$ 170.3

$ 309.8

$ 470.4

$ 921.1

117.7

76.9

335.7

220.6

67.5

79.3

247.0

191.0

Purchased gas, oil and NGL sales

46.3

57.1

141.9

162.6

140.6

356.8

449.9

810.6

542.4

^[1]

879.9

^[2]

1,644.9

^[3]

2,305.9

^[4]

142.6

352.7

455.9

803.3

Natural gas, oil and NGL transportation and other handling costs

42.2

37.0

122.8

104.1

36.3

27.5

111.5

73.2

22.1

27.0

66.4

79.4

41.7

28.7

114.5

89.1

24.3

27.7

68.4

78.5

Abandonment and impairment

234.1

189.0

647.4

566.4

Exploration expenses

2.2

2.4

6.3

7.5

9.5

5.7

71.8

16.4

Net gain from asset sales

555.0

697.7

1,665.0

1,817.9

1.2

1.5

1.4

OPERATING (LOSS) INCOME

(12.6)

^[5]

183.4

^[6]

(18.6)

^[7]

489.4

^[8]

Realized and unrealized gains on derivative contracts (See Note 7)

36.1

334.7

Interest and other (loss) income

(0.2)

(0.7)

2.4

(0.5)

2.3

5.6

4.5

(0.7)

(0.6)

(0.7)

(LOSS) INCOME BEFORE INCOME TAXES

(30.0)

(22.8)

(82.9)

(67.0)

(4.4)

161.5

240.6

425.7

Income tax benefit (provision)

2.3

(59.1)

(86.5)

(156.0)

NET (LOSS) INCOME

(2.1)

102.4

154.1

269.7

NET (LOSS) INCOME ATTRIBUTABLE TO QEP

(1.0)

(0.9)

(2.7)

(2.2)

$ (3.1)

^[9]

$ 101.5

^[10]

$ 151.4

^[11]

$ 267.5

^[12]

Earnings Per Common Share Attributable to QEP

Basic total (in dollars per share)

$ (0.02)

$ 0.58

$ 0.85

$ 1.52

Diluted total (in dollars per share)

$ (0.02)

$ 0.57

$ 0.85

$ 1.50

Weighted-average common shares outstanding

Used in basic calculation (in shares)

177.9

176.6

177.6

176.5

Used in diluted calculation (in shares)

177.9

178.5

178.6

178.5

Dividends per common share (in dollars per share)

$ 0.02

$ 0.06

[1]	The impact of QEP’s settled derivative contracts for the three months ended September 30, 2012 are reflected below operating (loss) income.
[2]	Revenues for the three months ended September 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 September 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 7 - Derivative Contracts for detailed information on derivative contract settlements in the three months ended September 30, 2011.
[3]	The impact of QEP’s settled derivative contracts, for the nine months ended September 30, 2012, are reflected below operating (loss) income.
[4]	Revenues for the nine months ended September 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 nine months ended September 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 7 - Derivative Contracts for detailed information on derivative contract settlements in the nine months ended September 30, 2011.
[5]	Operating (loss) income for the three months ended September 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the three months ended September 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.
[6]	Under hedge accounting, gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three months ended September 30, 2011.
[7]	Operating (loss) income for the nine months ended September 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the nine months ended September 30, 2012, gains and losses from realized commodity derivative contract settlements were included below operating (loss) income.
[8]	Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the three and nine months ended September 30, 2011.
[9]	Net (loss) income attributable to QEP for the three months ended September 30, 2012 includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.
[10]	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 September 30, 2011.
[11]	Net (loss) income attributable to QEP for the nine months ended September 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.
[12]	Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in accumulated other comprehensive income during the three and nine months ended September 30, 2011.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)
In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Statement of Other Comprehensive Income [Abstract]

Other comprehensive (loss) income, net of tax:

$ (2.1)

$ 102.4

$ 154.1

$ 269.7

Reclassification of previously deferred derivative gains(1)

(42.1)

^[1]

37.3

^[1]

(133.8)

^[1]

(13.0)

^[1]

Pension and other postretirement plans adjustments:

Amortization of net actuarial loss

0.5

^[2]

0.7

^[2]

Amortization of prior service cost

0.9

^[3]

1.4

^[3]

2.6

^[3]

3.1

^[3]

Total pension and other postretirement plans adjustments

1.4

3.3

3.1

Other comprehensive loss

(40.7)

38.7

(130.5)

(9.9)

Comprehensive (loss) income

(42.8)

141.1

23.6

259.8

Comprehensive income attributable to noncontrolling interests

(1.0)

(0.9)

(2.7)

(2.2)

Comprehensive (loss) income attributable to QEP

$ (43.8)

$ 140.2

$ 20.9

$ 257.6

[1]	Presented net of income tax benefit of $24.9 million and $79.2 million during the three and nine months ended September 30, 2012, respectively, and net of income tax expense of $22.1 million during the three months ended September 30, 2011 and income tax benefit of $7.7 million during the nine months ended September 30, 2011, respectively.
[2]	Presented net of income tax expense of $0.2 million and $0.4 million during the three and nine months ended September 30, 2012, respectively.
[3]	Presented net of income tax expense of $0.5 million and $1.6 million during three and nine months ended September 30, 2012, respectively, and net of income tax expense of $0.8 million and $1.9 million during the three and nine months ended September 30, 2011, respectively.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 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	$ (24.9)	$ 22.1	$ (79.2)	$ (7.7)
Pension and other postretirement plans adjustments:
Tax expense (benefit) on net unamortized gain (loss) incurred	0.2		0.4
Tax expense (benefit) on prior service cost incurred	$ 0.5	$ 0.8	$ 1.6	$ 1.9

Tax effect of the income statement impact of the reclassification adjustment for prior service costs recognized as a component of net period benefit cost.

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-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

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+ Details

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Tax effect of the increase (decrease) in the value of the projected benefit obligation and the (increase) decrease in the value of the plan assets resulting from experience different from that assumed or from a change in an actuarial assumption that has not been recognized in net periodic benefit cost.

+ References+ Details

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 0	$ 0
Accounts receivable, net	274.3	397.4
Fair value of derivative contracts	187.2	273.7
Inventories, at lower of average cost or market
Gas, oil and NGL	14.0	16.2
Materials and supplies	94.9	87.6
Prepaid expenses and other	49.4	43.7
Total Current Assets	619.8	818.6
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	9,882.4	8,172.4
Unproved properties	983.4	326.8
Midstream field services property	1,605.2	1,463.6
Marketing and other	56.3	49.8
Total Property, Plant and Equipment	12,527.3	10,012.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	3,977.6	3,339.2
Midstream field services	342.9	297.5
Marketing and other	16.9	14.6
Total Accumulated Depreciation, Depletion and Amortization	4,337.4	3,651.3
Net Property, Plant and Equipment	8,189.9	6,361.3
Investment in unconsolidated affiliates	41.7	42.2
Goodwill	59.5	59.5
Fair value of derivative contracts	35.2	123.5
Other noncurrent assets	50.0	37.6
TOTAL ASSETS	8,996.1	7,442.7
Current Liabilities
Checks outstanding in excess of cash balances	27.5	29.4
Accounts payable and accrued expenses	464.6	457.3
Production and property taxes	56.3	40.0
Interest payable	23.7	24.4
Fair value of derivative contracts	2.7	1.3
Deferred income taxes	41.9	85.4
Total Current Liabilities	616.7	637.8
Long-term debt	3,180.7	1,679.4
Deferred income taxes	1,505.8	1,484.7
Asset retirement obligations	176.6	163.9
Fair value of derivative contracts	4.1	0
Other long-term liabilities	135.2	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 - 0.4 million and 0.4 million shares, respectively	(11.6)	(13.1)
Additional paid-in capital	455.8	431.4
Retained earnings	2,805.6	2,673.5
Accumulated other comprehensive income	77.4	207.9
Total Common Shareholders' Equity	3,329.0	3,301.5
Noncontrolling interest	48.0	50.6
Total Equity	3,377.0	3,352.1
TOTAL LIABILITIES AND EQUITY	$ 8,996.1	$ 7,442.7

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Sep. 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	500
Common stock, shares issued (in shares)	178.5	177.2
Treasury stock (in shares)	0.4	0.4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
OPERATING ACTIVITIES
Net (loss) income	$ 154.1	$ 269.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	647.4	566.4
Deferred income taxes	54.7	155.9
Abandonment and impairment	71.8	16.4
Share-based compensation	19.5	16.5
Amortization of debt issuance costs and discounts	3.7	2.4
Dry exploratory well expense	0.1	0.5
Net gain from asset sales	(1.5)	(1.4)
Income from unconsolidated affiliates	(5.6)	(4.5)
Distributions from unconsolidated affiliates and other	6.1	7.6
Non-cash loss on early extinguishment of debt	0	0.7
Unrealized gain on derivative contracts	(32.8)	(86.7)
Changes in operating assets and liabilities	54.5	12.2
Net Cash Provided by Operating Activities	972.0	955.7
INVESTING ACTIVITIES
Property acquisitions	(1,400.3)	(40.7)
Property, plant and equipment, including dry exploratory well expense	(1,040.7)	(957.7)
Proceeds from disposition of assets	5.3	7.4
Net Cash Used in Investing Activities	(2,435.7)	(991.0)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(1.9)	7.2
Long-term debt issued	1,450.0	0
Long-term debt issuance costs paid	(17.0)	(10.5)
Long-term debt repaid	(6.7)	(58.5)
Proceeds from credit facility	933.5	280.0
Repayments of credit facility	(876.0)	(170.0)
Other capital contributions	(4.2)	0.1
Dividends paid	(10.7)	(10.6)
Excess tax benefit on share-based compensation	2.0	1.5
Distribution from Questar	0	0.2
Distribution to noncontrolling interest	(5.3)	(4.1)
Net Cash Provided by Financing Activities	1,463.7	35.3
Change in cash and cash equivalents	0	0
Beginning cash and cash equivalents	0	0
Ending cash and cash equivalents	0	0
Supplemental Disclosures:
Cash paid for interest	81.9	89.8
Cash paid (received) for income taxes	28.0	(7.2)
Non-cash investing activities
Change in capital expenditure accrual balance	$ 97.5	$ 12.5

Nature of Business

9 Months Ended

Sep. 30, 2012

Nature Of Business [Abstract]

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;


•	QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil, 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”.

Basis of Presentation of Interim Consolidated Financial Statements

9 Months Ended

Sep. 30, 2012

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 nine months ended September 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 nine months ended September 30, 2012, unrealized losses of $57.1 million and unrealized gains of $32.8 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 7 – 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 Operations 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 nine months ended September 30, 2011, on the Condensed Consolidated Statement of Operations.



	Three Months Ended September 30, 2011							Nine Months Ended September 30, 2011
	As reported ⁽¹⁾		As revised		Change			As reported ⁽¹⁾		As revised		Change
	(in millions)							(in millions)
REVENUES
Natural gas sales	$	266.7	$	309.8	$	43.1		$	795.8	$	921.1	$	125.3
Oil sales	76.1		76.9		0.8			218.4		220.6		2.2
NGL sales	75.7		79.3		3.6			183.1		191.0		7.9
Gathering, processing and other	77.1		57.1		(20.0		)	224.8		162.6		(62.2		)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs	—		27.5		27.5			—		73.2		73.2

____________________________

⁽¹⁾

The “As reported” numbers reflect QEP Field Services NGL sales of $41.6 million and $115.3 million for the three and nine months ended September 30, 2011, which were reclassified from “Gathering, processing and other” into “NGL sales” for consistency with current period presentation. In its third quarter 2011 Form 10-Q, QEP reported “NGL sales” of $34.1 million and $67.8 million, and “Gathering, processing and other” of $118.7 million and $340.1 million for the three and nine months ended September 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 oil and gas properties

Proved gas and oil properties are evaluated on a field-by-field basis for potential impairment. 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.

Unproved properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of individually significant unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether a significant unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, and the remaining lease term.

During the three and nine months ended September 30, 2012, QEP recorded impairment charges of $7.3 million and $68.7 million on its oil and gas properties, respectively. Of the $68.7 million impairment charge in the nine months ended September 30, 2012, $49.3 million related to the non-cash, price-related impairment charges on proved properties incurred in the first half of 2012. The impairment charges were related to the reduced value of certain fields resulting from lower natural gas, crude oil and NGL prices and impairments of unproven leasehold acquisition costs. Of the $68.7 million impairment charge during the nine months ended September 30, 2012, $60.0 million was related to oil and gas properties in the Southern Region and $8.7 million was related to oil and gas 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 supplies have resulted in downward pressure on natural gas and NGL prices, while growing U.S. supplies combined with concern about the global economy and other factors have 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 Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, 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 No. 2011-05, Presentation of Comprehensive Income, 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, Disclosures about Offsetting Assets and Liabilities, 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.

In July of 2012, the FASB issued ASU 2012-02, Intangibles - Goodwill and Other: Testing Indefinite-Lived Intangible Assets for Impairment, which revises the way an entity can test indefinite-lived intangible assets for impairment by allowing an entity to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If there is no indication of impairment from the qualitative impairment test, the entity is not required to complete a quantitative impairment test of determining and comparing the fair value with the carrying amount of the indefinite-lived asset. Under the guidance in this ASU, an entity also has the option to bypass the qualitative assessment in any period and proceed directly in performing the quantitative impairment test and can resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. The adoption of this standard will allow the Company to more efficiently complete the annual goodwill impairment test but will not have a significant impact on the Company's consolidated financial statements.

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

Acquisitions [Text Block]

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+ Details

Acquisitions

9 Months Ended

Sep. 30, 2012

Acquisitions [Abstract]

Acquisition

On September 27, 2012, QEP Energy completed an acquisition of oil and gas properties in the Williston Basin for an aggregate purchase price of approximately $1.4 billion, subject to post-closing adjustments (the “Acquisition”). The properties are located in Williams and McKenzie counties of North Dakota, approximately 12 miles west of QEP's existing core acreage in the Williston Basin.

The Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included proved properties. Pro-forma information has not been presented due to the immateriality of revenues and expenses related to the Acquisition during the periods presented. The results of operations from September 27 to September 30, 2012 from the assets purchased in the Acquisition are not included in the three and nine months ended September 30, 2012 Condensed Consolidated Statements of Operations. During the third quarter of 2012, QEP Energy recorded the acquisition on its Condensed Consolidated Balance Sheet; however, the final purchase price is subject to revision based on the final valuation work and settlement of post-closing adjustments. The following table presents a summary of the preliminary purchase accounting entries (in millions):



Consideration given:
Cash paid at closing	$	1,394.2

Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
Proved properties	$	707.6
Unproved properties	686.5
Asset retirement obligations	(0.6		)
Other assets	0.7
Total fair value	$	1,394.2

Earnings Per Share

9 Months Ended

Sep. 30, 2012

Earnings Per Share [Abstract]

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 September 30, 2012, 0.8 million shares were not included in diluted common shares outstanding as they were anti-dilutive due to QEP’s net loss position. There were no anti-dilutive shares during the nine months ended September 30, 2012, and during the three and nine months ended September 30, 2011.

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



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2012	2011	2012	2011
	(in millions)
Weighted-average basic common shares outstanding	177.9	176.6	177.6	176.5
Potential number of shares issuable upon excercise of in-the- money stock options under the Long-term Stock Incentive Plan	—	1.9	1.0	2.0
Average diluted common shares outstanding	177.9	178.5	178.6	178.5

Asset Retirement Obligation [Abstract]

The entire disclosure for earnings per share.

+ References+ Details

Asset Retirement Obligations

9 Months Ended

Sep. 30, 2012

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, to September 30, 2012, respectively:



	Asset Retirement Obligations
	2012
	(in millions)
ARO liability at January 1,	$	163.9
Accretion	7.7
Liabilities incurred	5.2
Liabilities settled	(0.2		)
ARO liability at September 30,	$	176.6

The entire disclosure for an asset retirement obligation and the associated long-lived asset. An asset retirement obligation is a legal obligation associated with the disposal or retirement from service of a tangible long-lived asset that results from the acquisition, construction or development, or the normal operations of a long-lived asset, except for certain obligations of lessees.

+ References+ Details

Fair Value Measurements

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

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 7 - Derivative Contracts) is based on market prices posted on the NYMEX on the last trading day of the reporting period and industry standard discounted cash flow models. 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 of the Company's 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 interest rate swaps that it has determined are Level 2. 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.

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



	Fair Value Measurements
	September 30, 2012
	Level 1		Level 2		Level 3		Netting Adjustments			Total
			(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	199.4	$	—	$	(12.2	)	$	187.2
Commodity derivative instruments - long-term	—		38.2		—		(3.0		)	$	35.2
Total financial assets	$	—	$	237.6	$	—	$	(15.2	)	$	222.4

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	12.3	$	—	$	(12.2	)	$	0.1
Interest rate swaps - short-term	—		2.6		—		—			$	2.6
Commodity derivative instruments - long-term	—		3.0		—		(3.0		)	$	—
Interest rate swaps - long-term	—		4.1		—		—			$	4.1
Total financial liabilities	$	—	$	22.0	$	—	$	(15.2	)	$	6.8

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 change in the fair value of Level 3 commodity derivative instruments assets and liabilities for the nine months ended September 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 September 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
	September 30, 2012				December 31, 2011
	(in millions)
Financial liabilities
Checks outstanding in excess of cash balances	$	27.5	$	27.5	$	29.4	$	29.4
Long-term debt	$	3,180.7	$	3,330.4	$	1,679.4	$	1,754.9

The carrying amount of checks outstanding in excess of cash balances approximates 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 because the floating interest rate paid on such debt was set for periods of one month.

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 5 – 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 nine months ended September 30, 2012 and the year ended December 31, 2011, the Company recorded impairments on certain oil and gas properties 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 are considered Level 3 within the fair value hierarchy. During the nine months ended September 30, 2012, the Company recorded $49.3 million of impairments related to some of its proved properties. The proved properties were written down to their estimated fair values of $36.7 million, at the time of impairment.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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+ Details

Derivative Contracts

9 Months Ended

Sep. 30, 2012

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 a portion of its 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 fixed in AOCI as of the de-designation date and are being reclassified into the Consolidated Statement of Operations as the transactions settle and affect earnings. At September 30, 2012, AOCI consisted of $182.9 million ($114.9 million after tax) of unrealized gains. QEP expects to reclassify into earnings from AOCI the fixed 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 Operations 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. 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 Energy Derivative Contracts

The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative contracts as of September 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	19.3	$	4.72
2012	Swap	IFPEPL (1)	1.8	$	4.70
2012	Swap	IFNPCR (2)	22.1	$	4.67
2012	Swap	IFCNPTE (3)	2.8	$	2.66
2013	Swap	NYMEX	29.2	$	3.68
2013	Swap	IFNPCR (2)	65.7	$	5.66
Oil sales			(Bbls)
2012	Swap	NYMEX WTI	1.3	$	97.42
2012	Collar	NYMEX WTI	0.4			$	87.50	$	115.36
2013	Swap	NYMEX WTI	5.1	$	98.48
2014	Swap	NYMEX WTI	1.8	$	92.72
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane	3.9	$	0.64
2012	Swap	Mt. Belvieu Propane	5.8	$	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 September 30, 2012:



Year	Type of Contract	Index	Total Volumes	Average Swap price per gallon
			(in millions)
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane	3.9	$	0.64
2012	Swap	Mt. Belvieu Propane	1.9	$	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 sell 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 September 30, 2012:



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2012	Swap	IFNPCR (1)	2.1	$	3.93
2013	Swap	IFNPCR (1)	3.1	$	3.77
Natural gas purchases			(MMBtu)
2012	Swap	IFNPCR (1)	1.5	$	2.76
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 September 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

QEP Derivative Financial Statement Presentation

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	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	199.4	$	284.1	$	12.3	$	11.7
Interest rate swaps	Fair value of derivative contracts	—		—		2.6		—
Long-term:
Commodity	Fair value of derivative contracts	38.2		123.5		3.0		—
Interest rate swaps	Fair value of derivative contracts	—		—		4.1		—
Total derivative instruments		$	237.6	$	407.6	$	22.0	$	11.7

The effects and location of the change in fair value and settlement of QEP's derivative contracts on the Condensed Consolidated Statements of Operations are summarized in the following tables:



Derivative instruments not designated as cash flow hedges	Location of gain (loss) recognized in earnings	Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2012			2011			2012			2011
		(in millions)
Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		$	86.2		$	(27.9	)	$	283.8		$	(86.7	)
Oil derivative contracts		2.7			—			2.2			—
NGL derivative contracts		3.4			—			6.5			—
QEP Field Services
NGL derivative contracts		1.9			—			6.3			—
QEP Marketing
Natural gas derivative contracts		(0.4		)	—			3.7			—
Total realized gain (loss) on commodity derivative contracts		93.8			(27.9		)	302.5			(86.7		)
Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		(50.6		)	27.9			3.3			86.7
Oil derivative contracts		4.1			—			31.2			—
NGL derivative contracts		(4.4		)	—			3.4			—
QEP Field Services
NGL derivative contracts		(2.5		)	—			2.0			—
QEP Marketing
Natural gas derivative contracts		(1.4		)	—			(0.5		)	—
Total unrealized (loss) gain on commodity derivative contracts		(54.8		)	27.9			39.4			86.7
Total realized and unrealized gain on commodity derivative contracts		$	39.0		$	—		$	341.9		$	—
Realized gain (loss) on interest rate swaps
Realized loss on interest rate swaps		$	(0.6	)	$	—		$	(0.6	)	$	—
Unrealized gain (loss) on interest rate swaps
Unrealized loss on interest rate swaps		(2.3		)	—			(6.6		)	—
Total realized and unrealized loss on interest rate swaps		$	(2.9	)	$	—		$	(7.2	)	$	—

Grand Total	Realized and unrealized gains on derivative contracts	$	36.1		$	—		$	334.7		$	—



Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	Three Months Ended					Nine Months Ended
		September 30,					September 30,
		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	$	—	$	129.6		$	—	$	191.1
Gain reclassified from AOCI into income for effective portion of hedge	Natural gas sales	—		71.6			—		209.1
Gain reclassified from AOCI into income for effective portion of hedge	Oil sales	—		0.9			—		1.0
Gain reclassified from AOCI into income for effective portion of hedge	NGL sales	—		(0.3		)	—		(0.3		)
Gain reclassified from AOCI into income for effective portion of hedge	Marketing sales	—		—			—		—
Gain reclassified from AOCI into income for effective portion of hedge	Marketing purchases	—		0.4			—		4.3
Gain recognized in income for the ineffective portion of hedges	Interest and other income	—		(2.7		)	—		(2.6		)

The Company estimates that derivative contracts that were outstanding in AOCI at September 30, 2012, having a fixed fair value of $97.7 million, will be settled and reclassified from AOCI to the Condensed Consolidated Statements of Operations during the next twelve months.

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

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+ Details

Restructuring Costs

9 Months Ended

Sep. 30, 2012

Restructuring Costs [Abstract]

Restructuring Costs

During the first quarter 2012, QEP began incurring costs related to 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. During the third quarter of 2012, QEP incurred additional restructuring and reorganization costs related to consolidating various corporate and accounting functions to the Denver corporate headquarters. As part of the reorganization, QEP will incur costs associated with the severance, retention and relocation of employees and other exit costs associated with the termination of operating leases arising from office space that will no longer be utilized by the Company. The majority of the restructuring costs will be incurred during the remainder of 2012 and in 2013.

The following table summarizes, by line of business, each major type of costs expected to be incurred and the total amounts recorded in "General and administrative" expense on the Condensed Consolidated Statement of Operations the respective periods indicated:



	QEP Energy		QEP Field Services		QEP Marketing		Total
Restructuring costs expected to be incurred	(in millions)
One-time termination benefits	$	3.4	$	—	$	0.3	$	3.7
Retention & relocation expense	5.5		0.2		0.2		5.9
Lease termination costs	0.6		—		—		0.6
Total restructuring costs expected to be incurred	$	9.5	$	0.2	$	0.5	$	10.2

Total restructuring costs recognized in income during the current period
During the three months ended September 30, 2012
One-time termination benefits	$	0.2	$	—	$	—	$	0.2
Retention & relocation expense	—		—		—		—
Lease termination costs	—		—		—		—
Total restructuring costs incurred for the three months ended September 30, 2012	$	0.2	$	—	$	—	$	0.2

During the nine months ended September 30, 2012
One-time termination benefits	$	2.1	$	—	$	—	$	2.1
Retention & relocation expense	3.2		—		—		3.2
Lease termination costs	—		—		—		—
Total restructuring costs incurred for the nine months ended September 30, 2012	$	5.3	$	—	$	—	$	5.3

The following is a reconciliation of the restructuring liability, by line of business, which is included within “Accounts payable and accrued expenses” on the Condensed Consolidated Balance Sheets:



	QEP Energy			QEP Field Services		QEP Marketing		Total
	(in millions)
Balance at December 31, 2011	$	—		$	—	$	—	$	—
Costs incurred and charged to expense	5.3			—		—		5.3
Costs paid or otherwise settled	(5.1		)	—		—		(5.1		)
Balance at September 30, 2012	$	0.2		—		—		$	0.2

The entire disclosure for restructuring and related activities. Description of restructuring activities such as exit and disposal activities, include facts and circumstances leading to the plan, the expected plan completion date, the major types of costs associated with the plan activities, total expected costs, the accrual balance at the end of the period, and the periods over which the remaining accrual will be settled.

+ References+ Details

Debt

9 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Debt

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



	September 30, 2012			December 31, 2011
	(in millions)
Revolving Credit Facility due 2016	$	664.0		$	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			—
5.25% Senior Notes due 2023	650.0			—
Total principal amount of debt	3,185.8			1,684.9
Less unamortized discount	(5.1		)	(5.5		)
Total long-term debt outstanding	$	3,180.7		$	1,679.4

Of the total debt outstanding on September 30, 2012, 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 Facility

QEP’s revolving credit facility agreement, 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 credit facility 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, with the agreement of the lenders.

During the nine months ended September 30, 2012, QEP’s weighted-average interest rate on borrowings from its Credit Facility was 2.05%. At September 30, 2012 and December 31, 2011, QEP was in compliance with the covenants under the credit agreement. At September 30, 2012, there was $664.0 million 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 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 nine months ended September 30, 2012, QEP’s weighted-average interest rate on borrowings from the Term Loan was 2.02%. At September 30, 2012, QEP was in compliance with the covenants under the Term Loan credit agreement.

Senior Notes

During the third quarter of 2012, QEP completed a public offering of $650.0 million in aggregate principal amount of 5.25% senior notes due in May 2023 (2023 Senior Notes). The 2023 Senior Notes were issued at face value. Interest on the 2023 Senior Notes will be paid semi-annually, in May and November of each year. The estimated net proceeds of $640.8 million were used to fund a portion of the Acquisition, as described in Note 3 - Acquisition. The estimated costs associated with the offering were $9.2 million and were deferred and are being amortized over the life of the notes. The amortization expense related to all of the Company's deferred finance costs is included in “Interest expense” on the Condensed Consolidated Statement of Operations.

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.

During the first quarter of 2012, QEP completed a public offering of $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 year. The net proceeds of $493.1 million were used to repay indebtedness under QEP's Credit Facility. The finance costs associated with the offering were $6.9 million and were deferred and are being amortized over the life of the notes.

At September 30, 2012, the Company had $2,221.8 million principal amount of senior notes outstanding with maturities ranging from September 2016 to May 2023 and coupons ranging from 5.25% 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.

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References+ Details

Contingencies	9 Months Ended
Contingencies	Sep. 30, 2012
Commitments and Contingencies Disclosure [Abstract]
Contingencies	Contingencies QEP is involved in various commercial and regulatory claims, 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 effect on the Company's financial position, results of operations or cash flows, except with regard to cases discussed below where management cannot determine at this time whether they will have a material effect. In accordance with ASC 450, Contingencies, an accrual 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, and experience in contesting, litigating and settling similar claims. Disclosures are also provided for reasonably possible losses that could have a material effect on the Company's financial position, results of operations or cash flows. 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. The U.S. Environmental Protection Agency (EPA) alleged that QEP Field Services (f/k/a Questar Gas Management) violated the Clean Air Act (CAA) and sought 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 and the parties executed a consent decree which was subsequently approved by court order. The civil penalty paid to the government during the third quarter of 2012 was $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 $0.8 million had been spent as of September 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 two royalty owners on behalf of all QEP Energy royalty owners in the state of Oklahoma since 1988, asserting various claims for damages related to royalty valuation on all of QEP's Oklahoma wells. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The court has certified the class as to the breach of contract, breach of fiduciary duty and unjust enrichment claims. Because this case involves complex legal issues and uncertainties, a large class of plaintiffs and a large number of producing properties and wells, and because the proceedings are in the early stages, with substantive discovery yet to be conducted, the Company is unable to estimate a reasonably possible loss or range of loss. Although the plaintiff class has not made a formal demand, based upon the class allegations, we believe the class may seek damages in excess of $200 million. QEP Energy is still evaluating the claims, but believes that it has properly valued and paid royalty under Oklahoma law and will vigorously defend this case. 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 calculation 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. 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.

The entire disclosure for commitments and contingencies.

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+ Details

Share-Based Compensation

9 Months Ended

Sep. 30, 2012

Share-based Compensation [Abstract]

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 September 30, 2012. Share-based compensation expense is recognized in “General and administrative” on the Condensed Consolidated Statements of Operations. During the three and nine months ended September 30, 2012, QEP recognized $7.2 million and $19.5 million, respectively, in total compensation expense related to share-based compensation compared to $5.7 million and $16.5 million during the three and nine months ended September 30, 2011. The increase in share-based compensation recognized in 2012 compared to 2011 was due to increased restricted shares and options granted in late 2011 and throughout 2012.

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
	Nine Months Ended
	September 30, 2012
Fair value of options at grant date	$	14.29
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	301,035		30.76
Exercised	(336,675	)	9.21
Forfeited	—		—		—
Outstanding at September 30, 2012	1,968,054		$	24.74	3.4	$	15.1
Options Exercisable at September 30, 2012	1,505,051		$	22.38	2.6	$	14.6
Unvested Options at September 30, 2012	463,003		$	32.43	5.9	$	0.2

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $7.1 million and $2.7 million during the nine months ended September 30, 2012 and 2011, respectively. As of September 30, 2012, $3.6 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.2 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 nine months ended September 30, 2012 and 2011, was $16.6 million and $11.5 million, respectively. The weighted average grant-date fair value of restricted stock was $30.59 per share and $39.26 per share for the nine months ended September 30, 2012 and 2011, respectively. As of September 30, 2012, $21.1 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 2.2 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	778,780		30.59
Vested	(538,668	)	31.88
Forfeited	(61,502	)	32.70
Unvested balance at September 30, 2012	1,278,362		$	31.85

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 nine months ended September 30, 2012 and 2011, respectively. As of September 30, 2012, $6.2 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 2.1 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	179,304		30.90
Vested	—		—
Forfeited	(12,713	)	35.69
Unvested balance at September 30, 2012	281,865		$	34.03

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

Compensation and Retirement Disclosure [Abstract]

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-Publisher SEC

-Name Staff Accounting Bulletin (SAB)

-Number Topic 14

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-Name Statement of Position (SOP)

-Number 93-6

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+ Details

Employee Benefits

9 Months Ended

Sep. 30, 2012

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 benefit plans that provide certain health care and life insurance benefits for certain retired employees. During the nine months ended September 30, 2012, the Company made contributions of $4.9 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 $0.7 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 21^st 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 the remainder of 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						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(in millions)
Service cost	$	1.1		$	0.7		$	3.0		$	2.1
Interest cost	1.3			1.2			3.7			3.4
Expected return on plan assets	(0.9		)	(0.7		)	(2.7		)	(1.9		)
Amortization of prior service costs	1.3			1.4			3.9			4.0
Amortization of actuarial loss	0.6			—			1.0			—
Periodic expense	$	3.4		$	2.6		$	8.9		$	7.6



	Postretirement benefits
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(in millions)
Service cost	$	0.1	$	0.1	$	0.1	$	0.1
Interest cost	—		—		0.2		0.2
Expected return on plan assets	—		—		—		—
Amortization of prior service costs	0.1		0.1		0.3		0.3
Recognized net actuarial loss	—		—		—		—
Periodic expense	$	0.2	$	0.2	$	0.6	$	0.6

The entire disclosure for pension and other postretirement benefits.

Operations by Line of Business

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+ Details

Operations by Line of Business

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

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 for the three months ended September 30, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	374.0		$	77.9		$	90.5		$	—		$	542.4
From affiliated customers	—			31.8			145.8			(177.6		)	—
Total Revenues	374.0			109.7			236.3			(177.6		)	542.4
Operating expenses
Purchased gas, oil and NGL expense	45.9			4.9			236.7			(144.9		)	142.6
Lease operating expense	43.1			—			—			(0.9		)	42.2
Natural gas, oil and NGL transportation and other handling costs	59.8			6.9			—			(30.4		)	36.3
Gathering, processing and other	—			21.8			0.1			0.2			22.1
General and administrative	32.2			10.6			0.5			(1.6		)	41.7
Production and property taxes	22.5			1.7			0.1			—			24.3
Depreciation, depletion and amortization	217.4			15.8			0.9			—			234.1
Other operating expenses	11.7			—			—			—			11.7
Total operating expenses	432.6			61.7			238.3			(177.6		)	555.0
Operating (loss) income ⁽²⁾	(58.6		)	48.0			(2.0		)	—			(12.6		)
Realized and unrealized gains (losses) on derivative contracts	41.4			(0.6		)	(4.7		)	—			36.1
Interest and other income	(0.2		)	—			28.4			(28.4		)	(0.2		)
Income from unconsolidated affiliates	—			2.3			—			—			2.3
Interest expense	(24.1		)	(3.5		)	(30.8		)	28.4			(30.0		)
(Loss) income before income taxes	(41.5		)	46.2			(9.1		)	—			(4.4		)
Income tax benefit (provision)	15.3			(16.5		)	3.5			—			2.3
Net (loss) income	(26.2		)	29.7			(5.6		)	—			(2.1		)
Net income attributable to noncontrolling interest	—			(1.0		)	—			—			(1.0		)
Net (loss) income attributable to QEP ⁽³⁾	$	(26.2	)	$	28.7		$	(5.6	)	$	—		$	(3.1	)

____________________________


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


⁽²⁾	Operating (loss) income for the three months ended September 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the three months ended September 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 three months ended September 30, 2012 includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

The following table is a summary of operating results for the three months ended September 30, 2011, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	635.6		$	98.6		$	145.7		$	—		$	879.9
From affiliated customers	—			21.0			148.5			(169.5		)	—
Total Revenues	635.6			119.6			294.2			(169.5		)	879.9
Operating expenses
Purchased gas, oil and NGL expenses	208.1			—			292.0			(147.4		)	352.7
Lease operating expense	38.0			—			—			(1.0		)	37.0
Natural gas, oil and NGL transportation and other handling costs	45.0			2.5			—			(20.0		)	27.5
Gathering, processing and other	—			26.6			0.4			—			27.0
General and administrative	23.0			6.6			0.2			(1.1		)	28.7
Production and property taxes	26.3			1.4			—			—			27.7
Depreciation, depletion and amortization	174.4			14.0			0.6			—			189.0
Other operating expenses	8.1			—			—			—			8.1
Total operating expenses	522.9			51.1			293.2			(169.5		)	697.7
Net gain (loss) from asset sales	1.2			(0.1		)	0.1			—			1.2
Operating income ⁽²⁾	113.9			68.4			1.1			—			183.4
Interest and other (loss) income	(0.7		)	—			25.0			(25.0		)	(0.7		)
Income from unconsolidated affiliates	—			2.3			—			—			2.3
Loss on early extinguishment of debt	—			—			(0.7		)	—			(0.7		)
Interest expense	(20.5		)	(3.8		)	(23.5		)	25.0			(22.8		)
Income before income taxes	92.7			66.9			1.9			—			161.5
Income taxes	(34.4		)	(24.0		)	(0.7		)	—			(59.1		)
Net income	58.3			42.9			1.2			—			102.4
Net income attributable to noncontrolling interest	—			(0.9		)	—			—			(0.9		)
Net income attributable to QEP ⁽³⁾	$	58.3		$	42.0		$	1.2		$	—		$	101.5

____________________________

⁽¹⁾

Revenues for the three months ended September 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 September 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 7 - Derivative Contracts for detailed information on derivative contract settlements in the three months ended September 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 September 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 September 30, 2011.

The following table is a summary of operating results for the nine months ended September 30, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	1,106.3		$	254.9		$	283.7		$	—		$	1,644.9
From affiliated customers	—			88.1			396.3			(484.4		)	—
Total Revenues	1,106.3			343.0			680.0			(484.4		)	1,644.9
Operating expenses
Purchased gas, oil and NGL expense	159.0			9.0			681.7			(393.8		)	455.9
Lease operating expense	125.3			—			—			(2.5		)	122.8
Natural gas, oil and NGL transportation and other handling costs	167.4			27.7			—			(83.6		)	111.5
Gathering, processing and other	—			65.6			0.8			—			66.4
General and administrative	94.3			24.1			0.6			(4.5		)	114.5
Production and property taxes	63.6			4.6			0.2			—			68.4
Depreciation, depletion and amortization	597.7			47.2			2.5			—			647.4
Other operating expenses	78.1			—			—			—			78.1
Total operating expenses	1,285.4			178.2			685.8			(484.4		)	1,665.0
Net gain from asset sales	1.5			—			—			—			1.5
Operating (loss) income ⁽²⁾	(177.6		)	164.8			(5.8		)	—			(18.6		)
Realized and unrealized gains (losses) on derivative contracts	330.4			8.3			(4.0		)	—			334.7
Interest and other income	2.2			0.1			81.1			(81.0		)	2.4
Income from unconsolidated affiliates	0.1			5.5			—			—			5.6
Loss on early extinguishment of debt	—			—			(0.6		)	—			(0.6		)
Interest expense	(71.1		)	(9.4		)	(83.4		)	81.0			(82.9		)
Income (loss) before income taxes	84.0			169.3			(12.7		)	—			240.6
Income tax (provision) benefit	(32.4		)	(59.2		)	5.1			—			(86.5		)
Net income (loss)	51.6			110.1			(7.6		)	—			154.1
Net income attributable to noncontrolling interest	—			(2.7		)	—			—			(2.7		)
Net income (loss) attributable to QEP ⁽³⁾	$	51.6		$	107.4		$	(7.6	)	$	—		$	151.4

____________________________


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


⁽²⁾	Operating (loss) income for the nine months ended September 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the nine months ended September 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 nine months ended September 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

The following table is a summary of operating results for the nine months ended September 30, 2011, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	1,587.3		$	273.9		$	444.7		$	—		$	2,305.9
From affiliated customers	—			64.5			426.8			(491.3		)	—
Total Revenues	1,587.3			338.4			871.5			(491.3		)	2,305.9
Operating expenses
Purchased gas, oil and NGL expense	362.8			—			862.4			(421.9		)	803.3
Lease operating expense	106.4			—			—			(2.3		)	104.1
Natural gas, oil and NGL transportation and other handling costs	130.8			4.6			—			(62.2		)	73.2
Gathering, processing and other	—			78.3			1.1			—			79.4
General and administrative	69.8			22.4			1.8			(4.9		)	89.1
Production and property taxes	73.9			4.4			0.2			—			78.5
Depreciation, depletion and amortization	524.0			40.7			1.7			—			566.4
Other operating expenses	23.9			—			—			—			23.9
Total operating expenses	1,291.6			150.4			867.2			(491.3		)	1,817.9
Net gain (loss) from asset sales	1.4			—			—			—			1.4
Operating income ⁽²⁾	297.1			188.0			4.3			—			489.4
Interest and other income	(0.5		)	—			74.2			(74.2		)	(0.5		)
Income from unconsolidated affiliates	0.1			4.4			—			—			4.5
Loss on extinguishment of debt	—			—			(0.7		)	—			(0.7		)
Interest expense	(60.8		)	(10.4		)	(70.0		)	74.2			(67.0		)
Income before income taxes	235.9			182.0			7.8			—			425.7
Income taxes	(87.7		)	(65.6		)	(2.7		)	—			(156.0		)
Net income	148.2			116.4			5.1			—			269.7
Net income attributable to noncontrolling interest	—			(2.2		)	—			—			(2.2		)
Net income attributable to QEP ⁽³⁾	$	148.2		$	114.2		$	5.1		$	—		$	267.5

____________________________

⁽¹⁾

Revenues for the nine months ended September 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 nine months ended September 30, 2011, reflect the impact of QEP’s settled derivative contracts. See Note 7 - Derivative Contracts for detailed information on derivative contract settlements in the nine months ended September 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 nine months ended September 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 nine months ended September 30, 2011.

The following table is a summary of balance sheet information by line of business:



	QEP Energy		QEP Field Services		QEP Marketing & Other		Eliminations		QEP Consolidated
	(in millions)
Total assets as of September 30, 2012	$	7,416.1	$	1,362.7	$	217.3	$	—	$	8,996.1
Total assets as of December 31, 2011	5,815.7		1,312.7		314.3		—		7,442.7

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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-Publisher FASB

-Name Accounting Standards Codification

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+ Details

Basis of Presentation of Interim Consolidated Financial Statements (Policies)

9 Months Ended

Sep. 30, 2012

De-designation of commodity derivative contracts

Transportation and other handling costs



	Three Months Ended September 30, 2011							Nine Months Ended September 30, 2011
	As reported ⁽¹⁾		As revised		Change			As reported ⁽¹⁾		As revised		Change
	(in millions)							(in millions)
REVENUES
Natural gas sales	$	266.7	$	309.8	$	43.1		$	795.8	$	921.1	$	125.3
Oil sales	76.1		76.9		0.8			218.4		220.6		2.2
NGL sales	75.7		79.3		3.6			183.1		191.0		7.9
Gathering, processing and other	77.1		57.1		(20.0		)	224.8		162.6		(62.2		)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs	—		27.5		27.5			—		73.2		73.2

____________________________

⁽¹⁾

Impairment of long-lived assets

Impairment of oil and gas properties

New accounting pronouncements

Disclosure of accounting policy for its derivative instruments and hedging activities.

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-Name Statement of Financial Accounting Standard (FAS)

-Number 133

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+ Details

Disclosure of accounting policy for recognizing and measuring the impairment of long-lived assets. An entity also may disclose its accounting policy for long-lived assets to be sold. This policy excludes goodwill and intangible assets.

+ References+ Details

Disclosure of accounting policy for the classification of shipping and handling costs, including whether the costs are included in cost of sales or included in other income statement accounts. If shipping and handling fees are significant and are not included in cost of sales, disclosure includes both the amounts of such costs and the line item on the income statement which includes such costs.

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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+ Details

Basis of Presentation of Interim Consolidated Financial Statements (Tables)

9 Months Ended

Sep. 30, 2012

Impact of change in transportation and other handling costs



	Three Months Ended September 30, 2011							Nine Months Ended September 30, 2011
	As reported ⁽¹⁾		As revised		Change			As reported ⁽¹⁾		As revised		Change
	(in millions)							(in millions)
REVENUES
Natural gas sales	$	266.7	$	309.8	$	43.1		$	795.8	$	921.1	$	125.3
Oil sales	76.1		76.9		0.8			218.4		220.6		2.2
NGL sales	75.7		79.3		3.6			183.1		191.0		7.9
Gathering, processing and other	77.1		57.1		(20.0		)	224.8		162.6		(62.2		)
OPERATING EXPENSES
Natural gas, oil and NGL transportation and other handling costs	—		27.5		27.5			—		73.2		73.2

____________________________

⁽¹⁾

Fair value of financial assets and liabilities

Tabular disclosure of prior period adjustments to previously issued financial statements including (1) the effect of the correction on each financial statement line item and any per-share amounts affected for each prior period presented (2) the cumulative effect of the change on retained earnings or other appropriate components of equity or net assets in the statement of financial position, as of the beginning of the earliest period presented, and (3) the effect of the prior period adjustments (both gross and net of applicable income tax) on the net income of each prior period presented in the entity's annual report for the year in which the adjustments are made.

+ References+ Details

Fair Value Measurements (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Fair Value Disclosures [Abstract]

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



	Fair Value Measurements
	September 30, 2012
	Level 1		Level 2		Level 3		Netting Adjustments			Total
			(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	199.4	$	—	$	(12.2	)	$	187.2
Commodity derivative instruments - long-term	—		38.2		—		(3.0		)	$	35.2
Total financial assets	$	—	$	237.6	$	—	$	(15.2	)	$	222.4

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	12.3	$	—	$	(12.2	)	$	0.1
Interest rate swaps - short-term	—		2.6		—		—			$	2.6
Commodity derivative instruments - long-term	—		3.0		—		(3.0		)	$	—
Interest rate swaps - long-term	—		4.1		—		—			$	4.1
Total financial liabilities	$	—	$	22.0	$	—	$	(15.2	)	$	6.8

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 nine months ended September 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 September 30,	$	—

Fair value and related carrying amount of certain financial instruments



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	September 30, 2012				December 31, 2011
	(in millions)
Financial liabilities
Checks outstanding in excess of cash balances	$	27.5	$	27.5	$	29.4	$	29.4
Long-term debt	$	3,180.7	$	3,330.4	$	1,679.4	$	1,754.9

Tabular disclosure related to assets and liabilities by class, including financial instruments measured at fair value that are classified in shareholders' equity, if any, that are measured at fair value on a recurring and/or nonrecurring basis in periods after initial recognition. Disclosures include, but are not limited to: (a) the fair value measurements recorded and the reasons for the measurements and (b) the level within the fair value hierarchy in which the fair value measurements are categorized in their entirety (levels 1, 2, 3) as well as transfers between levels 1 and 2.

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+ Details

Tabular disclosure of the fair value measurement of assets using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets) and gains or losses recognized in other comprehensive income (loss), and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issues, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs), by class of asset.

+ References+ Details

Tabular disclosure of the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such certain disclosures about the financial instruments, assets, and liabilities include: (1) the fair value of the required items together with their carrying amounts (as appropriate) and (2) the methodology and assumptions used in developing such estimates of fair value.

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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+ Details

Derivative Contracts (Tables)

9 Months Ended

Sep. 30, 2012

Derivative Volumes and Average Prices

QEP Energy Derivative Contracts

The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative contracts as of September 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	19.3	$	4.72
2012	Swap	IFPEPL (1)	1.8	$	4.70
2012	Swap	IFNPCR (2)	22.1	$	4.67
2012	Swap	IFCNPTE (3)	2.8	$	2.66
2013	Swap	NYMEX	29.2	$	3.68
2013	Swap	IFNPCR (2)	65.7	$	5.66
Oil sales			(Bbls)
2012	Swap	NYMEX WTI	1.3	$	97.42
2012	Collar	NYMEX WTI	0.4			$	87.50	$	115.36
2013	Swap	NYMEX WTI	5.1	$	98.48
2014	Swap	NYMEX WTI	1.8	$	92.72
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane	3.9	$	0.64
2012	Swap	Mt. Belvieu Propane	5.8	$	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



Year	Type of Contract	Index	Total Volumes	Average Swap price per gallon
			(in millions)
NGL sales			(Gals)
2012	Swap	Mt. Belvieu Ethane	3.9	$	0.64
2012	Swap	Mt. Belvieu Propane	1.9	$	1.28

QEP Marketing Derivative Contracts



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2012	Swap	IFNPCR (1)	2.1	$	3.93
2013	Swap	IFNPCR (1)	3.1	$	3.77
Natural gas purchases			(MMBtu)
2012	Swap	IFNPCR (1)	1.5	$	2.76
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 September 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



		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	199.4	$	284.1	$	12.3	$	11.7
Interest rate swaps	Fair value of derivative contracts	—		—		2.6		—
Long-term:
Commodity	Fair value of derivative contracts	38.2		123.5		3.0		—
Interest rate swaps	Fair value of derivative contracts	—		—		4.1		—
Total derivative instruments		$	237.6	$	407.6	$	22.0	$	11.7

Effects of Derivative Transactions

The effects and location of the change in fair value and settlement of QEP's derivative contracts on the Condensed Consolidated Statements of Operations are summarized in the following tables:



Derivative instruments not designated as cash flow hedges	Location of gain (loss) recognized in earnings	Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2012			2011			2012			2011
		(in millions)
Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		$	86.2		$	(27.9	)	$	283.8		$	(86.7	)
Oil derivative contracts		2.7			—			2.2			—
NGL derivative contracts		3.4			—			6.5			—
QEP Field Services
NGL derivative contracts		1.9			—			6.3			—
QEP Marketing
Natural gas derivative contracts		(0.4		)	—			3.7			—
Total realized gain (loss) on commodity derivative contracts		93.8			(27.9		)	302.5			(86.7		)
Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts		(50.6		)	27.9			3.3			86.7
Oil derivative contracts		4.1			—			31.2			—
NGL derivative contracts		(4.4		)	—			3.4			—
QEP Field Services
NGL derivative contracts		(2.5		)	—			2.0			—
QEP Marketing
Natural gas derivative contracts		(1.4		)	—			(0.5		)	—
Total unrealized (loss) gain on commodity derivative contracts		(54.8		)	27.9			39.4			86.7
Total realized and unrealized gain on commodity derivative contracts		$	39.0		$	—		$	341.9		$	—
Realized gain (loss) on interest rate swaps
Realized loss on interest rate swaps		$	(0.6	)	$	—		$	(0.6	)	$	—
Unrealized gain (loss) on interest rate swaps
Unrealized loss on interest rate swaps		(2.3		)	—			(6.6		)	—
Total realized and unrealized loss on interest rate swaps		$	(2.9	)	$	—		$	(7.2	)	$	—

Grand Total	Realized and unrealized gains on derivative contracts	$	36.1		$	—		$	334.7		$	—



Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	Three Months Ended					Nine Months Ended
		September 30,					September 30,
		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	$	—	$	129.6		$	—	$	191.1
Gain reclassified from AOCI into income for effective portion of hedge	Natural gas sales	—		71.6			—		209.1
Gain reclassified from AOCI into income for effective portion of hedge	Oil sales	—		0.9			—		1.0
Gain reclassified from AOCI into income for effective portion of hedge	NGL sales	—		(0.3		)	—		(0.3		)
Gain reclassified from AOCI into income for effective portion of hedge	Marketing sales	—		—			—		—
Gain reclassified from AOCI into income for effective portion of hedge	Marketing purchases	—		0.4			—		4.3
Gain recognized in income for the ineffective portion of hedges	Interest and other income	—		(2.7		)	—		(2.6		)

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

+ References+ Details

Reconciliation of QEP Energy's restructuring cost

Tabular disclosure of the location and fair value amounts of derivative instruments (and nonderivative instruments that are designated and qualify as hedging instruments) reported in the statement of financial position.

+ References+ Details

Restructuring Costs (Tables)

9 Months Ended

Sep. 30, 2012

Restructuring Costs [Abstract]



	QEP Energy		QEP Field Services		QEP Marketing		Total
Restructuring costs expected to be incurred	(in millions)
One-time termination benefits	$	3.4	$	—	$	0.3	$	3.7
Retention & relocation expense	5.5		0.2		0.2		5.9
Lease termination costs	0.6		—		—		0.6
Total restructuring costs expected to be incurred	$	9.5	$	0.2	$	0.5	$	10.2

Total restructuring costs recognized in income during the current period
During the three months ended September 30, 2012
One-time termination benefits	$	0.2	$	—	$	—	$	0.2
Retention & relocation expense	—		—		—		—
Lease termination costs	—		—		—		—
Total restructuring costs incurred for the three months ended September 30, 2012	$	0.2	$	—	$	—	$	0.2

During the nine months ended September 30, 2012
One-time termination benefits	$	2.1	$	—	$	—	$	2.1
Retention & relocation expense	3.2		—		—		3.2
Lease termination costs	—		—		—		—
Total restructuring costs incurred for the nine months ended September 30, 2012	$	5.3	$	—	$	—	$	5.3

Schedule of Restructuring Reserve by Type of Cost [Table Text Block]



	QEP Energy			QEP Field Services		QEP Marketing		Total
	(in millions)
Balance at December 31, 2011	$	—		$	—	$	—	$	—
Costs incurred and charged to expense	5.3			—		—		5.3
Costs paid or otherwise settled	(5.1		)	—		—		(5.1		)
Balance at September 30, 2012	$	0.2		—		—		$	0.2

Tabular disclosure of restructuring and related costs by type of restructuring including the description of the restructuring costs, such as the expected cost; the costs incurred during the period; the cumulative costs incurred as of the balance sheet date; the income statement caption within which the restructuring charges recognized for the period are included; and changes to an entity's restructuring reserve that occurred during the period associated with the exit from or disposal of business activities or restructurings for each major type of cost.

+ References+ Details

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

Tabular disclosure of an entity's restructuring reserve that occurred during the period associated with the exit from or disposal of business activities or restructurings for each major type of cost. This element may also include a description of any reversal and other adjustment made during the period to the amount of an accrued liability for restructuring activities. This element may be used to encapsulate the roll forward presentations of an entity's restructuring reserve by type of cost and in total, and explanation of changes that occurred in the period.

+ References+ Details

Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2012

Share-based Compensation [Abstract]

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



	Stock Option Variables
	Nine Months Ended
	September 30, 2012
Fair value of options at grant date	$	14.29
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	301,035		30.76
Exercised	(336,675	)	9.21
Forfeited	—		—		—
Outstanding at September 30, 2012	1,968,054		$	24.74	3.4	$	15.1
Options Exercisable at September 30, 2012	1,505,051		$	22.38	2.6	$	14.6
Unvested Options at September 30, 2012	463,003		$	32.43	5.9	$	0.2

Restricted Shares and Performance Share Units Activity

Restricted Shares

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	778,780		30.59
Vested	(538,668	)	31.88
Forfeited	(61,502	)	32.70
Unvested balance at September 30, 2012	1,278,362		$	31.85

Performance Share Units

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	179,304		30.90
Vested	—		—
Forfeited	(12,713	)	35.69
Unvested balance at September 30, 2012	281,865		$	34.03

Employee Benefits (Tables)

9 Months Ended

Sep. 30, 2012

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefit Costs



	Pension
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(in millions)
Service cost	$	1.1		$	0.7		$	3.0		$	2.1
Interest cost	1.3			1.2			3.7			3.4
Expected return on plan assets	(0.9		)	(0.7		)	(2.7		)	(1.9		)
Amortization of prior service costs	1.3			1.4			3.9			4.0
Amortization of actuarial loss	0.6			—			1.0			—
Periodic expense	$	3.4		$	2.6		$	8.9		$	7.6



	Postretirement benefits
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(in millions)
Service cost	$	0.1	$	0.1	$	0.1	$	0.1
Interest cost	—		—		0.2		0.2
Expected return on plan assets	—		—		—		—
Amortization of prior service costs	0.1		0.1		0.3		0.3
Recognized net actuarial loss	—		—		—		—
Periodic expense	$	0.2	$	0.2	$	0.6	$	0.6

Operations by Line of Business (Tables)

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Summary of operating results by line of business

The following table is a summary of operating results for the three months ended September 30, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	374.0		$	77.9		$	90.5		$	—		$	542.4
From affiliated customers	—			31.8			145.8			(177.6		)	—
Total Revenues	374.0			109.7			236.3			(177.6		)	542.4
Operating expenses
Purchased gas, oil and NGL expense	45.9			4.9			236.7			(144.9		)	142.6
Lease operating expense	43.1			—			—			(0.9		)	42.2
Natural gas, oil and NGL transportation and other handling costs	59.8			6.9			—			(30.4		)	36.3
Gathering, processing and other	—			21.8			0.1			0.2			22.1
General and administrative	32.2			10.6			0.5			(1.6		)	41.7
Production and property taxes	22.5			1.7			0.1			—			24.3
Depreciation, depletion and amortization	217.4			15.8			0.9			—			234.1
Other operating expenses	11.7			—			—			—			11.7
Total operating expenses	432.6			61.7			238.3			(177.6		)	555.0
Operating (loss) income ⁽²⁾	(58.6		)	48.0			(2.0		)	—			(12.6		)
Realized and unrealized gains (losses) on derivative contracts	41.4			(0.6		)	(4.7		)	—			36.1
Interest and other income	(0.2		)	—			28.4			(28.4		)	(0.2		)
Income from unconsolidated affiliates	—			2.3			—			—			2.3
Interest expense	(24.1		)	(3.5		)	(30.8		)	28.4			(30.0		)
(Loss) income before income taxes	(41.5		)	46.2			(9.1		)	—			(4.4		)
Income tax benefit (provision)	15.3			(16.5		)	3.5			—			2.3
Net (loss) income	(26.2		)	29.7			(5.6		)	—			(2.1		)
Net income attributable to noncontrolling interest	—			(1.0		)	—			—			(1.0		)
Net (loss) income attributable to QEP ⁽³⁾	$	(26.2	)	$	28.7		$	(5.6	)	$	—		$	(3.1	)

____________________________


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


⁽²⁾	Operating (loss) income for the three months ended September 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the three months ended September 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 three months ended September 30, 2012 includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

The following table is a summary of operating results for the three months ended September 30, 2011, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	635.6		$	98.6		$	145.7		$	—		$	879.9
From affiliated customers	—			21.0			148.5			(169.5		)	—
Total Revenues	635.6			119.6			294.2			(169.5		)	879.9
Operating expenses
Purchased gas, oil and NGL expenses	208.1			—			292.0			(147.4		)	352.7
Lease operating expense	38.0			—			—			(1.0		)	37.0
Natural gas, oil and NGL transportation and other handling costs	45.0			2.5			—			(20.0		)	27.5
Gathering, processing and other	—			26.6			0.4			—			27.0
General and administrative	23.0			6.6			0.2			(1.1		)	28.7
Production and property taxes	26.3			1.4			—			—			27.7
Depreciation, depletion and amortization	174.4			14.0			0.6			—			189.0
Other operating expenses	8.1			—			—			—			8.1
Total operating expenses	522.9			51.1			293.2			(169.5		)	697.7
Net gain (loss) from asset sales	1.2			(0.1		)	0.1			—			1.2
Operating income ⁽²⁾	113.9			68.4			1.1			—			183.4
Interest and other (loss) income	(0.7		)	—			25.0			(25.0		)	(0.7		)
Income from unconsolidated affiliates	—			2.3			—			—			2.3
Loss on early extinguishment of debt	—			—			(0.7		)	—			(0.7		)
Interest expense	(20.5		)	(3.8		)	(23.5		)	25.0			(22.8		)
Income before income taxes	92.7			66.9			1.9			—			161.5
Income taxes	(34.4		)	(24.0		)	(0.7		)	—			(59.1		)
Net income	58.3			42.9			1.2			—			102.4
Net income attributable to noncontrolling interest	—			(0.9		)	—			—			(0.9		)
Net income attributable to QEP ⁽³⁾	$	58.3		$	42.0		$	1.2		$	—		$	101.5

____________________________

⁽¹⁾


⁽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 September 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 September 30, 2011.

The following table is a summary of operating results for the nine months ended September 30, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	1,106.3		$	254.9		$	283.7		$	—		$	1,644.9
From affiliated customers	—			88.1			396.3			(484.4		)	—
Total Revenues	1,106.3			343.0			680.0			(484.4		)	1,644.9
Operating expenses
Purchased gas, oil and NGL expense	159.0			9.0			681.7			(393.8		)	455.9
Lease operating expense	125.3			—			—			(2.5		)	122.8
Natural gas, oil and NGL transportation and other handling costs	167.4			27.7			—			(83.6		)	111.5
Gathering, processing and other	—			65.6			0.8			—			66.4
General and administrative	94.3			24.1			0.6			(4.5		)	114.5
Production and property taxes	63.6			4.6			0.2			—			68.4
Depreciation, depletion and amortization	597.7			47.2			2.5			—			647.4
Other operating expenses	78.1			—			—			—			78.1
Total operating expenses	1,285.4			178.2			685.8			(484.4		)	1,665.0
Net gain from asset sales	1.5			—			—			—			1.5
Operating (loss) income ⁽²⁾	(177.6		)	164.8			(5.8		)	—			(18.6		)
Realized and unrealized gains (losses) on derivative contracts	330.4			8.3			(4.0		)	—			334.7
Interest and other income	2.2			0.1			81.1			(81.0		)	2.4
Income from unconsolidated affiliates	0.1			5.5			—			—			5.6
Loss on early extinguishment of debt	—			—			(0.6		)	—			(0.6		)
Interest expense	(71.1		)	(9.4		)	(83.4		)	81.0			(82.9		)
Income (loss) before income taxes	84.0			169.3			(12.7		)	—			240.6
Income tax (provision) benefit	(32.4		)	(59.2		)	5.1			—			(86.5		)
Net income (loss)	51.6			110.1			(7.6		)	—			154.1
Net income attributable to noncontrolling interest	—			(2.7		)	—			—			(2.7		)
Net income (loss) attributable to QEP ⁽³⁾	$	51.6		$	107.4		$	(7.6	)	$	—		$	151.4

____________________________


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


⁽²⁾	Operating (loss) income for the nine months ended September 30, 2012, excludes the impact of realized commodity derivative contract settlements. During the nine months ended September 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 nine months ended September 30, 2012, includes the impact of unrealized gains and losses from changes in the fair value of the commodity derivative contracts.

The following table is a summary of operating results for the nine months ended September 30, 2011, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	1,587.3		$	273.9		$	444.7		$	—		$	2,305.9
From affiliated customers	—			64.5			426.8			(491.3		)	—
Total Revenues	1,587.3			338.4			871.5			(491.3		)	2,305.9
Operating expenses
Purchased gas, oil and NGL expense	362.8			—			862.4			(421.9		)	803.3
Lease operating expense	106.4			—			—			(2.3		)	104.1
Natural gas, oil and NGL transportation and other handling costs	130.8			4.6			—			(62.2		)	73.2
Gathering, processing and other	—			78.3			1.1			—			79.4
General and administrative	69.8			22.4			1.8			(4.9		)	89.1
Production and property taxes	73.9			4.4			0.2			—			78.5
Depreciation, depletion and amortization	524.0			40.7			1.7			—			566.4
Other operating expenses	23.9			—			—			—			23.9
Total operating expenses	1,291.6			150.4			867.2			(491.3		)	1,817.9
Net gain (loss) from asset sales	1.4			—			—			—			1.4
Operating income ⁽²⁾	297.1			188.0			4.3			—			489.4
Interest and other income	(0.5		)	—			74.2			(74.2		)	(0.5		)
Income from unconsolidated affiliates	0.1			4.4			—			—			4.5
Loss on extinguishment of debt	—			—			(0.7		)	—			(0.7		)
Interest expense	(60.8		)	(10.4		)	(70.0		)	74.2			(67.0		)
Income before income taxes	235.9			182.0			7.8			—			425.7
Income taxes	(87.7		)	(65.6		)	(2.7		)	—			(156.0		)
Net income	148.2			116.4			5.1			—			269.7
Net income attributable to noncontrolling interest	—			(2.2		)	—			—			(2.2		)
Net income attributable to QEP ⁽³⁾	$	148.2		$	114.2		$	5.1		$	—		$	267.5

____________________________

⁽¹⁾


⁽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 nine months ended September 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 nine months ended September 30, 2011.

The following table is a summary of balance sheet information by line of business:



	QEP Energy		QEP Field Services		QEP Marketing & Other		Eliminations		QEP Consolidated
	(in millions)
Total assets as of September 30, 2012	$	7,416.1	$	1,362.7	$	217.3	$	—	$	8,996.1
Total assets as of December 31, 2011	5,815.7		1,312.7		314.3		—		7,442.7

De-designation of commodity derivative contracts [Abstract]

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References+ Details

Basis of Presentation of Interim Consolidated Financial Statements (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Unrealized gain (Loss) on derivatives contract

$ (57.1)

$ 32.8

$ 86.7

REVENUES

170.3

309.8

470.4

921.1

117.7

76.9

335.7

220.6

67.5

79.3

247.0

191.0

46.3

57.1

141.9

162.6

Natural gas, oil and NGL transportation and other handling costs

36.3

27.5

111.5

73.2

QEP Field Services [Member]

REVENUES

34.1

67.8

118.7

340.1

Prior periods presentation of revenues [Member]

REVENUES

266.7

^[1]

795.8

^[1]

76.1

^[1]

218.4

^[1]

75.7

^[1]

183.1

^[1]

77.1

^[1]

224.8

^[1]

Natural gas, oil and NGL transportation and other handling costs

^[1]

Prior periods presentation of revenues [Member] | QEP Field Services [Member]

REVENUES

41.6

115.3

Restatement Adjustment [Member]

REVENUES

43.1

125.3

0.8

2.2

3.6

7.9

(20.0)

(62.2)

Natural gas, oil and NGL transportation and other handling costs

$ 27.5

$ 73.2

[1]

Cost incurred during the reporting period in transporting goods and services to customers. Includes freight-out costs.

Reference 1: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 235

-SubTopic 10

-Section 50

-Paragraph 3

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Reference 2: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

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-Paragraph 1

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Reference 3: http://www.xbrl.org/2003/role/presentationRef

-Publisher AICPA

-Name Accounting Principles Board Opinion (APB)

-Number 22

-Paragraph 8

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 605

-SubTopic 45

-Section 50

-Paragraph 2

-URI http://asc.fasb.org/extlink&oid=6408196&loc=d3e61069-111654

Reference 5: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Handling Costs

-URI http://asc.fasb.org/extlink&oid=6514758

Reference 6: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 605

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-Paragraph 20

-URI http://asc.fasb.org/extlink&oid=21915142&loc=d3e60635-111653

Reference 7: http://www.xbrl.org/2003/role/presentationRef

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-Name Accounting Standards Codification

-Topic 605

-SubTopic 45

-Section S99

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6408413&loc=d3e221937-122793

Reference 8: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Shipping Costs

-URI http://asc.fasb.org/extlink&oid=6525344

Reference 9: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 00-10

-Paragraph 6

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Basis of Presentation of Interim Consolidated Financisl Statements (Impairments) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		$ 68.7
Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	7.3	49.3
Southern Region [Member] \| Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		60.0
Northern Region [Member] \| Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		$ 8.7

The expense recorded to reduce the value of oil and gas assets consisting of proved properties and unproved properties as the estimate of future successful production from these properties is reduced.

+ References+ Details

Acquisitions (Details) (USD $) In Millions, unless otherwise specified	Sep. 27, 2012
Business Combination, Consideration Given [Abstract]
Cash Paid at Closing	$ 1,394.2
Total estimate consideration given	1,394.2
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net [Abstract]
Proved properties	707.6
Unproved Properties	686.5
Asset retirement obligations	(0.6)
Other assets	$ 0.7

The amount of acquisition cost of a business combination allocated to mineral rights for acquired entities in the mining industry.

+ References+ Details

Earnings Per Share (Details) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Earnings Per Share [Abstract]
Anti-dilutive shares not included in diluted common share outstanding (in shares)	0.8
Weighted-average basic common shares outstanding (in shares)	177.9	176.6	177.6	176.5
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan	0	1.9	1.0	2.0
Average diluted common shares outstanding (in shares)	177.9	178.5	178.6	178.5

Securities (including those issuable pursuant to contingent stock agreements) that could potentially dilute basic earnings per share (EPS) or earnings per unit (EPU) in the future that were not included in the computation of diluted EPS or EPU because to do so would increase EPS or EPU amounts or decrease loss per share or unit amounts for the period presented.

Reference 1: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Antidilution

-URI http://asc.fasb.org/extlink&oid=6505113

Reference 2: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Diluted Earnings Per Share

-URI http://asc.fasb.org/extlink&oid=6510752

Reference 3: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Contingent Stock Agreement

-URI http://asc.fasb.org/extlink&oid=6508534

Reference 4: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 260

-SubTopic 10

-Section 50

-Paragraph 1

-Subparagraph (c)

-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 40

-Subparagraph c

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 13, 14

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 07-4

-Paragraph 4

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 171

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

The average number of shares or units issued and outstanding that are used in calculating diluted EPS or earnings per unit (EPU), determined based on the timing of issuance of shares or units in the period.

+ References+ Details

Number of [basic] shares or units, after adjustment for contingently issuable shares or units and other shares or units not deemed outstanding, determined by relating the portion of time within a reporting period that common shares or units have been outstanding to the total time in that period.

Reference 1: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 260

-SubTopic 10

-Section 50

-Paragraph 1

-Subparagraph (a)

-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 2: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 07-4

-Paragraph 4

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 171

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 40

-Subparagraph a

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 260

-SubTopic 10

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-Paragraph 10

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Reference 6: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 8

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Weighted-Average Number of Common Shares Outstanding

-URI http://asc.fasb.org/extlink&oid=6528421

+ Details

Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	$ 163.9
Accretion	7.7
Liabilities incurred	5.2
Liabilities settled	(0.2)
ARO liability, Ending Balance	$ 176.6

The carrying amount of a liability for an asset retirement obligation. An asset retirement obligation is a legal obligation associated with the disposal or retirement of a tangible long-lived asset that results from the acquisition, construction or development, or the normal operations of a long-lived asset, except for certain obligations of lessees.

+ References+ Details

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Amount of accretion expense recognized during the period that is associated with an asset retirement obligation. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.

+ References+ Details

Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended		3 Months Ended	9 Months Ended																				9 Months Ended										9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 Proved properties [Member]	Sep. 30, 2012 Proved properties [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Commodity derivative [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Commodity derivative [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Interest Rate Swap [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Carrying Amount [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Carrying Amount [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Sep. 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]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 1 [Member] Interest Rate Swap [Member]	Sep. 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]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Sep. 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]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 2 [Member] Interest Rate Swap [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Sep. 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]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Level 3 [Member] Interest Rate Swap [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Sep. 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]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member] Interest Rate Swap [Member]	Sep. 30, 2012 Fair Value, Measurements, Nonrecurring [Member] Level 3 [Member] Proved properties [Member]
Financial Assets
Derivative instruments - short-term							$ 187.2	$ 273.7						$ 0	$ 0						$ 199.4	$ 284.1				$ 0	$ 0				$ (12.2)	$ (10.4)
Derivative instruments - long-term							35.2	123.5						0	0						38.2	123.5				0	0				(3.0)	0
Total financial assets					222.4	397.2						0	0						237.6	407.6				0	0				(15.2)	(10.4)
Financial liabilities
Derivative instruments - short-term							0.1	1.3	2.6					0	0	0					12.3	11.7	2.6			0	0	0			(12.2)	(10.4)	0
Derivative instruments - long-term	4.1	0					0	0	4.1					0	0	0					3.0	0	4.1			0	0	0			(3.0)	0	0
Total financial liabilities					6.8	1.3						0	0						22.0	11.7				0	0				(15.2)	(10.4)
Checks outstanding in excess of cash balances										27.5	29.4						27.5	29.4
Long-term debt										3,180.7	1,679.4						3,330.4	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
Impairment of Oil and Gas Properties	68.7		7.3	49.3																														49.3
Proved properties, estimated fair values																																		$ 36.7

Derivative Contracts (Details) (USD $)
In Millions, unless otherwise specified

9 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Forecasted production from proved reserves (in hundredths)

100.00%

Unrealized gains on derivative contracts

$ 182.9

Unrealized gains on derivative contracts, net of tax

114.9

300.0

Total principal amount of debt

3,185.8

1,684.9

Fair Value of Derivative Contracts, Gross [Abstract]

300.0

237.6

407.6

Fair Value of Derivative Contracts, Gross [Abstract]

22.0

11.7

Commodity Contract [Member] | Short-term [Member]

199.4

284.1

Fair Value of Derivative Contracts, Gross [Abstract]

12.3

11.7

Commodity Contract [Member] | Long-term [Member]

38.2

123.5

3.0

Commodity Contract [Member] | Oil Sales (Bbls) [Member] | 2012 [Member] | NYMEX WTI [Member]

2012

NYMEX WTI

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

400,000

Collars Floor Price ($ per unit)

87.50

Collars Ceiling Price ($ per unit)

115.36

Interest Rate Swap [Member] | Short-term [Member]

Fair Value of Derivative Contracts, Gross [Abstract]

Fair Value of Derivative Contracts, Gross [Abstract]

2.6

Interest Rate Swap [Member] | Long-term [Member]

4.1

Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2012 [Member] | NYMEX [Member]

2012

NYMEX

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

19,300,000

4.72

Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2012 [Member] | IFPEPL [Member]

2012

IFPEPL (1)

^[1]

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

1,800,000

4.70

Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2012 [Member] | IFNPCR [Member]

2012

IFNPCR (2)

^[2]

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

22,100,000

4.67

Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2012 [Member] | IFCNPTE [Member]

2012

IFCNPTE (3)

^[3]

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

2,800,000

2.66

Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2013 [Member] | IFNPCR [Member]

2013

IFNPCR (2)

^[2]

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

65,700,000

5.66

Swap [Member] | Natural Gas Sales (MMbtu) [Member] | 2013 [Member] | NYMEX WTI [Member]

2013

NYMEX

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

29,200,000

3.68

Swap [Member] | Oil Sales (Bbls) [Member] | 2012 [Member] | NYMEX WTI [Member]

2012

NYMEX WTI

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

1,300,000

97.42

Swap [Member] | Oil Sales (Bbls) [Member] | 2013 [Member] | NYMEX WTI [Member]

2013

NYMEX WTI

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

5,100,000

98.48

Swap [Member] | Oil Sales (Bbls) [Member] | 2014 [Member] | NYMEX WTI [Member]

2014

NYMEX WTI

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

1,800,000

92.72

Swap [Member] | NGL Sales [Member] | 2012 [Member] | Mt. Belvieu Ethane [Member]

2012

Mt. Belvieu Ethane

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

3,900,000

0.64

Swap [Member] | NGL Sales [Member] | 2012 [Member] | Mt. Belvieu Propane [Member]

2012

Mt. Belvieu Propane

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

5,800,000

1.28

Swap [Member] | QEP Field Services [Member] | 2012 [Member] | Mt. Belvieu Ethane [Member]

2012

Mt. Belvieu Ethane

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

3,900,000

0.64

Swap [Member] | QEP Field Services [Member] | 2012 [Member] | Mt. Belvieu Propane [Member]

2012

Mt. Belvieu Propane

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

1,900,000

1.28

Swap [Member] | QEP Marketing [Member] | 2012 [Member] | IFNPCR [Member]

2012

IFNPCR (1)

^[2]

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

2,100,000

3.93

Swap [Member] | QEP Marketing [Member] | 2013 [Member] | IFNPCR [Member]

2013

IFNPCR (1)

^[2]

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

3,100,000

Derivative Instruments and Hedging Activities Disclosure [Abstract]

3.77

Swap [Member] | QEP Resources [Member]

300.0

Fixed Rate Paid (in hundredths)

300.0

Maturity

Mar. 31, 2017

1.07%

Variable Rate Received

One month LIBOR

Swap [Member] | Purchased Gas and Oil Expense [Member] | 2012 [Member] | IFNPCR [Member]

2012

IFNPCR (1)

^[2]

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

1,500,000

2.76

Swap [Member] | Purchased Gas and Oil Expense [Member] | 2013 [Member] | IFNPCR [Member]

2013

IFNPCR (1)

^[2]

Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)

100,000

2.59

Term Loan due 2017 [Member]

Total principal amount of debt

$ 300.0

$ 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.

Derivative Contracts - Gain (Loss) in Statement of Financial Performance (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net [Abstract]
Fair value of frozen derivative to be settled and reclassified within twelve months			$ 97.7
Natural gas derivative contracts [Member] \| QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	86.2	(27.9)	283.8	(86.7)
Unrealized gain (loss) on commodity derivative contracts	(50.6)	27.9	3.3	86.7
Natural gas derivative contracts [Member] \| QEP Marketing [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(0.4)	0	3.7	0
Unrealized gain (loss) on commodity derivative contracts	(1.4)	0	(0.5)	0
Oil derivative contracts [Member] \| QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	2.7	0	2.2	0
Unrealized gain (loss) on commodity derivative contracts	4.1	0	31.2	0
NGL derivative contracts [Member] \| QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	3.4	0	6.5	0
Unrealized gain (loss) on commodity derivative contracts	(4.4)	0	3.4	0
NGL derivative contracts [Member] \| QEP Field Services [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	1.9	0	6.3	0
Unrealized gain (loss) on commodity derivative contracts	(2.5)	0	2.0	0
Interest Rate Swap [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(0.6)	0	(0.6)	0
Unrealized gain (loss) on commodity derivative contracts	(2.3)	0	(6.6)	0
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	(2.9)	0	(7.2)	0
Total gain (loss) on commodity derivative instruments	36.1	0	334.7	0
Other Comprehensive Income (Loss) [Member]
Gain (loss) 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	129.6	0	191.1
Natural Gas Sales (MMbtu) [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net [Abstract]
Gain reclassified from AOCI into income for effective portion of hedge	0	71.6	0	209.1
NGL Sales [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net [Abstract]
Gain reclassified from AOCI into income for effective portion of hedge	0	(0.3)	0	(0.3)
Oil Sales (Bbls) [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net [Abstract]
Gain reclassified from AOCI into income for effective portion of hedge	0	0.9	0	1.0
QEP Marketing [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net [Abstract]
Gain reclassified from AOCI into income for effective portion of hedge	0	0	0	0
Marketing Purchases [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net [Abstract]
Gain reclassified from AOCI into income for effective portion of hedge	0	0.4	0	4.3
Interest Income [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net [Abstract]
Gain recognized in income for the ineffective portion of hedges	0	(2.7)	0	(2.6)
Realized and unrealized gains on commodity derivative instruments [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	93.8	(27.9)	302.5	(86.7)
Unrealized gain (loss) on commodity derivative contracts	(54.8)	27.9	39.4	86.7
Total gain (loss) on commodity derivative instruments	$ 39.0	$ 0	$ 341.9	$ 0

Restructuring Costs (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		$ 10.2
Restructuring costs incurred to date	0.2	5.3
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2011		0
Costs paid or otherwise settled		(5.1)
Balance at September 30, 2012	0.2	0.2
Number of regional offices created		1
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		3.7
Restructuring costs incurred to date	0.2	2.1
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		5.9
Restructuring costs incurred to date	0	3.2
Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0.6
Restructuring costs incurred to date	0	0
QEP Energy [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		9.5
Restructuring costs incurred to date	0.2	5.3
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2011		0
Costs paid or otherwise settled		(5.1)
Balance at September 30, 2012	0.2	0.2
QEP Energy [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		3.4
Restructuring costs incurred to date	0.2	2.1
QEP Energy [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		5.5
Restructuring costs incurred to date	0	3.2
QEP Energy [Member] \| Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0.6
Restructuring costs incurred to date	0	0
QEP Field Services [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0.2
Restructuring costs incurred to date	0	0
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2011		0
Costs paid or otherwise settled		0
Balance at September 30, 2012	0	0
QEP Field Services [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0
Restructuring costs incurred to date	0	0
QEP Field Services [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0.2
Restructuring costs incurred to date	0	0
QEP Field Services [Member] \| Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0
Restructuring costs incurred to date	0	0
QEP Marketing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0.5
Restructuring costs incurred to date	0	0
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2011		0
Costs paid or otherwise settled		0
Balance at September 30, 2012	0	0
QEP Marketing [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0.3
Restructuring costs incurred to date	0	0
QEP Marketing [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0.2
Restructuring costs incurred to date	0	0
QEP Marketing [Member] \| Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		0
Restructuring costs incurred to date	$ 0	$ 0

Amount of costs incurred to date for the specified type of restructuring cost.

+ References+ Details

Amount expected to be charged against earnings in the current and future periods for the specified restructuring cost.

+ References+ Details

Amount of cash paid in the period to fully or partially settle a specified, previously accrued type of restructuring cost.

+ References+ Details

Debt (Details) (USD $)	3 Months Ended		9 Months Ended			9 Months Ended		9 Months Ended		9 Months Ended								9 Months Ended				3 Months Ended	9 Months Ended
Debt (Details) (USD $)	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Sep. 30, 2012 Revolving Credit Facility due 2016 [Member]	Dec. 31, 2011 Revolving Credit Facility due 2016 [Member]	Sep. 30, 2012 Term Loan due 2017 [Member]	Dec. 31, 2011 Term Loan due 2017 [Member]	Sep. 30, 2012 6.05% Senior Notes due 2016 [Member]	Dec. 31, 2011 6.05% Senior Notes due 2016 [Member]	Sep. 30, 2012 6.80% Senior Notes due 2018 [Member]	Dec. 31, 2011 6.80% Senior Notes due 2018 [Member]	Sep. 30, 2012 6.80% Senior Notes due 2020 [Member]	Dec. 31, 2011 6.80% Senior Notes due 2020 [Member]	Sep. 30, 2012 6.875% Senior Notes due 2021 [Member]	Dec. 31, 2011 6.875% Senior Notes due 2021 [Member]	Sep. 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]	Sep. 30, 2012 Senior Notes [Member]	Sep. 30, 2012 5.25% Senior Notes Due 2023 [Member]	Sep. 30, 2012 5.25% Senior Notes Due 2023 [Member]	Dec. 31, 2011 5.25% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	$ 3,185,800,000		$ 3,185,800,000		$ 1,684,900,000	$ 664,000,000	$ 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		$ 650,000,000	$ 650,000,000	$ 0
Less unamortized discount	(5,100,000)		(5,100,000)		(5,500,000)
Total long-term debt outstanding	3,180,700,000		3,180,700,000		1,679,400,000
Long-term debt, interest rate (in hundredths)										6.05%								5.375%				5.25%	5.25%
Maturity date of long-term debt						Aug. 25, 2016		Apr. 18, 2017		Sep. 01, 2016								Oct. 01, 2022					May 01, 2023
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		1 year
Weighted-average interest rate (in hundredths)						2.05%		2.02%
Debt Instrument, Face Amount																						650,000,000	650,000,000
Proceeds from Issuance of Long-term Debt			1,450,000,000	0																		640,800,000
Amount outstanding						664,000,000
Letters of credit outstanding						4,100,000
Proceeds from issuance of debt																		493,100,000
Debt issuance costs																		6,900,000				9,200,000	9,200,000
Senior notes repurchased																					6,700,000
Principal amount of senior notes outstanding	2,221,800,000		2,221,800,000
Debt Instrument, Maturity Date Range, Start			Sep. 01, 2016
Debt Instrument, Maturity Date Range, End			May 01, 2023
Non-cash loss on early extinguishment of debt	$ 0	$ 700,000	$ 600,000	$ 700,000
Senior Notes, stated interest rate, minimum (in hundredths)			5.25%
Senior Notes, stated interest rate, maximim (in hundredths)			6.875%

Environmental (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Environmental Exit Cost [Line Items]
Environmental Exit Costs, Anticipated Cost	$ 2.4
Environmental Costs Recognized, Capitalized	0.8
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

Name of the other party to the settlement agreement.

+ References+ Details

The effective date of a duly executed litigation settlement agreement.

+ References+ Details

Contingencies Schedule of Contingencies (Details) (Breach of Contract, Fiduciary Duty and Unjust Enrichment Claims [Member], Pending Litigation [Member], U.S. District Court for Utah [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Breach of Contract, Fiduciary Duty and Unjust Enrichment Claims [Member] \| Pending Litigation [Member] \| U.S. District Court for Utah [Member]
Loss Contingencies [Line Items]
Damages sought	$ 200

The value (monetary amount) of the award the plaintiff seeks in the legal matter.

Reference 1: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 450

-SubTopic 20

-Section 50

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14326-108349

Reference 2: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 5

-Paragraph 9

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 5

-Paragraph 10

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef

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-Name Accounting Standards Codification

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-Name Accounting Standards Codification

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-Subparagraph (a)

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-Name Statement of Financial Accounting Standard (FAS)

-Number 5

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Reference 7: http://www.xbrl.org/2003/role/presentationRef

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-Number 5

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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Share-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 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	$ 7.2	$ 5.7	$ 19.5	$ 16.5
Stock Options [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Fair value of options at grant date			$ 14.29
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)			301,035
Exercised (in shares)			(336,675)
Forfeited (in shares)			0
Outstanding at June 30, 2012 (in shares)	1,968,054		1,968,054
Options Excercisable (in shares)	1,505,051		1,505,051
Unvested Options (in shares)	463,003		463,003
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning (in dollars per share)			$ 21.23
Weighted-Average Price, Granted (in dollars per share)			$ 30.76
Weighted-Average Price, Exercised (in dollars per share)			$ 9.21
Weighted-Average Price, Forfeited (in dollars per share)			$ 0
Weighted-Average Price, Ending (in dollars per share)	$ 24.74		$ 24.74
Weighted-Average Price, Options Excercisable	$ 22.38		$ 22.38
Weighted-Average Price, Unvested Options	$ 32.43		$ 32.43
Weighted-Average Remaining Contractual Term, Outstanding			3 years 4 months 24 days
Aggregate Intrinsic Value, Outstanding	15.1		15.1
Weighted-Average Remaining Contractual Term, Options Excercisable			2 years 7 months 6 days
Aggregate Intrinsic Value, Options Excercisable	14.6		14.6
Weighted-Average Remaining Contractual Term, Unvested Options			5 years 10 months 24 days
Aggregate Intrinsic Value, Unvested Options	0.2		0.2
Intrinsic value of options exercised			7.1	2.7
Unrecognized compensation cost	3.6		3.6
Weighted-average period for recognition of compensation costs			2 years 2 months 12 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)			$ 30.59	$ 39.26
Weighted-Average Price, Vested (in dollars per share)			$ 31.88
Weighted-Average Price, Forfeited (in dollars per share)			$ 32.70
Weighted-Average Price, Ending Balance (in dollars per share)	$ 31.85		$ 31.85
Unrecognized compensation cost	21.1		21.1
Weighted-average period for recognition of compensation costs			2 years 2 months 12 days
Total fair value of stock that vested			16.6	11.5
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)			1,099,752
Granted (in shares)			778,780
Vested (in shares)			(538,668)
Forfeited (in shares)			(61,502)
Balance, Ending (in shares)	1,278,362		1,278,362
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)			$ 0.00
Weighted-Average Price, Forfeited (in dollars per share)			$ (35.69)
Weighted-Average Price, Ending Balance (in dollars per share)	$ 34.03		$ 34.03
Unrecognized compensation cost	$ 6.2		$ 6.2
Weighted-average period for recognition of compensation costs			2 years 1 month 17 days
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)			115,274
Granted (in shares)			179,304
Vested (in shares)			0
Forfeited (in shares)			(12,713)
Balance, Ending (in shares)	281,865		281,865

Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 1.1	$ 0.7	$ 3.0	$ 2.1
Interest cost	1.3	1.2	3.7	3.4
Expected return on plan assets	(0.9)	(0.7)	(2.7)	(1.9)
Amortization of prior service costs	1.3	1.4	3.9	4.0
Amortization of actuarial loss	0.6	0	1.0	0
Periodic expense	3.4	2.6	8.9	7.6
Pension [Member] \| Funded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan			4.9
Expected to contribute to pension plans	0.7		0.7
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	0.1	0.1	0.1	0.1
Interest cost	0	0	0.2	0.2
Expected return on plan assets	0	0	0	0
Amortization of prior service costs	0.1	0.1	0.3	0.3
Amortization of actuarial loss	0	0	0	0
Periodic expense	$ 0.2	$ 0.2	$ 0.6	$ 0.6

An amount calculated as a basis for determining the extent of delayed recognition of the effects of changes in the fair value of assets. The expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets.

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-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 87

-Paragraph 264

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Reference 2: http://www.xbrl.org/2003/role/presentationRef

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-Name Statement of Financial Accounting Standard (FAS)

-Number 106

-Paragraph 518

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Reference 3: http://www.xbrl.org/2003/role/presentationRef

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-Number 132R

-Paragraph 5

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Reference 4: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-SubTopic 30

-Glossary Expected Return on Plan Assets

-URI http://asc.fasb.org/extlink&oid=6512136

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-Glossary Expected Return on Plan Assets

-URI http://asc.fasb.org/extlink&oid=6512171

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-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e1928-114920

+ Details

The increase in a defined benefit pension plan's projected benefit obligation or a defined benefit postretirement plan's accumulated postretirement benefit obligation due to the passage of time.

+ References+ Details

The actuarial present value of benefits attributed by the pension benefit formula to services rendered by employees during the period. The portion of the expected postretirement benefit obligation attributed to employee service during the period. The service cost component is a portion of the benefit obligation and is unaffected by the funded status of the plan.

Reference 1: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 87

-Paragraph 264

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Reference 2: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 106

-Paragraph 518

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Reference 3: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-SubTopic 20

-Section 50

-Paragraph 1

-Subparagraph (h)(1)

-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e1928-114920

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-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

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Reference 5: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Service Cost (Component of Net Periodic Pension Cost)

-URI http://asc.fasb.org/extlink&oid=6525008

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-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-SubTopic 20

-Section 50

-Paragraph 1

-Subparagraph (a)(1)

-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e1928-114920

+ Details

Operations by Line of Business (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

$ 8,996.1

$ 7,442.7

Revenues

542.4

^[1]

879.9

^[2]

1,644.9

^[3]

2,305.9

^[4]

142.6

352.7

455.9

803.3

Natural gas, oil and NGL transportation and other handling costs

42.2

37.0

122.8

104.1

36.3

27.5

111.5

73.2

22.1

27.0

66.4

79.4

41.7

28.7

114.5

89.1

24.3

27.7

68.4

78.5

234.1

189.0

647.4

566.4

11.7

8.1

78.1

23.9

555.0

697.7

1,665.0

1,817.9

1.2

1.5

1.4

Realized and unrealized gains (losses) on derivative contracts

(12.6)

^[5]

183.4

^[6]

(18.6)

^[7]

489.4

^[8]

36.1

334.7

(0.2)

(0.7)

2.4

(0.5)

2.3

5.6

4.5

(0.7)

(0.6)

(0.7)

(30.0)

(22.8)

(82.9)

(67.0)

(4.4)

161.5

240.6

425.7

2.3

(59.1)

(86.5)

(156.0)

(2.1)

102.4

154.1

269.7

(1.0)

(0.9)

(2.7)

(2.2)

(3.1)

^[9]

101.5

^[10]

151.4

^[11]

267.5

^[12]

Unaffiliated customers [Member]

Revenues

542.4

^[1]

879.9

^[2]

1,644.9

^[3]

2,305.9

^[4]

Affiliated customers [Member]

Revenues

^[1]

^[2]

^[3]

^[4]

QEP Energy [Member]

7,416.1

5,815.7

Revenues

374.0

^[1]

635.6

^[2]

1,106.3

^[3]

1,587.3

^[4]

45.9

208.1

159.0

362.8

Natural gas, oil and NGL transportation and other handling costs

43.1

38.0

125.3

106.4

59.8

45.0

167.4

130.8

32.2

23.0

94.3

69.8

22.5

26.3

63.6

73.9

217.4

174.4

597.7

524.0

11.7

8.1

78.1

23.9

432.6

522.9

1,285.4

1,291.6

1.2

1.5

1.4

Realized and unrealized gains (losses) on derivative contracts

(58.6)

^[5]

113.9

^[6]

(177.6)

^[7]

297.1

^[8]

41.4

330.4

(0.2)

(0.7)

2.2

(0.5)

0.1

(24.1)

(20.5)

(71.1)

(60.8)

(41.5)

92.7

84.0

235.9

15.3

(34.4)

(32.4)

(87.7)

(26.2)

58.3

51.6

148.2

(26.2)

^[9]

58.3

^[10]

51.6

^[11]

148.2

^[12]

QEP Energy [Member] | Unaffiliated customers [Member]

Revenues

374.0

^[1]

635.6

^[2]

1,106.3

^[3]

1,587.3

^[4]

QEP Energy [Member] | Affiliated customers [Member]

Revenues

^[1]

^[2]

^[3]

^[4]

QEP Field Services [Member]

1,362.7

1,312.7

Revenues

109.7

^[1]

119.6

^[2]

343.0

^[3]

338.4

^[4]

4.9

9.0

Natural gas, oil and NGL transportation and other handling costs

6.9

2.5

27.7

4.6

21.8

26.6

65.6

78.3

10.6

6.6

24.1

22.4

1.7

1.4

4.6

4.4

15.8

14.0

47.2

40.7

61.7

51.1

178.2

150.4

(0.1)

Realized and unrealized gains (losses) on derivative contracts

48.0

^[5]

68.4

^[6]

164.8

^[7]

188.0

^[8]

(0.6)

8.3

0.1

2.3

5.5

4.4

(3.5)

(3.8)

(9.4)

(10.4)

46.2

66.9

169.3

182.0

(16.5)

(24.0)

(59.2)

(65.6)

29.7

42.9

110.1

116.4

(1.0)

(0.9)

(2.7)

(2.2)

28.7

^[9]

42.0

^[10]

107.4

^[11]

114.2

^[12]

QEP Field Services [Member] | Unaffiliated customers [Member]

Revenues

77.9

^[1]

98.6

^[2]

254.9

^[3]

273.9

^[4]

QEP Field Services [Member] | Affiliated customers [Member]

Revenues

31.8

^[1]

21.0

^[2]

88.1

^[3]

64.5

^[4]

QEP Marketing and Other [Member]

217.3

314.3

Revenues

236.3

^[1]

294.2

^[2]

680.0

^[3]

871.5

^[4]

236.7

292.0

681.7

862.4

Natural gas, oil and NGL transportation and other handling costs

0.1

0.4

0.8

1.1

0.5

0.2

0.6

1.8

0.1

0.2

0.9

0.6

2.5

1.7

238.3

293.2

685.8

867.2

0.1

Realized and unrealized gains (losses) on derivative contracts

(2.0)

^[5]

1.1

^[6]

(5.8)

^[7]

4.3

^[8]

(4.7)

(4.0)

28.4

25.0

81.1

74.2

(0.7)

(0.6)

(0.7)

(30.8)

(23.5)

(83.4)

(70.0)

(9.1)

1.9

(12.7)

7.8

3.5

(0.7)

5.1

(2.7)

(5.6)

1.2

(7.6)

5.1

(5.6)

^[9]

1.2

^[10]

(7.6)

^[11]

5.1

^[12]

QEP Marketing and Other [Member] | Unaffiliated customers [Member]

Revenues

90.5

^[1]

145.7

^[2]

283.7

^[3]

444.7

^[4]

QEP Marketing and Other [Member] | Affiliated customers [Member]

Revenues

145.8

^[1]

148.5

^[2]

396.3

^[3]

426.8

^[4]

Elimination [Member]

Revenues

(177.6)

^[1]

(169.5)

^[2]

(484.4)

^[3]

(491.3)

^[4]

(144.9)

(147.4)

(393.8)

(421.9)

Natural gas, oil and NGL transportation and other handling costs

(0.9)

(1.0)

(2.5)

(2.3)

(30.4)

(20.0)

(83.6)

(62.2)

0.2

(1.6)

(1.1)

(4.5)

(4.9)

(177.6)

(169.5)

(484.4)

(491.3)

Realized and unrealized gains (losses) on derivative contracts

^[5]

^[6]

^[7]

^[8]

(28.4)

(25.0)

(81.0)

(74.2)

28.4

25.0

81.0

74.2

^[9]

^[10]

^[11]

^[12]

Elimination [Member] | Unaffiliated customers [Member]

Revenues

^[1]

^[2]

^[3]

^[4]

Elimination [Member] | Affiliated customers [Member]

Revenues