior Notes due March 2020

• $625.0 million 6.875% Senior Notes due March 2021

• $500.0 million 5.375% Senior Notes due October 2022

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.

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

	Six Months Ended June 30,
	2012		2011		Change
	(in millions)
Net income	$	156.2	$	167.3	$	(11.1	)
Noncash adjustments to net income		476.4		438.0		38.4
Changes in operating assets and liabilities		61.7		23.3		38.4
Net cash provided from operating activities	$	694.3	$	628.6	$	65.7

Cash Flow from Investing Activities

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

	Six Months Ended June 30,									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	$	641.5		$	639.6		$	1.9		$	1,320.0	$	1,315.0
QEP Field Services		85.9			33.2			52.7			170.0		170.0
QEP Marketing		0.6			0.2			0.4			1.0		1.0
Corporate		2.8			1.1			1.7			9.0		14.0
Total accrued capital expenditures		730.8			674.1			56.7			1,500.0		1,500.0
Change in accruals		(45.3	)		(12.3	)		(33.0	)		-		-
Total cash capital expenditures	$	685.5		$	661.8		$	23.7		$	1,500.0	$	1,500.0

(1) Forecast as reported in the 2012 First Quarter Report on Form 10-Q, filed on April 26, 2012.

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

During the first half of 2012 capital expenditures on a cash basis increased 4% to $685.5 million, compared to $661.8 million during the first half of 2011. The increase of $23.7 million during the first half of 2012 was the result of increased investment in QEP Field Services. Approximately $600.9 million was invested in QEP Energy, including $596.9 million in drilling and completion and other expenditures and $4.0 million in property acquisition costs. QEP Field Services first half of 2012 capital expenditures of $81.2 million were invested to expand capacity at the Company’s gathering, processing and treating facilities, including the construction of a new 150 MMcfd cryogenic gas processing plant in the Uinta Basin.

QEP Energy capital investment, on an accrual basis, in the first half of 2012 increased $1.9 million over the first half of 2011 due to increased capital expenditures in the Legacy Division (approximately 85% higher) and in Pinedale (approximately 65% higher) Offsetting these increased capital expenditures in the first half of 2012 were lower capital expenditures in the Haynesville (approximately 61% lower) due to the reduced drilling program as capital is allocated out of the dry-gas Haynesville play into these higher return oil and liquids-rich natural gas drilling programs in Legacy and Pinedale.

QEP Field Services capital investment increased $52.7 million on an accrual basis in the first half of 2012 compared to the first half of 2011 due to the projects directed to grow the midstream business including the construction of a new 150 MMcfd fee-based cryogenic gas processing plant in the Uinta Basin and the 10,000 Bbl/d expansion to the NGL fractionators located at the Blacks Fork processing complex.

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At June 30, 2012, forecasted capital investments for 2012 is expected to be $1,500.0 million, comprised of $1,320.0 million at QEP Energy, $170.0 million at QEP Field Services, and $10.0 million for QEP Resources and QEP Marketing. For the remainder of 2012, QEP intends to fund capital expenditures with cash flow from operating activities, cash on hand and, if needed, borrowings under its revolving credit facility. As a result of the continued spread between crude oil and natural gas prices, 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, for the remainder of 2012. QEP Energy has allocated approximately 90% of its forecasted 2012 drilling and completion capital expenditure budget to crude oil and liquids-rich natural gas projects in its portfolio. QEP plans to invest a total of approximately $170.0 million in capital expenditures during 2012 to grow its midstream business, including the construction of a new 150 MMcfd fee-based cryogenic gas processing plant in the Uinta Basin (expected to be completed in early 2013) as well as a new 10,000 Bbl/d expansion of the NGL fractionators located at the Blacks Fork processing complex (expected to be completed in the second half of 2013). QEP Resources plans to invest approximately $9.0 million in capital expenditures related to corporate activities, primarily the implementation of a new Enterprise Resource Planning system. The aggregate levels of capital expenditures for 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.

Cash Flow from Financing Activities

In the first half of 2012, net cash proceeds from financing activities was $134.0 million compared to $31.6 million in the first half of 2011. During the first half of 2012, QEP completed an offering of $500.0 million in senior notes and entered into a $300.0 million Term Loan. QEP had borrowings from the Credit Facility of $194.5 million and repayments on the Credit Facility of $801.0 million. In addition, QEP retired $6.7 million of Senior Notes.

At June 30, 2012, long-term debt consisted of no borrowings outstanding under the Credit Facility, $300.0 million under the Term Loan and $1,566.6 million in senior notes (including $5.2 million of net original issue discount).

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market risk exposures arise from changes in the market price for natural gas, oil and NGL, and to volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. QEP Energy and QEP Marketing also have long-term contracts for pipeline capacity and are obligated to pay for transportation services with no guarantee that QEP will be able to fully utilize the contractual capacity of these transportation commitments. In addition, a non-cash write-down of the Company’s oil and gas properties may be required if future oil and natural gas commodity prices experience a sustained, significant decline. Furthermore, the Company’s credit facility and term loan agreement have floating interest rates which expose QEP to interest rate risk. To manage the Company’s exposure to these risks, QEP enters into commodity derivative contracts in the form of costless collars and fixed-price swaps to manage commodity price risk and periodically interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP’s subsidiaries use commodity price derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. The Company’s risk management policies provide for the use of derivative instruments to manage this risk. However, these same arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments 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. The derivative instruments currently utilized by the Company do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of June 30, 2012, QEP held commodity price derivative contracts totaling 193.7 million MMBtu of natural gas, 2.5 million barrels of oil, and 30.9 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 June 30, 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		(208.8	)
Change in gas and oil prices on futures markets		143.7
Contracts added		13.2
Net fair value of gas, oil and NGL derivative contracts outstanding at June 30, 2012	$	344.0

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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:

	June 30, 2012
	(in millions)
Net fair value - asset (liability)	$	344.0
Fair value if market prices of gas, oil and NGL and basis differentials decline by 10%		419.0
Fair value if market prices of gas, oil and NGL and basis differentials increase by 10%		264.1

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $79.9 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $75.0 million as of June 30, 2012. 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 6 – Derivative Contracts under Part I, Item 1 of this Form 10-Q.

Interest-Rate Risk Management

The Company’s ability to borrow and the rates quoted by lenders can be adversely affected by illiquid credit markets as described in the risk factors in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011. The Company’s Credit Facility and Term Loan have floating interest rates which expose QEP to interest rate risk. At June 30, 2012, the Company had no borrowings outstanding under our credit facility and $300.0 million under the term loan agreement. If interest rates were to increase or decrease 10% over the six months ended June 30, 2012, at our average level of borrowing for those same periods, our interest expense would increase or decrease by $0.3 million for the six months ended June 30, 2012, or less than 1% in each period. The remaining $1,566.5 million of the Company’s debt is fixed rate Senior Notes that are not subject to interest rate movements.

During the second quarter of 2012, QEP entered into interest rate swap contracts, with an aggregate notional amount of $300.0 million, to minimize the interest rate volatility risk associated with its $300.0 million senior, unsecured term loan agreement. QEP pays a fixed interest rate and receives a floating interest rate indexed to the one-month LIBOR. At June 30, 2012, the fair value of the interest rate swaps was a derivative liability balance of $4.3 million. A 50 basis point decrease would cause the fair value of the interest rate swaps to decrease by $6.3 million while a 50 basis point increase would cause the fair value of the interest rate swaps to increase by $6.8 million. For additional information regarding the Company’s debt instruments, see Note 8 – Debt under Part I, Item 1 of this Form 10-Q.

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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;

§ volatility of natural gas, oil and NGL prices and factors affecting such volatility;

§ plans to drill or participate in wells;

§ future expenses and operating costs;

§ the outcome of contingencies such as legal proceedings;

§ expected contributions related to the Company’s pension plans;

§ results from planned drilling operations and production operations;

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

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

§ incurrence of unrealized derivative gains and losses;

§ 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;

§ payment of required royalties and outcome of litigation;

§ potential for future asset impairments;

§ maintaining an appropriate debt rating; 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;

§ global geopolitical and macroeconomic factors;

§ 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;

50

§ 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;

§ derivatives and hedging activities;

§ legislative or regulatory changes, including initiatives related to drilling and completion techniques, including hydraulic fracturing;

§ liabilities from litigation; and

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

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

ITEM  4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of June 30, 2012. Based on such evaluation, such officers have concluded that, as of June 30, 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 June 30, 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. As previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, and its Quarterly Report on Form 10-Q for the three months ended March 31, 2012, 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. On May 16, 2012, QEP Field Services settled this matter by the parties’ execution of a consent decree which was subsequently approved by court order. The civil penalty payable to the government is $3.7 million. A contribution of $0.4 million will be payable to a non-profit corporation or trust to be created by the Ute Indian Tribe of the Uintah and Ouray Reservation for the implementation of environmental programs for the benefit of tribal members. The settlement also requires the Company to reduce its emissions by removing certain equipment, installing additional pollution controls and replacing the natural gas powered instrument control systems with compressed air control systems, all of which will require capital expenditures of approximately $2.4 million, of which $0.5 million had been spent at June 30, 2012. QEP Field Services will have continuing operations compliance obligations under the consent decree at the affected facilities.

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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.

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services’ former affiliate Questar Gas Company (QGC) filed this complaint in state court in Utah on May 1, 2012 asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, for an accounting and declaratory judgment related to a 1993 gathering agreement (1993 Agreement) entered when the parties were affiliates. Under the 1993 Agreement QEP Field Services provides gathering services throughout its historical gathering system serving producing properties developed by former affiliate Wexpro Company on behalf of QGC’s utility ratepayers. The core dispute regards the annual recalculation of the gathering rate which is based on a cost of service concept expressed in the 1993 Agreement and in a 1998 amendment. Specific monetary damages are not asserted. Also, on May 1, 2012, QEP Field Services Company filed a legal action against Questar Gas entitled QEP Field Services Company v. Questar Gas Company, in the Second District Court in Denver County, Colorado, seeking declaratory judgment relating to its gathering service and charges under the same agreement. While QEP Field Services intends to defend itself against QGC’s claims and vigorously pursue its legal rights, the claims involve complex legal issues and uncertainties that make it difficult to predict the outcome of the cases and therefore management cannot determine at this time whether this litigation may have an adverse material effect on its financial position, results of operations or cash flows.

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 six months ended June 30, 2012.

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

QEP had no unregistered sales of equity during the second 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

52

SIGNATURES

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

	QEP RESOURCES, INC.
	(Registrant)
July 31, 2012	/s/ C. B. Stanley
	C. B. Stanley,
	Chairman, President and Chief Executive Officer
July 31, 2012	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President,
	Chief Financial Officer and Treasurer

53

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

54

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.

July 31, 2012

/s/ Charles B. Stanley

Charles B. Stanley

Chairman, 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.

July 31, 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 June 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the Report), C. B. Stanley, Chairman, 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.
July 31, 2012
	/s/ C. B. Stanley
	C. B. Stanley
	Chairman, President and Chief Executive Officer
July 31, 2012
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President,
	Chief Financial Officer and Treasurer

XML

Share-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Share-Based Compensation [Abstract]
Shares available for future grants	13,100,000		13,100,000
Total compensation expense related to share-based compensation	$ 6.6	$ 3.4	$ 12.3	$ 10.8
Stock Options [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Fair value of options at grant date			$ 14.46
Risk-free interest rate (in hundredths)			0.81%
Expected price volatility (in hundredths)			55.90%
Expected dividend yield (in hundredths)			0.26%
Expected life in years			5 years
Options Outstanding [RollForward]
Outstanding at December 31, 2011 (in shares)			2,003,694
Granted (in shares)			291,143
Exercised (in shares)			(313,342)
Forfeited (in shares)			0
Outstanding at June 30, 2012 (in shares)	1,981,495		1,981,495
Options Excercisable (in shares)	1,500,192		1,500,192
Unvested Options (in shares)	481,303		481,303
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning (in dollars per share)			$ 21.23
Weighted-Average Price, Granted (in dollars per share)			$ 30.83
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)	$ 24.71		$ 24.71
Weighted-Average Price, Options Excercisable	$ 22.19		$ 22.19
Weighted-Average Price, Unvested Options	$ 32.56		$ 32.56
Weighted-Average Remaining Contractual Term, Outstanding			3 years 7 months 6 days
Aggregate Intrinsic Value, Outstanding	12.5		12.5
Weighted-Average Remaining Contractual Term, Options Excercisable			2 years 9 months 18 days
Aggregate Intrinsic Value, Options Excercisable	12.3		12.3
Weighted-Average Remaining Contractual Term, Unvested Options			6 years 1 month 6 days
Aggregate Intrinsic Value, Unvested Options	0.2		0.2
Intrinsic value of options exercised			6.9	2.6
Unrecognized compensation cost	4.6		4.6
Weighted-average period for recognition of compensation costs			2 years 4 months 24 days
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)			$ 30.74	$ 39.14
Weighted-Average Price, Vested (in dollars per share)			$ 32.31
Weighted-Average Price, Forfeited (in dollars per share)			$ 32.71
Weighted-Average Price, Ending Balance (in dollars per share)	$ 31.88		$ 31.88
Unrecognized compensation cost	25.3		25.3
Weighted-average period for recognition of compensation costs			2 years 4 months 24 days
Total fair value of stock that vested			12.6	9.9
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)			1,099,752
Granted (in shares)			706,221
Vested (in shares)			(397,204)
Forfeited (in shares)			(49,209)
Balance, Ending (in shares)	1,359,560		1,359,560
Restricted Stock [Member] | Maximum [Member]
Weighted-Average Price [Abstract]
Vesting period (in years)			4 years
Restricted Stock [Member] | Minimum [Member]
Weighted-Average Price [Abstract]
Vesting period (in years)			3 years
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)	$ 34.11		$ 34.11
Unrecognized compensation cost	$ 5.3		$ 5.3
Weighted-average period for recognition of compensation costs			2 years 4 months 24 days
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)			115,274
Granted (in shares)			171,954
Vested (in shares)			0
Forfeited (in shares)			(4,148)
Balance, Ending (in shares)	283,080		283,080

XML

Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	$ 163.9	$ 148.3
Accretion	5.1	4.8
Liabilities incurred	3.6	2.9
Liabilities settled	(0.4)	(0.3)
ARO liability, Ending Balnce	$ 172.2	$ 155.7

XML

Derivative Contracts (Tables)

6 Months Ended

Jun. 30, 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						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
QEP Energy
Natural gas derivative volumes as a percent of QEP Energy natural gas production
Fixed price swaps		67	%		46	%		63	%		44	%
Costless collars		0	%		12	%		0	%		12	%
Oil derivative volumes as a percent of QEP Energy oil production
Fixed price swaps		35	%		3	%		36	%		2	%
Costless collars		28	%		31	%		22	%		33	%
NGL derivative volumes as a percent of QEP Energy NGL production
Fixed price swaps		18	%		0	%		17	%		0	%
QEP Field Services
Ethane derivative volumes as a percent of ethane volumes - QEP Field Services
Fixed price swaps		15	%		0	%		27	%		0	%
Propane derivative volumes as a percent of propane volumes - QEP Field Services
Fixed price swaps		59	%		0	%		76	%		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 June 30, 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		39.9	$	4.66
2012	Swap	IFPEPL (1)		4.9	$	4.14
2012	Swap	IFNPCR (2)		45.4	$	4.61
2012	Swap	IFCNPTE (3)		5.5	$	2.66
2013	Swap	NYMEX		29.2	$	3.68
2013	Swap	IFNPCR (2)		65.7	$	5.66
Oil sales			(Bbls)
2012	Swap	NYMEX WTI		0.9	$	97.03
2012	Collar	NYMEX WTI		0.7			$	87.50	$	115.36
2013	Swap	NYMEX WTI		0.9	$	104.12
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		7.7	$	0.64
2012	Swap	Mt. Belvieu Propane		11.6	$	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 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 June 30, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swap price per gallon
			(in millions)
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		7.7	$	0.64
2012	Swap	Mt. Belvieu Propane		3.9	$	1.28

QEP Marketing Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage and for marketing transactions in which QEP Marketing is required to deliver gas volumes at a fixed price. The following table sets forth QEP Marketing's volumes and swap prices for its commodity derivative contracts as of June 30, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swaps price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2012	Swap	IFNPCR (1)		1.8	$	4.06
2013	Swap	IFNPCR (1)		1.2	$	4.57
Natural gas purchases			(MMBtu)
2012	Swap	IFNPCR (1)		0.7	$	2.97
2013	Swap	IFNPCR (1)		0.1	$	2.59

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

QEP Resources Derivative Contracts

In the second quarter of 2012, QEP Resources entered into interest rate swap agreements to effectively lock in a fixed interest rate on debt outstanding under its Term Loan.

The following table sets forth QEP Resources' notional amounts and interest rates for its interest rate swaps outstanding as of June 30, 2012:

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

Fair values of Derivatives by Balance Sheet Location

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

		Gross asset derivative instruments fair value					Gross liability derivative instruments fair value
	Balance Sheet line item	June 30, 2012		December 31, 2011		Balance Sheet line item	June 30, 2012		December 31, 2011
		(in millions)					(in millions)
Current:
Commodity	Fair value of derivative contracts	$	272.2	$	284.1	Fair value of derivative contracts	$	4.0	$	11.7
Interest rate swaps	Fair value of derivative contracts		-		-	Fair value of derivative contracts		2.3		-
Long-term:
Commodity	Fair value of derivative contracts		77.5		123.5	Fair value of derivative contracts		1.7		-
Interest rate swaps	Fair value of derivative contracts		-		-	Fair value of derivative contracts		2.0		-
Total derivative    instruments		$	349.7	$	407.6		$	10.0	$	11.7

Effects of Derivative Transactions

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

		Three Months Ended						Six Months Ended
Derivative instruments not designated as	Location of gain (loss)	June 30,						June 30,
cash flow hedges	recognized in earnings	2012			2011			2012			2011
		(in millions)
Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		$	111.9		$	(27.6	)	$	197.6		$	(58.8	)
Oil derivative contracts			2.2			-			(0.5	)		-
NGL derivative contracts			2.7			-			3.1			-
QEP Field Services
NGL derivative contracts			3.3			-			4.4			-
QEP Marketing
Natural gas derivative contracts			0.6			-			4.1			-
Total realized gain (loss) on commodity derivative contracts			120.7			(27.6	)		208.7			(58.8	)
Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts			(78.4	)		27.6			53.9			58.8
Oil derivative contracts			38.6			-			27.1			-
NGL derivative contracts			4.9			-			7.8			-
QEP Field Services
NGL derivative contracts			1.5			-			4.5			-
QEP Marketing
Natural gas derivative contracts			(0.7	)		-			0.9			-
Total unrealized (loss) gain on    commodity derivative contracts			(34.1	)		27.6			94.2			58.8
Total realized and unrealized    gain on commodity derivative    contracts	Realized and unrealized gains on derivative contracts	$	86.6		$	-		$	302.9		$	-
Unrealized gain (loss) on interest rate swaps
Unrealized loss on interest rate swaps	Realized and unrealized gains on derivative contracts	$	(4.3	)	$	-		$	(4.3	)	$	-

			Three Months Ended				Six Months Ended
	Location of gain (loss)		June 30,				June 30,
Derivative instruments classified as cash flow hedges	recognized in earnings		2012		2011		2012		2011
Commodity derivatives			(in millions)
Gain on derivative instruments for the effective    portion of hedge recognized in AOCI	Accumulated other    comprehensive income	$	-	$	61.3	$	-	$	61.5
Gain reclassified from AOCI into income for    effective portion of hedge	Natural gas sales		-		64.4		-		137.5
Gain reclassified from AOCI into income for    effective portion of hedge	Oil sales		-		0.1		-		0.1
Gain  reclassified from AOCI into income for    effective portion of hedge	Marketing purchases		-		0.5		-		3.9
Gain recognized in income for the ineffective    portion of hedges	Interest and other income		-		0.3		-		0.1

XML

Debt (Details) (USD $)	3 Months Ended		6 Months Ended			6 Months Ended		6 Months Ended		6 Months Ended								6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Jun. 30, 2012 Revolving Credit Facility due 2016 [Member]	Dec. 31, 2011 Revolving Credit Facility due 2016 [Member]	Jun. 30, 2012 Term Loan due 2017 [Member]	Dec. 31, 2011 Term Loan due 2017 [Member]	Jun. 30, 2012 6.05% Senior Notes due 2016 [Member]	Dec. 31, 2011 6.05% Senior Notes due 2016 [Member]	Jun. 30, 2012 6.80% Senior Notes due 2018 [Member]	Dec. 31, 2011 6.80% Senior Notes due 2018 [Member]	Jun. 30, 2012 6.80% Senior Notes due 2020 [Member]	Dec. 31, 2011 6.80% Senior Notes due 2020 [Member]	Jun. 30, 2012 6.875% Senior Notes due 2021 [Member]	Dec. 31, 2011 6.875% Senior Notes due 2021 [Member]	Jun. 30, 2012 5.375% Senior Notes due 2022 [Member]	Mar. 31, 2012 5.375% Senior Notes due 2022 [Member]	Dec. 31, 2011 5.375% Senior Notes due 2022 [Member]	Jun. 30, 2012 Senior Notes [Member]
Debt Instrument [Line Items]
Total principal amount of debt	$ 1,871,800,000		$ 1,871,800,000		$ 1,684,900,000	$ 0	$ 606,500,000	$ 300,000,000	$ 0	$ 176,800,000	$ 176,800,000	$ 134,000,000	$ 138,600,000	$ 136,000,000	$ 138,000,000	$ 625,000,000	$ 625,000,000	$ 500,000,000	$ 500,000,000	$ 0
Less unamortized discount	(5,200,000)		(5,200,000)		(5,500,000)
Total long-term debt outstanding	1,866,600,000		1,866,600,000		1,679,400,000
Long-term debt, interest rate (in hundredths)										6.05%
Maturity date of long-term debt						Aug. 25, 2016		Apr. 18, 2017		Sep. 01, 2016
Maturity period of long-term debt										5 years
Borrowing capacity						1,500,000,000
Potential increased borrowing capacity						2,000,000,000
Number of maturity date extentions						2
Additional period with in which maturity to be extended						1 year
Weighted-average interest rate (in hundredths)						2.05%		2.02%
Amount outstanding						0
Letters of credit outstanding						4,100,000
Proceeds from issuance of debt																		493,100,000
Debt issuance costs																			6,900,000
Senior notes repurchased																					6,700,000
Principal amount of senior notes outstanding	1,571,800,000		1,571,800,000
Non-cash loss on early extinguishment of debt	$ 600,000	$ 0	$ 600,000	$ 0
Senior Notes, stated interest rate, minimum (in hundredths)			5.375%
Senior Notes, stated interest rate, maximim (in hundredths)			6.875%

XML

Basis of Presentation of Interim Consolidated Financial Statements

6 Months Ended

Jun. 30, 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 and six months ended June 30, 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 for all of its derivative instruments. 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 three and six months ended June 30, 2012 unrealized losses of $38.4 million and unrealized gains of $89.9 million were included in income that, prior to January 1, 2012, would have been deferred in Accumulated Other Comprehensive Income (AOCI) under hedge accounting. Refer to Note 6 - Derivative Contracts 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, were recast on the Condensed Consolidated Statement of Income from "Revenues" to "Natural gas, oil and NGL transportation and other handling costs" for prior periods presented. The impact of this revision was immaterial to the accompanying financial statements and had no effect on income from continuing operations, net income, or earnings per share. The following table details the impact for the three and six months ended June 30, 2011, on the Condensed Consolidated Statement of Income.

	Three Months Ended June 30, 2011							Six Months Ended June 30, 2011
	As reported (1)		As revised		Change			As reported (1)		As revised		Change
	(in millions)							(in millions)
REVENUES
Natural gas sales	$	258.1	$	298.7	$	40.6		$	529.1	$	611.3	$	82.2
Oil sales		80.0		80.7		0.7			142.3		143.7		1.4
NGL sales		61.6		63.8		2.2			107.4		111.7		4.3
Gathering, processing and other		78.4		58.9		(19.5	)		147.7		105.5		(42.2	)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		-		24.0		24.0			-		45.7		45.7

(1) The "As reported" numbers reflect QEP Field Services NGL sales of $45.1 million and $73.7 million for the three and six months ended June 30, 2011, which were reclassified from "Gathering, processing and other" into "NGL sales" for consistency with current period presentation. In its second quarter 2011 Form 10-Q, QEP reported "NGL sales" of $16.5 million and $33.7 million, and "Gathering, processing and other" of $123.5 million, and $221.4 million for the three and six months ended June 30, 2011, respectively. The QEP Field Services NGL reclassification is all within "Revenues" and has no effect on income from continuing operations, net income or earnings per share.

Impairment of long-lived assets

Proved gas and oil properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, an impairment of gas and oil reserves caused by mechanical problems, faster-than-expected decline of reserves, lease-ownership issues, other-than-temporary decline in natural gas, NGL and crude oil prices and changes in the utilization of midstream gathering and processing assets. If impairment is indicated, fair value is calculated using a discounted-cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating costs, and estimates of probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors. During the three and six months ended June 30, 2012, QEP Energy recorded non-cash, price-related impairment charges of $48.9 million and $49.3 million, respectively, on some of its proved properties. The impairment charges are related to the reduced value of certain fields resulting from lower natural gas, crude oil and NGL prices. The assets were written down to their estimated fair values. Of the $49.3 million impairment charge during six months ended June 30, 2012, $48.9 million is related to proved properties in the Southern Region and $0.4 million is related to proved properties in the Northern Region.

The Company also performs periodic assessments of unproved gas and oil properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired the Company considers numerous factors including current development and exploration plans, results of development or exploration activity on adjacent leaseholds, technical personnel evaluations of the properties, and the remaining lease term. During the three and six months ended June 30, 2012, QEP recorded non-cash impairment charges of $6.1 million and $12.1 million, respectively,  on some of its unproved properties relating to the various factors described. Of the $6.1 million and $12.1 million impairment charges during the three and six months ended June 30, 2012, $3.1 million and $6.1 million, respectively, related to unproved properties in the Southern Region and $3.0 million and $6.0 million, respectively, related to unproved properties in the Northern Region.

Natural gas, NGL and crude oil prices

Historically, field-level prices received for QEP's natural gas, NGL, and crude oil production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic natural gas supply has grown faster than natural gas demand, driven by advances in drilling and completion technologies, including horizontal drilling and multi-stage hydraulic fracturing, which have allowed producers to extract increased quantities of natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas and NGL drilling and supplies have resulted in downward pressure on natural gas and NGL 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 may impact the carrying value of its oil and natural gas properties.

New accounting pronouncements

In May of 2011, the FASB issued ASU 2011-04, which develops common measurement and disclosure requirements regarding an entity's fair value measurements and aligns GAAP and International Financial Reporting Standards. The amendments are required for interim and annual reporting periods beginning after December 15, 2011. The adoption of these requirements did not have a material impact on the financial statements of QEP.

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

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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Employee Benefits (Tables)

6 Months Ended

Jun. 30, 2012

Employee Benefits [Abstract]

Pension and Other Postretirement Benefit Costs

	Pension
	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Service cost	$	0.9		$	0.7		$	1.9		$	1.4
Interest cost		1.2			1.1			2.4			2.2
Expected return on plan assets		(0.9	)		(0.6	)		(1.8	)		(1.2	)
Amortization of prior service costs		1.3			1.3			2.6			2.6
Amortization of actuarial loss		0.2			-			0.4			-
Periodic expense	$	2.7		$	2.5		$	5.5		$	5.0

	Postretirement benefits
	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)
Service cost	$	-	$	-	$	-	$	-
Interest cost		0.1		0.1		0.2		0.2
Expected return on plan assets		-		-		-		-
Amortization of prior service costs		0.1		0.1		0.2		0.2
Recognized net actuarial loss		-		-		-		-
Periodic expense	$	0.2	$	0.2	$	0.4	$	0.4

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Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2012

Share-Based Compensation [Abstract]

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

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

	Stock Option Variables Six Months Ended June 30, 2012
Fair value of options at grant date	$	14.46
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		291,143			30.83
Exercised		(313,342	)		8.15
Forfeited		-			-		-
Outstanding at June 30, 2012		1,981,495		$	24.71		3.6	$	12.5
Options Exercisable at June 30, 2012		1,500,192		$	22.19		2.8	$	12.3
Unvested Options at June 30, 2012		481,303		$	32.56		6.1	$	0.2

Restricted Shares and Performance Share Units Activity

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 during the six months ended June 30, 2012 and 2011 was $12.6 million and $9.9 million, respectively. The weighted average grant-date fair value of restricted stock was $30.74 per share and $39.14 per share for the six months ended June 30, 2012 and 2011, respectively. As of June 30, 2012, $25.3 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.4 years. Transactions involving restricted shares under the terms of the LTSIP are summarized below:

	Restricted Shares Outstanding			Weighted-Average Price
				(per share)
Unvested balance at December 31, 2011		1,099,752		$	32.80
Granted		706,221			30.74
Vested		(397,204	)		32.31
Forfeited		(49,209	)		32.71
Unvested balance at June 30, 2012		1,359,560		$	31.88

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 six months ended June 30, 2012 and 2011, respectively. As of June 30, 2012, $5.3 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 2.4 years.

Transactions involving performance share 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		171,954			30.90
Vested		-			-
Forfeited		(4,148	)		39.07
Unvested balance at June 30, 2012		283,080		$	34.11

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Operations by Line of Business (Tables)

6 Months Ended

Jun. 30, 2012

Operations by Line of Business [Abstract]

Summary of operating results 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:

	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
For the three months ended June 30, 2012	(in millions)
Revenues (1)
From unaffiliated customers	$	335.5		$	83.4		$	80.4		$	-		$	499.3
From affiliated customers		-			30.2			118.2			(148.4	)		-
Total Revenues		335.5			113.6			198.6			(148.4	)		499.3
Operating expenses
Purchased gas, oil and NGL expense		40.6			4.1			197.4			(117.2	)		124.9
Lease operating expense		41.4			-			-			(0.9	)		40.5
Natural gas, oil and NGL transportation    and other handling costs		57.2			12.0			-			(28.5	)		40.7
Gathering, processing and other		-			20.4			0.5			(0.3	)		20.6
General and administrative		29.2			9.0			0.1			(1.5	)		36.8
Production and property taxes		18.2			1.2			-			-			19.4
Depreciation, depletion and amortization		197.2			16.1			0.8			-			214.1
Other operating expenses		57.8			-			-			-			57.8
Total operating expenses		441.6			62.8			198.8			(148.4	)		554.8
Operating (loss) income (2)		(106.1	)		50.8			(0.2	)		-			(55.5	)
Realized and unrealized gains (losses) on    derivative contracts		81.8			4.8			(4.3	)		-			82.3
Interest and other income		0.7			0.1			26.8			(26.7	)		0.9
Income from unconsolidated affiliates		0.1			1.3			-			-			1.4
Loss on early extinguishment of debt		-			-			(0.6	)		-			(0.6	)
Interest expense		(23.4	)		(3.6	)		(27.9	)		26.7			(28.2	)
(Loss) income before income taxes		(46.9	)		53.4			(6.2	)		-			0.3
Income taxes		16.6			(19.2	)		2.5			-			(0.1	)
Net (loss) income		(30.3	)		34.2			(3.7	)		-			0.2
Net income attributable to    noncontrolling interest		-			(0.9	)		-			-			(0.9	)
Net (loss) income attributable to QEP (3)	$	(30.3	)	$	33.3		$	(3.7	)	$	-		$	(0.7	)

⁽¹⁾ The impact of QEP's settled derivative contracts, for the three months ended June 30, 2012, are reflected below operating (loss) income.

⁽²⁾ Operating (loss) income for the three months ended June 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the three months ended June 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.

⁽³⁾ Net income (loss) attributable to QEP for the three months ended June 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
For the three months ended June 30, 2011	(in millions)
Revenues (1)
From unaffiliated customers	$	555.5		$	102.0		$	150.6		$	-		$	808.1
From affiliated customers		-			20.2			145.2			(165.4	)		-
Total Revenues		555.5			122.2			295.8			(165.4	)		808.1
Operating expenses
Purchased gas, oil and NGL expense		154.7			-			292.5			(143.3	)		303.9
Lease operating expense		35.0			-			-			(0.7	)		34.3
Natural gas, oil and NGL transportation    and other handling costs		42.3			1.2			-			(19.5	)		24.0
Gathering, processing and other		-			26.9			0.4			(0.1	)		27.2
General and administrative		22.9			6.8			0.8			(1.8	)		28.7
Production and property taxes		25.4			1.6			0.1			-			27.1
Depreciation, depletion and amortization		172.5			13.5			0.6			-			186.6
Other operating expenses		7.6			-			-			-			7.6
Total operating expenses		460.4			50.0			294.4			(165.4	)		639.4
Net gain (loss) from asset sales		0.2			0.1			(0.1	)		-			0.2
Operating income (2)		95.3			72.3			1.3			-			168.9
Interest and other (loss) income		(0.5	)		-			24.8			(24.7	)		(0.4	)
Income from unconsolidated affiliates		0.1			1.2			-			-			1.3
Interest expense		(20.4	)		(3.1	)		(23.3	)		24.7			(22.1	)
Income before income taxes		74.5			70.4			2.8			-			147.7
Income taxes		(27.7	)		(25.5	)		(1.0	)		-			(54.2	)
Net income		46.8			44.9			1.8			-			93.5
Net income attributable to    noncontrolling interest		-			(0.7	)		-			-			(0.7	)
Net income attributable to QEP (3)	$	46.8		$	44.2		$	1.8		$	-		$	92.8

⁽¹⁾ Revenues for the three months ended June 30, 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 June 30, 2011, reflect the impact of QEP's settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the three months ended June 30, 2011.

⁽²⁾ Under hedge accounting, gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three months ended June 30, 2011.

⁽³⁾ Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three months ended June 30, 2011.

	QEP Energy			QEP Field Services			QEP Marketing  & Other			Eliminations			QEP Consolidated
For the six months ended June 30, 2012	(in millions)
Revenues (1)
From unaffiliated customers	$	732.3		$	177.0		$	193.2		$	-		$	1,102.5
From affiliated customers		-			56.3			250.5			(306.8	)		-
Total Revenues		732.3			233.3			443.7			(306.8	)		1,102.5
Operating expenses
Purchased gas, oil and NGL expense		113.1			4.1			445.0			(248.9	)		313.3
Lease operating expense		82.2			-			-			(1.6	)		80.6
Natural gas, oil and NGL transportation    and other handling costs		107.6			20.8			-			(53.2	)		75.2
Gathering, processing and other		-			43.8			0.7			(0.2	)		44.3
General and administrative		62.1			13.5			0.1			(2.9	)		72.8
Production and property taxes		41.1			2.9			0.1			-			44.1
Depreciation, depletion and amortization		380.3			31.4			1.6			-			413.3
Other operating expenses		66.4			-			-			-			66.4
Total operating expenses		852.8			116.5			447.5			(306.8	)		1,110.0
Net gain from asset sales		1.5			-			-			-			1.5
Operating (loss) income (2)		(119.0	)		116.8			(3.8	)		-			(6.0	)
Realized and unrealized gains on derivative    contracts		289.0			8.9			0.7			-			298.6
Interest and other income		2.4			0.1			52.7			(52.6	)		2.6
Income from unconsolidated affiliates		0.1			3.2			-			-			3.3
Loss on early extinguishment of debt		-			-			(0.6	)		-			(0.6	)
Interest expense		(47.0	)		(5.9	)		(52.6	)		52.6			(52.9	)
Income (loss) before income taxes		125.5			123.1			(3.6	)		-			245.0
Income taxes		(47.7	)		(42.7	)		1.6			-			(88.8	)
Net income (loss)		77.8			80.4			(2.0	)		-			156.2
Net income attributable to    noncontrolling interest		-			(1.7	)		-			-			(1.7	)
Net income (loss) attributable to QEP (3)	$	77.8		$	78.7		$	(2.0	)	$	-		$	154.5

⁽¹⁾ The impact of QEP's settled derivative contracts, for the six months ended June 30, 2012, are reflected below operating (loss) income.

⁽²⁾ Operating (loss) income for the six months ended June 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the six months ended June 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.

⁽³⁾ Net (loss) income attributable to QEP for the six months ended June 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
For the six months ended June 30, 2011	(in millions)
Revenues (1)
From unaffiliated customers	$	951.7		$	175.3		$	299.0		$	-		$	1,426.0
From affiliated customers		-			43.5			278.3			(321.8	)		-
Total Revenues		951.7			218.8			577.3			(321.8	)		1,426.0
Operating expenses
Purchased gas, oil and NGL expense		154.7			-			570.4			(274.5	)		450.6
Lease operating expense		68.4			-			-			(1.3	)		67.1
Natural gas, oil and NGL transportation    and other handling costs		85.8			2.1			-			(42.2	)		45.7
Gathering, processing and other		-			51.7			0.7			-			52.4
General and administrative		46.8			15.8			1.6			(3.8	)		60.4
Production and property taxes		47.6			3.0			0.2			-			50.8
Depreciation, depletion and amortization		349.6			26.7			1.1			-			377.4
Other operating expenses		15.8			-			-			-			15.8
Total operating expenses		768.7			99.3			574.0			(321.8	)		1,120.2
Net gain (loss) from asset sales		0.2			0.1			(0.1	)		-			0.2
Operating income (2)		183.2			119.6			3.2			-			306.0
Interest and other income		0.2			-			49.2			(49.2	)		0.2
Income from unconsolidated affiliates		0.1			2.1			-			-			2.2
Interest expense		(40.3	)		(6.6	)		(46.5	)		49.2			(44.2	)
Income before income taxes		143.2			115.1			5.9			-			264.2
Income taxes		(53.3	)		(41.6	)		(2.0	)		-			(96.9	)
Net income		89.9			73.5			3.9			-			167.3
Net income attributable to    noncontrolling interest		-			(1.3	)		-			-			(1.3	)
Net income attributable to QEP (3)	$	89.9		$	72.2		$	3.9		$	-		$	166.0

⁽¹⁾ Revenues for the six months ended June 30, 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 six months ended June 30, 2011, reflect the impact of QEP's settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the six months ended June 30, 2011.

⁽²⁾ Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three and six months ended June 30, 2011.

⁽³⁾ Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three and six months ended June 30, 2011.

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Basis of Presentation of Interim Consolidated Financial Statements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011		Jun. 30, 2012	Jun. 30, 2011
De-designation of commodity derivative contracts [Abstract]
Unrealized gain (Loss) on derivatives contract	$ (38.4)			$ 89.9	$ 58.8
REVENUES
Natural gas sales	138.9	298.7		300.1	611.3
Oil sales	107.2	80.7		218.0	143.7
NGL sales	82.1	63.8		179.5	111.7
Gathering, processing and other	45.8	58.9		95.6	105.5
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs	40.7	24.0		75.2	45.7
Proved Properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	48.9			49.3
Unproved Properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	6.1			12.1
Southern Region [Member] | Proved Properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	48.9
Southern Region [Member] | Unproved Properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	3.1			6.1
Northern Region [Member] | Proved Properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets				0.4
Northern Region [Member] | Unproved Properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	3.0			6.0
QEP Field Services [Member]
REVENUES
NGL sales		16.5			33.7
Gathering, processing and other		123.5			221.4
Prior periods presentation of revenues [Member]
REVENUES
Natural gas sales		258.1	[1]		529.1	[1]
Oil sales		80.0	[1]		142.3	[1]
NGL sales		61.6	[1]		107.4	[1]
Gathering, processing and other		78.4	[1]		147.7	[1]
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		0	[1]		0	[1]
Prior periods presentation of revenues [Member] | QEP Field Services [Member]
REVENUES
NGL sales		45.1			73.7
Restatement Adjustment [Member]
REVENUES
Natural gas sales		40.6			82.2
Oil sales		0.7			1.4
NGL sales		2.2			4.3
Gathering, processing and other		(19.5)			(42.2)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		$ 24.0			$ 45.7

[1] The "As reported" numbers reflect QEP Field Services NGL sales of $45.1 million and $73.7 million in the three and six months ended June 30, 2011, which have been reclassified from "Gathering, processing and other" into "NGL sales" for consistency with current period presentation. In its second quarter 2011 Form 10-Q, QEP reported "NGL sales" of $16.5 million and $33.7 million, and "Gathering, processing and other" of $123.5 million, and $221.4 million for the three and six months ended June 30, 2011, respectively. The QEP Field Services NGL reclassification is all within "Revenues" and has no effect on income from continuing operations, net income or earnings per share.

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Nature of Business

6 Months Ended

Jun. 30, 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 - natural gas and crude oil exploration and production; midstream field services; and energy marketing. These businesses are conducted through the Company's three principal subsidiaries:

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

§ QEP Field Services Company (QEP Field Services) provides midstream field services; including natural gas gathering, processing, compression, and treating services, for affiliates and third parties; 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 two major regions, the Northern Region (primarily in the Rockies) and the Southern Region (primarily Oklahoma, Louisiana, and the Texas Panhandle) of the United States. QEP's corporate headquarters are located in Denver, Colorado.

Shares of QEP Resources' common stock trade on the New York Stock Exchange under the ticker symbol "QEP".

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Earnings Per Share (Details) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Earnings Per Share [Abstract]
Anti-dilutive shares not included in diluted common share outstanding (in shares)	0.9
Weighted-average basic common shares outstanding (in shares)	177.7	176.6	177.6	176.4
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan	0	2.0	0.9	2.1
Average diluted common shares outstanding (in shares)	177.7	178.6	178.5	178.5

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Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 0.9	$ 0.7	$ 1.9	$ 1.4
Interest cost	1.2	1.1	2.4	2.2
Expected return on plan assets	(0.9)	(0.6)	(1.8)	(1.2)
Amortization of prior service costs	1.3	1.3	2.6	2.6
Amortization of actuarial loss	0.2	0	0.4	0
Periodic expense	2.7	2.5	5.5	5.0
Pension [Member] | Funded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan			2.7
Expected to contribute to pension plans	3.6		3.6
Pension [Member] | Unfunded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan			1.0
Expected to contribute to pension plans	0.3		0.3
Postretirement benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0	0	0	0
Interest cost	0.1	0.1	0.2	0.2
Expected return on plan assets	0	0	0	0
Amortization of prior service costs	0.1	0.1	0.2	0.2
Amortization of actuarial loss	0	0	0	0
Periodic expense	$ 0.2	$ 0.2	$ 0.4	$ 0.4

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
REVENUES
Natural gas sales	$ 138.9	$ 298.7		$ 300.1		$ 611.3
Oil sales	107.2	80.7		218.0		143.7
NGL sales	82.1	63.8		179.5		111.7
Gathering, processing and other	45.8	58.9		95.6		105.5
Purchased gas, oil and NGL sales	125.3	306.0		309.3		453.8
Total Revenues	499.3	808.1	[1]	1,102.5	[2]	1,426.0	[3]
OPERATING EXPENSES
Purchased gas, oil and NGL expense	124.9	303.9		313.3		450.6
Lease operating expense	40.5	34.3		80.6		67.1
Natural gas, oil and NGL transportation and other handling costs	40.7	24.0		75.2		45.7
Gathering, processing and other	20.6	27.2		44.3		52.4
General and administrative	36.8	28.7		72.8		60.4
Production and property taxes	19.4	27.1		44.1		50.8
Depreciation, depletion and amortization	214.1	186.6		413.3		377.4
Exploration expenses	2.1	2.3		4.1		5.1
Abandonment and impairment	55.7	5.3		62.3		10.7
Total Operating Expenses	554.8	639.4		1,110.0		1,120.2
Net gain from asset sales	0	0.2		1.5		0.2
OPERATING (LOSS) INCOME	(55.5)	168.9	[4]	(6.0)	[5]	306.0	[6]
Realized and unrealized gains on derivative contracts (See Note 6)	82.3	0		298.6		0
Interest and other income (loss)	0.9	(0.4)		2.6		0.2
Income from unconsolidated affiliates	1.4	1.3		3.3		2.2
Loss from early extinguishment of debt	(0.6)	0		(0.6)		0
Interest expense	(28.2)	(22.1)		(52.9)		(44.2)
INCOME BEFORE INCOME TAXES	0.3	147.7		245.0		264.2
Income taxes	(0.1)	(54.2)		(88.8)		(96.9)
NET INCOME	0.2	93.5		156.2		167.3
Net income attributable to noncontrolling interest	(0.9)	(0.7)		(1.7)		(1.3)
NET (LOSS) INCOME ATTRIBUTABLE TO QEP	$ (0.7)	$ 92.8	[7]	$ 154.5	[8]	$ 166.0	[9]
Earnings Per Common Share Attributable to QEP
Basic total (in dollars per share)	$ 0.00	$ 0.52		$ 0.87		$ 0.94
Diluted total (in dollars per share)	$ 0.00	$ 0.52		$ 0.87		$ 0.93
Weighted-average common shares outstanding
Used in basic calculation (in shares)	177.7	176.6		177.6		176.4
Used in diluted calculation (in shares)	177.7	178.6		178.5		178.5
Dividends per common share (in dollars per share)	$ 0.02	$ 0.02		$ 0.04		$ 0.04

[1] Revenues for the three months ended June 30, 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 June 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the three months ended June 30, 2011.

[2] The impact of QEP’s settled derivative contracts, for the six months ended June 30, 2012, are reflected below operating (loss) income.

[3] Revenues for the six months ended June 30, 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 six months ended June 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the six months ended June 30, 2011.

[4] Under hedge accounting, gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three months ended June 30, 2011.

[5] Operating (loss) income for the six months ended June 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the six months ended June 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.

[6] Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three and six months ended June 30, 2011.

[7] Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three months ended June 30, 2011.

[8] Net (loss) income attributable to QEP for the six months ended June 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

[9] Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three and six months ended June 30, 2011.

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
EQUITY
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)	178.5	177.2
Treasury stock (in shares)	0.7	0.4

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Derivative Contracts (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended																																			6 Months Ended	3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 Interest rate swap [Member]	Jun. 30, 2011 Interest rate swap [Member]	Jun. 30, 2012 Interest rate swap [Member]	Jun. 30, 2011 Interest rate swap [Member]	Jun. 30, 2012 QEP Energy [Member] Natural gas derivative contracts [Member]	Jun. 30, 2011 QEP Energy [Member] Natural gas derivative contracts [Member]	Jun. 30, 2012 QEP Energy [Member] Natural gas derivative contracts [Member]	Jun. 30, 2011 QEP Energy [Member] Natural gas derivative contracts [Member]	Jun. 30, 2012 QEP Energy [Member] Oil derivative contracts [Member]	Jun. 30, 2011 QEP Energy [Member] Oil derivative contracts [Member]	Jun. 30, 2012 QEP Energy [Member] Oil derivative contracts [Member]	Jun. 30, 2011 QEP Energy [Member] Oil derivative contracts [Member]	Jun. 30, 2012 QEP Energy [Member] NGL derivative contracts [Member]	Jun. 30, 2011 QEP Energy [Member] NGL derivative contracts [Member]	Jun. 30, 2012 QEP Energy [Member] NGL derivative contracts [Member]	Jun. 30, 2011 QEP Energy [Member] NGL derivative contracts [Member]	Jun. 30, 2012 QEP Field Services [Member] NGL derivative contracts [Member]	Jun. 30, 2011 QEP Field Services [Member] NGL derivative contracts [Member]	Jun. 30, 2012 QEP Field Services [Member] NGL derivative contracts [Member]	Jun. 30, 2011 QEP Field Services [Member] NGL derivative contracts [Member]	Jun. 30, 2012 QEP Marketing [Member] Natural gas derivative contracts [Member]	Jun. 30, 2011 QEP Marketing [Member] Natural gas derivative contracts [Member]	Jun. 30, 2012 QEP Marketing [Member] Natural gas derivative contracts [Member]	Jun. 30, 2011 QEP Marketing [Member] Natural gas derivative contracts [Member]	Jun. 30, 2012 Realized and unrealized gains on commodity derivative instruments [Member]	Jun. 30, 2011 Realized and unrealized gains on commodity derivative instruments [Member]	Jun. 30, 2012 Realized and unrealized gains on commodity derivative instruments [Member]	Jun. 30, 2011 Realized and unrealized gains on commodity derivative instruments [Member]	Jun. 30, 2012 Accumulated other comprehensive income (loss) [Member]	Jun. 30, 2011 Accumulated other comprehensive income (loss) [Member]	Jun. 30, 2012 Accumulated other comprehensive income (loss) [Member]	Jun. 30, 2011 Accumulated other comprehensive income (loss) [Member]	Jun. 30, 2012 Natural Gas Sales [Member]	Jun. 30, 2011 Natural Gas Sales [Member]	Jun. 30, 2012 Natural Gas Sales [Member]	Jun. 30, 2011 Natural Gas Sales [Member]	Jun. 30, 2012 Oil Sales [Member]	Jun. 30, 2011 Oil Sales [Member]	Jun. 30, 2012 Oil Sales [Member]	Jun. 30, 2011 Oil Sales [Member]	Jun. 30, 2012 Marketing Purchases [Member]	Jun. 30, 2011 Marketing Purchases [Member]	Jun. 30, 2012 Marketing Purchases [Member]	Jun. 30, 2011 Marketing Purchases [Member]	Jun. 30, 2012 Interest and Other Income [Member]	Jun. 30, 2011 Interest and Other Income [Member]	Jun. 30, 2012 Interest and Other Income [Member]	Jun. 30, 2011 Interest and Other Income [Member]	Jun. 30, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2012 [Member] NYMEX [Member] Btu	Jun. 30, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2012 [Member] IFPEPL [Member] Btu		Jun. 30, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2012 [Member] IFNPCR [Member] Btu		Jun. 30, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2012 [Member] IFCNPTE [Member] Btu		Jun. 30, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2013 [Member] IFNPCR [Member] Btu		Jun. 30, 2012 Swap [Member] Natural Gas Sales (MMbtu) [Member] 2013 [Member] NYMEX WTI [Member] Btu	Jun. 30, 2012 Swap [Member] Oil Sales (Bbls) [Member] 2012 [Member] NYMEX WTI [Member] bbl	Jun. 30, 2012 Swap [Member] Oil Sales (Bbls) [Member] 2013 [Member] NYMEX WTI [Member] bbl	Jun. 30, 2012 Swap [Member] NGL Sales [Member] 2012 [Member] Mt. Belvieu Ethane [Member] gal	Jun. 30, 2012 Swap [Member] NGL Sales [Member] 2012 [Member] Mt. Belvieu Propane [Member] gal	Jun. 30, 2012 Swap [Member] QEP Field Services [Member] 2012 [Member] Mt. Belvieu Ethane [Member] gal	Jun. 30, 2012 Swap [Member] QEP Field Services [Member] 2012 [Member] Mt. Belvieu Propane [Member] gal	Jun. 30, 2012 Swap [Member] QEP Marketing [Member] 2012 [Member] IFNPCR [Member] Btu		Jun. 30, 2012 Swap [Member] QEP Marketing [Member] 2013 [Member] IFNPCR [Member] Btu		Jun. 30, 2012 Swap [Member] QEP Resources [Member]	Jun. 30, 2012 Swap [Member] Purchased Gas and Oil Expense [Member] 2012 [Member] IFNPCR [Member] Btu		Jun. 30, 2012 Swap [Member] Purchased Gas and Oil Expense [Member] 2013 [Member] IFNPCR [Member] Btu		Jun. 30, 2012 Interest Rate Swap [Member] Short-term [Member]	Dec. 31, 2011 Interest Rate Swap [Member] Short-term [Member]	Jun. 30, 2012 Interest Rate Swap [Member] Long-term [Member]	Dec. 31, 2011 Interest Rate Swap [Member] Long-term [Member]	Jun. 30, 2012 Commodity Contract [Member] Short-term [Member]	Dec. 31, 2011 Commodity Contract [Member] Short-term [Member]	Jun. 30, 2012 Commodity Contract [Member] Long-term [Member]	Dec. 31, 2011 Commodity Contract [Member] Long-term [Member]	Jun. 30, 2012 Commodity Contract [Member] Oil Sales (Bbls) [Member] 2012 [Member] NYMEX WTI [Member] bbl	Jun. 30, 2012 QEP Energy [Member] Fixed-price swaps [Member] Natural Gas Sales (MMbtu) [Member]	Jun. 30, 2011 QEP Energy [Member] Fixed-price swaps [Member] Natural Gas Sales (MMbtu) [Member]	Jun. 30, 2012 QEP Energy [Member] Fixed-price swaps [Member] Natural Gas Sales (MMbtu) [Member]	Jun. 30, 2011 QEP Energy [Member] Fixed-price swaps [Member] Natural Gas Sales (MMbtu) [Member]	Jun. 30, 2012 QEP Energy [Member] Fixed-price swaps [Member] Oil Sales (Bbls) [Member]	Jun. 30, 2011 QEP Energy [Member] Fixed-price swaps [Member] Oil Sales (Bbls) [Member]	Jun. 30, 2012 QEP Energy [Member] Fixed-price swaps [Member] Oil Sales (Bbls) [Member]	Jun. 30, 2011 QEP Energy [Member] Fixed-price swaps [Member] Oil Sales (Bbls) [Member]	Jun. 30, 2012 QEP Energy [Member] Fixed-price swaps [Member] NGL Sales [Member]	Jun. 30, 2011 QEP Energy [Member] Fixed-price swaps [Member] NGL Sales [Member]	Jun. 30, 2012 QEP Energy [Member] Fixed-price swaps [Member] NGL Sales [Member]	Jun. 30, 2011 QEP Energy [Member] Fixed-price swaps [Member] NGL Sales [Member]	Jun. 30, 2012 QEP Energy [Member] Costless Collars [Member] Natural Gas Sales (MMbtu) [Member]	Jun. 30, 2011 QEP Energy [Member] Costless Collars [Member] Natural Gas Sales (MMbtu) [Member]	Jun. 30, 2012 QEP Energy [Member] Costless Collars [Member] Natural Gas Sales (MMbtu) [Member]	Jun. 30, 2011 QEP Energy [Member] Costless Collars [Member] Natural Gas Sales (MMbtu) [Member]	Jun. 30, 2012 QEP Energy [Member] Costless Collars [Member] Oil Sales (Bbls) [Member]	Jun. 30, 2011 QEP Energy [Member] Costless Collars [Member] Oil Sales (Bbls) [Member]	Jun. 30, 2012 QEP Energy [Member] Costless Collars [Member] Oil Sales (Bbls) [Member]	Jun. 30, 2011 QEP Energy [Member] Costless Collars [Member] Oil Sales (Bbls) [Member]	Jun. 30, 2012 QEP Field Services [Member] Fixed-price swaps [Member] Ethane Sales (Gals) [Member]	Jun. 30, 2011 QEP Field Services [Member] Fixed-price swaps [Member] Ethane Sales (Gals) [Member]	Jun. 30, 2012 QEP Field Services [Member] Fixed-price swaps [Member] Ethane Sales (Gals) [Member]	Jun. 30, 2011 QEP Field Services [Member] Fixed-price swaps [Member] Ethane Sales (Gals) [Member]	Jun. 30, 2012 QEP Field Services [Member] Fixed-price swaps [Member] Propane Sales (Gals) [Member]	Jun. 30, 2011 QEP Field Services [Member] Fixed-price swaps [Member] Propane Sales (Gals) [Member]	Jun. 30, 2012 QEP Field Services [Member] Fixed-price swaps [Member] Propane Sales (Gals) [Member]	Jun. 30, 2011 QEP Field Services [Member] Fixed-price swaps [Member] Propane Sales (Gals) [Member]	Jun. 30, 2012 Term Loan due 2017 [Member]	Dec. 31, 2011 Term Loan due 2017 [Member]
Derivative Contracts [Abstract]
Forecasted production from proved reserves (in hundredths)	100.00%
Unrealized gains on derivative contracts	$ 249.8
Unrealized gains on derivative contracts, net of tax	156.9
Notional amount of interest rate derivatives	300.0																																																																						300.0
Debt Instrument [Line Items]
Principal amount of debt	1,871.8	1,684.9																																																																																																															300.0	0
Derivative [Line Items]
Derivative volumes as a percent of production (in hundredths)																																																																																					67.00%	46.00%	63.00%	44.00%	35.00%	3.00%	36.00%	2.00%	18.00%	0.00%	17.00%	0.00%	0.00%	12.00%	0.00%	12.00%	28.00%	31.00%	22.00%	33.00%	15.00%	0.00%	27.00%	0.00%	59.00%	0.00%	76.00%	0.00%
Derivatives, Fair Value [Line Items]
Year																																																			2012	2012		2012		2012		2013		2013	2012	2013	2012	2012	2012	2012	2012		2013			2012		2013										2012
Index																																																			NYMEX	IFPEPL (1)	[1]	IFNPCR (2)	[2]	IFCNPTE (3)	[3]	IFNPCR (2)	[2]	NYMEX	NYMEX WTI	NYMEX WTI	Mt. Belvieu Ethane	Mt. Belvieu Propane	Mt. Belvieu Ethane	Mt. Belvieu Propane	IFNPCR (1)	[2]	IFNPCR (1)	[2]		IFNPCR (1)	[2]	IFNPCR (1)	[2]									NYMEX WTI
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)																																																			39,900,000	4,900,000		45,400,000		5,500,000		65,700,000	[2]	29,200,000	900,000	900,000	7,700,000	11,600,000	7,700,000	3,900,000	1,800,000		1,200,000			700,000	[1]	100,000	[1]									700,000
Average Swap price per unit ($ per unit)																																																			$ 4.66	$ 4.14		$ 4.61		$ 2.66		$ 5.66	[2]	$ 3.68	$ 97.03	$ 104.12	$ 0.64	$ 1.28	$ 0.64	$ 1.28	$ 4.06		$ 4.57			$ 2.97	[1]	$ 2.59	[1]
Collars Floor Price ($ per unit)																																																																																				$ 87.50
Collars Ceiling Price ($ per unit)																																																																																				$ 115.36
Notional amount	300.0																																																																						300.0
Maturity																																																																							Mar. 31, 2017
Fixed Rate Paid (in hundredths)																																																																							1.07%
Variable Rate Received																																																																							One month LIBOR
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross	349.7	407.6																																																																										0	0	0	0	272.2	284.1	77.5	123.5
Derivative Liability, Fair Value, Gross	10.0	11.7																																																																										2.3	0	2.0	0	4.0	11.7	1.7	0
Derivatives not designated as hedging instruments - Commodity derivatives [Abstract]
Realized gain (loss) on commodity derivative contracts							111.9	(27.6)	197.6	(58.8)	2.2	0	(0.5)	0	2.7	0	3.1	0	3.3	0	4.4	0	0.6	0	4.1	0	120.7	(27.6)	208.7	(58.8)
Unrealized gain (loss) on commodity derivative contracts			(4.3)	0	(4.3)	0	(78.4)	27.6	53.9	58.8	38.6	0	27.1	0	4.9	0	7.8	0	1.5	0	4.5	0	(0.7)	0	0.9	0	(34.1)	27.6	94.2	58.8
Total gain (loss) on commodity derivative instruments																											86.6	0	302.9	0
Gain on derivative instruments for the effective portion of hedge recognized in AOCI [Abstract]
Gain on derivative instruments for the effective portion of hedge recognized in AOCI																															0	61.3	0	61.5
Gain recognized in income for the ineffective portion of hedges [Abstract]
Gain recognized in income for the ineffective portion of hedges																																															0	0.3	0	0.1
Gain reclassified from AOCI into income for effective portion of hedge [Abstract]
Gain reclassified from AOCI into income for effective portion of hedge																																			0	64.4	0	137.5	0	0.1	0	0.1	0	0.5	0	3.9
Fair value of frozen derivative to be settled and reclassified within twelve months	$ 120.0

[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.

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 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				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(in millions)
Weighted-average basic common shares outstanding		177.7		176.6		177.6		176.4
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan		-		2.0		0.9		2.1
Average diluted common shares outstanding		177.7		178.6		178.5		178.5

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Restructuring Costs (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
Restructuring Costs [Abstract]
Number of regional offices created		1
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		$ 6.0
Restructuring costs incurred to date	2.3	5.0
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2011		0
Costs incurred and charged to expense		5.0
Costs paid or otherwise settled		(4.6)
Balance at June 30, 2012	0.4	0.4
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		2.1
Restructuring costs incurred to date	0.8	1.9
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		3.4
Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		$ 0.5

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Measurements [Abstract]

Fair value of financial assets and liabilities

The fair value of financial assets and liabilities at June 30, 2012, is shown in the table below:

	Fair Value Measurements
	June 30, 2012
	Level 1		Level 2		Level 3		Netting Adjustments			Total
			(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	-	$	272.2	$	-	$	(4.0	)	$	268.2
Commodity derivative instruments - long-term		-		77.5		-		(1.3	)		76.2
Total financial assets	$	-	$	349.7	$	-	$	(5.3	)	$	344.4
Financial Liabilities
Commodity derivative instruments - short-term	$	-	$	4.0			$	(4.0	)	$	-
Interest rate swaps - short-term		-		2.3				-			2.3
Commodity derivative instruments - long-term		-		1.7				(1.3	)		0.4
Interest rate swaps - long-term		-		2.0		-					2.0
Total financial liabilities	$	-	$	10.0	$	-	$	(5.3	)	$	4.7

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

	Fair Value Measurements
	December 31, 2011
	Level 1		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 six months ended June 30, 2012, is shown below:

	Change in Level 3 Fair Value Measurements
	2012
	(in millions)
Balance at January 1,	$	-
Realized gains and losses		0.6
Unrealized gains and losses		3.8
Settlements		(0.6	)
Transfers out of Level 3		(3.8	)
Balance at June 30,	$	-

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
	June 30, 2012				December 31, 2011
	(in millions)
Financial assets
Cash and cash equivalents	$	146.4	$	146.4	$	-	$	-
Financial liabilities
Checks outstanding in excess of cash balances	$	-	$	-	$	29.4	$	29.4
Long-term debt	$	1,866.6	$	1,967.2	$	1,679.4	$	1,754.9

Fair value of non financial assets and liabilities measured at nonrecurring basis

The following table summarizes the non-financial assets and liabilities measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition and their associated impairment:

	Level 3 Fair Value		Impairment		Level 3 Fair Value		Impairment
	June 30, 2012				December 31, 2011
	(in millions)
Proved Property	$	5,058.6	$	49.3	$	4,833.2	$	195.5

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
OPERATING ACTIVITIES
Net income	$ 156.2	$ 167.3
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	413.3	377.4
Deferred income taxes	77.1	95.7
Abandonment and impairment	62.3	10.7
Share-based compensation	12.3	10.8
Amortization of debt issuance costs and discounts	2.4	1.5
Dry exploratory well expense	0.1	0.5
Net gain from asset sales	(1.5)	(0.2)
Income from unconsolidated affiliates	(3.3)	(2.2)
Distributions from unconsolidated affiliates and other	3.5	2.6
Non-cash loss on early extinguishment of debt	0.1	0
Unrealized gain on derivative contracts	(89.9)	(58.8)
Changes in operating assets and liabilities	61.7	23.3
Net Cash Provided by Operating Activities	694.3	628.6
INVESTING ACTIVITIES
Property acquisitions	(4.0)	(29.8)
Property, plant and equipment, including dry exploratory well expense	(681.5)	(632.0)
Proceeds from disposition of assets	3.6	1.6
Net Cash Used in Investing Activities	(681.9)	(660.2)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(29.4)	(1.5)
Long-term debt issued	800.0	0
Long-term debt issuance costs paid	(8.8)	0
Long-term debt repaid	(6.7)	(58.5)
Proceeds from credit facility	194.5	200.0
Repayments of credit facility	(801)	(100)
Other capital contributions	(6.4)	(0.4)
Dividends paid	(7.1)	(7.1)
Excess tax benefit on share-based compensation	2.0	1.4
Distribution from Questar	0	0.2
Distribution to noncontrolling interest	(3.1)	(2.5)
Net Cash Provided by Financing Activities	134.0	31.6
Change in cash and cash equivalents	146.4	0
Beginning cash and cash equivalents	0	0
Ending cash and cash equivalents	146.4	0
Supplemental Disclosures:
Cash paid for interest	42.7	64.6
Cash paid (received) for income taxes	8.0	(7.2)
Non-cash investing activities
Change in capital expenditure accrual balance	$ 45.3	$ 12.3

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Net income	$ 0.2		$ 93.5		$ 156.2		$ 167.3
Other comprehensive (loss) income, net of tax:
Reclassification of previously deferred derivative gains(1)	(44.7)	[1]	(2.5)	[1]	(91.7)	[1]	(50.3)	[1]
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss	0.1	[2]	0	[2]	0.2	[2]	0	[2]
Amortization of prior service cost	0.8	[3]	1.7	[3]	1.7	[3]	1.7	[3]
Total pension and other postretirement plans adjustments	0.9		1.7		1.9		1.7
Other comprehensive loss	(43.8)		(0.8)		(89.8)		(48.6)
Comprehensive (loss) income	(43.6)		92.7		66.4		118.7
Comprehensive income attributable to noncontrolling interests	(0.9)		(0.7)		(1.7)		(1.3)
Comprehensive (loss) income attributable to QEP	$ (44.5)		$ 92.0		$ 64.7		$ 117.4

[1] Presented net of income tax benefit of $26.5 million and $54.3 million during the three and six months ended June 30, 2012, respectively, and net of income tax benefit of $1.5 million and $29.8 million during the three and six months ended June 30, 2011, respectively.

[2] Presented net of income tax expense of $0.1 million and $0.2 million during the three and six months ended June 30, 2012, respectively,.

[3] Presented net of income tax expense of $0.5 million and $1.1 million during the three and six months ended June 30, 2012, respectively, and net of income tax expense of $1.1 million during the three and six months ended June 30, 2011, respectively.

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Share-Based Compensation

6 Months Ended

Jun. 30, 2012

Share-Based Compensation [Abstract]

Share-Based Compensation

Note 10 - 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 13.1 million shares available for future grants under the LTSIP at June 30, 2012. Share-based compensation expense is recognized in "General and administrative" on the Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2012, QEP recognized $6.6 million and $12.3 million, respectively, in total compensation expense related to share-based compensation compared to $3.4 million and $10.8 million during the three and six months ended June 30, 2011.

Stock Options

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

	Stock Option Variables Six Months Ended June 30, 2012
Fair value of options at grant date	$	14.46
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		291,143			30.83
Exercised		(313,342	)		8.15
Forfeited		-			-		-
Outstanding at June 30, 2012		1,981,495		$	24.71		3.6	$	12.5
Options Exercisable at June 30, 2012		1,500,192		$	22.19		2.8	$	12.3
Unvested Options at June 30, 2012		481,303		$	32.56		6.1	$	0.2

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 $2.6 million during the six months ended June 30, 2012 and 2011, respectively. As of June 30, 2012, $4.6 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.4 years.

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 during the six months ended June 30, 2012 and 2011 was $12.6 million and $9.9 million, respectively. The weighted average grant-date fair value of restricted stock was $30.74 per share and $39.14 per share for the six months ended June 30, 2012 and 2011, respectively. As of June 30, 2012, $25.3 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.4 years. Transactions involving restricted shares under the terms of the LTSIP are summarized below:

	Restricted Shares Outstanding			Weighted-Average Price
				(per share)
Unvested balance at December 31, 2011		1,099,752		$	32.80
Granted		706,221			30.74
Vested		(397,204	)		32.31
Forfeited		(49,209	)		32.71
Unvested balance at June 30, 2012		1,359,560		$	31.88

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 six months ended June 30, 2012 and 2011, respectively. As of June 30, 2012, $5.3 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 2.4 years.

Transactions involving performance share 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		171,954			30.90
Vested		-			-
Forfeited		(4,148	)		39.07
Unvested balance at June 30, 2012		283,080		$	34.11

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012
Document and Entity Information [Abstract]
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 Common Stock, Shares Outstanding	177,769,238
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2012

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Employee Benefits

6 Months Ended

Jun. 30, 2012

Employee Benefits [Abstract]

Employee Benefits

Note 11 - Employee Benefits

The Company has a funded qualified defined benefit pension plan and an unfunded supplemental defined benefit pension plan. The Company also has unfunded postretirement benefits that provide certain health care and life insurance benefits for certain retired employees. During the six months ended June 30, 2012, the Company made contributions of $2.7 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 $3.6 million to its funded pension plans, and approximately $0.3 million to its unfunded pension plans. In July 2012, Congress passed the Moving Ahead for Progress in the 21st Century Act, which included pension funding stabilization provisions. The measure, which is designed to stabilize the discount rate used to determine funding requirements from the effects of interest rate volatility, may reduce the Company's United States Pension Plan contributions during 2012 from the planned amounts.

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

	Pension
	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Service cost	$	0.9		$	0.7		$	1.9		$	1.4
Interest cost		1.2			1.1			2.4			2.2
Expected return on plan assets		(0.9	)		(0.6	)		(1.8	)		(1.2	)
Amortization of prior service costs		1.3			1.3			2.6			2.6
Amortization of actuarial loss		0.2			-			0.4			-
Periodic expense	$	2.7		$	2.5		$	5.5		$	5.0

	Postretirement benefits
	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)
Service cost	$	-	$	-	$	-	$	-
Interest cost		0.1		0.1		0.2		0.2
Expected return on plan assets		-		-		-		-
Amortization of prior service costs		0.1		0.1		0.2		0.2
Recognized net actuarial loss		-		-		-		-
Periodic expense	$	0.2	$	0.2	$	0.4	$	0.4

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Other comprehensive income (loss), tax
Tax expense (benefit) on gains (losses) on changes in unrealized fair value of derivatives designated as cash flow hedges	$ (26.5)	$ (1.5)	$ (54.3)	$ (29.8)
Pension and other postretirement plans adjustments:
Tax expense (benefit) on net unamortized gain (loss) incurred	0.1		0.2
Tax expense (benefit) on prior service cost incurred	$ 0.5	$ 1.1	$ 1.1	$ 1.1

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Fair Value Measurements

6 Months Ended

Jun. 30, 2012

Fair Value Measurements [Abstract]

Fair Value Measurements

Note 5 - Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820 "Fair Value Measurements and Disclosures". This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements, but does not change existing guidance as to whether or not an instrument is carried at fair value. ASC 820 also establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.

QEP has determined its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (see Note 6 - 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.

QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.

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

In addition, QEP has Level 2 interest rate swaps. The fair values of the interest rate swaps are determined using the market standard methodology of discounting the future expected cash flows that would occur under the contractual terms of the swap. The variable interest rates used in the calculation of projected cash flows are based on an expectation of future interest rates derived from observable market interest rate curves. QEP incorporates credit valuation adjustments to reflect both its nonperformance risk and the respective counterparty's nonperformance risk in the fair value measurements. While the credit valuation adjustments are not observable inputs, they are not significant to the overall valuation and the other inputs used to value the interest rate swaps are observable Level 2 inputs.

As of June 30, 2012 and December 31, 2011, the Company did not have assets or liabilities classified as Level 1 or Level 3 within the fair value hierarchy.

The fair value of financial assets and liabilities at June 30, 2012, is shown in the table below:

	Fair Value Measurements
	June 30, 2012
	Level 1		Level 2		Level 3		Netting Adjustments			Total
			(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	-	$	272.2	$	-	$	(4.0	)	$	268.2
Commodity derivative instruments - long-term		-		77.5		-		(1.3	)		76.2
Total financial assets	$	-	$	349.7	$	-	$	(5.3	)	$	344.4
Financial Liabilities
Commodity derivative instruments - short-term	$	-	$	4.0			$	(4.0	)	$	-
Interest rate swaps - short-term		-		2.3				-			2.3
Commodity derivative instruments - long-term		-		1.7				(1.3	)		0.4
Interest rate swaps - long-term		-		2.0		-					2.0
Total financial liabilities	$	-	$	10.0	$	-	$	(5.3	)	$	4.7

Fair values related to the Company's crude oil costless collars, were transferred from Level 3 to Level 2 in the second quarter of 2012, due to the enhancements to the Company's internal valuation process, including the use of observable inputs to assess the fair value. There were no other significant transfers in or out of Levels 1, 2 or 3 for the periods presented herein. The Company's policy is to recognize transfers in and/or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.

The change in the fair value of Level 3 commodity derivative instruments assets and liabilities for the six months ended June 30, 2012, is shown below:

	Change in Level 3 Fair Value Measurements
	2012
	(in millions)
Balance at January 1,	$	-
Realized gains and losses		0.6
Unrealized gains and losses		3.8
Settlements		(0.6	)
Transfers out of Level 3		(3.8	)
Balance at June 30,	$	-

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

	Fair Value Measurements
	December 31, 2011
	Level 1		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
	June 30, 2012				December 31, 2011
	(in millions)
Financial assets
Cash and cash equivalents	$	146.4	$	146.4	$	-	$	-
Financial liabilities
Checks outstanding in excess of cash balances	$	-	$	-	$	29.4	$	29.4
Long-term debt	$	1,866.6	$	1,967.2	$	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. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment.  Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives.  A reconciliation of the Company's asset retirement obligations is presented in Note 4 - Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring, non-financial measurements.  The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property.  During the first half of 2012 and through the period ended December 31, 2011, the Company recorded impairments on certain oil & gas property resulting in a write down of the associated carrying value to fair value. The fair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flow models.  Given the unobservable nature of the inputs, proved oil and gas property impairments would be considered Level 3 within the fair value hierarchy.

The following table summarizes the non-financial assets and liabilities measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition and their associated impairment:

	Level 3 Fair Value		Impairment		Level 3 Fair Value		Impairment
	June 30, 2012				December 31, 2011
	(in millions)
Proved Property	$	5,058.6	$	49.3	$	4,833.2	$	195.5

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 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.

The following is a reconciliation of the changes in the asset retirement obligation from January 1, 2012 and 2011 to June 30, 2012 and 2011, respectively:

	Asset Retirement Obligations
	2012			2011
	(in millions)
ARO liability at January 1,	$	163.9		$	148.3
Accretion		5.1			4.8
Liabilities incurred		3.6			2.9
Liabilities settled		(0.4	)		(0.3	)
ARO liability at June 30,	$	172.2		$	155.7

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligations [Abstract]

Asset retirement obligations roll forward

The following is a reconciliation of the changes in the asset retirement obligation from January 1, 2012 and 2011 to June 30, 2012 and 2011, respectively:

	Asset Retirement Obligations
	2012			2011
	(in millions)
ARO liability at January 1,	$	163.9		$	148.3
Accretion		5.1			4.8
Liabilities incurred		3.6			2.9
Liabilities settled		(0.4	)		(0.3	)
ARO liability at June 30,	$	172.2		$	155.7

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Operations by Line of Business

6 Months Ended

Jun. 30, 2012

Operations by Line of Business [Abstract]

Operations by Line of Business

Note 12 - 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:

	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
For the three months ended June 30, 2012	(in millions)
Revenues (1)
From unaffiliated customers	$	335.5		$	83.4		$	80.4		$	-		$	499.3
From affiliated customers		-			30.2			118.2			(148.4	)		-
Total Revenues		335.5			113.6			198.6			(148.4	)		499.3
Operating expenses
Purchased gas, oil and NGL expense		40.6			4.1			197.4			(117.2	)		124.9
Lease operating expense		41.4			-			-			(0.9	)		40.5
Natural gas, oil and NGL transportation    and other handling costs		57.2			12.0			-			(28.5	)		40.7
Gathering, processing and other		-			20.4			0.5			(0.3	)		20.6
General and administrative		29.2			9.0			0.1			(1.5	)		36.8
Production and property taxes		18.2			1.2			-			-			19.4
Depreciation, depletion and amortization		197.2			16.1			0.8			-			214.1
Other operating expenses		57.8			-			-			-			57.8
Total operating expenses		441.6			62.8			198.8			(148.4	)		554.8
Operating (loss) income (2)		(106.1	)		50.8			(0.2	)		-			(55.5	)
Realized and unrealized gains (losses) on    derivative contracts		81.8			4.8			(4.3	)		-			82.3
Interest and other income		0.7			0.1			26.8			(26.7	)		0.9
Income from unconsolidated affiliates		0.1			1.3			-			-			1.4
Loss on early extinguishment of debt		-			-			(0.6	)		-			(0.6	)
Interest expense		(23.4	)		(3.6	)		(27.9	)		26.7			(28.2	)
(Loss) income before income taxes		(46.9	)		53.4			(6.2	)		-			0.3
Income taxes		16.6			(19.2	)		2.5			-			(0.1	)
Net (loss) income		(30.3	)		34.2			(3.7	)		-			0.2
Net income attributable to    noncontrolling interest		-			(0.9	)		-			-			(0.9	)
Net (loss) income attributable to QEP (3)	$	(30.3	)	$	33.3		$	(3.7	)	$	-		$	(0.7	)

⁽¹⁾ The impact of QEP's settled derivative contracts, for the three months ended June 30, 2012, are reflected below operating (loss) income.

⁽²⁾ Operating (loss) income for the three months ended June 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the three months ended June 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.

⁽³⁾ Net income (loss) attributable to QEP for the three months ended June 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
For the three months ended June 30, 2011	(in millions)
Revenues (1)
From unaffiliated customers	$	555.5		$	102.0		$	150.6		$	-		$	808.1
From affiliated customers		-			20.2			145.2			(165.4	)		-
Total Revenues		555.5			122.2			295.8			(165.4	)		808.1
Operating expenses
Purchased gas, oil and NGL expense		154.7			-			292.5			(143.3	)		303.9
Lease operating expense		35.0			-			-			(0.7	)		34.3
Natural gas, oil and NGL transportation    and other handling costs		42.3			1.2			-			(19.5	)		24.0
Gathering, processing and other		-			26.9			0.4			(0.1	)		27.2
General and administrative		22.9			6.8			0.8			(1.8	)		28.7
Production and property taxes		25.4			1.6			0.1			-			27.1
Depreciation, depletion and amortization		172.5			13.5			0.6			-			186.6
Other operating expenses		7.6			-			-			-			7.6
Total operating expenses		460.4			50.0			294.4			(165.4	)		639.4
Net gain (loss) from asset sales		0.2			0.1			(0.1	)		-			0.2
Operating income (2)		95.3			72.3			1.3			-			168.9
Interest and other (loss) income		(0.5	)		-			24.8			(24.7	)		(0.4	)
Income from unconsolidated affiliates		0.1			1.2			-			-			1.3
Interest expense		(20.4	)		(3.1	)		(23.3	)		24.7			(22.1	)
Income before income taxes		74.5			70.4			2.8			-			147.7
Income taxes		(27.7	)		(25.5	)		(1.0	)		-			(54.2	)
Net income		46.8			44.9			1.8			-			93.5
Net income attributable to    noncontrolling interest		-			(0.7	)		-			-			(0.7	)
Net income attributable to QEP (3)	$	46.8		$	44.2		$	1.8		$	-		$	92.8

⁽¹⁾ Revenues for the three months ended June 30, 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 June 30, 2011, reflect the impact of QEP's settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the three months ended June 30, 2011.

⁽²⁾ Under hedge accounting, gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three months ended June 30, 2011.

⁽³⁾ Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three months ended June 30, 2011.

	QEP Energy			QEP Field Services			QEP Marketing  & Other			Eliminations			QEP Consolidated
For the six months ended June 30, 2012	(in millions)
Revenues (1)
From unaffiliated customers	$	732.3		$	177.0		$	193.2		$	-		$	1,102.5
From affiliated customers		-			56.3			250.5			(306.8	)		-
Total Revenues		732.3			233.3			443.7			(306.8	)		1,102.5
Operating expenses
Purchased gas, oil and NGL expense		113.1			4.1			445.0			(248.9	)		313.3
Lease operating expense		82.2			-			-			(1.6	)		80.6
Natural gas, oil and NGL transportation    and other handling costs		107.6			20.8			-			(53.2	)		75.2
Gathering, processing and other		-			43.8			0.7			(0.2	)		44.3
General and administrative		62.1			13.5			0.1			(2.9	)		72.8
Production and property taxes		41.1			2.9			0.1			-			44.1
Depreciation, depletion and amortization		380.3			31.4			1.6			-			413.3
Other operating expenses		66.4			-			-			-			66.4
Total operating expenses		852.8			116.5			447.5			(306.8	)		1,110.0
Net gain from asset sales		1.5			-			-			-			1.5
Operating (loss) income (2)		(119.0	)		116.8			(3.8	)		-			(6.0	)
Realized and unrealized gains on derivative    contracts		289.0			8.9			0.7			-			298.6
Interest and other income		2.4			0.1			52.7			(52.6	)		2.6
Income from unconsolidated affiliates		0.1			3.2			-			-			3.3
Loss on early extinguishment of debt		-			-			(0.6	)		-			(0.6	)
Interest expense		(47.0	)		(5.9	)		(52.6	)		52.6			(52.9	)
Income (loss) before income taxes		125.5			123.1			(3.6	)		-			245.0
Income taxes		(47.7	)		(42.7	)		1.6			-			(88.8	)
Net income (loss)		77.8			80.4			(2.0	)		-			156.2
Net income attributable to    noncontrolling interest		-			(1.7	)		-			-			(1.7	)
Net income (loss) attributable to QEP (3)	$	77.8		$	78.7		$	(2.0	)	$	-		$	154.5

⁽¹⁾ The impact of QEP's settled derivative contracts, for the six months ended June 30, 2012, are reflected below operating (loss) income.

⁽²⁾ Operating (loss) income for the six months ended June 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the six months ended June 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.

⁽³⁾ Net (loss) income attributable to QEP for the six months ended June 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
For the six months ended June 30, 2011	(in millions)
Revenues (1)
From unaffiliated customers	$	951.7		$	175.3		$	299.0		$	-		$	1,426.0
From affiliated customers		-			43.5			278.3			(321.8	)		-
Total Revenues		951.7			218.8			577.3			(321.8	)		1,426.0
Operating expenses
Purchased gas, oil and NGL expense		154.7			-			570.4			(274.5	)		450.6
Lease operating expense		68.4			-			-			(1.3	)		67.1
Natural gas, oil and NGL transportation    and other handling costs		85.8			2.1			-			(42.2	)		45.7
Gathering, processing and other		-			51.7			0.7			-			52.4
General and administrative		46.8			15.8			1.6			(3.8	)		60.4
Production and property taxes		47.6			3.0			0.2			-			50.8
Depreciation, depletion and amortization		349.6			26.7			1.1			-			377.4
Other operating expenses		15.8			-			-			-			15.8
Total operating expenses		768.7			99.3			574.0			(321.8	)		1,120.2
Net gain (loss) from asset sales		0.2			0.1			(0.1	)		-			0.2
Operating income (2)		183.2			119.6			3.2			-			306.0
Interest and other income		0.2			-			49.2			(49.2	)		0.2
Income from unconsolidated affiliates		0.1			2.1			-			-			2.2
Interest expense		(40.3	)		(6.6	)		(46.5	)		49.2			(44.2	)
Income before income taxes		143.2			115.1			5.9			-			264.2
Income taxes		(53.3	)		(41.6	)		(2.0	)		-			(96.9	)
Net income		89.9			73.5			3.9			-			167.3
Net income attributable to    noncontrolling interest		-			(1.3	)		-			-			(1.3	)
Net income attributable to QEP (3)	$	89.9		$	72.2		$	3.9		$	-		$	166.0

⁽¹⁾ Revenues for the six months ended June 30, 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 six months ended June 30, 2011, reflect the impact of QEP's settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the six months ended June 30, 2011.

⁽²⁾ Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three and six months ended June 30, 2011.

⁽³⁾ Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three and six months ended June 30, 2011.

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Debt

6 Months Ended

Jun. 30, 2012

Debt [Abstract]

Debt

Note 8 - Debt

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

	June 30,			December 31,
	2012			2011
	(in millions)
Revolving Credit Facility due 2016	$	-		$	606.5
Term Loan due 2017		300.0			-
6.05% Senior Notes due 2016		176.8			176.8
6.80% Senior Notes due 2018		134.0			138.6
6.80% Senior Notes due 2020		136.0			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		1,871.8			1,684.9
Less unamortized discount		(5.2	)		(5.5	)
Total long-term debt outstanding	$	1,866.6		$	1,679.4

Of the total debt outstanding on June 30, 2012, only the revolving credit facility, due August 25, 2016, athe Term Loan due April 18, 2017, and the 6.05% Senior Notes, due September 1, 2016, will mature within the next five years.

Credit Arrangements

QEP's revolving credit facility agreement (Credit Facility), which matures in August 2016, provides for loan commitments of $1.5 billion from a group of financial institutions. The Credit Facility provides for borrowing at short-term interest rates and contains customary covenants and restrictions. The revolving credit agreement also contains an accordion provision that would allow for the amount of the facility to be increased to $2.0 billion and for the maturity to be extended for up to two additional one-year periods.

During the first half of 2012, QEP's weighted-average interest rate on borrowings from its Credit Facility was 2.05%. At June 30, 2012, and December 31, 2011, QEP was in compliance with the covenants under the credit agreement. At June 30, 2012, there were no borrowings outstanding and QEP had $4.1 million in letters of credit outstanding under the Credit Facility.

Term Loan

During the second quarter of 2012, QEP entered into a $300.0 million senior, unsecured term loan agreement (Term Loan) with a group of financial institutions. The Term Loan 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 Credit Facility. The Term Loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. The proceeds from the Term Loan were used to pay down the Credit Facility and for general corporate purposes. During the second quarter of 2012, QEP's weighted-average interest rate on borrowings from the Term Loan was 2.02%. At June 30, 2012, QEP was in compliance with the covenants under the credit agreement.

Senior Notes

During the first quarter of 2012, QEP completed a public offering for $500.0 million in aggregate principal amount of 5.375% senior notes due in October 2022 (2022 Senior Notes). The 2022 Senior Notes were issued at face value. Interest on the 2022 Senior Notes will be paid semi-annually, in April and October of each respective year. The net proceeds of $493.1 million were used to repay indebtedness under QEP's Credit Facility. The finance costs incurred of $6.9 million were deferred and are being amortized over the life of the notes. The amortization of all of the Company's deferred finance costs is included in "Interest expense" on the Condensed Consolidated Statement of Income.

During the second quarter of 2012, QEP repurchased $6.7 million of its senior notes outstanding. QEP recognized a loss on extinguishment of debt from those repurchases and associated write-offs of debt issuance costs, discounts and premiums paid of $0.6 million. At June 30, 2012, the Company had $1,571.8 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.

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Derivative Contracts

6 Months Ended

Jun. 30, 2012

Derivative Contracts [Abstract]

Derivative Contracts

Note 6 - Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity 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 gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production from proved reserves. In addition, QEP may enter into commodity derivative contracts on a portion of its extracted NGL volumes in its midstream business and may enter into commodity derivative contracts on natural gas sales and purchases for marketing transactions. QEP does not enter into commodity derivative instruments for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps 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 commodity 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 commodity derivative transactions that do not have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. Commodity derivative contract counterparties are normally financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and avoids concentration of credit exposure by transacting with multiple counterparties.

Through December 31, 2011, QEP designated the majority of its natural gas, oil and NGL derivative contracts as cash flow hedges, whose unrealized fair value gains and losses were recorded to AOCI. Effective January 1, 2012, QEP elected to de-designate all of its natural gas, crude oil and NGL derivative contracts that were previously designated as cash flow hedges and discontinue hedge accounting prospectively. As a result of discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were frozen in AOCI as of the de-designation date and are being reclassified into the Consolidated Statement of Income as the transactions settle and affect earnings. At June 30, 2012, AOCI consisted of $249.8 million ($156.9 million after tax) of unrealized gains. QEP expects to reclassify into earnings from AOCI the frozen value related to de-designated natural gas, oil and NGL hedges over the remainder of 2012 and 2013. Currently, QEP recognizes all gains and losses from changes in the fair value of natural gas, oil and NGL derivative contracts immediately in earnings rather than deferring any such amounts in AOCI. All commodity derivative instruments are recorded on the Consolidated Balance Sheets as either assets or liabilities measured at their fair values and  all realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012, are presented in the Consolidated Statement of Income in "Realized and unrealized gains on derivative contracts" below operating income.

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

QEP 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						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
QEP Energy
Natural gas derivative volumes as a percent of QEP Energy natural gas production
Fixed price swaps		67	%		46	%		63	%		44	%
Costless collars		0	%		12	%		0	%		12	%
Oil derivative volumes as a percent of QEP Energy oil production
Fixed price swaps		35	%		3	%		36	%		2	%
Costless collars		28	%		31	%		22	%		33	%
NGL derivative volumes as a percent of QEP Energy NGL production
Fixed price swaps		18	%		0	%		17	%		0	%
QEP Field Services
Ethane derivative volumes as a percent of ethane volumes - QEP Field Services
Fixed price swaps		15	%		0	%		27	%		0	%
Propane derivative volumes as a percent of propane volumes - QEP Field Services
Fixed price swaps		59	%		0	%		76	%		0	%

QEP Energy Derivative Contracts

The following table sets forth QEP Energy's volumes and average prices for its commodity derivative contracts as of June 30, 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		39.9	$	4.66
2012	Swap	IFPEPL (1)		4.9	$	4.14
2012	Swap	IFNPCR (2)		45.4	$	4.61
2012	Swap	IFCNPTE (3)		5.5	$	2.66
2013	Swap	NYMEX		29.2	$	3.68
2013	Swap	IFNPCR (2)		65.7	$	5.66
Oil sales			(Bbls)
2012	Swap	NYMEX WTI		0.9	$	97.03
2012	Collar	NYMEX WTI		0.7			$	87.50	$	115.36
2013	Swap	NYMEX WTI		0.9	$	104.12
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		7.7	$	0.64
2012	Swap	Mt. Belvieu Propane		11.6	$	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 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 June 30, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swap price per gallon
			(in millions)
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane		7.7	$	0.64
2012	Swap	Mt. Belvieu Propane		3.9	$	1.28

QEP Marketing Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on natural gas volumes placed into storage and for marketing transactions in which QEP Marketing is required to deliver gas volumes at a fixed price. The following table sets forth QEP Marketing's volumes and swap prices for its commodity derivative contracts as of June 30, 2012:

Year	Type of Contract	Index	Total Volumes		Average Swaps price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2012	Swap	IFNPCR (1)		1.8	$	4.06
2013	Swap	IFNPCR (1)		1.2	$	4.57
Natural gas purchases			(MMBtu)
2012	Swap	IFNPCR (1)		0.7	$	2.97
2013	Swap	IFNPCR (1)		0.1	$	2.59

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

QEP Resources Derivative Contracts

In the second quarter of 2012, QEP Resources entered into interest rate swap agreements to effectively lock in a fixed interest rate on debt outstanding under its Term Loan.

The following table sets forth QEP Resources' notional amounts and interest rates for its interest rate swaps outstanding as of June 30, 2012:

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

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

		Gross asset derivative instruments fair value					Gross liability derivative instruments fair value
	Balance Sheet line item	June 30, 2012		December 31, 2011		Balance Sheet line item	June 30, 2012		December 31, 2011
		(in millions)					(in millions)
Current:
Commodity	Fair value of derivative contracts	$	272.2	$	284.1	Fair value of derivative contracts	$	4.0	$	11.7
Interest rate swaps	Fair value of derivative contracts		-		-	Fair value of derivative contracts		2.3		-
Long-term:
Commodity	Fair value of derivative contracts		77.5		123.5	Fair value of derivative contracts		1.7		-
Interest rate swaps	Fair value of derivative contracts		-		-	Fair value of derivative contracts		2.0		-
Total derivative    instruments		$	349.7	$	407.6		$	10.0	$	11.7

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

		Three Months Ended						Six Months Ended
Derivative instruments not designated as	Location of gain (loss)	June 30,						June 30,
cash flow hedges	recognized in earnings	2012			2011			2012			2011
		(in millions)
Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		$	111.9		$	(27.6	)	$	197.6		$	(58.8	)
Oil derivative contracts			2.2			-			(0.5	)		-
NGL derivative contracts			2.7			-			3.1			-
QEP Field Services
NGL derivative contracts			3.3			-			4.4			-
QEP Marketing
Natural gas derivative contracts			0.6			-			4.1			-
Total realized gain (loss) on commodity derivative contracts			120.7			(27.6	)		208.7			(58.8	)
Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts			(78.4	)		27.6			53.9			58.8
Oil derivative contracts			38.6			-			27.1			-
NGL derivative contracts			4.9			-			7.8			-
QEP Field Services
NGL derivative contracts			1.5			-			4.5			-
QEP Marketing
Natural gas derivative contracts			(0.7	)		-			0.9			-
Total unrealized (loss) gain on    commodity derivative contracts			(34.1	)		27.6			94.2			58.8
Total realized and unrealized    gain on commodity derivative    contracts	Realized and unrealized gains on derivative contracts	$	86.6		$	-		$	302.9		$	-
Unrealized gain (loss) on interest rate swaps
Unrealized loss on interest rate swaps	Realized and unrealized gains on derivative contracts	$	(4.3	)	$	-		$	(4.3	)	$	-

			Three Months Ended				Six Months Ended
	Location of gain (loss)		June 30,				June 30,
Derivative instruments classified as cash flow hedges	recognized in earnings		2012		2011		2012		2011
Commodity derivatives			(in millions)
Gain on derivative instruments for the effective    portion of hedge recognized in AOCI	Accumulated other    comprehensive income	$	-	$	61.3	$	-	$	61.5
Gain reclassified from AOCI into income for    effective portion of hedge	Natural gas sales		-		64.4		-		137.5
Gain reclassified from AOCI into income for    effective portion of hedge	Oil sales		-		0.1		-		0.1
Gain  reclassified from AOCI into income for    effective portion of hedge	Marketing purchases		-		0.5		-		3.9
Gain recognized in income for the ineffective    portion of hedges	Interest and other income		-		0.3		-		0.1

The Company estimates that derivative contracts that were outstanding and frozen in AOCI at June 30, 2012, having a frozen fair value of $120.0 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

6 Months Ended

Jun. 30, 2012

Restructuring Costs [Abstract]

Restructuring Costs

Note 7 - Restructuring Costs

During the first quarter 2012, QEP announced the closure of its Oklahoma City office and the subsequent consolidation of its Southern Region operations into a single regional office located in Tulsa. The creation of one office for QEP's Southern Region is intended to increase regional efficiency, team-based collaboration and organizational productivity, over the long-term. As part of this restructuring plan and office closure, QEP 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. In addition, QEP has incurred costs from other restructuring and reorganization activities in an effort to centralize and gain efficiencies. 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 $6.0 million, consisting of $2.1 million in one-time termination benefits, $3.4 million in retention and relocation expenses for certain employees relocating to the Tulsa office, and $0.5 million for the termination of the QEP's Oklahoma City office space lease. During the three and six months ended June 30, 2012, a total of $2.3 million and $5.0 million, respectively, of restructuring costs were incurred and recorded in "General and administrative" expense on the Condensed Consolidated Statement of Income, of which $0.8 million and $1.9 million, respectively, 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 Liability
	(in millions)
Balance at December 31, 2011	$	-
Costs incurred and charged to expense		5.0
Costs paid or otherwise settled		(4.6	)
Balance at June 30, 2012	$	0.4

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Contingencies

6 Months Ended

Jun. 30, 2012

Contingencies [Abstract]

Contingencies

Note 9 - 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. QEP's estimates are based on information known about the claims, experience in contesting, litigating and settling similar claims. Although actual amounts could differ from management's estimates, QEP believes that the exposure to potential losses, in excess of the amount which has been accrued, from its probable contingencies 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. As previously disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2011, and its Quarterly Report on Form 10-Q for the three months ended March 31, 2012, 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.On May 16, 2012, QEP Field Services settled this matter through the parties' execution of a consent decree which was subsequently approved by court order. The civil penalty payable to the government is $3.7 million. A contribution of $0.4 million will be payable to a non-profit corporation or trust to be created by the Ute Indian Tribe of the Uintah and Ouray Reservation for the implementation of environmental programs for the benefit of tribal members. The settlement also requires the Company to reduce its emissions by removing certain equipment, installing additional pollution controls and replacing the natural gas powered instrument control systems with compressed air control systems, all of which will require capital expenditures of approximately $2.4 million, of which $0.5 million had been spent at June 30, 2012. QEP Field Services will have continuing operational compliance obligations under the consent decree at the affected facilities.

Litigation

Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for Oklahoma. 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, including the early stage of discovery and the number of plaintiffs, it is difficult to predict all reasonably possible outcomes.

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services' former affiliate Questar Gas Company (QGC) filed this complaint in state court in Utah on May 1, 2012 asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, for an accounting and declaratory judgment related to a 1993 gathering agreement (1993 Agreement) entered when the parties were affiliates. Under the 1993 Agreement, QEP Field Services provides gathering services for producing properties developed by former affiliate Wexpro Company on behalf of QGC's utility ratepayers. The core dispute pertains to the annual recalculation of the gathering rate which is based on a cost of service concept expressed in the 1993 Agreement and in a 1998 amendment. The annual gathering rate has been calculated in the same manner under the contract since it was amended in 1998, without any prior objection or challenge by QGC. Specific monetary damages are not asserted. Because of the complexities and uncertainties of this legal dispute in its early stages, it is difficult to predict all reasonably possible outcomes. Also, on May 1, 2012, QEP Field Services Company filed a legal action against Questar Gas entitled QEP Field Services Company v. Questar Gas Company, in the Second District Court in Denver County, Colorado, seeking declaratory judgment relating to its gathering service and charges under the same agreement. While QEP Field Services intends to defend itself against QGC's claims and vigorously pursue its legal rights, the claims involve complex legal issues and uncertainties that make it difficult to predict the outcome of the cases and therefore management cannot determine at this time whether this litigation may have an adverse material effect on its financial position, results of operations or cash flows.

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified			3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended																				6 Months Ended										6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 Unproved Properties [Member]	Jun. 30, 2012 Unproved Properties [Member]	Jun. 30, 2012 Proved Properties [Member]	Jun. 30, 2012 Proved Properties [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Commodity derivative [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Commodity derivative [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Interest Rate Swap [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Carrying Amount [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Carrying Amount [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 1 [Member] Commodity derivative [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 1 [Member] Commodity derivative [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 1 [Member] Interest Rate Swap [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 1 [Member] Fair Value [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 1 [Member] Fair Value [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 2 [Member] Commodity derivative [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 2 [Member] Commodity derivative [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 2 [Member] Interest Rate Swap [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 3 [Member] Commodity derivative [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 3 [Member] Commodity derivative [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 3 [Member] Interest Rate Swap [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member] Commodity derivative [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member] Commodity derivative [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member] Interest Rate Swap [Member]	Jun. 30, 2012 Fair Value, Measurements, Nonrecurring [Member] Proved Properties [Member]	Dec. 31, 2011 Fair Value, Measurements, Nonrecurring [Member] Proved Properties [Member]	Jun. 30, 2012 Fair Value, Measurements, Nonrecurring [Member] Level 3 [Member] Proved Properties [Member]	Dec. 31, 2011 Fair Value, Measurements, Nonrecurring [Member] Level 3 [Member] Proved Properties [Member]
Financial Assets
Commodity derivative instruments - short-term									$ 268.2	$ 273.7						$ 0	$ 0						$ 272.2	$ 284.1				$ 0	$ 0				$ (4.0)	$ (10.4)
Commodity derivative instruments - long-term									76.2	123.5						0	0						77.5	123.5				0	0				(1.3)	0
Total financial assets							344.4	397.2						0	0						349.7	407.6				0	0				(5.3)	(10.4)
Cash and Cash Equivalents, Fair Value Disclosure												146.4	0						146.4	0
Financial liabilities
Commodity derivative instruments - short-term									0	1.3	2.3					0	0	0					4.0	11.7	2.3				0				(4.0)	(10.4)	0
Commodity derivative instruments - long-term	2.4	0							0.4	0	2.0					0	0	0					1.7	0	2.0				0	0			(1.3)	0
Total financial liabilities							4.7	1.3						0	0						10.0	11.7				0	0				(5.3)	(10.4)
Checks outstanding in excess of cash balances												0	29.4						0	29.4
Long-term debt												1,866.6	1,679.4						1,967.2	1,754.9
Level 3 Unobservable input reconciliation [Roll Forward]
Beginning Balance	0	0
Realized gains and losses																										0.6
Unrealized gains and losses																										3.8
Settlements																										(0.6)
Transfers out of Level 3																										(3.8)
Ending Balance	0	0
Proved properties																																						5,058.6	4,833.2
Impairment			$ 6.1	$ 12.1	$ 48.9	$ 49.3																														$ 49.3	$ 195.5

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Basis of Presentation of Interim Consolidated Financial Statements (Tables)

6 Months Ended

Jun. 30, 2012

Basis of Presentation of Interim Consolidated Financial Statements [Abstract]

Impact of change in 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, were recast on the Condensed Consolidated Statement of Income from "Revenues" to "Natural gas, oil and NGL transportation and other handling costs" for prior periods presented. The impact of this revision was immaterial to the accompanying financial statements and had no effect on income from continuing operations, net income, or earnings per share. The following table details the impact for the three and six months ended June 30, 2011, on the Condensed Consolidated Statement of Income.

	Three Months Ended June 30, 2011							Six Months Ended June 30, 2011
	As reported (1)		As revised		Change			As reported (1)		As revised		Change
	(in millions)							(in millions)
REVENUES
Natural gas sales	$	258.1	$	298.7	$	40.6		$	529.1	$	611.3	$	82.2
Oil sales		80.0		80.7		0.7			142.3		143.7		1.4
NGL sales		61.6		63.8		2.2			107.4		111.7		4.3
Gathering, processing and other		78.4		58.9		(19.5	)		147.7		105.5		(42.2	)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		-		24.0		24.0			-		45.7		45.7

(1) The "As reported" numbers reflect QEP Field Services NGL sales of $45.1 million and $73.7 million for the three and six months ended June 30, 2011, which were reclassified from "Gathering, processing and other" into "NGL sales" for consistency with current period presentation. In its second quarter 2011 Form 10-Q, QEP reported "NGL sales" of $16.5 million and $33.7 million, and "Gathering, processing and other" of $123.5 million, and $221.4 million for the three and six months ended June 30, 2011, respectively. The QEP Field Services NGL reclassification is all within "Revenues" and has no effect on income from continuing operations, net income or earnings per share.

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Restructuring Costs (Tables)

6 Months Ended

Jun. 30, 2012

Restructuring Costs [Abstract]

Reconciliation of QEP Energy's restructuring cost

During the first quarter 2012, QEP announced the closure of its Oklahoma City office and the subsequent consolidation of its Southern Region operations into a single regional office located in Tulsa. The creation of one office for QEP's Southern Region is intended to increase regional efficiency, team-based collaboration and organizational productivity, over the long-term. As part of this restructuring plan and office closure, QEP 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. In addition, QEP has incurred costs from other restructuring and reorganization activities in an effort to centralize and gain efficiencies. 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 $6.0 million, consisting of $2.1 million in one-time termination benefits, $3.4 million in retention and relocation expenses for certain employees relocating to the Tulsa office, and $0.5 million for the termination of the QEP's Oklahoma City office space lease. During the three and six months ended June 30, 2012, a total of $2.3 million and $5.0 million, respectively, of restructuring costs were incurred and recorded in "General and administrative" expense on the Condensed Consolidated Statement of Income, of which $0.8 million and $1.9 million, respectively, 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 Liability
	(in millions)
Balance at December 31, 2011	$	-
Costs incurred and charged to expense		5.0
Costs paid or otherwise settled		(4.6	)
Balance at June 30, 2012	$	0.4

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Operations by Line of Business (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Revenues
Total Revenues	$ 499.3	$ 808.1	[1]	$ 1,102.5	[2]	$ 1,426.0	[3]
Operating expenses
Purchased gas, oil and NGL expense	124.9	303.9		313.3		450.6
Lease operating expense	40.5	34.3		80.6		67.1
Natural gas, oil and NGL transportation and other handling costs	40.7	24.0		75.2		45.7
Gathering, processing and other	20.6	27.2		44.3		52.4
General and administrative	36.8	28.7		72.8		60.4
Production and property taxes	19.4	27.1		44.1		50.8
Depreciation, depletion and amortization	214.1	186.6		413.3		377.4
Other operating expenses	57.8	7.6		66.4		15.8
Total Operating Expenses	554.8	639.4		1,110.0		1,120.2
Net loss from asset sales	0	0.2		1.5		0.2
Operating (loss) income	(55.5)	168.9	[4]	(6.0)	[5]	306.0	[6]
Realized and unrealized gains (losses) on derivative contracts	82.3	0		298.6		0
Interest and other income	0.9	(0.4)		2.6		0.2
Income from unconsolidated affiliates	1.4	1.3		3.3		2.2
Loss from early extinguishment of debt	(0.6)	0		(0.6)		0
Interest expense	(28.2)	(22.1)		(52.9)		(44.2)
Income (loss) before income taxes	0.3	147.7		245.0		264.2
Income taxes	(0.1)	(54.2)		(88.8)		(96.9)
Net income	0.2	93.5		156.2		167.3
Net income attributable to noncontrolling interest	(0.9)	(0.7)		(1.7)		(1.3)
Net income (loss) attributable to QEP	(0.7)	92.8	[7]	154.5	[8]	166.0	[9]
Unaffiliated customers [Member]
Revenues
Total Revenues	499.3	808.1	[1]	1,102.5	[2]	1,426.0	[3]
Affiliated customers [Member]
Revenues
Total Revenues	0	0	[1]	0	[2]	0	[3]
QEP Energy [Member]
Revenues
Total Revenues	335.5	555.5	[1]	732.3	[2]	951.7	[3]
Operating expenses
Purchased gas, oil and NGL expense	40.6	154.7		113.1		154.7
Lease operating expense	41.4	35.0		82.2		68.4
Natural gas, oil and NGL transportation and other handling costs	57.2	42.3		107.6		85.8
Gathering, processing and other	0	0		0		0
General and administrative	29.2	22.9		62.1		46.8
Production and property taxes	18.2	25.4		41.1		47.6
Depreciation, depletion and amortization	197.2	172.5		380.3		349.6
Other operating expenses	57.8	7.6		66.4		15.8
Total Operating Expenses	441.6	460.4		852.8		768.7
Net loss from asset sales		0.2		1.5		0.2
Operating (loss) income	(106.1)	95.3	[4]	(119.0)	[5]	183.2	[6]
Realized and unrealized gains (losses) on derivative contracts	81.8			289.0
Interest and other income	0.7	(0.5)		2.4		0.2
Income from unconsolidated affiliates	0.1	0.1		0.1		0.1
Loss from early extinguishment of debt	0			0
Interest expense	(23.4)	(20.4)		(47.0)		(40.3)
Income (loss) before income taxes	(46.9)	74.5		125.5		143.2
Income taxes	16.6	(27.7)		(47.7)		(53.3)
Net income	(30.3)	46.8		77.8		89.9
Net income attributable to noncontrolling interest	0	0		0		0
Net income (loss) attributable to QEP	(30.3)	46.8	[7]	77.8	[8]	89.9	[9]
QEP Energy [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	335.5	555.5	[1]	732.3	[2]	951.7	[3]
QEP Energy [Member] | Affiliated customers [Member]
Revenues
Total Revenues	0	0	[1]	0	[2]	0	[3]
QEP Field Services [Member]
Revenues
Total Revenues	113.6	122.2	[1]	233.3	[2]	218.8	[3]
Operating expenses
Purchased gas, oil and NGL expense	4.1	0		4.1		0
Lease operating expense	0	0		0		0
Natural gas, oil and NGL transportation and other handling costs	12.0	1.2		20.8		2.1
Gathering, processing and other	20.4	26.9		43.8		51.7
General and administrative	9.0	6.8		13.5		15.8
Production and property taxes	1.2	1.6		2.9		3.0
Depreciation, depletion and amortization	16.1	13.5		31.4		26.7
Other operating expenses	0	0		0		0
Total Operating Expenses	62.8	50.0		116.5		99.3
Net loss from asset sales		0.1		0		0.1
Operating (loss) income	50.8	72.3	[4]	116.8	[5]	119.6	[6]
Realized and unrealized gains (losses) on derivative contracts	4.8			8.9
Interest and other income	0.1	0		0.1		0
Income from unconsolidated affiliates	1.3	1.2		3.2		2.1
Loss from early extinguishment of debt	0			0
Interest expense	(3.6)	(3.1)		(5.9)		(6.6)
Income (loss) before income taxes	53.4	70.4		123.1		115.1
Income taxes	(19.2)	(25.5)		(42.7)		(41.6)
Net income	34.2	44.9		80.4		73.5
Net income attributable to noncontrolling interest	(0.9)	(0.7)		(1.7)		(1.3)
Net income (loss) attributable to QEP	33.3	44.2	[7]	78.7	[8]	72.2	[9]
QEP Field Services [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	83.4	102.0	[1]	177.0	[2]	175.3	[3]
QEP Field Services [Member] | Affiliated customers [Member]
Revenues
Total Revenues	30.2	20.2	[1]	56.3	[2]	43.5	[3]
QEP Marketing and Other [Member]
Revenues
Total Revenues	198.6	295.8	[1]	443.7	[2]	577.3	[3]
Operating expenses
Purchased gas, oil and NGL expense	197.4	292.5		445.0		570.4
Lease operating expense	0	0		0		0
Natural gas, oil and NGL transportation and other handling costs	0	0		0		0
Gathering, processing and other	0.5	0.4		0.7		0.7
General and administrative	0.1	0.8		0.1		1.6
Production and property taxes	0	0.1		0.1		0.2
Depreciation, depletion and amortization	0.8	0.6		1.6		1.1
Other operating expenses	0	0		0		0
Total Operating Expenses	198.8	294.4		447.5		574.0
Net loss from asset sales		(0.1)		0		(0.1)
Operating (loss) income	(0.2)	1.3	[4]	(3.8)	[5]	3.2	[6]
Realized and unrealized gains (losses) on derivative contracts	(4.3)			0.7
Interest and other income	26.8	24.8		52.7		49.2
Income from unconsolidated affiliates	0	0		0		0
Loss from early extinguishment of debt	(0.6)			(0.6)
Interest expense	(27.9)	(23.3)		(52.6)		(46.5)
Income (loss) before income taxes	(6.2)	2.8		(3.6)		5.9
Income taxes	2.5	(1.0)		1.6		(2.0)
Net income	(3.7)	1.8		(2.0)		3.9
Net income attributable to noncontrolling interest	0	0		0		0
Net income (loss) attributable to QEP	(3.7)	1.8	[7]	(2.0)	[8]	3.9	[9]
QEP Marketing and Other [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	80.4	150.6	[1]	193.2	[2]	299.0	[3]
QEP Marketing and Other [Member] | Affiliated customers [Member]
Revenues
Total Revenues	118.2	145.2	[1]	250.5	[2]	278.3	[3]
Elimination [Member]
Revenues
Total Revenues	(148.4)	(165.4)	[1]	(306.8)	[2]	(321.8)	[3]
Operating expenses
Purchased gas, oil and NGL expense	(117.2)	(143.3)		(248.9)		(274.5)
Lease operating expense	(0.9)	(0.7)		(1.6)		(1.3)
Natural gas, oil and NGL transportation and other handling costs	(28.5)	(19.5)		(53.2)		(42.2)
Gathering, processing and other	(0.3)	(0.1)		(0.2)		0
General and administrative	(1.5)	(1.8)		(2.9)		(3.8)
Production and property taxes	0	0		0		0
Depreciation, depletion and amortization	0	0		0		0
Other operating expenses	0	0		0		0
Total Operating Expenses	(148.4)	(165.4)		(306.8)		(321.8)
Net loss from asset sales		0		0		0
Operating (loss) income	0	0	[4]	0	[5]	0	[6]
Realized and unrealized gains (losses) on derivative contracts	0			0
Interest and other income	(26.7)	(24.7)		(52.6)		(49.2)
Income from unconsolidated affiliates	0	0		0		0
Loss from early extinguishment of debt	0			0
Interest expense	26.7	24.7		52.6		49.2
Income (loss) before income taxes	0	0		0		0
Income taxes	0	0		0		0
Net income	0	0		0		0
Net income attributable to noncontrolling interest	0	0		0		0
Net income (loss) attributable to QEP	0	0	[7]	0	[8]	0	[9]
Elimination [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	0	0	[1]	0	[2]	0	[3]
Elimination [Member] | Affiliated customers [Member]
Revenues
Total Revenues	$ (148.4)	$ (165.4)	[1]	$ (306.8)	[2]	$ (321.8)	[3]

[1] Revenues for the three months ended June 30, 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 June 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the three months ended June 30, 2011.

[2] The impact of QEP’s settled derivative contracts, for the six months ended June 30, 2012, are reflected below operating (loss) income.

[3] Revenues for the six months ended June 30, 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 six months ended June 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 6 - Derivative Contracts for detailed information on derivative contract settlements in the six months ended June 30, 2011.

[4] Under hedge accounting, gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three months ended June 30, 2011.

[5] Operating (loss) income for the six months ended June 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the six months ended June 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.

[6] Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three and six months ended June 30, 2011.

[7] Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three months ended June 30, 2011.

[8] Net (loss) income attributable to QEP for the six months ended June 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

[9] Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three and six months ended June 30, 2011.

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 146.4	$ 0
Accounts receivable, net	236.9	397.4
Fair value of derivative contracts	268.2	273.7
Inventories, at lower of average cost or market
Gas, oil and NGL	11.6	16.2
Materials and supplies	90.0	87.6
Prepaid expenses and other	42.5	43.7
Total Current Assets	795.6	818.6
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	8,822.3	8,172.4
Unproved properties	305.4	326.8
Midstream field services	1,550.1	1,463.6
Marketing and other	53.6	49.8
Total Property, Plant and Equipment	10,731.4	10,012.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	3,763.7	3,339.2
Midstream field services	327.8	297.5
Marketing and other	16.3	14.6
Total Accumulated Depreciation, Depletion and Amortization	4,107.8	3,651.3
Net Property, Plant and Equipment	6,623.6	6,361.3
Investment in unconsolidated affiliates	41.9	42.2
Goodwill	59.5	59.5
Fair value of derivative contracts	76.2	123.5
Other noncurrent assets	40.8	37.6
TOTAL ASSETS	7,637.6	7,442.7
Current Liabilities
Checks outstanding in excess of cash balances	0	29.4
Accounts payable and accrued expenses	373.8	457.3
Production and property taxes	47.2	40.0
Interest payable	33.0	24.4
Fair value of derivative contracts	2.3	1.3
Deferred income taxes	31.0	85.4
Total Current Liabilities	487.3	637.8
Long-term debt	1,866.6	1,679.4
Deferred income taxes	1,563.1	1,484.7
Asset retirement obligations	172.2	163.9
Fair value of derivative contracts	2.4	0
Other long-term liabilities	129.8	124.8
Commitments and contingencies
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 178.5 million and 177.2 million shares issued, respectively	1.8	1.8
Treasury stock - 0.7 million and 0.4 million shares, respectively	(24.0)	(13.1)
Additional paid-in capital	450.4	431.4
Retained earnings	2,820.7	2,673.5
Accumulated other comprehensive income	118.1	207.9
Total Common Shareholders' Equity	3,367.0	3,301.5
Noncontrolling interest	49.2	50.6
Total Equity	3,416.2	3,352.1
TOTAL LIABILITIES AND EQUITY	$ 7,637.6	$ 7,442.7

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Earnings Per Share

6 Months Ended

Jun. 30, 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. QEP's unvested restricted shares are included in weighted-average basic common shares outstanding because once the shares are granted, the restricted shares are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company's unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. During the three months ended June 30, 2012, 0.9 million shares were not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss. There were no anti-dilutive shares during the six months ended June 30, 2012 and during the three and six months ended June 30, 2011.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(in millions)
Weighted-average basic common shares outstanding		177.7		176.6		177.6		176.4
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan		-		2.0		0.9		2.1
Average diluted common shares outstanding		177.7		178.6		178.5		178.5

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Debt (Tables)

6 Months Ended

Jun. 30, 2012

Debt [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:

	June 30,			December 31,
	2012			2011
	(in millions)
Revolving Credit Facility due 2016	$	-		$	606.5
Term Loan due 2017		300.0			-
6.05% Senior Notes due 2016		176.8			176.8
6.80% Senior Notes due 2018		134.0			138.6
6.80% Senior Notes due 2020		136.0			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		1,871.8			1,684.9
Less unamortized discount		(5.2	)		(5.5	)
Total long-term debt outstanding	$	1,866.6		$	1,679.4

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Contingencies (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Contingencies [Abstract]
Loss Contingency, Settlement Agreement, Date	May 16, 2012
Gain (Loss) Related to Litigation Settlement	$ 3.7
Contribution payable to non profit corporation or trust created by Ute Idian tribe	$ 0.4
Loss Contingency, Settlement Agreement, Counterparty's Name	Ute Indian Tribe of the Uintah and Ouray Reservation

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Basis of Presentation of Interim Consolidated Financial Statements (Policies)

6 Months Ended

Jun. 30, 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 for all of its derivative instruments. 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 three and six months ended June 30, 2012 unrealized losses of $38.4 million and unrealized gains of $89.9 million were included in income that, prior to January 1, 2012, would have been deferred in Accumulated Other Comprehensive Income (AOCI) under hedge accounting. Refer to Note 6 - Derivative Contracts 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, were recast on the Condensed Consolidated Statement of Income from "Revenues" to "Natural gas, oil and NGL transportation and other handling costs" for prior periods presented. The impact of this revision was immaterial to the accompanying financial statements and had no effect on income from continuing operations, net income, or earnings per share. The following table details the impact for the three and six months ended June 30, 2011, on the Condensed Consolidated Statement of Income.

	Three Months Ended June 30, 2011							Six Months Ended June 30, 2011
	As reported (1)		As revised		Change			As reported (1)		As revised		Change
	(in millions)							(in millions)
REVENUES
Natural gas sales	$	258.1	$	298.7	$	40.6		$	529.1	$	611.3	$	82.2
Oil sales		80.0		80.7		0.7			142.3		143.7		1.4
NGL sales		61.6		63.8		2.2			107.4		111.7		4.3
Gathering, processing and other		78.4		58.9		(19.5	)		147.7		105.5		(42.2	)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs		-		24.0		24.0			-		45.7		45.7

(1) The "As reported" numbers reflect QEP Field Services NGL sales of $45.1 million and $73.7 million for the three and six months ended June 30, 2011, which were reclassified from "Gathering, processing and other" into "NGL sales" for consistency with current period presentation. In its second quarter 2011 Form 10-Q, QEP reported "NGL sales" of $16.5 million and $33.7 million, and "Gathering, processing and other" of $123.5 million, and $221.4 million for the three and six months ended June 30, 2011, respectively. The QEP Field Services NGL reclassification is all within "Revenues" and has no effect on income from continuing operations, net income or earnings per share.

Impairment of long-lived assets

Impairment of long-lived assets

Proved gas and oil properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, an impairment of gas and oil reserves caused by mechanical problems, faster-than-expected decline of reserves, lease-ownership issues, other-than-temporary decline in natural gas, NGL and crude oil prices and changes in the utilization of midstream gathering and processing assets. If impairment is indicated, fair value is calculated using a discounted-cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating costs, and estimates of probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors. During the three and six months ended June 30, 2012, QEP Energy recorded non-cash, price-related impairment charges of $48.9 million and $49.3 million, respectively, on some of its proved properties. The impairment charges are related to the reduced value of certain fields resulting from lower natural gas, crude oil and NGL prices. The assets were written down to their estimated fair values. Of the $49.3 million impairment charge during six months ended June 30, 2012, $48.9 million is related to proved properties in the Southern Region and $0.4 million is related to proved properties in the Northern Region.

The Company also performs periodic assessments of unproved gas and oil properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired the Company considers numerous factors including current development and exploration plans, results of development or exploration activity on adjacent leaseholds, technical personnel evaluations of the properties, and the remaining lease term. During the three and six months ended June 30, 2012, QEP recorded non-cash impairment charges of $6.1 million and $12.1 million, respectively,  on some of its unproved properties relating to the various factors described. Of the $6.1 million and $12.1 million impairment charges during the three and six months ended June 30, 2012, $3.1 million and $6.1 million, respectively, related to unproved properties in the Southern Region and $3.0 million and $6.0 million, respectively, related to unproved properties in the Northern Region.

New accounting pronouncements

New accounting pronouncements

In May of 2011, the FASB issued ASU 2011-04, which develops common measurement and disclosure requirements regarding an entity's fair value measurements and aligns GAAP and International Financial Reporting Standards. The amendments are required for interim and annual reporting periods beginning after December 15, 2011. The adoption of these requirements did not have a material impact on the financial statements of QEP.

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

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.