Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2012	Jan. 31, 2013	Jun. 30, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	QEP RESOURCES, INC.
Entity Central Index Key	0001108827
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		178,116,761
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Entity Public Float			$ 5,327,744,063

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
REVENUES
Natural gas sales	$ 667.4	$ 1,239.1	$ 1,205.3
Oil sales	532.6	324.2	198.1
NGL sales	322.1	309.8	142.6
Gathering, processing and other	181.6	200.8	156.6
Purchased gas, oil and NGL sales	646.1	1,085.3	598.0
Total Revenues	2,349.8	3,159.2	2,300.6
OPERATING EXPENSES
Purchased gas, oil and NGL expense	655.6	1,077.1	589.3
Lease operating expense	172.3	145.2	125.0
Natural gas, oil and NGL transport and other handling costs	148.9	102.2	54.2
Gathering, processing and other	88.0	107.3	83.2
General and administrative	266.6	123.2	107.2
Separation costs	0	0	13.5
Production and property taxes	103.4	105.4	82.5
Depreciation, depletion and amortization	904.9	765.4	643.4
Exploration expenses	11.2	10.5	23.0
Abandonment and impairment	133.4	218.4	46.1
Total Operating Expenses	2,484.3	2,654.7	1,767.4
Net gain from asset sales	1.2	1.4	12.1
OPERATING (LOSS) INCOME	(133.3)	505.9	545.3
Realized and unrealized gains on derivative contracts (See Note 6)	441.9	0	0
Interest and other income	6.6	4.1	2.3
Income from unconsolidated affiliates	6.8	5.5	3.0
Loss from early extinguishment of debt	(0.6)	(0.7)	(13.3)
Interest expense	(122.9)	(90.0)	(84.4)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	198.5	424.8	452.9
Income taxes	(66.5)	(154.4)	(167.0)
INCOME FROM CONTINUING OPERATIONS	132.0	270.4	285.9
Discontinued operations, net of income tax	0	0	43.2
NET INCOME	132.0	270.4	329.1
Net income attributable to noncontrolling interest	(3.7)	(3.2)	(2.9)
NET INCOME ATTRIBUTABLE TO QEP	$ 128.3	$ 267.2	$ 326.2
Earnings Per Common Share Attributable to QEP
Basic from continuing operations	$ 0.72	$ 1.51	$ 1.61
Basic from discontinued operations	$ 0.00	$ 0.00	$ 0.25
Basic total	$ 0.72	$ 1.51	$ 1.86
Diluted from continuing operations	$ 0.72	$ 1.50	$ 1.60
Diluted from discontinued operations	$ 0.00	$ 0.00	$ 0.24
Diluted total	$ 0.72	$ 1.50	$ 1.84
Weighted-average common shares outstanding
Used in basic calculation	177.8	176.5	175.3
Used in diluted calculation	178.7	178.4	177.3

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

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Statement of Other Comprehensive Income [Abstract]

NET INCOME

$ 132.0

$ 270.4

$ 329.1

Other comprehensive (loss) income, net of tax:

Effect of derivative financial instruments

(171.1)

^[1]

24.8

^[1]

136.7

^[1]

Pension and other postretirement plans adjustments:

Current year net actuarial gain (loss)

(10.0)

^[2]

(14.7)

^[2]

2.6

^[2]

Amortization of net actuarial loss

1.1

^[3]

Net prior service cost inccured

^[4]

(33.8)

^[4]

Amortization of net prior service cost

3.5

^[5]

3.5

^[5]

1.7

^[5]

Net curtailment cost incurred

1.4

^[6]

Total pension and other postretirement plans adjustments

(4.0)

(11.2)

(29.5)

Other comprehensive (loss) income

(175.1)

13.6

107.2

Comprehensive (loss) income

(43.1)

284.0

436.3

Comprehensive income attributable to noncontrolling interests

(3.7)

(3.2)

(2.9)

Comprehensive (loss) income attributable to QEP

$ (46.8)

$ 280.8

$ 433.4

[1]	Presented net of income tax benefit of $101.3 million during the year ended December 31, 2012, and net of income tax expense of $14.7 million and $81.0 million during the years ended December 31, 2011 and 2010, respectively.
[2]	Presented net of income tax benefit of $6.3 million and $9.2 million during the years ended December 31, 2012 and 2011, respectively, and net of income tax expense of $1.6 million for the year ended December 31, 2010.
[3]	Presented net of income tax expense of $0.9 million during the year ended December 31, 2012.
[4]	Presented net of income tax benefit of $20.9 million during the year ended December 31, 2010.
[5]	Presented net of income tax expense of $2.2 million, $2.1 million and $1.0 million during the years ended December 31, 2012, 2011 and 2010, respectively.
[6]	Presented net of income tax expense of $0.8 million during the year ended December 31, 2012.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other comprehensive income (loss), tax
Tax expense (benefit) on gains (losses) on changes in unrealized fair value of derivatives designated as cash flow hedges	$ 101.3	$ (14.7)	$ (81.0)
Pension and other postretirement plans adjustments:
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Transition Asset (Obligation), Recognized in Net Periodic Benefit Cost, Tax			20.9
Tax expense (benefit) on prior service cost incurred	(2.2)	(2.1)	(1.0)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	(0.8)
Current year net actuarial gain loss [Member]
Pension and other postretirement plans adjustments:
Tax expense (benefit) on net unamortized gain (loss) incurred	6.3	9.2	(1.6)
Amortization net actuarial gain loss [Member] [Member]
Pension and other postretirement plans adjustments:
Tax expense (benefit) on net unamortized gain (loss) incurred	$ (0.9)

- Definition

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

+ References

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

-Publisher AICPA

-Name Accounting Research Bulletin (ARB)

-Number 51

-Paragraph 38

-Subparagraph c(3)

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 220

-SubTopic 10

-Section 45

-Paragraph 12

-URI http://asc.fasb.org/extlink&oid=20435746&loc=d3e640-108580

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 158

-Paragraph 7

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 130

-Paragraph 25

-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 Statement of Financial Accounting Standard (FAS)

-Number 87

-Paragraph 25

-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

- Definition

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

CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 0	$ 0
Accounts receivable, net	387.5	397.4
Fair value of derivative contracts	188.7	273.7
Gas, oil and NGL inventories, at lower of average cost or market	13.1	16.2
Prepaid expenses and other	60.4	43.7
Total Current Assets	649.7	731.0
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	10,234.3	8,172.4
Unproved properties, net	937.9	326.8
Midstream field services	1,634.9	1,463.6
Marketing and other	64.6	49.8
Materials and supplies	61.9	87.6
Total Property, Plant and Equipment	12,933.6	10,100.2
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	4,258.1	3,339.2
Midstream field services	357.9	297.5
Marketing and other	18.1	14.6
Total Accumulated Depreciation, Depletion and Amortization	4,634.1	3,651.3
Net Property, Plant and Equipment	8,299.5	6,448.9
Investment in unconsolidated affiliates	41.2	42.2
Goodwill	59.5	59.5
Fair value of derivative contracts	4.1	123.5
Other noncurrent assets	54.5	37.6
TOTAL ASSETS	9,108.5	7,442.7
Current Liabilities
Checks outstanding in excess of cash balances	39.7	29.4
Accounts payable and accrued expenses	635.9	457.3
Production and property taxes	41.8	40.0
Interest payable	36.9	24.4
Fair value of derivative contracts	2.6	1.3
Deferred income taxes	5.0	85.4
Total Current Liabilities	761.9	637.8
Long-term debt	3,206.9	1,679.4
Deferred income taxes	1,493.5	1,484.7
Asset retirement obligations	191.4	163.9
Fair value of derivative contracts	3.6	0
Other long-term liabilities	137.5	124.8
Commitments and contingencies (see Note 9)
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 - 0.1 million and 0.4 million shares, respectively	(3.7)	(13.1)
Additional paid-in capital	462.1	431.4
Retained earnings	2,773.0	2,673.5
Accumulated other comprehensive income	32.8	207.9
Total Common Shareholders' Equity	3,266.0	3,301.5
Noncontrolling interest	47.7	50.6
Total Equity	3,313.7	3,352.1
TOTAL LIABILITIES AND EQUITY	$ 9,108.5	$ 7,442.7

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Dec. 31, 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)	0.1	0.4

CONSOLIDATED STATEMENTS OF EQUITY (USD $) In Millions, unless otherwise specified	Total	Common Stock [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2009	$ 2,808.7	$ 1.7	$ 0	$ 126.8	$ 2,538.2	$ 87.1	$ 54.9
Shares, Issued at Dec. 31, 2009		174.6
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Questar common stock issued net of repurchases, Value	0	0	0	0	0	0	0
Questar common stock issued, net of repurchases		0.4
NET INCOME	329.1	0	0	0	326.2	0	2.9
Payments of Ordinary Dividends, Common Stock	(7.0)
Dividends	(15.9)	0	0	0	(15.9)	0	0
Share-based compensation	19.5	0.1	(3.9)	23.3	0	0	0
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures		0.9
Stock Issued During Period, Shares, Treasury Stock Reissued			(0.1)
Stockholders' Equity Note, Spinoff Transaction	250.0	0	0	250.0	0	0	0
Payments to Noncontrolling Interests	(5.0)	0	0	0	0	0	(5.0)
Transfer Wexpro to Questar	(430.5)	0	0	(2.0)	(428.5)	0	0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	136.7	0	0	0	0	136.7	0
Change in pension and postretirement liability, net of tax	(29.5)	0	0	0	0	(29.5)	0
Treasury stock (in shares)			(0.1)
Balance at Dec. 31, 2010	3,063.1	1.8	(3.9)	398.1	2,420.0	194.3	52.8
Shares, Issued at Dec. 31, 2010		175.9
Increase (Decrease) in Stockholders' Equity [Roll Forward]
NET INCOME	270.4	0	0	0	267.2	0	3.2
Payments of Ordinary Dividends, Common Stock	(14.1)
Dividends	(14.1)	0	0	0	(14.1)	0	0
Share-based compensation	24.1	0	(9.2)	33.3	0	0	0
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures		1.3
Stock Issued During Period, Shares, Treasury Stock Reissued			(0.3)
Payments to Noncontrolling Interests	(5.4)	0	0	0	0	0	(5.4)
Equity from Questar	0.4	0	0	0	0.4	0	0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	24.8	0	0	0	0	24.8	0
Change in pension and postretirement liability, net of tax	(11.2)	0	0	0	0	(11.2)	0
Treasury stock (in shares)	0.4		(0.4)
Balance at Dec. 31, 2011	3,352.1	1.8	(13.1)	431.4	2,673.5	207.9	50.6
Shares, Issued at Dec. 31, 2011		177.2
Increase (Decrease) in Stockholders' Equity [Roll Forward]
NET INCOME	132.0	0	0	0	128.3	0	3.7
Payments of Ordinary Dividends, Common Stock	(14.2)
Dividends	(14.2)	0	0	0	(14.2)	0	0
Share-based compensation	23.2	0	7.1	30.7	(14.6)	0	0
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures		1.3
Stock Issued During Period, Shares, Treasury Stock Reissued			0.2
Distribution to QEP Education Foundation	2.3	0	2.3	0	0	0	0
Payments to Noncontrolling Interests	(6.6)	0	0	0	0	0	(6.6)
TreasuryStockIssuedCharitableContribution			0.1
Gain reclassified from AOCI into income for effective portion of hedge	(171.1)	0	0	0	0	(171.1)	0
Change in pension and postretirement liability, net of tax	(4.0)	0	0	0	0	(4.0)	0
Treasury stock (in shares)	0.1		(0.1)
Balance at Dec. 31, 2012	$ 3,313.7	$ 1.8	$ (3.7)	$ 462.1	$ 2,773.0	$ 32.8	$ 47.7
Shares, Issued at Dec. 31, 2012		178.5

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
OPERATING ACTIVITIES
NET INCOME	$ 132.0	$ 270.4	$ 329.1
Discontinued operations, net of income tax	0	0	43.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	904.9	765.4	643.4
Deferred income taxes	32.1	156.8	188.2
Abandonment and impairment	133.4	218.4	46.1
Share-based compensation	25.6	22.0	16.1
Amortization of debt issuance costs and discounts	5.3	4.1	2.4
Net gain from asset sales	(1.2)	(1.4)	(12.1)
Income from unconsolidated affiliates	(6.8)	(5.5)	(3.0)
Distributions from unconsolidated affiliates and dry exploratory well expense	7.9	8.1	11.8
Non-cash loss on early extinguishment of debt	0	0.7	13.3
Unrealized gain on derivative contracts	(63.2)	(117.7)	(121.7)
Changes in operating assets and liabilities
Accounts receivable	9.6	(144.6)	(32.6)
Inventories	28.7	(22.0)	10.1
Prepaid expenses	(16.8)	1.6	(16.2)
Accounts payable and accrued expenses	101.3	127.8	4.2
Federal income taxes	3.5	17.0	(30.9)
Other	(0.3)	(8.5)	(7.5)
Net Cash Provided by Operating Activities of Continuing Operations	1,296.0	1,292.6	997.5
INVESTING ACTIVITIES
Property acquisitions	(1,401.0)	(48.0)	(109.3)
Property, plant and equipment, including dry exploratory well expense	(1,398.7)	(1,383.1)	(1,359.7)
Proceeds from disposition of assets	5.2	8.2	25.6
Change in notes receivable	0	0	52.9
Net Cash Used in Investing Activities of Continuing Operations	(2,794.5)	(1,422.9)	(1,390.5)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	10.3	9.9	19.5
Long-term debt issued	1,450.0	0	1,034.4
Long-term debt issuance costs paid	(17.8)	(10.6)	(16.6)
Long-term debt repaid	(6.7)	(58.5)	(91.5)
Repayments of notes payable	0	0	(39.3)
Long-term debt extinguishment costs	0	0	(4.9)
Proceeds from credit facility	1,234.5	591.5	0
Repayments of credit facility	(1,151.0)	(385.0)	(761.5)
Other capital contributions	(2.2)	0.7	2.8
Equity contribution	0	0	250.0
Dividends paid	(14.2)	(14.1)	(7.0)
Dividends	(14.2)	(14.1)	(15.9)
Excess tax benefit on share-based compensation	2.2	1.6	0
Distribution from Questar	0	0.2	(7.2)
Distribution to noncontrolling interest	(6.6)	(5.4)	(5.0)
Net Cash Provided by Financing Activities of Continuing Operations	1,498.5	130.3	373.7
CASH USED IN CONTINUING OPERATIONS	0	0	(19.3)
Cash provided by operating activities of discontinued operations	0	0	68.6
Cash used in investing activities of discontinued operations	0	0	(39.9)
Cash used in financing activities of discontinued operations	0	0	(26.9)
Effect of change in cash and cash equivalents of discontinued operations	0	0	1.8
Change in cash and cash equivalents	0	0	(19.3)
Beginning cash and cash equivalents	0	0	19.3
Ending cash and cash equivalents	$ 0	$ 0	$ 0

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Nature of Business

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


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


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


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

Operations are focused in two major regions: the Northern Region (primarily in North Dakota, Wyoming and Utah) 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".

Principles of Consolidation

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

Effective May 18, 2010, Questar Market Resources, Inc., (Market Resources) then a wholly owned subsidiary of Questar Corporation (Questar), merged with and into a newly-formed, wholly owned subsidiary, QEP, a Delaware corporation in order to reincorporate in the State of Delaware (Reincorporation Merger). The Reincorporation Merger was affected pursuant to an Agreement and Plan of Merger entered into between Market Resources and QEP. The Reincorporation Merger was approved by the boards of directors of Market Resources and QEP and submitted to a vote of, and approved by, the Board of Directors of Questar, as sole shareholder of Market Resources, and by Market Resources, as sole shareholder of QEP on May 18, 2010.

On June 30, 2010, Questar distributed all of the shares of common stock of QEP held by Questar to Questar shareholders in a tax-free, pro rata dividend (the Spin-off). Each Questar shareholder received one share of QEP common stock for each one share of Questar common stock held (including fractional shares) at the close of business on the record date. In connection therewith, QEP distributed Wexpro Company (Wexpro), a wholly owned subsidiary of QEP at the time, to Questar. In addition, Questar contributed $250.0 million of equity to QEP prior to the Spin-off.

The financial information presented in this Annual Report on Form 10-K presents QEP's financial results as an independent company separate from Questar and reflects Wexpro's financial condition and operating results as discontinued operations for all periods presented. A summary of discontinued operations can be found in Note 13 to the consolidated financial statements.

All dollar and share amounts in this Form 10-K are in millions, except per-share information and where otherwise noted.

Investment in Unconsolidated Affiliates

QEP uses the equity method to account for investment in unconsolidated affiliates where it does not have control, but has significant influence. The investment in unconsolidated affiliates on the Company's consolidated balance sheets equals the Company's proportionate share of equity reported by the unconsolidated affiliates. Investment is assessed for possible impairment when events indicate that the fair value of the investment may be below the Company's carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in the determination of net income.

The principal unconsolidated affiliates and QEP's ownership percentage as of December 31, 2012 and 2011, were Uintah Basin Field Services, LLC, (38%) and and Three Rivers Gathering, LLC, (50%), both limited liability companies engaged in gathering and compressing natural gas.

Reclassifications

In 2011, "Gathering, processing and other" revenues included "NGL" which were reclassified to conform with the current period presentation on the Consolidated Statement of Operations. The NGL reclassification is all within "Revenues" and has no effect on income from continuing operations, net income or earnings per share. Additionally, QEP reclassified "Materials and supplies" as of December 31, 2011, from current to long-term on the Consolidated Balance Sheet for consistency with current period presentation.

Use of Estimates

The preparation of the consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management's estimates and assumptions is the estimate of proved natural gas, oil and NGL reserves which are used in the calculation of depreciation, depletion and amortization rates of its gas and oil properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved gas and oil reserves. Other items subject to estimates and assumptions include the carrying amount of property, plant and equipment and goodwill, assigning fair value and allocating purchase price in connection with business combinations, valuation allowances for receivables, income taxes, valuation of derivatives instruments, accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Revenue Recognition

QEP subsidiaries recognize revenues in the period that services are provided or products are delivered. Revenues associated with the sale of natural gas and oil are accounted for using the sales method, whereby revenue is recognized as gas and oil is sold to purchasers. A liability is recorded to the extent that the Company has sold volumes in excess of its share of remaining gas and oil reserves in an underlying property. QEP's imbalance obligations at December 31, 2012 and 2011, were $13.2 million and $13.3 million, respectively.

QEP Marketing reports revenues on a gross basis because, in the judgment of management, the nature and circumstances of its marketing transactions are consistent with guidance for gross revenue reporting. QEP Marketing markets affiliate and third-party natural gas, oil and NGL volumes. QEP Marketing uses derivatives to secure a known price for a specific volume over a specific time period. QEP Marketing does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. QEP Marketing has not engaged in buy/sell arrangements, as described in ASC 845-10-25-4, Accounting for Purchases and Sales of Inventory with the Same Counterparty.

Cash and Cash Equivalents

Cash equivalents consist principally of repurchase agreements with maturities of three months or less. The repurchase agreements are highly liquid investments in overnight securities made through commercial-bank accounts that result in available funds the next business day.

Supplemental cash flow information is shown in the below table:



	Year Ended December 31,
	2012		2011			2010
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	105.1	$	90.5		$	80.2
Cash paid (received) for income taxes	30.0		(28.5		)	14.0
Non-cash investing activities
Change in capital expenditure accrual balance	$	88.5	$	14.7		$	16.9

Accounts Receivable Trade

Accounts receivable trade consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's oil and gas receivables are collected and bad-debts are minimal. Bad-debt expense associated with accounts receivable for the years ended December 31, 2012 and 2011 was $1.4 million and $0.2 million, respectively, and a credit of $0.3 million in 2010. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad-debt expenses was $2.8 million at December 31, 2012, and $1.7 million at December 31, 2011.

Property, Plant and Equipment

Property, plant and equipment balances are stated at historical cost. Material and supplies inventories are valued at the lower of cost or market. Maintenance and repair costs are expensed as incurred with the exception of compressor maintenance costs, which are capitalized and depreciated. Significant accounting policies for our property, plant and equipment are as follows:

Gas and oil properties

QEP Energy uses the successful efforts method to account for gas and oil properties. The costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, purchasing related support equipment and facilities are capitalized. Geological and geophysical studies and other exploratory activities are expensed as incurred. Costs of production and general- corporate activities are expensed in the period incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected.

Capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized exploratory well costs

The Company capitalizes exploratory well costs until it determines whether an exploratory well is commercial or noncommercial. If the Company deems the well commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed gas and oil reserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory-well costs capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantial activities to assess whether the well is commercial.

Depreciation, depletion and amortization

Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved gas and oil reserves. Oil and NGL volumes are converted to natural gas equivalents using the ratio of one barrel of crude oil, condensate or NGL to 6,000 cubic feet of natural gas. Capitalized costs of exploratory wells that have found proved gas and oil reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves for a successful effort field pool. The Company capitalizes an estimate of the fair value of future abandonment costs.

Depreciation, depletion and amortization for the remaining Company properties is based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using either a straight-line or unit-of-production method. Investment in gas gathering and processing fixed assets is charged to expense using either the straight-line or unit-of-production method depending upon the facility. The estimated useful lives of those assets depreciated under the straight-line basis generally range as follows:



Buildings	10 to 30 years
Leasehold improvements	3 to 10 years
Service, transportation and field service equipment	3 to 7 years
Furniture and office equipment	3 to 7 years

Impairment of Long-Lived Assets

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, declines 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 proved, 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 unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

During the year ended December 31, 2012, QEP recorded abandonment and impairment charges of $133.4 million on its oil and gas properties. Of the $133.4 million abandonment and impairment charges during the year ended December 31, 2012, $107.6 million related to price-related impairment charges on proved properties and $23.7 million related to impairment on unproved properties. 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 $133.4 million abandonment and impairment charges during the year ended December 31, 2012, $104.8 million was related to oil and gas properties in the Southern Region and $28.6 million was related to oil and gas properties in the Northern Region. During the year ended December 31, 2011, QEP recorded abandonment and impairment charges of $218.4 million, $173.1 million were related to properties in the Northern Region with the remaining $45.3 million related to properties in the Southern Region. Of the $218.4 million abandonment and impairment charges during the year ended December 31, 2011, $195.5 million related to the impairment charges on proved properties and $20.3 million related to impairment on unproved properties. During the year ended December 31, 2010, QEP recorded abandonment and impairment charges of $46.1 million, of which $0.7 million related to proved property impairments and $40.7 million related to impairment on unproved properties.

Asset Retirement Obligations

Asset retirement obligations (ARO) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

Capitalized Interest

The Company capitalizes interest costs during the construction phase of large capital projects that meet certain criteria. Capitalized interest was $3.4 million, $3.0 million and $3.1 million during the years ended December 31, 2012, 2011 and 2010, respectively.

Litigation and Other Contingencies

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 regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. See Note 9 - Commitments and Contingencies, for additional information.

Except for environmental contingencies acquired in a business combination, which are recorded at fair value, QEP accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.

Goodwill

Goodwill represents the excess of the amount paid over the fair value of net assets acquired in a business combination and is not subject to amortization. As of December 31, 2012 and 2011, goodwill was $59.5 million and related to the Uinta Basin reporting unit within QEP Energy. Goodwill is tested for impairment at a minimum of once a year or when a triggering event occurs using the income approach. Under the income approach, the fair value is estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model consider estimated quantities of crude oil, NGL and natural gas reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. The undiscounted net cash flows of the reporting unit to which the goodwill relates are evaluated. Impairment is indicated if undiscounted cash flows are less than the carrying value of the assets. The amount of the impairment is measured using a discounted, cash flow model considering future revenues, operating costs, a risk-adjusted discount rate and other factors. There have been no goodwill impairments.

Derivative Instruments

Effective January 1, 2012, the Company elected to de-designate all of its natural gas, oil and NGL derivative contracts that had previously been designated as cash flow hedges and has elected to discontinue hedge accounting prospectively. Accordingly, all realized and unrealized gains and losses are recognized in earnings immediately as derivative contracts are settled and marked-to-market. For the year ended December 31, 2012, unrealized gains of $63.2 million were included in income that, prior to January 1, 2012, would have been deferred in Accumulated Other Comprehensive Income (AOCI) under hedge accounting (Refer to Note 6 – Derivative Contracts, for additional information). At December 31, 2011, AOCI consisted of $395.9 million ($248.6 million after tax) of unrealized gains, representing the mark-to-market value of the Company's cash flow hedges as of the balance sheet date, less any ineffectiveness recognized. As a result of discontinuing hedge accounting, such mark-to-market values at December 31, 2011, were frozen in AOCI as of the de-designation date and are being reclassified into earnings as the original hedged transactions occur and effect earnings. QEP expects to reclassify into earnings from AOCI the remaining frozen value, $123.5 million ($77.6 million after tax), related to de-designated natural gas, oil and NGL hedges during 2013.

All of QEP's derivative contracts are net settled in cash without delivery of product. These contracts also have a nominal quantity and exchange an index price for a fixed price, and are net settled with the brokers as the price bulletins become available. These derivative contracts are recorded in revenues or cost of sales in the month of settlement. Basis-only swaps are used to manage the risk of widening basis differentials. These contracts are marked to market monthly with any change in the valuation recognized in the determination of income.

Credit Risk

The Northern and Southern Regions constitute the Company's primary market areas. Exposure to credit risk may be affected by the concentration of customers in these regions due to changes in economic or other conditions. Customers include individuals and numerous commercial and industrial enterprises that may react differently to changing conditions. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses. Commodity-based hedging arrangements also expose the Company to credit risk. The Company monitors the creditworthiness of its counterparties, which generally are major financial institutions and energy companies. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. QEP requests credit support and, in some cases, fungible collateral, financial guarantees, letters of credit or prepayment from companies with unacceptable credit risks. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

The Company's five largest customers accounted for 37%, 32%, and 27% in aggregate, of QEP revenues during the years ended December 31, 2012, 2011 and 2010, respectively. During the year ended December 31, 2012, Chevron U.S.A. Inc. and Enterprise Products Operating, L.P. accounted for 13% and 10%, respectively, of the Company's total revenues. Management believes that the loss of either customer, or any other customer, would not have a material effect on the financial position or results of operations of QEP since there are numerous potential purchasers of its production. During the years ended December 31, 2011 and 2010, each of the five largest customers sales were below 10% of QEP's total revenues.

Income Taxes

Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. The Company records interest earned on income tax refunds in interest and other income and records penalties and interest charged on tax deficiencies in interest expense.

ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company's recorded income tax benefits will be fully realized. There were no unrecognized tax benefits at the beginning or at the end of the twelve-month periods ended December 31, 2012, 2011 and 2010. The federal income tax returns for 2011 and 2010 are currently under examination by the Internal Revenue Service. Income tax returns for 2012 have not yet been filed. Most state tax returns for 2009 and subsequent years remain subject to examination.

Treasury Stock

We record treasury stock purchases at costs, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders' equity in the consolidated balance sheets. Acquired treasury stock is used for stock grants to employees; refer to Note 10 - Share-Based Compensation for additional information.

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 considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares receive dividends.

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



	December 31,
	2012	2011	2010
	(in millions)
Weighted-average basic common shares outstanding	177.8	176.5	175.3
Potential number of shares issuable under the Long-Term Stock Incentive Plan	0.9	1.9	2.0
Average diluted common shares outstanding	178.7	178.4	177.3

Share-Based Compensation

QEP issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The granting of restricted shares results in recognition of compensation cost measured at the grant-date market price. QEP uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have terms of seven years. Restricted shares vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted shares have voting and dividend rights; however, sale or transfer is restricted. At the time of the Spin-off, all outstanding options and restricted stock were bifurcated. The Company also awards performance share units which are paid out in cash that is dependent upon the Company's total shareholder return compared to a group of its peers over a three-year period. The performance share unit's compensation cost is equal to its fair value as of the period end and is classified as a liability. For a summary of LTSIP transactions see Note 10—Share-Based Compensation.

Pension Plans, Other Postretirement Benefits and Defined-Contribution Plans

QEP measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected rate of return on plan assets (for funded pension plans), the rate of future compensation increases and the health care cost trend rate. Other assumptions involve demographic factors such as retirement, mortality and turnover. QEP evaluates and updates its actuarial assumptions at least annually.

Comprehensive Income

Comprehensive income is the sum of net income attributable to QEP as reported in the Consolidated Statements of Operations and changes in the components of other comprehensive income. Other comprehensive income includes certain items that are recorded directly to equity and classified as AOCI. One component of other comprehensive income is changes in the market value of commodity-based derivative instruments that qualified for hedge accounting. Income or loss associated with commodity-based derivative instruments that qualified for hedge accounting is realized when the natural gas, oil or NGL underlying the derivative instrument is sold. Comprehensive income also includes changes in the under-funded portion of the defined benefit pension plans and other postretirement benefits plans and changes in deferred income taxes on such amounts. These transactions are not the culmination of the earnings process but result from periodically adjusting historical balances to fair value.

Business Segments

Line of business information is presented according to senior management's basis for evaluating performance considering differences in the nature of products, services and regulation. QEP's lines of business are QEP Energy, QEP Field Services, and QEP Marketing and other corporate activities not attributable to a line of business.

Recent Accounting Developments

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.

- Definition

The entire disclosure for all significant accounting policies of the reporting entity.

+ References+ Details

Acquisitions

12 Months Ended

Dec. 31, 2012

Acquisitions [Abstract]

Acquisitions [Text Block]

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 2012 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 2012 Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included proved properties. QEP allocated the cost of the 2012 Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $63.7 million and net income of $14.9 million generated from the acquired properties for the fourth quarter of 2012 and have been included in QEP's Consolidated Statements of Operations for the year ended December 31, 2012. During the year ended December 31, 2012, QEP Energy's acquisition-related costs of $1.1 million are included in "General and administrative" on the Consolidated Statements of Operations.

QEP Energy recorded the 2012 Acquisition on its Consolidated Balance Sheets; however, the final purchase price is subject to revision based on the settlement of post-closing adjustments. The following table presents a summary of the preliminary purchase accounting entries:



	As of December 31, 2012
Consideration given:	(in millions)
Cash consideration	$	1,388.7

Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
Proved properties	$	713.8
Unproved properties	679.4
Asset retirement obligations	(0.9		)
Liabilities assumed	(4.4		)
Other assets acquired	0.8
Total fair value	$	1,388.7

The following unaudited, pro forma results of operations are provided for the years ended December 31, 2012 and 2011, as though the 2012 Acquisition had been completed as of the beginning of January 1, 2011. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the properties for the periods presented or that may be achieved by the properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the years ended December 31, 2012 and 2011, on the acquired properties historical results of operations and on estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the preliminary purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the 2012 Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties.



	Year ended December 31,
	2012				2011
	Actual		Pro forma		Actual		Pro forma
	(in millions, except per share data)

Revenues	$	2,349.8	$	2,485.3	$	3,159.2	$	3,236.7
Net income attributable to QEP	128.3		143.0		267.2		259.8
Earnings per common share attributable to QEP
Basic	$	0.72	$	0.80	$	1.51	$	1.47
Diluted	0.72		0.80		1.50		1.46

Capitalized Exploratory Well Costs

12 Months Ended

Dec. 31, 2012

Capitalized Exploratory Well Costs [Abstract]

Suspended Well Costs Disclosure [Text Block]

Net changes in capitalized exploratory well costs are presented in the table below and exclude amounts that were capitalized and subsequently expensed in the period. The balance at December 31, 2012, 2011 and 2010, represents the amount of capitalized exploratory well costs that are pending the determination of proved reserves.



	2012			2011			2010
	(in millions)
Balance at January 1,	$	5.0		$	13.6		$	51.7
Additions to capitalized exploratory well costs pending the determination of proved reserves	12.7			—			12.2
Reclassifications to proved properties after the determination of proved reserves	(15.6		)	(8.3		)	(50.3		)
Capitalized exploratory well costs charged to expense	—			(0.3		)	—
Balance at December 31,	$	2.1		$	5.0		$	13.6

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation [Abstract]

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 the ARO liability occur due to changes in estimated abandonment costs and well economic lives. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $193.1 million ARO liability,$1.7 million was included as a liability in "Accounts payable and accrued expenses" on the Consolidated Balance Sheet.

The following is a reconciliation of the changes in the asset retirement obligation for the periods specified below:



	Asset Retirement Obligations
	2012			2011
	(in millions)
ARO liability at January 1,	$	163.9		$	148.3
Accretion	10.5			9.7
Liabilities incurred	8.5			7.9
Revisions	11.1			—
Liabilities settled	(0.9		)	(2.0		)
ARO liability at December 31,	$	193.1		$	163.9

- Definition

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

12 Months Ended

Dec. 31, 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. 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 that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (see Note 6 - Derivative Contracts) is based on market prices posted on the NYMEX on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.

However, certain 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 December 31, 2012 and 2011, is shown in the tables below:



	Fair Value Measurements
	December 31, 2012
	Level 1		Level 2		Level 3		Netting Adjustments			Total
			(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	189.7	$	—	$	(1.0	)	$	188.7
Commodity derivative instruments - long-term	—		4.2		—		(0.1		)	$	4.1
Total financial assets	$	—	$	193.9	$	—	$	(1.1	)	$	192.8

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	1.0	$	—	$	(1.0	)	$	—
Interest rate swaps - short-term	—		2.6		—		—			$	2.6
Commodity derivative instruments - long-term	—		0.1		—		(0.1		)	$	—
Interest rate swaps - long-term	—		3.6		—		—			$	3.6
Total financial liabilities	$	—	$	7.3	$	—	$	(1.1	)	$	6.2



	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

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 years ended December 31, 2012 and 2011, are shown below:



	Change in Level 3 Fair Value Measurements
	2012			2011
	(in millions)
Balance at January 1,	$	—		$	36.3
Realized gains and losses	0.6			25.3
Unrealized gains and losses	3.8			(36.3		)
Settlements	(0.6		)	(25.3		)
Transfers out of Level 3	(3.8		)	—
Balance at December 31,	$	—		$	—

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



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2012				December 31, 2011
	(in millions)
Financial liabilities
Checks outstanding in excess of cash balances	$	39.7	$	39.7	$	29.4	$	29.4
Long-term debt	$	3,206.9	$	3,420.7	$	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 are used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company's asset retirement obligations is presented in Note 4 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring, non-financial measurements. The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties and goodwill for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the years ended December 31, 2012 and 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 years ended December 31, 2012 and 2011, the Company recorded $107.6 million and $195.5 million, respectively, of impairments related to some of its proved properties. The proved properties were written down to their estimated fair values of $71.9 million and $157.2 million at the time of the impairments during 2012 and 2011, respectively.

Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilized a discounted cash flow model to estimates the fair value of acquired property as of the acquisition date which utilized the following inputs to estimate future net cash flows: estimated quantities of crude oil, natural gas and NGL reserves; estimates of future commodity prices; and estimated production rates, future operating and development costs which were based on the Company's historic experience with similar properties. Due to the unobservable characteristics of the inputs, the fair value of the properties are considered Level 3 within the fair value hierarchy. Refer to Note 2 - Acquisition, for additional information on the fair value of acquired properties.

- Definition

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.

+ References

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+ Details

Derivative Contracts

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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 commodity 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.

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 December 31, 2012, AOCI consisted of $123.5 million ($77.6 million after tax) of unrealized gains. During 2012, $171.1 million unrealized gains, after tax, were reclassified from AOCI into the Consolidated Statement of Operations in "Realized and unrealized gains on derivative contracts" as the transactions settled. QEP expects to reclassify into earnings from AOCI the remaining fixed value related to de-designated natural gas, oil and NGL hedges during 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. 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 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 are valued at mark-to-market, 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 December 31, 2012:



				Swaps
Year	Type of Contract	Index	Total Volumes	Average price per unit
			(in millions)
Natural gas sales			(MMBtu)
2013	Swap	NYMEX	51.1	$	3.79
2013	Swap	IFNPCR	65.7	$	5.66
2014	Swap	NYMEX	18.3	$	4.21
Oil sales			(Bbls)
2013	Swap	NYMEX WTI	5.1	$	98.48
2014	Swap	NYMEX WTI	1.8	92.72

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 December 31, 2012:



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2013	Swap	IFNPCR	4.0	$	3.78
Natural gas purchases			(MMBtu)
2013	Swap	IFNPCR	0.2	$	2.88
2014	Swap	IFNPCR	0.1	$	3.02

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 December 31, 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 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
		December 31,
	Balance Sheet line item	2012		2011		2012		2011
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	189.7	$	284.1	$	1.0	$	11.7
Interest rate swaps	Fair value of derivative contracts	—		—		2.6		—
Long-term:
Commodity	Fair value of derivative contracts	4.2		123.5		0.1		—
Interest rate swaps	Fair value of derivative contracts	—		—		3.6		—
Total derivative instruments		$	193.9	$	407.6	$	7.3	$	11.7

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



Derivative instruments not designated as cash flow hedges ⁽¹⁾	Year Ended December 31,
	2012			2011			2010

Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts	$	341.9		$	(117.7	)	$	(121.7	)
Oil derivative contracts	14.4			—			—
NGL derivative contracts	10.2			—			—
QEP Field Services
NGL derivative contracts	8.4			—			—
QEP Marketing
Natural gas derivative contracts	5.1			—			—
Total realized gain (loss) on commodity derivative contracts	380.0			(117.7		)	(121.7		)
Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts	37.8			117.7			121.7
Oil derivative contracts	29.0			—			—
NGL derivative contracts	1.6			—			—
QEP Field Services
NGL derivative contracts	—			—			—
QEP Marketing
Natural gas derivative contracts	0.9			—			—
Total unrealized gain on commodity derivative contracts	69.3			117.7			121.7
Total realized and unrealized gain on commodity derivative contracts	$	449.3		$	—		$	—
Realized gain (loss) on interest rate swaps
Realized loss on interest rate swaps	$	(1.3	)	$	—		$	—
Unrealized gain (loss) on interest rate swaps
Unrealized loss on interest rate swaps	(6.1		)	—			—
Total realized and unrealized loss on interest rate swaps	$	(7.4	)	$	—		$	—
Total net realized gain on derivative contracts	$	378.7		$	(117.7	)	$	(121.7	)
Total net unrealized gain on derivative contracts	$	63.2		$	117.7		$	121.7
Grand Total	$	441.9		$	—		$	—

____________________________

⁽¹⁾ Gains and losses on derivatives not designated as cash flow hedges, are included in earnings in "Realized and unrealized gains on derivative contracts" on the Consolidated Statement of Operations.

The following table presents the change in the fair value and settlement of QEP's derivative contracts that were designated as cash flow hedges in 2011 and 2010:



Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	December 31,
Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	2012		2011			2010
Commodity derivatives
Gain on derivative instruments for the effective portion of hedge recognized in AOCI	Accumulated other comprehensive income	$	—	$	350.8		$	565.8
Gain reclassified from AOCI into income for effective portion of hedge	Natural gas sales	—		305.5			353.8
Gain reclassified from AOCI into income for effective portion of hedge	Oil sales	—		1.6			(8.7		)
Gain reclassified from AOCI into income for effective portion of hedge	NGL sales	—		(0.2		)	—
Gain reclassified from AOCI into income for effective portion of hedge	Marketing purchases	—		4.3			3.1
Gain recognized in income for the ineffective portion of hedges	Interest and other income	—		0.1			0.2

The Company estimates that the remaining derivative contracts that were outstanding in AOCI at December 31, 2012, with a fixed fair value of $77.6 million after tax, will be settled and reclassified from AOCI to the Consolidated Statements of Operations during the next twelve months.

- Definition

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

12 Months Ended

Dec. 31, 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. During the second half of 2012, QEP incurred additional restructuring and reorganization costs related to consolidating various corporate and accounting functions to the Denver corporate headquarters. The creation of one office for QEP's Southern Region as well as consolidation of corporate and accounting functions is intended to increase efficiency, team-based collaboration and organizational productivity over the long term. As part of the reorganization, QEP incurred and will continue to incur costs associated with the severance, retention and relocation of employees, additional pension expenses, exit costs associated with the termination of operating leases arising from office space that will no longer be utilized by the Company and other expenses. The Company currently estimates that the remaining restructuring costs will be incurred during 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 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	$	3.3	$	—	$	0.2	$	3.5
Retention and relocation expense	5.4		0.2		0.2		5.8
Lease termination costs and other expenses	0.6		—		—		0.6
Total restructuring costs expected to be incurred	$	9.3	$	0.2	$	0.4	$	9.9

Total restructuring costs recognized in income for the year ended December 31, 2012
One-time termination benefits	$	2.9	$	—	$	0.1	$	3.0
Retention and relocation expense	3.4		—		—		3.4
Lease termination costs and other expenses	0.6		—		—		0.6
Total restructuring costs incurred during the year	$	6.9	$	—	$	0.1	$	7.0
ended December 31, 2012	$	6.9	$	—	$	0.1	$	7.0

In addition to the costs incurred above, during the year ended December 31, 2012, the Company recognized a curtailment loss of $2.2 million as part of its pension plan's net periodic benefit cost. The curtailment loss was a result of the Company's restructuring efforts and termination benefits and is included on the Consolidated Balance Sheet as part of the Company's pension liability. For additional information related to the Company's pension plans, see Note 11 - Employee Benefits. The following is a reconciliation of the restructuring liability, by line of business, which is included within "Accounts payable and accrued expenses" on the Consolidated Balance Sheets:



	QEP Energy			QEP Field Services		QEP Marketing			Total
	(in millions)
Balance at December 31, 2011	$	—		$	—	$	—		$	—
Costs incurred and charged to expense	6.9			—		0.1			7.0
Costs paid or otherwise settled	(5.9		)	—		(0.1		)	(6.0		)
Balance at December 31, 2012	$	1.0		—		—			$	1.0

- Definition

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

12 Months Ended

Dec. 31, 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 and term loan agreement, consisted of the following:



	December 31,
	2012			2011
	(in millions)
Revolving credit facility due 2016	$	690.0		$	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	3,211.8			1,684.9
Less unamortized discount	(4.9		)	(5.5		)
Total long-term debt outstanding	$	3,206.9		$	1,679.4

Of the total debt outstanding on December 31, 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 borrowings 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 two additional one-year periods, with the agreement of the lenders.

During the year ended December 31, 2012, QEP's weighted-average interest rate on borrowings from its credit facility was 2.08%. At December 31, 2012 and 2011, QEP was in compliance with the covenants under the credit agreement. At December 31, 2012, there was $690.0 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 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 year ended December 31, 2012, QEP's weighted-average interest rate on borrowings from the term loan was 2.05%. At December 31, 2012, QEP was in compliance with the covenants under the term loan credit agreement.

Senior Notes

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. The 2022 senior notes were issued at par. Interest on the 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.

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 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. The notes were issued at par. Interest on the notes will be paid semi-annually, in May and November of each year. The net proceeds of $641.0 million were used to fund a portion of the 2012 Acquisition, as described in Note 2 - Acquisition. The costs associated with the offering were $9.0 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 Consolidated Statement of Operations.

At December 31, 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.

- Definition

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

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Contingencies

Commitments and Contingencies

QEP is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. QEP assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. 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. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, QEP may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. QEP regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The following discussion describes the nature of QEP's material loss contingencies.

Environmental Claims

United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah filed on February 28, 2008. The U.S. Environmental Protection Agency (EPA) 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 was paid to a trust 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 $1.2 million had been spent as of December 31, 2012. QEP Field Services will have continuing operational compliance obligations under the consent decree at the affected facilities.

In October 2009, the Company received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from unpermitted work resulting in the discharge of dredged and/or fill material into waters of the United States at three sites located in Caddo and Red River Parishes, Louisiana. EPA Region 6 has assumed lead responsibility for enforcement of the cease and desist order and any possible future orders for the removal of unauthorized fills and/or civil penalties under the Clean Water Act. In 2012, the Company completed a field audit, which identified 112 additional instances affecting approximately 90 acres where work may have been conducted in violation of the Clean Water Act. The Company has disclosed each of these instances to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. The Company is working with the EPA and the COE to resolve these matters, which will require the Company to undertake certain mitigation and permitting activities, and may require the Company to pay a monetary penalty. At this time, QEP is unable to estimate the potential loss related to this matter, but believes it exceeds the $100,000 threshold for disclosure of environmental matters.

Litigation

Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for the Western District of Oklahoma. This statewide class action was filed on January 20, 2011, on behalf of QEP's Oklahoma royalty owners asserting various claims for damages related to royalty valuation on all of QEP's Oklahoma wells operated by QEP or from which QEP marketed gas. 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 certified the class as to the breach of contract, breach of fiduciary duty and unjust enrichment claims. The parties successfully mediated the case in January 2013. On February 13, 2013, the parties executed a Stipulation and Agreement of Settlement (the Chieftain Settlement Agreement) providing for a cash payment from QEP to the class in the amount of $115.0 million. In consideration for the settlement payment, QEP will receive a full release of all claims regarding the calculation, reporting and payment of royalties from the sale of natural gas and its constituents for all periods prior to February 28, 2013, and all class members are enjoined from asserting claims related to such royalties. As part of the Chieftain Settlement Agreement, the parties also agreed on the methodology for the calculation and payment of future royalties payable by QEP, or its successors and assigns, under all class leases for the life of such leases. The Court has entered a Preliminary Order Approving Class Action Settlement. During the year ended December 31, 2012, QEP recorded a loss contingency accrual of $115.0 million, which is included in "General and administrative" expense on the Consolidated Statement of Operations. The accrual is included in "Accounts payable and accrued expenses" on the Consolidated Balance Sheet.

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.

Commitments

Subsidiaries of QEP have contracted for firm-transportation services with various third-party pipelines. Market conditions, drilling activity and competition may prevent full utilization of the contractual capacity. In addition, QEP has contracts with third parties who provide drilling services and fractionation contracts. Annual payments and the corresponding years for transportation contracts, drilling contracts and fractionation contracts are as follows (in millions):



Year	Amount
2013	$	161.3
2014	$	146.2
2015	$	112.0
2016	$	107.7
2017	$	107.0
After 2017	$	385.7

QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $7.3 million, $5.0 million and $4.5 million during the years ended December 31, 2012, 2011 and 2010, respectively. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions):



Year	Amount
2013	$	6.7
2014	$	6.5
2015	$	6.6
2016	$	6.5
2017	$	6.7
After 2017	$	29.1

- Definition

The entire disclosure for commitments and contingencies.

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+ Details

Share-Based Compensation

12 Months Ended

Dec. 31, 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 Consolidated Balance Sheets. There were 13.1 million shares available for future grants under the LTSIP at December 31, 2012. Share-based compensation expense is recognized in "General and administrative" on the Consolidated Statements of Operations. During the year ended December 31, 2012, QEP recognized $25.6 million in total compensation expense related to share-based compensation compared to $22.0 million and $16.1 million during the years ended December 31, 2011 and 2010, respectively.

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options awards at the date of the grant. 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 Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date.

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
	Year Ended December 31,
	2012			2011			2010
Weighted-average grant-date fair value of awards granted during the period	$	14.29		$	18.80		$	27.55
Risk-free interest rate range	0.63% - 1.04%			n/a			n/a
Weighted-average risk-free interest rate	0.8		%	2.1		%	2.3		%
Expected price volatility range	55.9% - 56.5%			n/a			n/a
Weighted-average expected price volatility	55.9		%	54.7		%	30.3		%
Expected dividend yield	0.26		%	0.21		%	1.18		%
Expected term in years at the date of grant	5.0			5.0			5.2

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



	Options Outstanding		Weighted- Average Exercise 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	304,660		30.75
Exercised	(610,883	)	14.87
Forfeited	—		—		—
Outstanding at December 31, 2012	1,697,471		$	25.23	3.64	$	10.5
Options Exercisable at December 31, 2012	1,230,843		$	22.50	2.88	$	10.3
Unvested Options at December 31, 2012	466,628		$	32.40	5.65	$	0.2

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $9.6 million, $2.7 million and $0.3 million during the years ended December 31, 2012, 2011 and 2010, respectively. The Company realized $4.6 million and $0.4 million of income tax benefits for the years ended December 31, 2012 and 2011 (no income tax benefit realized in 2010), which increased its Additional Paid-in-Capital (APIC) pool by $5.1 million as of December 31, 2012. As of December 31, 2012, $2.7 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 1.99 years. During the year ended December 31, 2012, QEP issued shares for stock option exercises from its treasury stock. During the year end December 31, 2012, QEP received $2.6 million in cash in relation to the exercise of stock options.

Restricted Shares

Restricted share grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The total fair value of restricted stock that vested during the years ended December 31, 2012 and 2011, was $16.7 million and $11.7 million, respectively, with minimal vestings in 2010. The Company realized $0.3 million income tax expense and $1.0 million income tax benefit for the years ended December 31, 2012 and 2011, respectively, and increased the Company's APIC pool by $0.9 million as of December 31, 2012. The weighted average grant-date fair value of restricted stock granted during the years was $30.54 per share, $38.50 per share and $28.70 per share for the years ended December 31, 2012, 2011 and 2010, respectively. As of December 31, 2012, $16.5 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 2.09 years.

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



	Restricted Shares Outstanding		Weighted- Average Grant-Date Fair Value
			(per share)
Unvested balance at December 31, 2011	1,099,752		$	32.80
Granted	827,986		30.54
Vested	(541,230	)	31.90
Forfeited	(85,920	)	32.30
Unvested balance at December 31, 2012	1,300,588		$	31.78

Performance Share Units

The 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 granted during the period was $30.90 per unit and $39.07 per unit for the years ended December 31, 2012 and 2011, respectively. As of December 31, 2012, $3.2 million of unrecognized compensation cost classified as a liability, 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 1.90 years.

Transactions involving performance share units under the terms of the CIP are summarized below:



	Performance Share Units Outstanding		Weighted- Average Grant-Date Fair Value
Unvested balance at December 31, 2011	115,274		$	39.07
Granted	180,923		30.90
Vested	—		—
Forfeited	(12,713	)	35.69
Unvested balance at December 31, 2012	283,484		$	34.01

- Definition

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.

+ References

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+ Details

Employee Benefits

12 Months Ended

Dec. 31, 2012

Compensation and Retirement Disclosure [Abstract]

Employee Benefits

Defined Benefit Pension Plans and Other Postretirement Benefits

The Company maintains closed, defined-benefit pension and postretirement medical plans providing coverage to 145, or 16%, of QEP's active employees and to 70 participants that are retired, terminated and vested, or suspended. Pension-plan benefits are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding retirement. QEP pension plans include a qualified and a nonqualified retirement plan. Postretirement health care benefits and life insurance are provided only to employees hired before January 1, 1997. The Company pays a portion of the costs of health-care benefits determined by an employee's years of service. The Company has capped its exposure to increasing medical care and life insurance costs by paying a fixed dollar monthly contribution toward these retiree benefits. The Company contribution is prorated based on an employee's years of service at retirement; only those employees with 25 or more years of service receive the maximum Company contribution. At December 31, 2012 and 2011, QEP's accumulated benefit obligation exceeded the fair value of plan assets as the plan is unfunded.

During the year ended December 31, 2012, the Company recognized a $2.2 million loss on curtailment as part of its restructuring efforts and related termination benefits. A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services. For additional information regarding the Company's restructuring efforts see Note 7 - Restructuring Costs. During the year ended December 31, 2012, the Company made contributions of $5.6 million to its funded pension plan, and $1.3 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 2013, the Company expects to contribute approximately $8.1 million to its funded pension plan, approximately $3.2 million to its unfunded pension plan and approximately $0.2 million for retiree health care and life insurance benefits. The accumulated postretirement benefit obligation for all defined-benefit pension plans was $106.9 million and $78.3 million at December 31, 2012 and 2011, respectively.

The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's pension and other postretirement benefit plans for the years ended December 31, 2012 and 2011, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2012 and 2011:



	Pension benefits						Other postretirement benefits
	2012			2011			2012			2011
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$	104.1		$	78.0		$	5.9		$	4.5
Service cost	4.0			2.9			0.1			0.1
Interest cost	5.1			4.5			0.3			0.3
Change in plan assumptions	8.4			19.6			—			—
Benefit payments	(2.7		)	(0.2		)	—			—
Actuarial loss (gain)	10.8			(0.7		)	0.4			1.0
Benefit obligation at December 31,	$	129.7		$	104.1		$	6.7		$	5.9
Change in plan assets
Fair value of plan assets at January 1,	$	44.2		$	30.9		$	—		$	—
Actual gain (loss) on plan assets	6.9			(1.3		)	—			—
Company contributions to the plan	6.9			14.8			—			—
Benefit payments	(2.7		)	(0.2		)	—			—
Fair value of plan assets at December 31,	55.3			44.2			—			—
Underfunded status (current and long-term)	$	(74.4	)	$	(59.9	)	$	(6.7	)	$	(5.9	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(3.2	)	$	(1.3	)	$	(0.2	)	$	—
Other long-term liabilities	(71.2		)	(58.6		)	(6.5		)	(5.9		)
Total amount recognized in balance sheet	$	(74.4	)	$	(59.9	)	$	(6.7	)	$	(5.9	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	32.6		$	18.6		$	1.3		$	1.0
Prior service cost	35.1			42.6			3.4			3.8
Total amount recognized in AOCI	$	67.7		$	61.2		$	4.7		$	4.8

The following table sets forth the Company's pension and other postretirement benefit cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31:



	Pension benefits									Other postretirement benefits
	2012			2011			2010			2012			2011			2010

Components of net periodic benefit cost
Service cost	$	4.0		$	2.9		$	1.3		$	0.1		$	0.1		$	0.1
Interest cost	5.1			4.5			2.1			0.3			0.3			0.1
Expected return on plan assets	(3.6		)	(2.6		)	(1.1		)	—			—			—
Curtailment loss	2.2			—			—			—			—			—
Amortization of prior service costs	5.3			5.3			2.6			0.3			0.3			0.2
Amortization of actuarial loss	1.9			—			—			0.1			—			—
Periodic expense	$	14.9		$	10.1		$	4.9		$	0.8		$	0.7		$	0.4
Components recognized in accumulated other comprehensive income
Current period actuarial loss (gain)	$	15.9		$	22.9		$	(4.2	)	$	0.4		$	1.0		$	—
Amortization of actuarial loss	(1.9		)	—			—			(0.1		)	—			—
Current period prior service cost	—			—			50.4			—			—			4.3
Amortization of prior service cost	(5.3		)	(5.3		)	(2.6		)	(0.4		)	(0.3		)	(0.1		)
Loss on curtailment in current period	(2.2		)	—			—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	6.5		$	17.6		$	43.6		$	(0.1	)	$	0.7		$	4.2

The estimated portion of net actuarial loss and net prior service cost for the pension plans that will be amortized from AOCI into net periodic benefit cost in 2013 is $7.3 million, of which $5.0 million represents amortization of prior service cost recognition and the remaining $2.3 million represents amortization of net actuarial losses. The estimated portion to be recognized in net periodic cost for other postretirement benefits from AOCI in 2013 is $0.5 million, of which $0.4 million represents amortization of prior service cost recognition and the remaining $0.1 million represents amortization of net actuarial losses.

Following are the weighted-average assumptions (weighted by the plan level benefit obligation for pension benefits) used by the Company to calculate pension and other postretirement benefit obligations at December 31, 2012 and 2011:



	Pension benefits				Other postretirement benefits
	2012		2011		2012		2011
Discount rate	3.88	%	4.54	%	4.10	%	4.70	%
Rate of increase in compensation	3.60	%	3.60	%	3.60	%	4.00	%

The discount rate assumptions used by the Company represents an estimate of the interest rate at which the pension and other postretirement obligations could effectively be settled on the measurement date.

Following are the weighted-average assumptions (weighted by the net period benefit cost for pension benefits) used by the Company in determining the net periodic pension and other postretirement benefit cost for the years ended December 31:



	Pension benefits						Other postretirement benefits
	2012		2011		2010		2012		2011		2010
Discount rate	4.38	%	5.80	%	5.70	%	4.70	%	5.80	%	5.70	%
Expected long-term return on plan assets	7.25	%	7.50	%	7.50	%	n/a		n/a		n/a
Rate of increase in compensation	3.60	%	3.60	%	3.60	%	4.00	%	n/a		n/a

In selecting the assumption for expected long-term rate of return on assets, the Company considers the average rate of return expected on the funds to be invested to provide benefits. This includes considering the plan's asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. No plan assets are expected to be returned to the Company in 2013. Historical heath care cost trend rates are not applicable to the Company because the Company's medical costs are capped at a fixed amount. As the Company's medical costs are capped at a fixed amount, the sensitivity to increase and decreases in the health-care inflation rate is not applicable.

Plan Assets

The Company's Employee Benefits Committee (EBC) oversees investment of pension plan assets. The EBC uses a third-party asset manager to assist in setting targeted-policy ranges for the allocation of assets among various investment categories. The EBC allocates pension-plan assets among broad asset categories and reviews the asset allocation at least annually. Asset-allocation decisions consider risk and return, future-benefit requirements, participant growth and other expected cash flows. These characteristics affect the level, risk and expected growth of postretirement-benefit assets. The EBC uses asset-mix guidelines that include targets for each asset category, return objectives for each asset group and the desired level of diversification and liquidity. These guidelines may change from time to time based on the committee's ongoing evaluation of each plan's risk tolerance. The EBC estimates an expected overall long-term rate of return on assets by weighting expected returns of each asset class by its targeted asset allocation percentage. Expected return estimates are developed from analysis of past performance and forecasts of long-term return expectations by third-parties. Responsibility for individual security selection rests with each investment manager, who is subject to guidelines specified by the EBC. The EBC sets performance objectives for each investment manager that are expected to be met over a three-year period or a complete market cycle, whichever is shorter. Performance and risk levels are regularly monitored to confirm policy compliance and that results are within expectations. Performance for each investment is measured relative to the appropriate index benchmark for its category. QEP securities may be considered for purchase at an investment manager's discretion, but within limitations prescribed by ERISA and other laws. There was no direct investment in QEP shares for the periods disclosed. The majority of retirement-benefit assets were invested as follows:

Equity securities: Domestic equity assets were mostly invested in a stock index fund, and a smaller portion was invested in an actively managed product, with a diversification goal representative of the whole U.S. stock market. Foreign equity securities consisted of developed and emerging market foreign equity assets that were invested in funds that hold diversified portfolio of common stocks of corporations in developed and emerging foreign countries.

Debt securities: Investment grade intermediate-term debt assets are invested in funds holding a diversified portfolio of debt of governments, corporations and mortgage borrowers with average maturities of 5 to 10 years and investment grade credit ratings. Investment grade long-term debt assets are invested in a diversified portfolio of debt of corporate and non-corporate issuers, with an average maturity of more than ten years and investment grade credit ratings.

Although the actual allocation to cash and short-term investments is minimal (less than 1%), larger cash allocations may be held from time to time if deemed necessary for operational aspects of the retirement plan. Cash is invested in a high-quality, short-term temporary investment fund that purchases investment-grade quality short-term debt issued by governments and corporations.

Commingled funds: The EBC made the decision to invest all of the retirement plan assets in commingled funds as these funds typically have lower expense ratios and are more tax efficient than mutual funds. While commingled funds are classified as Level 3 assets because there are calculations involved in determining the net asset value of the funds, the underlying assets can be traced back to observable asset values and these commingled funds are audited annually by an independent accounting firm.

The fair value measurement provision of ASC 820, Fair Value Measurements, defines fair value in applying generally accepted accounting principles as well as establishes a framework for measuring fair value and for making disclosures about fair-value measurements. Fair value measurement establishes a fair-value hierarchy. Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for an asset, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset. The Company's Level 3 investments are public investment vehicles valued using the net asset value (NAV) of the fund, but are considered Level 3 because they are commingled funds. The NAV is based on the value of the underlying assets owned by the fund excluding transaction costs, and minus liabilities.

The following table sets forth by level, within the fair value hierarchy, the fair value of pension and postretirement benefit assets.:



	As of December 31, 2012								Percentage of total
	Level 1		Level 2		Level 3		Total		Percentage of total
	(in millions except percentages)
Cash and short-term investments	$	—	$	—	$	0.2	$	0.2	—		%
Equity securities:
Domestic	—		—		22.2		22.2		40		%
International	—		—		16.7		16.7		30		%
Fixed income	—		—		16.2		16.2		30		%
Total investments	—		—		$	55.3	$	55.3	100		%
	As of December 31, 2011								Percentage of total
	Level 1		Level 2		Level 3		Total		Percentage of total
	(in millions except percentages)
Cash and short-term investments	$	—	$	—	$	—	$	—	$	—
Equity securities:
Domestic	—		—		17.6		17.6		40		%
International	—		—		13		13.0		29		%
Fixed income	—		—		13.6		13.6		31		%
Total investments	—		—		$	44.2	$	44.2	100		%

The following table presents a summary of changes in the fair value of QEP's Level 3 investments:



	Year ended December 31,
	2012			2011
	(in millions)
Balance at January 1,	$	44.2		30.9
Employer contributions	5.6			14.8
Unrealized gains (losses)	6.3			(1.4		)
Realized gains	0.7			0.3
Administrative fees	(0.2		)	(0.2		)
Benefits paid	(1.3		)	(0.2		)
Balance at December 31,	$	55.3		$	44.2

Expected Benefit Payments

As of December 31, 2012, the following future benefit payments are expected to be paid:



	Pension		Postretirement benefits
	(in millions)
2013	$	5.7	$	0.2
2014	5.3		0.2
2015	4.9		0.2
2016	5.6		0.3
2017	5.2		0.3
2018 through 2021	40.9		1.8

Employee Investment Plan

QEP employees may participate in the QEP Employee Investment Plan (EIP), a defined-contribution plan. The EIP allows eligible employees to purchase shares of QEP common stock or other investments through payroll deduction at the current fair market value on the transaction date. The Company currently contributes an overall match of 100% of employees' contribution up to a maximum of 6% of their qualifying earnings. In addition, from time-to-time at the discretion of management, the Company may contribute a discretionary portion beyond the company match to employees not in the Company's closed defined benefit plan. The Company recognizes expense equal to its yearly contributions, which amounted to $6.4 million, $5.8 million and $4.2 million during the years ended December 31, 2012, 2011 and 2010.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5, 6, 7, 8

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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Income Taxes

Details of income tax expenses and deferred income taxes from continuing operations are provided in the following tables. The components of income tax expenses were as follows:



	Year Ended December 31,
	2012			2011			2010
	(in millions)
Federal income tax expense (benefit)
Current	$	33.7		$	(5.3	)	$	(16.6	)
Deferred	36.5			153.0			172.9
State income tax expense (benefit)
Current	0.7			2.9			(4.7		)
Deferred	(4.4		)	3.8			15.4
Total income tax expense	$	66.5		$	154.4		$	167.0

The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:



	Year Ended December 31,
	2012		2011		2010
Federal income taxes statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	(1.2	)%	1.0	%	1.5	%
Penalties	(0.6	)%	—	%	—	%
Return to provision adjustment	0.4	%	1.3	%	0.2	%
Noncontrolling interest	(0.7	)%	(0.3	)%	(0.2	)%
Non-deductible Spin-off costs	—	%	—	%	0.5	%
Other	0.6	%	(0.7	)%	(0.1	)%
Effective income tax rate	33.5	%	36.3	%	36.9	%

Significant components of the Company's deferred income taxes were as follows:



	December 31,
	2012		2011
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$	1,606.6	$	1,714.6
Commodity price and interest rate derivatives	69.4		147.2
Total deferred tax liabilities	1,676.0		1,861.8
Deferred tax assets
NOL and tax credit carryforwards	65.6		232.9
Employee benefits and compensation costs	47.7		42.9
Accrued litigation loss contingency	42.8		—
Bonus and vacation accrual	11.8		10.7
Other	9.6		5.2
Total deferred tax assets	177.5		291.7
Net deferred income tax liability	$	1,498.5	$	1,570.1
Balance sheet classification
Deferred income tax liability - current	$	5.0	$	85.4
Deferred income tax liability - non-current	1,493.5		1,484.7
Net deferred income tax liability	$	1,498.5	$	1,570.1

Federal and state income tax NOLs and credits declined significantly at December 31, 2012, compared to December 31, 2011, due to an election to capitalize and amortize certain intangible drilling costs in order to minimize alternative minimum tax. The amounts and expiration dates of operating loss and tax credit carryforwards at December 31, 2012:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and credit carryforwards	2014-2032	$	21.2
U.S. alternative minimum tax credit	Indefinite	44.4
Total		$	65.6

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

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-Number 210

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+ Details

Discontinued Operations

12 Months Ended

Dec. 31, 2012

Discontinued Operations [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

Discontinued Operations

Wexpro's operating results prior to the Spin-off are reflected in this Annual Report on Form 10-K as discontinued operations and summarized in the table below:



	Year Ended December 31,
	2012		2011		2010
	(in millions, except per share amounts)
Revenues	$	—	$	—	$	131.2
Income before income taxes	—		—		67.4
Income taxes	—		—		(24.2		)
Discontinued operations, net of income taxes	$	—	$	—	$	43.2
Earnings per common share attributable to QEP
Basic from discontinued operations	$	—	$	—	$	0.25
Diluted from discontinued operations	—		—		0.24

- Definition

The entire disclosure for the facts and circumstances leading to the completed or expected disposal, manner and timing of disposal, the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the segment in which the disposal group was reported, and the classification (whether sold or classified as held for sale) and carrying value of the assets and liabilities comprising the disposal group. Includes all disposal groups, including those classified as components of the entity (discontinued operations).

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+ Details

Operations by Line of Business

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Operations by Line of Business

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

The following table is a summary of operating results for the year ended December 31, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	1,615.4		$	320.2		$	414.2		$	—		$	2,349.8
From affiliated customers	—			119.0			605.7			(724.7		)	—
Total Revenues	1,615.4			439.2			1,019.9			(724.7		)	2,349.8
Operating expenses
Purchased gas, oil and NGL expense	224.7			12.1			1,021.1			(602.3		)	655.6
Lease operating expense	175.8			—			—			(3.5		)	172.3
Natural gas, oil and NGL transportation and other handling costs	228.1			33.6			—			(112.8		)	148.9
Gathering, processing and other	—			86.8			1.2			—			88.0
General and administrative	237.6			34.7			0.4			(6.1		)	266.6
Production and property taxes	97.2			6.0			0.2			—			103.4
Depreciation, depletion and amortization	838.0			63.2			3.7			—			904.9
Abandonment, impairment and exploration expenses	144.6			—			—			—			144.6
Total operating expenses	1,946.0			236.4			1,026.6			(724.7		)	2,484.3
Net gain from asset sales	1.2			—			—			—			1.2
Operating (loss) income ⁽¹⁾	(329.4		)	202.8			(6.7		)	—			(133.3		)
Realized and unrealized gains (losses) on derivative contracts	434.9			8.4			(1.4		)	—			441.9
Interest and other income	6.2			0.2			132.1			(131.9		)	6.6
Income from unconsolidated affiliates	0.1			6.7			—			—			6.8
Loss on early extinguishment of debt	—			—			(0.6		)	—			(0.6		)
Interest expense	(116.8		)	(13.6		)	(124.4		)	131.9			(122.9		)
Income (loss) before income taxes	(5.0		)	204.5			(1.0		)	—			198.5
Income tax (provision) benefit	4.3			(71.8		)	1.0			—			(66.5		)
Net income (loss)	(0.7		)	132.7			—			—			132.0
Net income attributable to noncontrolling interest	—			(3.7		)	—			—			(3.7		)
Net income (loss) attributable to QEP ⁽²⁾	$	(0.7	)	$	129.0		$	—		$	—		$	128.3
Identifiable total assets	$	7,436.5		$	1,399.7		$	272.3		$	—		$	9,108.5
Investment in unconsolidated affiliates	—			41.2			—			—			41.2
Cash capital expenditures	2,621.1			164.0			14.6			—			2,799.7
Accrued capital expenditures	2,702.4			171.2			14.6			—			2,888.2
Goodwill	59.5			—			—			—			59.5

____________________________


⁽¹⁾	The impact of QEP's settled derivative contracts, for the year ended December 31, 2012, are reflected below operating (loss) income.


⁽²⁾	Net (loss) income attributable to QEP for the year ended December 31, 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 year ended December 31, 2011, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	2,213.2		$	369.3		$	576.7		$	—		$	3,159.2
From affiliated customers	—			96.2			580.2			(676.4		)	—
Total Revenues	2,213.2			465.5			1,156.9			(676.4		)	3,159.2
Operating expenses
Purchased gas, oil and NGL expense	506.4			—			1,144.5			(573.8		)	1,077.1
Lease operating expense	148.2			—			—			(3.0		)	145.2
Natural gas, oil and NGL transportation and other handling costs	186.0			9.3			—			(93.1		)	102.2
Gathering, processing and other	—			106.0			1.3			—			107.3
General and administrative	98.4			29.2			2.1			(6.5		)	123.2
Production and property taxes	99.1			6.1			0.2			—			105.4
Depreciation, depletion and amortization	707.2			55.7			2.5			—			765.4
Abandonment, impairment and exploration expenses	228.9			—			—			—			228.9
Total operating expenses	1,974.2			206.3			1,150.6			(676.4		)	2,654.7
Net gain (loss) from asset sales	1.4			—			—			—			1.4
Operating income ⁽²⁾	240.4			259.2			6.3			—			505.9
Interest and other income	4.0			0.1			98.7			(98.7		)	4.1
Income from unconsolidated affiliates	0.1			5.4			—			—			5.5
Loss on extinguishment of debt	—			—			(0.7		)	—			(0.7		)
Interest expense	(81.9		)	(13.6		)	(93.2		)	98.7			(90.0		)
Income before income taxes	162.6			251.1			11.1			—			424.8
Income taxes	(57.9		)	(93.4		)	(3.1		)	—			(154.4		)
Net income	104.7			157.7			8.0			—			270.4
Net income attributable to noncontrolling interest	—			(3.2		)	—			—			(3.2		)
Net income attributable to QEP ⁽³⁾	$	104.7		$	154.5		$	8.0		$	—		$	267.2
Identifiable assets	$	5,815.7		$	1,312.7		$	314.3		$	—		$	7,442.7
Investment in unconsolidated affiliates	—			42.2			—			—			42.2
Cash capital expenditures	1,295.5			130.1			5.5			—			1,431.1
Accrued capital expenditures	1,338.7			101.6			5.5			—			1,445.8
Goodwill	59.5			—			—			—			59.5

____________________________


⁽¹⁾	Revenues for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts. See Note 6 - Derivative Contracts, for additional information on derivative contract settlements in the year ended December 31, 2011.


⁽²⁾	Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the year ended December 31, 2011.


⁽³⁾	Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in AOCI during the year ended December 31, 2011.

The following table is a summary of operating results for the year ended December 31, 2010, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	1,456.3		$	245.5		$	598.8		$	—		$	2,300.6
From affiliated customers	—			73.7			499.7			(573.4		)	—
Total Revenues	1,456.3			319.2			1,098.5			(573.4		)	2,300.6
Operating expenses
Purchased gas, oil and NGL expense	—			—			1,082.8			(493.5		)	589.3
Lease operating expense	127.3			—			—			(2.3		)	125.0
Natural gas, oil and NGL transportation and other handling costs	125.5			—			—			(71.3		)	54.2
Gathering, processing and other	—			82.1			1.1			—			83.2
General and administrative	78.0			31.6			3.9			(6.3		)	107.2
Separation costs	—			—			13.5			—			13.5
Production and property taxes	77.8			4.4			0.3			—			82.5
Depreciation, depletion and amortization	592.5			48.9			2.0			—			643.4
Abandonment, impairment and exploration expenses	69.1			—			—			—			69.1
Total operating expenses	1,070.2			167.0			1,103.6			(573.4		)	1,767.4
Net gain (loss) from asset sales	13.7			(1.6		)	—			—			12.1
Operating income ⁽²⁾	399.8			150.6			(5.1		)	—			545.3
Interest and other income	2.1			0.1			87.2			(87.1		)	2.3
Income from unconsolidated affiliates	0.2			2.8			—			—			3.0
Loss on extinguishment of debt	—			—			(13.3		)	—			(13.3		)
Interest expense	(78.5		)	(7.6		)	(85.4		)	87.1			(84.4		)
Income before income taxes	323.6			145.9			(16.6		)	—			452.9
Income taxes	(119.7		)	(51.9		)	4.6			—			(167.0		)
Net income from continuing operations	203.9			94.0			(12.0		)	—			285.9
Discontinued operations, net of income tax	—			—			43.2			—			43.2
Net Income	203.9			94.0			31.2			—			329.1
Net income attributable to noncontrolling interest	—			(2.9		)	—			—			(2.9		)
Net income attributable to QEP ⁽³⁾	$	203.9		$	91.1		$	31.2		$	—		$	326.2
Identifiable assets	$	5,391.9		$	1,197.5		$	195.9		$	—		$	6,785.3
Investment in unconsolidated affiliates	—			44.5			—			—			44.5
Cash capital expenditures	1,205.0			262.1			1.9			—			1,469.0
Accrued capital expenditures	1,215.8			268.2			1.9			—			1,485.9
Goodwill	59.6			—			—			—			59.6

____________________________


(1)	Revenues for the year ended December 31, 2010, reflect the impact of QEP's settled derivative contracts. See Note 6 - Derivative Contracts, for detailed information on derivative contract settlements in the year ended December 31, 2010.


(2)	Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the year ended December 31, 2010.


(3)	Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in AOCI during the year ended December 31, 2010.

- Definition

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.

+ References

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-Name Statement of Financial Accounting Standard (FAS)

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+ Details

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2012
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Subsequent Event On January 7, 2013, QEP announced that its Board of Directors had authorized the formation of a midstream Master Limited Partnership (MLP) accompanied by the preparation and filing of a registration statement with the SEC for an initial public offering (IPO) of common units of the MLP. The Company expects to file a registration statement with the SEC in the second quarter of 2013. The MLP is intended to support the growth of QEP's midstream business and is consistent with the Company's focus on maximizing shareholder value and maintaining balance sheet strength. The Company expects to initially contribute a majority share of its gathering assets in Wyoming, North Dakota and Utah to the MLP. Subject to final board approval and market conditions, QEP expects to sell a minority interest in the MLP in the IPO and raise approximately $300 million to $400 million in gross proceeds. Proceeds from the offering would be used to fund ongoing operations, to repay debt under the Company's credit facility and for general corporate purposes. Additional detail will be included in the registration statement. See Note 9 (Commitments and Contingencies) to these consolidated financial statements for a discussion of the mediation and resulting execution of the Chieftain Settlement Agreement in February 2013.

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure (Unaudited) [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

Quarterly Financial Information (unaudited)

The following table provides a summary of unaudited quarterly financial information:



	First Quarter		Second Quarter			Third Quarter			Fourth Quarter			Year
	(in millions)
2012
Revenues	$	603.2	$	499.3		$	542.4		$	704.9		$	2,349.8
Operating income (loss)	49.5		(55.5		)	(12.6		)	(114.7		)	(133.3		)
Income (loss) before income taxes	244.7		0.3			(4.4		)	(42.1		)	198.5
Net income (loss) attributable to QEP	155.2		(0.7		)	(3.1		)	(23.1		)	128.3
Per share information attributable to QEP
Basic EPS attributable to QEP	$	0.87	$	—		$	(0.02	)	$	(0.13	)	$	0.72
Diluted EPS attributable to QEP	0.87		—			(0.02		)	(0.13		)	0.72



2011
Revenues	$	617.9	$	808.1	$	879.9	$	853.3		$	3,159.2
Operating income	137.1		168.9		183.4		16.5			505.9
Income (loss) before income taxes	116.5		147.7		161.5		(0.9		)	424.8
Net income (loss) attributable to QEP	73.2		92.8		101.5		(0.3		)	267.2
Per share information attributable to QEP
Basic EPS from continuing operations	$	0.42	$	0.52	$	0.58	$	(0.01	)	$	1.51
Basic EPS attributable to QEP	0.41		0.52		0.57		—			1.50

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References+ Details

Supplemental Gas and Oil Information (Unaudited)

12 Months Ended

Dec. 31, 2012

Supplemental Gas and Oil Information (Unaudited) [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Gas and Oil Information (Unaudited)

The Company is making the following supplemental disclosures of gas and oil producing activities, in accordance with ASC 932, Extractive Activities - Oil and Gas, as amended by ASU 2010-03, Oil and Gas Reserve Estimation and Disclosures, and SEC Regulation S-X. The Company uses the successful efforts accounting method for its gas and oil exploration and development activities. All properties are located in the United States.

Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below:



	December 31,
	2012			2011
	(in millions)
Proved properties	$	10,234.3		$	8,172.4
Unproved properties, net	937.9			326.8
Total proved and unproved properties	11,172.2			8,499.2
Accumulated depreciation, depletion and amortization	(4,258.1		)	(3,339.2		)
Net capitalized costs	$	6,914.1		$	5,160.0

Costs Incurred

The costs incurred in gas and oil exploration and development activities are displayed in the table below. Development costs incurred reflect accrued capital costs of $81.3 million and ARO additions and revisions of $17.7 million during the year ended December 31, 2012. The costs incurred to advance the development of reserves that were classified as proved undeveloped were approximately $513.0 million in 2012, $533.6 million in 2011 and $434.2 million in 2010.



	Year Ended December 31,
	2012		2011		2010
	(in millions)
Property acquisitions
Unproved	$	692.6	$	48.0	$	109.1
Proved	714.4		0.1		0.2
Total property acquisitions	1,407.0		48.1		109.3
Exploration (capitalized and expensed)	14.3		36.5		146.4
Development	1,310.0		1,267.8		988.8
Total costs incurred	$	2,731.3	$	1,352.4	$	1,244.5

Results of Operations

Following are the results of operations of QEP Energy gas and oil exploration and development activities, before allocated corporate overhead and interest expenses.



	Year Ended December 31,
	2012			2011			2010
	(in millions)
Revenues ⁽¹⁾	$	1,393.4		$	1,703.4		$	1,456.3
Production costs	501.1			433.3			330.6
Exploration expenses	11.2			10.5			23.0
Depreciation, depletion and amortization	838.0			707.2			592.5
Abandonment and impairment	133.4			218.4			46.1
Total expenses	1,483.7			1,369.4			992.2
Income (loss) before income taxes	(90.3		)	334.0			464.1
Income tax benefit (expense)	33.6			(119.0		)	(171.8		)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(56.7	)	$	215.0		$	292.3

___________________________


⁽¹⁾	Revenue for the years ended December 31, 2011 and 2010, reflect the impact of QEP's settled derivative contracts which during the year ended December 31, 2012, are reflected below operating (loss) income. See Note 6 - Derivative Contracts.

Estimated Quantities of Proved Gas and Oil Reserves

Estimates of proved gas and oil reserves have been completed in accordance with professional engineering standards and the Company's established internal controls, which includes the compliance oversight of a multi-functional reserves review committee responsible to the Company's Board of Directors. QEP Energy's estimated proved reserves have been prepared by Ryder Scott Company, L.P., independent reservoir engineering consultants, in accordance with the SEC's Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

All of QEP Energy's proved undeveloped reserves at December 31, 2012, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves, except for 200 Bcfe located within the northern portion of the Company's Pinedale Anticline leasehold in western Wyoming. Long-term development of natural gas reserves in the Pinedale Anticline Project Area (PAPA) is governed by the Bureau of Land Management's September 2008, Record of Decision (ROD) on the Final Supplemental Environmental Impact Statements. Under the ROD, QEP Energy is allowed to drill and complete wells year-round in designated concentrated development areas defined in the PAPA. The ROD contains additional requirements and restrictions on the sequence of development of the PAPA, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development of the PAPA that is beyond the control of the Company. The Company has an ongoing development plan for the PAPA and the financial capability to continue development in the manner estimated.

As of December 31, 2012, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil and gas reserves for the years ended December 31, 2010, 2011 and 2012 are as follows:



	Natural Gas		Oil		NGL		Natural Gas Equivalents
	(Bcf)		(MMbbl)		(MMbbl)		(Bcfe)
Proved reserves
Balance at December 31, 2009	2,525.0		29.3		7.7		2,746.9
Revisions of previous estimates	46.3		0.7		4.8		78.6
Extensions and discoveries	248.4		26.1		6.1		441.8
Purchase of reserves in place	0.2		—		—		0.2
Sale of reserves in place	(3.2	)	(0.8	)	—		(7.8	)
Production	(203.8	)	(3.0	)	(1.2	)	(229.0	)
Balance at December 31, 2010	2,612.9		52.3		17.4		3,030.7
Revisions of previous estimates ⁽⁴⁾	(270.1	)	1.7		39.3		(23.5	)
Extensions and discoveries ⁽⁵⁾	641.9		17.4		22.6		881.6
Purchase of reserves in place	1.9		—		—		2.1
Sale of reserves in place	(0.8	)	(0.2	)	—		(1.9	)
Production	(236.4	)	(3.7	)	(2.7	)	(275.2	)
Balance at December 31, 2011	2,749.4		67.5		76.6		3,613.8
Revisions of previous estimates ⁽¹⁾	(240.6	)	(1.5	)	0.7		(244.8	)
Extensions and discoveries ⁽²⁾	330.6		17.3		23.0		572.5
Purchase of reserves in place ⁽³⁾	32.3		42.0		4.9		313.8
Sale of reserves in place	—		—		—		—
Production	(249.3	)	(6.3	)	(5.3	)	(319.2	)
Balance at December 31, 2012	2,622.4		119.0		99.9		3,936.1
Proved developed reserves
Balance at December 31, 2009	1,178.7		22.4		4.9		1,342.8
Balance at December 31, 2010	1,404.8		25.1		9.3		1,611.5
Balance at December 31, 2011	1,538.3		33.0		38.4		1,966.3
Balance at December 31, 2012	1,531.7		47.4		49.3		2,111.9
Proved undeveloped reserves
Balance at December 31, 2009	1,346.3		6.9		2.8		1,404.1
Balance at December 31, 2010	1,208.1		27.2		8.0		1,419.2
Balance at December 31, 2011	1,211.1		34.6		38.2		1,647.5
Balance at December 31, 2012	1,090.7		71.6		50.6		1,824.2

____________________________

⁽¹⁾

Revisions of previous estimates in 2012 include negative impacts due to 152.4 Bcfe pricing revisions, 35.6 Bcfe performance revisions, 27.6 Bcfe operating cost revisions and 29.1 Bcfe other revisions. The 152.4 Bcfe pricing revisions were due to lower natural gas prices which reduced natural gas reserve volumes by 147.7 Bcf. Negative performance revisions were driven by a 56.0 Bcfe decrease in Pinedale reserves. Pinedale reserve adjustments are based on additional production history, well performance and current pricing causing a revised future development plan which includes lower density drilling in some flank areas, resulting in 25 proved undeveloped (PUD) locations being eliminated. Reserve decreases are partially offset by a 35.9 Bcfe positive impact from revisions in the Uinta Basin, due to the installation of the Iron Horse Cryogenic plant to increase liquid recoveries and improved well performance in the Red Wash Mesaverde field.

⁽²⁾

Extensions and discoveries in 2012 increased proved reserves by 572.5 Bcfe, primarily related to extensions and discoveries in the Uinta Basin of 258.3 Bcfe, in Pinedale of 151.6 Bcfe, and 162.6 Bcfe in the Williston Basin, Midcontinent and other Legacy areas of operation combined. All of these extensions and discoveries related to new well completions and the associated new PUD locations as part of the Company's development drilling plans.


⁽³⁾	Purchase of reserves in place primarily relate to the Company's $1.4 billion 2012 Acquisition as discussed in Note 2 - Acquisition.

⁽⁴⁾

Revisions of previous estimates in 2011 include 173.7 Bcfe negative impact due to performance revisions offset by 150.2 Bcfe positive impact from other revisions. The 173.7 Bcfe performance revisions were due to the reduction of natural gas volumes of 209.8 Bcf, partially offset by an increase in NGL volumes of 33.2 MMbbls, which is included in other revisions. The primary reason for the increase in the NGL volumes, or 31.8 MMbbls, relates to the completion of the Blacks Fork II plant and the fee-based processing agreement entered into between QEP Energy and QEP Field Services for QEP Energy's Pinedale production, offset by a reduction in the dry natural gas reserve related to shrink of about 59.6 Bcf. The remaining performance related reduction in the natural gas reserves was primarily related to the removal of certain PUD locations in the Haynesville/Cotton Valley area to recognize the 80-acre increased density development plan.

⁽⁵⁾

Extensions and discoveries increased proved reserves by 881.6 Bcfe, primarily related to extensions and discoveries at the Haynesville/Cotton Valley area (358.8 Bcfe), Uinta Basin area (189.1 Bcfe) and Pinedale Anticline area (161.2 Bcfe). All of these extensions and discoveries related to new well completions and associated new PUD locations. Estimates of the quantity of proved reserves from the Company's Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and the development and application of reliable technologies. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling are included in extensions and discoveries for the years ended December 31, 2011 and 2010, because each new well drilled recovers incremental reserves that would otherwise be unrecoverable.

Standardized Measure of Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31, 2012, 2011 and 2010, by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the 12-months of 2012, 2011 and 2010 with consideration of known contractual price changes. The prices used do not include any impact of QEP's commodity derivatives portfolio. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:



	For the year ended December 31,
	2012		2011		2010
Average benchmark price per unit:
Natural gas price (per MMbtu)	$	2.76	$	4.12	$	4.38
Crude oil price (per Bbl)	94.71		96.19		79.43

Year-end operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop booked proved undeveloped reserves are approximately $1,042.5 million in 2013, $871.1 million in 2014 and $814.5 million in 2015.

The assumptions used to derive the standardized measure of future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating QEP or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:


•	Future commodity prices received for selling the Company's net production will probably differ from those required to be used in these calculations.


•	Future operating and capital costs will probably differ from those required to be used in these calculations.


•	Future market conditions, government regulations and reservoir conditions may cause production rates in future years to vary significantly from those rates used in the calculations.


•	Future revenues may be subject to different production, severance and property taxation rates.


•	The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.

The standardized measure of future net cash flows relating to proved reserves is presented in the table below:



	Year Ended December 31,
	2012			2011			2010
	(in millions)
Future cash inflows	$	18,200.2		$	18,300.6		$	14,174.8
Future production costs	(5,027.2		)	(4,276.1		)	(3,701.8		)
Future development costs	(3,927.3		)	(3,250.0		)	(2,275.9		)
Future income tax expenses	(2,269.0		)	(2,837.1		)	(1,957.6		)
Future net cash flows	6,976.7			7,937.4			6,239.5
10% annual discount for estimated timing of net cash flows	(3,942.0		)	(4,411.8		)	(3,533.9		)
Standardized measure of discounted future net cash flows	$	3,034.7		$	3,525.6		$	2,705.6

The principal sources of change in the standardized measure of future net cash flows relating to proved reserves is presented in the table below:



	Year Ended December 31,
	2012			2011			2010
	(in millions)
Balance at January 1,	$	3,525.6		$	2,705.6		$	1,443.0
Sales of gas, oil and NGL produced during the period, net of production costs	(892.3		)	(1,779.9		)	(1,125.7		)
Net change in sales prices and in production (lifting) costs related to future production	(2,083.5		)	1,472.5			1,775.8
Net change due to extensions, discoveries and improved recovery	948.5			1,806.4			789.1
Net change due to revisions of quantity estimates	(387.8		)	(48.2		)	140.4
Changes due to purchases of reserves in place	831.4			0.1			0.2
Changes due to sales of reserves in place	—			(8.0		)	(26.0		)
Previously estimated development costs incurred during the period	513.0			533.6			434.2
Changes in estimated future development costs	(209.3		)	(1,110.4		)	(325.4		)
Accretion of discount	499.4			355.4			170.9
Net change in income taxes	273.6			(411.4		)	(582.4		)
Other	16.1			9.9			11.5
Net change	(490.9		)	820.0			1,262.6
Balance at December 31,	$	3,034.7		$	3,525.6		$	2,705.6

Schedule of Valuation and Qualifying Accounts (Notes)

12 Months Ended

Dec. 31, 2012

Valuation And Qualifying Accounts Abstract [Abstract]

Schedule of Valuation and Qualifying Accounts

QEP RESOURCES, INC.

Schedule of Valuation and Qualifying Accounts



Description	Beginning Balance		Amounts charged (credited) to expense			Deductions for accounts written off and other			Ending Balance
	(in millions)
Year ended December 31, 2012
Allowance for bad debts	$	1.7	$	1.4		$	(0.3	)	$	2.8
Year ended December 31, 2011
Allowance for bad debts	2.3		0.2			(0.8		)	1.7
Year ended December 31, 2010
Allowance for bad debts	3.0		(0.3		)	(0.4		)	2.3

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Summary of Significant Accounting Policies [Abstract]

Consolidation, Policy [Policy Text Block]

Principles of Consolidation

All dollar and share amounts in this Form 10-K are in millions, except per-share information and where otherwise noted.

Equity Method Investments, Policy [Policy Text Block]

Investment in Unconsolidated Affiliates

Reclassification, Policy [Policy Text Block]

Reclassifications

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Receivables, Policy [Policy Text Block]

Accounts Receivable Trade

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment

Gas and oil properties

Capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized exploratory well costs

Depreciation, depletion and amortization



Buildings	10 to 30 years
Leasehold improvements	3 to 10 years
Service, transportation and field service equipment	3 to 7 years
Furniture and office equipment	3 to 7 years

Impairment of Long-Lived Assets

Asset Retirement Obligations

Capitalized Interest

Commitments and Contingencies, Policy [Policy Text Block]

Litigation and Other Contingencies

Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]

Goodwill

Derivatives, Policy [Policy Text Block]

Derivative Instruments

Concentration Risk, Credit Risk, Policy [Policy Text Block]

Credit Risk

Income Tax, Policy [Policy Text Block]

Income Taxes

TreasuryStock [Policy Text Block]

Treasury Stock

Earnings Per Share, Policy [Policy Text Block]

Earnings Per Share

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

Share-Based Compensation

Pension and Other Postretirement Plans, Policy [Policy Text Block]

Pension Plans, Other Postretirement Benefits and Defined-Contribution Plans

Comprehensive Income, Policy [Policy Text Block]

Comprehensive Income

Segment Reporting, Policy [Policy Text Block]

Business Segments

New Accounting Pronouncements, Policy [Policy Text Block]

Recent Accounting Developments

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Cash Flow, Supplemental Disclosures [Text Block]

Supplemental cash flow information is shown in the below table:



	Year Ended December 31,
	2012		2011			2010
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	105.1	$	90.5		$	80.2
Cash paid (received) for income taxes	30.0		(28.5		)	14.0
Non-cash investing activities
Change in capital expenditure accrual balance	$	88.5	$	14.7		$	16.9

Property, Plant and Equipment [Table Text Block]



Buildings	10 to 30 years
Leasehold improvements	3 to 10 years
Service, transportation and field service equipment	3 to 7 years
Furniture and office equipment	3 to 7 years

Components of basic and diluted shares used in EPS

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



	December 31,
	2012	2011	2010
	(in millions)
Weighted-average basic common shares outstanding	177.8	176.5	175.3
Potential number of shares issuable under the Long-Term Stock Incentive Plan	0.9	1.9	2.0
Average diluted common shares outstanding	178.7	178.4	177.3

- Definition

The entire disclosure for supplemental cash flow activities, including cash, noncash, and part noncash transactions, for the period. Noncash is defined as information about all investing and financing activities of an enterprise during a period that affect recognized assets or liabilities but that do not result in cash receipts or cash payments in the period. "Part noncash" refers to that portion of the transaction not resulting in cash receipts or cash payments in the period.

+ References+ Details

- Definition

Tabular disclosure of the useful life and salvage value of long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software.

+ References+ Details

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2012

Acquisitions [Abstract]

Schedule of Purchase Price Allocation [Table Text Block]

The following table presents a summary of the preliminary purchase accounting entries:



	As of December 31, 2012
Consideration given:	(in millions)
Cash consideration	$	1,388.7

Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
Proved properties	$	713.8
Unproved properties	679.4
Asset retirement obligations	(0.9		)
Liabilities assumed	(4.4		)
Other assets acquired	0.8
Total fair value	$	1,388.7

Business Acquisition, Pro Forma Information [Abstract]



	Year ended December 31,
	2012				2011
	Actual		Pro forma		Actual		Pro forma
	(in millions, except per share data)

Revenues	$	2,349.8	$	2,485.3	$	3,159.2	$	3,236.7
Net income attributable to QEP	128.3		143.0		267.2		259.8
Earnings per common share attributable to QEP
Basic	$	0.72	$	0.80	$	1.51	$	1.47
Diluted	0.72		0.80		1.50		1.46

- Definition

Tabular disclosure of pro forma results of operations for a material business acquisition or series of individually immaterial business acquisitions that are material in the aggregate.

+ References+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair value of financial assets and liabilities

The fair value of financial assets and liabilities at December 31, 2012 and 2011, is shown in the tables below:



	Fair Value Measurements
	December 31, 2012
	Level 1		Level 2		Level 3		Netting Adjustments			Total
			(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	189.7	$	—	$	(1.0	)	$	188.7
Commodity derivative instruments - long-term	—		4.2		—		(0.1		)	$	4.1
Total financial assets	$	—	$	193.9	$	—	$	(1.1	)	$	192.8

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	1.0	$	—	$	(1.0	)	$	—
Interest rate swaps - short-term	—		2.6		—		—			$	2.6
Commodity derivative instruments - long-term	—		0.1		—		(0.1		)	$	—
Interest rate swaps - long-term	—		3.6		—		—			$	3.6
Total financial liabilities	$	—	$	7.3	$	—	$	(1.1	)	$	6.2



	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 years ended December 31, 2012 and 2011, are shown below:



	Change in Level 3 Fair Value Measurements
	2012			2011
	(in millions)
Balance at January 1,	$	—		$	36.3
Realized gains and losses	0.6			25.3
Unrealized gains and losses	3.8			(36.3		)
Settlements	(0.6		)	(25.3		)
Transfers out of Level 3	(3.8		)	—
Balance at December 31,	$	—		$	—

Fair value and related carrying amount of certain financial instruments



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2012				December 31, 2011
	(in millions)
Financial liabilities
Checks outstanding in excess of cash balances	$	39.7	$	39.7	$	29.4	$	29.4
Long-term debt	$	3,206.9	$	3,420.7	$	1,679.4	$	1,754.9

- Definition

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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- Definition

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

- Definition

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.

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+ Details

Derivative Contracts (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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 December 31, 2012:



				Swaps
Year	Type of Contract	Index	Total Volumes	Average price per unit
			(in millions)
Natural gas sales			(MMBtu)
2013	Swap	NYMEX	51.1	$	3.79
2013	Swap	IFNPCR	65.7	$	5.66
2014	Swap	NYMEX	18.3	$	4.21
Oil sales			(Bbls)
2013	Swap	NYMEX WTI	5.1	$	98.48
2014	Swap	NYMEX WTI	1.8	92.72

QEP Marketing Derivative Contracts



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Natural gas sales			(MMBtu)
2013	Swap	IFNPCR	4.0	$	3.78
Natural gas purchases			(MMBtu)
2013	Swap	IFNPCR	0.2	$	2.88
2014	Swap	IFNPCR	0.1	$	3.02

QEP Resources Derivative Contracts



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
		December 31,
	Balance Sheet line item	2012		2011		2012		2011
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	189.7	$	284.1	$	1.0	$	11.7
Interest rate swaps	Fair value of derivative contracts	—		—		2.6		—
Long-term:
Commodity	Fair value of derivative contracts	4.2		123.5		0.1		—
Interest rate swaps	Fair value of derivative contracts	—		—		3.6		—
Total derivative instruments		$	193.9	$	407.6	$	7.3	$	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 Consolidated Statements of Operations are summarized in the following tables:



Derivative instruments not designated as cash flow hedges ⁽¹⁾	Year Ended December 31,
	2012			2011			2010

Realized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts	$	341.9		$	(117.7	)	$	(121.7	)
Oil derivative contracts	14.4			—			—
NGL derivative contracts	10.2			—			—
QEP Field Services
NGL derivative contracts	8.4			—			—
QEP Marketing
Natural gas derivative contracts	5.1			—			—
Total realized gain (loss) on commodity derivative contracts	380.0			(117.7		)	(121.7		)
Unrealized gain (loss) on commodity derivative contracts
QEP Energy
Natural gas derivative contracts	37.8			117.7			121.7
Oil derivative contracts	29.0			—			—
NGL derivative contracts	1.6			—			—
QEP Field Services
NGL derivative contracts	—			—			—
QEP Marketing
Natural gas derivative contracts	0.9			—			—
Total unrealized gain on commodity derivative contracts	69.3			117.7			121.7
Total realized and unrealized gain on commodity derivative contracts	$	449.3		$	—		$	—
Realized gain (loss) on interest rate swaps
Realized loss on interest rate swaps	$	(1.3	)	$	—		$	—
Unrealized gain (loss) on interest rate swaps
Unrealized loss on interest rate swaps	(6.1		)	—			—
Total realized and unrealized loss on interest rate swaps	$	(7.4	)	$	—		$	—
Total net realized gain on derivative contracts	$	378.7		$	(117.7	)	$	(121.7	)
Total net unrealized gain on derivative contracts	$	63.2		$	117.7		$	121.7
Grand Total	$	441.9		$	—		$	—

____________________________

The following table presents the change in the fair value and settlement of QEP's derivative contracts that were designated as cash flow hedges in 2011 and 2010:



Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	December 31,
Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	2012		2011			2010
Commodity derivatives
Gain on derivative instruments for the effective portion of hedge recognized in AOCI	Accumulated other comprehensive income	$	—	$	350.8		$	565.8
Gain reclassified from AOCI into income for effective portion of hedge	Natural gas sales	—		305.5			353.8
Gain reclassified from AOCI into income for effective portion of hedge	Oil sales	—		1.6			(8.7		)
Gain reclassified from AOCI into income for effective portion of hedge	NGL sales	—		(0.2		)	—
Gain reclassified from AOCI into income for effective portion of hedge	Marketing purchases	—		4.3			3.1
Gain recognized in income for the ineffective portion of hedges	Interest and other income	—		0.1			0.2

- Definition

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

- Definition

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)

12 Months Ended

Dec. 31, 2012

Restructuring Costs [Abstract]

Reconciliation of QEP Energy's restructuring cost



	QEP Energy		QEP Field Services		QEP Marketing		Total
Restructuring costs expected to be incurred	(in millions)
One-time termination benefits	$	3.3	$	—	$	0.2	$	3.5
Retention and relocation expense	5.4		0.2		0.2		5.8
Lease termination costs and other expenses	0.6		—		—		0.6
Total restructuring costs expected to be incurred	$	9.3	$	0.2	$	0.4	$	9.9

Total restructuring costs recognized in income for the year ended December 31, 2012
One-time termination benefits	$	2.9	$	—	$	0.1	$	3.0
Retention and relocation expense	3.4		—		—		3.4
Lease termination costs and other expenses	0.6		—		—		0.6
Total restructuring costs incurred during the year	$	6.9	$	—	$	0.1	$	7.0
ended December 31, 2012	$	6.9	$	—	$	0.1	$	7.0

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	6.9			—		0.1			7.0
Costs paid or otherwise settled	(5.9		)	—		(0.1		)	(6.0		)
Balance at December 31, 2012	$	1.0		—		—			$	1.0

- Definition

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

- Definition

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

Commitments and Contingencies Commitments (Tables)

12 Months Ended

Dec. 31, 2012

Long-term Purchase Commitment [Line Items]

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

Annual payments and the corresponding years for transportation contracts, drilling contracts and fractionation contracts are as follows (in millions):



Year	Amount
2013	$	161.3
2014	$	146.2
2015	$	112.0
2016	$	107.7
2017	$	107.0
After 2017	$	385.7

Operating Leases of Lessee Disclosure [Table Text Block]

Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions):



Year	Amount
2013	$	6.7
2014	$	6.5
2015	$	6.6
2016	$	6.5
2017	$	6.7
After 2017	$	29.1

- Definition

Tabular disclosure of a lessee's leasing arrangements including: (1) the basis on which contingent rental payments are determined, (2) the existence and terms of renewal or purchase options and escalation clauses, (3) restrictions imposed by lease arrangements, such as those concerning dividends, additional debt, and further leasing, (4) rent holidays, rent concessions, or leasehold improvement incentives and unusual provisions or conditions. Disclosure may also include the specific period used to amortize material leasehold improvements made at the inception of the lease or during the lease term. Additionally, for operating leases having initial or remaining noncancelable lease terms in excess of one year: (a) future minimum rental payments required as of the date of the latest balance sheet presented, in the aggregate and for each of the five succeeding fiscal years, (b) the total of minimum rentals to be received in the future under noncancelable subleases as of the date of the latest balance sheet presented, and (c) for all operating leases, rental expense for each period for which an income statement is presented, with separate amounts for minimum rentals, contingent rentals, and sublease rentals. Rental payments under leases with terms of a month or less that were not renewed need not be included.

+ References+ Details

- Definition

Tabular disclosure of unconditional purchase obligations that are not recognized as a liability on the balance sheet, including the nature and significant terms of an unconditional purchase obligation; the amount of the fixed and determinable portion of the obligation as of the date of the latest balance sheet presented in the aggregate and, if determinable, for each of the five succeeding fiscal years; the nature of any variable components of the obligation; the amount purchased under the obligation (for example, the take-or-pay or throughput contract) for the reporting period; and may include the amount of imputed interest necessary to reduce the obligation to present value.

+ References+ Details

Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

Share-based Compensation [Abstract]

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

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



	Stock Option Variables
	Year Ended December 31,
	2012			2011			2010
Weighted-average grant-date fair value of awards granted during the period	$	14.29		$	18.80		$	27.55
Risk-free interest rate range	0.63% - 1.04%			n/a			n/a
Weighted-average risk-free interest rate	0.8		%	2.1		%	2.3		%
Expected price volatility range	55.9% - 56.5%			n/a			n/a
Weighted-average expected price volatility	55.9		%	54.7		%	30.3		%
Expected dividend yield	0.26		%	0.21		%	1.18		%
Expected term in years at the date of grant	5.0			5.0			5.2

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 Exercise 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	304,660		30.75
Exercised	(610,883	)	14.87
Forfeited	—		—		—
Outstanding at December 31, 2012	1,697,471		$	25.23	3.64	$	10.5
Options Exercisable at December 31, 2012	1,230,843		$	22.50	2.88	$	10.3
Unvested Options at December 31, 2012	466,628		$	32.40	5.65	$	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 Grant-Date Fair Value
			(per share)
Unvested balance at December 31, 2011	1,099,752		$	32.80
Granted	827,986		30.54
Vested	(541,230	)	31.90
Forfeited	(85,920	)	32.30
Unvested balance at December 31, 2012	1,300,588		$	31.78

Performance Share Units

Transactions involving performance share units under the terms of the CIP are summarized below:



	Performance Share Units Outstanding		Weighted- Average Grant-Date Fair Value
Unvested balance at December 31, 2011	115,274		$	39.07
Granted	180,923		30.90
Vested	—		—
Forfeited	(12,713	)	35.69
Unvested balance at December 31, 2012	283,484		$	34.01

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2012

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]



	Pension benefits						Other postretirement benefits
	2012			2011			2012			2011
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$	104.1		$	78.0		$	5.9		$	4.5
Service cost	4.0			2.9			0.1			0.1
Interest cost	5.1			4.5			0.3			0.3
Change in plan assumptions	8.4			19.6			—			—
Benefit payments	(2.7		)	(0.2		)	—			—
Actuarial loss (gain)	10.8			(0.7		)	0.4			1.0
Benefit obligation at December 31,	$	129.7		$	104.1		$	6.7		$	5.9
Change in plan assets
Fair value of plan assets at January 1,	$	44.2		$	30.9		$	—		$	—
Actual gain (loss) on plan assets	6.9			(1.3		)	—			—
Company contributions to the plan	6.9			14.8			—			—
Benefit payments	(2.7		)	(0.2		)	—			—
Fair value of plan assets at December 31,	55.3			44.2			—			—
Underfunded status (current and long-term)	$	(74.4	)	$	(59.9	)	$	(6.7	)	$	(5.9	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(3.2	)	$	(1.3	)	$	(0.2	)	$	—
Other long-term liabilities	(71.2		)	(58.6		)	(6.5		)	(5.9		)
Total amount recognized in balance sheet	$	(74.4	)	$	(59.9	)	$	(6.7	)	$	(5.9	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	32.6		$	18.6		$	1.3		$	1.0
Prior service cost	35.1			42.6			3.4			3.8
Total amount recognized in AOCI	$	67.7		$	61.2		$	4.7		$	4.8

Pension and Other Postretirement Benefit Costs



	Pension benefits									Other postretirement benefits
	2012			2011			2010			2012			2011			2010

Components of net periodic benefit cost
Service cost	$	4.0		$	2.9		$	1.3		$	0.1		$	0.1		$	0.1
Interest cost	5.1			4.5			2.1			0.3			0.3			0.1
Expected return on plan assets	(3.6		)	(2.6		)	(1.1		)	—			—			—
Curtailment loss	2.2			—			—			—			—			—
Amortization of prior service costs	5.3			5.3			2.6			0.3			0.3			0.2
Amortization of actuarial loss	1.9			—			—			0.1			—			—
Periodic expense	$	14.9		$	10.1		$	4.9		$	0.8		$	0.7		$	0.4
Components recognized in accumulated other comprehensive income
Current period actuarial loss (gain)	$	15.9		$	22.9		$	(4.2	)	$	0.4		$	1.0		$	—
Amortization of actuarial loss	(1.9		)	—			—			(0.1		)	—			—
Current period prior service cost	—			—			50.4			—			—			4.3
Amortization of prior service cost	(5.3		)	(5.3		)	(2.6		)	(0.4		)	(0.3		)	(0.1		)
Loss on curtailment in current period	(2.2		)	—			—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	6.5		$	17.6		$	43.6		$	(0.1	)	$	0.7		$	4.2

Schedule of Assumptions Used [Table Text Block]



	Pension benefits				Other postretirement benefits
	2012		2011		2012		2011
Discount rate	3.88	%	4.54	%	4.10	%	4.70	%
Rate of increase in compensation	3.60	%	3.60	%	3.60	%	4.00	%



	Pension benefits						Other postretirement benefits
	2012		2011		2010		2012		2011		2010
Discount rate	4.38	%	5.80	%	5.70	%	4.70	%	5.80	%	5.70	%
Expected long-term return on plan assets	7.25	%	7.50	%	7.50	%	n/a		n/a		n/a
Rate of increase in compensation	3.60	%	3.60	%	3.60	%	4.00	%	n/a		n/a

Defined Benefit Plan, Actual Plan Asset Allocations [Abstract] (Deprecated 2012-01-31)

The following table sets forth by level, within the fair value hierarchy, the fair value of pension and postretirement benefit assets.:



	As of December 31, 2012								Percentage of total
	Level 1		Level 2		Level 3		Total		Percentage of total
	(in millions except percentages)
Cash and short-term investments	$	—	$	—	$	0.2	$	0.2	—		%
Equity securities:
Domestic	—		—		22.2		22.2		40		%
International	—		—		16.7		16.7		30		%
Fixed income	—		—		16.2		16.2		30		%
Total investments	—		—		$	55.3	$	55.3	100		%
	As of December 31, 2011								Percentage of total
	Level 1		Level 2		Level 3		Total		Percentage of total
	(in millions except percentages)
Cash and short-term investments	$	—	$	—	$	—	$	—	$	—
Equity securities:
Domestic	—		—		17.6		17.6		40		%
International	—		—		13		13.0		29		%
Fixed income	—		—		13.6		13.6		31		%
Total investments	—		—		$	44.2	$	44.2	100		%

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]

The following table presents a summary of changes in the fair value of QEP's Level 3 investments:



	Year ended December 31,
	2012			2011
	(in millions)
Balance at January 1,	$	44.2		30.9
Employer contributions	5.6			14.8
Unrealized gains (losses)	6.3			(1.4		)
Realized gains	0.7			0.3
Administrative fees	(0.2		)	(0.2		)
Benefits paid	(1.3		)	(0.2		)
Balance at December 31,	$	55.3		$	44.2

Schedule of Expected Benefit Payments [Table Text Block]

Expected Benefit Payments

As of December 31, 2012, the following future benefit payments are expected to be paid:



	Pension		Postretirement benefits
	(in millions)
2013	$	5.7	$	0.2
2014	5.3		0.2
2015	4.9		0.2
2016	5.6		0.3
2017	5.2		0.3
2018 through 2021	40.9		1.8

- Definition

Tabular disclosure of one or more of the entity's defined benefit pension plans or one or more other defined benefit postretirement plans, separately for pension plans and other postretirement benefit plans including the entity's schedule of fair value of plan assets for defined benefit or other postretirement plans.

+ References

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-SubTopic 20

-Section 50

-Paragraph 1

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

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-SubTopic 20

-Section 50

-Paragraph 3

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-SubTopic 20

-Section 55

-Paragraph 17

-URI http://asc.fasb.org/extlink&oid=21916443&loc=d3e4179-114921

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-SubTopic 20

-Section 50

-Paragraph 4

-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e2439-114920

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-SubTopic 20

-Section 50

-Paragraph 2

-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e2410-114920

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5, 6, 7

-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 Statement of Financial Accounting Standard (FAS)

-Number 158

-Paragraph 4, 7, 16, 20, 21

-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 132R

-Paragraph 5

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+ Details

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Details of income tax expenses and deferred income taxes from continuing operations are provided in the following tables. The components of income tax expenses were as follows:



	Year Ended December 31,
	2012			2011			2010
	(in millions)
Federal income tax expense (benefit)
Current	$	33.7		$	(5.3	)	$	(16.6	)
Deferred	36.5			153.0			172.9
State income tax expense (benefit)
Current	0.7			2.9			(4.7		)
Deferred	(4.4		)	3.8			15.4
Total income tax expense	$	66.5		$	154.4		$	167.0

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:



	Year Ended December 31,
	2012		2011		2010
Federal income taxes statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	(1.2	)%	1.0	%	1.5	%
Penalties	(0.6	)%	—	%	—	%
Return to provision adjustment	0.4	%	1.3	%	0.2	%
Noncontrolling interest	(0.7	)%	(0.3	)%	(0.2	)%
Non-deductible Spin-off costs	—	%	—	%	0.5	%
Other	0.6	%	(0.7	)%	(0.1	)%
Effective income tax rate	33.5	%	36.3	%	36.9	%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]



	December 31,
	2012		2011
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$	1,606.6	$	1,714.6
Commodity price and interest rate derivatives	69.4		147.2
Total deferred tax liabilities	1,676.0		1,861.8
Deferred tax assets
NOL and tax credit carryforwards	65.6		232.9
Employee benefits and compensation costs	47.7		42.9
Accrued litigation loss contingency	42.8		—
Bonus and vacation accrual	11.8		10.7
Other	9.6		5.2
Total deferred tax assets	177.5		291.7
Net deferred income tax liability	$	1,498.5	$	1,570.1
Balance sheet classification
Deferred income tax liability - current	$	5.0	$	85.4
Deferred income tax liability - non-current	1,493.5		1,484.7
Net deferred income tax liability	$	1,498.5	$	1,570.1

Summary of Operating Loss Carryforwards [Table Text Block]

The amounts and expiration dates of operating loss and tax credit carryforwards at December 31, 2012:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and credit carryforwards	2014-2032	$	21.2
U.S. alternative minimum tax credit	Indefinite	44.4
Total		$	65.6

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2012

Discontinued operations [Line Items]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

Wexpro's operating results prior to the Spin-off are reflected in this Annual Report on Form 10-K as discontinued operations and summarized in the table below:



	Year Ended December 31,
	2012		2011		2010
	(in millions, except per share amounts)
Revenues	$	—	$	—	$	131.2
Income before income taxes	—		—		67.4
Income taxes	—		—		(24.2		)
Discontinued operations, net of income taxes	$	—	$	—	$	43.2
Earnings per common share attributable to QEP
Basic from discontinued operations	$	—	$	—	$	0.25
Diluted from discontinued operations	—		—		0.24

- Definition

Tabular disclosure of disposal groups, which may include the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the classification and carrying value of the assets and liabilities comprising the disposal group, and the segment in which the disposal group was reported. Also may include the amount of adjustments to amounts previously reported in discontinued operations such as resolution of contingencies arising from the disposal transaction or the operations of the component prior to disposal.

+ References+ Details

Operations by Line of Business (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Summary of operating results by line of business

The following table is a summary of operating results for the year ended December 31, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	1,615.4		$	320.2		$	414.2		$	—		$	2,349.8
From affiliated customers	—			119.0			605.7			(724.7		)	—
Total Revenues	1,615.4			439.2			1,019.9			(724.7		)	2,349.8
Operating expenses
Purchased gas, oil and NGL expense	224.7			12.1			1,021.1			(602.3		)	655.6
Lease operating expense	175.8			—			—			(3.5		)	172.3
Natural gas, oil and NGL transportation and other handling costs	228.1			33.6			—			(112.8		)	148.9
Gathering, processing and other	—			86.8			1.2			—			88.0
General and administrative	237.6			34.7			0.4			(6.1		)	266.6
Production and property taxes	97.2			6.0			0.2			—			103.4
Depreciation, depletion and amortization	838.0			63.2			3.7			—			904.9
Abandonment, impairment and exploration expenses	144.6			—			—			—			144.6
Total operating expenses	1,946.0			236.4			1,026.6			(724.7		)	2,484.3
Net gain from asset sales	1.2			—			—			—			1.2
Operating (loss) income ⁽¹⁾	(329.4		)	202.8			(6.7		)	—			(133.3		)
Realized and unrealized gains (losses) on derivative contracts	434.9			8.4			(1.4		)	—			441.9
Interest and other income	6.2			0.2			132.1			(131.9		)	6.6
Income from unconsolidated affiliates	0.1			6.7			—			—			6.8
Loss on early extinguishment of debt	—			—			(0.6		)	—			(0.6		)
Interest expense	(116.8		)	(13.6		)	(124.4		)	131.9			(122.9		)
Income (loss) before income taxes	(5.0		)	204.5			(1.0		)	—			198.5
Income tax (provision) benefit	4.3			(71.8		)	1.0			—			(66.5		)
Net income (loss)	(0.7		)	132.7			—			—			132.0
Net income attributable to noncontrolling interest	—			(3.7		)	—			—			(3.7		)
Net income (loss) attributable to QEP ⁽²⁾	$	(0.7	)	$	129.0		$	—		$	—		$	128.3
Identifiable total assets	$	7,436.5		$	1,399.7		$	272.3		$	—		$	9,108.5
Investment in unconsolidated affiliates	—			41.2			—			—			41.2
Cash capital expenditures	2,621.1			164.0			14.6			—			2,799.7
Accrued capital expenditures	2,702.4			171.2			14.6			—			2,888.2
Goodwill	59.5			—			—			—			59.5

____________________________


⁽¹⁾	The impact of QEP's settled derivative contracts, for the year ended December 31, 2012, are reflected below operating (loss) income.


⁽²⁾	Net (loss) income attributable to QEP for the year ended December 31, 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 year ended December 31, 2011, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	2,213.2		$	369.3		$	576.7		$	—		$	3,159.2
From affiliated customers	—			96.2			580.2			(676.4		)	—
Total Revenues	2,213.2			465.5			1,156.9			(676.4		)	3,159.2
Operating expenses
Purchased gas, oil and NGL expense	506.4			—			1,144.5			(573.8		)	1,077.1
Lease operating expense	148.2			—			—			(3.0		)	145.2
Natural gas, oil and NGL transportation and other handling costs	186.0			9.3			—			(93.1		)	102.2
Gathering, processing and other	—			106.0			1.3			—			107.3
General and administrative	98.4			29.2			2.1			(6.5		)	123.2
Production and property taxes	99.1			6.1			0.2			—			105.4
Depreciation, depletion and amortization	707.2			55.7			2.5			—			765.4
Abandonment, impairment and exploration expenses	228.9			—			—			—			228.9
Total operating expenses	1,974.2			206.3			1,150.6			(676.4		)	2,654.7
Net gain (loss) from asset sales	1.4			—			—			—			1.4
Operating income ⁽²⁾	240.4			259.2			6.3			—			505.9
Interest and other income	4.0			0.1			98.7			(98.7		)	4.1
Income from unconsolidated affiliates	0.1			5.4			—			—			5.5
Loss on extinguishment of debt	—			—			(0.7		)	—			(0.7		)
Interest expense	(81.9		)	(13.6		)	(93.2		)	98.7			(90.0		)
Income before income taxes	162.6			251.1			11.1			—			424.8
Income taxes	(57.9		)	(93.4		)	(3.1		)	—			(154.4		)
Net income	104.7			157.7			8.0			—			270.4
Net income attributable to noncontrolling interest	—			(3.2		)	—			—			(3.2		)
Net income attributable to QEP ⁽³⁾	$	104.7		$	154.5		$	8.0		$	—		$	267.2
Identifiable assets	$	5,815.7		$	1,312.7		$	314.3		$	—		$	7,442.7
Investment in unconsolidated affiliates	—			42.2			—			—			42.2
Cash capital expenditures	1,295.5			130.1			5.5			—			1,431.1
Accrued capital expenditures	1,338.7			101.6			5.5			—			1,445.8
Goodwill	59.5			—			—			—			59.5

____________________________


⁽¹⁾	Revenues for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts. See Note 6 - Derivative Contracts, for additional information on derivative contract settlements in the year ended December 31, 2011.


⁽²⁾	Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the year ended December 31, 2011.


⁽³⁾	Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in AOCI during the year ended December 31, 2011.

The following table is a summary of operating results for the year ended December 31, 2010, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	1,456.3		$	245.5		$	598.8		$	—		$	2,300.6
From affiliated customers	—			73.7			499.7			(573.4		)	—
Total Revenues	1,456.3			319.2			1,098.5			(573.4		)	2,300.6
Operating expenses
Purchased gas, oil and NGL expense	—			—			1,082.8			(493.5		)	589.3
Lease operating expense	127.3			—			—			(2.3		)	125.0
Natural gas, oil and NGL transportation and other handling costs	125.5			—			—			(71.3		)	54.2
Gathering, processing and other	—			82.1			1.1			—			83.2
General and administrative	78.0			31.6			3.9			(6.3		)	107.2
Separation costs	—			—			13.5			—			13.5
Production and property taxes	77.8			4.4			0.3			—			82.5
Depreciation, depletion and amortization	592.5			48.9			2.0			—			643.4
Abandonment, impairment and exploration expenses	69.1			—			—			—			69.1
Total operating expenses	1,070.2			167.0			1,103.6			(573.4		)	1,767.4
Net gain (loss) from asset sales	13.7			(1.6		)	—			—			12.1
Operating income ⁽²⁾	399.8			150.6			(5.1		)	—			545.3
Interest and other income	2.1			0.1			87.2			(87.1		)	2.3
Income from unconsolidated affiliates	0.2			2.8			—			—			3.0
Loss on extinguishment of debt	—			—			(13.3		)	—			(13.3		)
Interest expense	(78.5		)	(7.6		)	(85.4		)	87.1			(84.4		)
Income before income taxes	323.6			145.9			(16.6		)	—			452.9
Income taxes	(119.7		)	(51.9		)	4.6			—			(167.0		)
Net income from continuing operations	203.9			94.0			(12.0		)	—			285.9
Discontinued operations, net of income tax	—			—			43.2			—			43.2
Net Income	203.9			94.0			31.2			—			329.1
Net income attributable to noncontrolling interest	—			(2.9		)	—			—			(2.9		)
Net income attributable to QEP ⁽³⁾	$	203.9		$	91.1		$	31.2		$	—		$	326.2
Identifiable assets	$	5,391.9		$	1,197.5		$	195.9		$	—		$	6,785.3
Investment in unconsolidated affiliates	—			44.5			—			—			44.5
Cash capital expenditures	1,205.0			262.1			1.9			—			1,469.0
Accrued capital expenditures	1,215.8			268.2			1.9			—			1,485.9
Goodwill	59.6			—			—			—			59.6

____________________________


(1)	Revenues for the year ended December 31, 2010, reflect the impact of QEP's settled derivative contracts. See Note 6 - Derivative Contracts, for detailed information on derivative contract settlements in the year ended December 31, 2010.


(2)	Under hedge accounting, realized gains and losses from realized commodity derivative contract settlements were included in revenues and operating income during the year ended December 31, 2010.


(3)	Under hedge accounting, unrealized gains and losses from changes in the fair value were deferred in AOCI during the year ended December 31, 2010.

- Definition

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

Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure (Unaudited) [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

The following table provides a summary of unaudited quarterly financial information:



	First Quarter		Second Quarter			Third Quarter			Fourth Quarter			Year
	(in millions)
2012
Revenues	$	603.2	$	499.3		$	542.4		$	704.9		$	2,349.8
Operating income (loss)	49.5		(55.5		)	(12.6		)	(114.7		)	(133.3		)
Income (loss) before income taxes	244.7		0.3			(4.4		)	(42.1		)	198.5
Net income (loss) attributable to QEP	155.2		(0.7		)	(3.1		)	(23.1		)	128.3
Per share information attributable to QEP
Basic EPS attributable to QEP	$	0.87	$	—		$	(0.02	)	$	(0.13	)	$	0.72
Diluted EPS attributable to QEP	0.87		—			(0.02		)	(0.13		)	0.72



2011
Revenues	$	617.9	$	808.1	$	879.9	$	853.3		$	3,159.2
Operating income	137.1		168.9		183.4		16.5			505.9
Income (loss) before income taxes	116.5		147.7		161.5		(0.9		)	424.8
Net income (loss) attributable to QEP	73.2		92.8		101.5		(0.3		)	267.2
Per share information attributable to QEP
Basic EPS from continuing operations	$	0.42	$	0.52	$	0.58	$	(0.01	)	$	1.51
Basic EPS attributable to QEP	0.41		0.52		0.57		—			1.50

Supplemental Gas and Oil Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Gas and Oil Information (Unaudited) [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]



	December 31,
	2012			2011
	(in millions)
Proved properties	$	10,234.3		$	8,172.4
Unproved properties, net	937.9			326.8
Total proved and unproved properties	11,172.2			8,499.2
Accumulated depreciation, depletion and amortization	(4,258.1		)	(3,339.2		)
Net capitalized costs	$	6,914.1		$	5,160.0

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]



	Year Ended December 31,
	2012		2011		2010
	(in millions)
Property acquisitions
Unproved	$	692.6	$	48.0	$	109.1
Proved	714.4		0.1		0.2
Total property acquisitions	1,407.0		48.1		109.3
Exploration (capitalized and expensed)	14.3		36.5		146.4
Development	1,310.0		1,267.8		988.8
Total costs incurred	$	2,731.3	$	1,352.4	$	1,244.5

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

Following are the results of operations of QEP Energy gas and oil exploration and development activities, before allocated corporate overhead and interest expenses.



	Year Ended December 31,
	2012			2011			2010
	(in millions)
Revenues ⁽¹⁾	$	1,393.4		$	1,703.4		$	1,456.3
Production costs	501.1			433.3			330.6
Exploration expenses	11.2			10.5			23.0
Depreciation, depletion and amortization	838.0			707.2			592.5
Abandonment and impairment	133.4			218.4			46.1
Total expenses	1,483.7			1,369.4			992.2
Income (loss) before income taxes	(90.3		)	334.0			464.1
Income tax benefit (expense)	33.6			(119.0		)	(171.8		)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(56.7	)	$	215.0		$	292.3

___________________________


⁽¹⁾	Revenue for the years ended December 31, 2011 and 2010, reflect the impact of QEP's settled derivative contracts which during the year ended December 31, 2012, are reflected below operating (loss) income. See Note 6 - Derivative Contracts.

Following are the results of operations of QEP Energy gas and oil exploration and development activities, before allocated corporate overhead and interest expenses.



	Year Ended December 31,
	2012			2011			2010
	(in millions)
Revenues ⁽¹⁾	$	1,393.4		$	1,703.4		$	1,456.3
Production costs	501.1			433.3			330.6
Exploration expenses	11.2			10.5			23.0
Depreciation, depletion and amortization	838.0			707.2			592.5
Abandonment and impairment	133.4			218.4			46.1
Total expenses	1,483.7			1,369.4			992.2
Income (loss) before income taxes	(90.3		)	334.0			464.1
Income tax benefit (expense)	33.6			(119.0		)	(171.8		)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(56.7	)	$	215.0		$	292.3

___________________________


⁽¹⁾	Revenue for the years ended December 31, 2011 and 2010, reflect the impact of QEP's settled derivative contracts which during the year ended December 31, 2012, are reflected below operating (loss) income. See Note 6 - Derivative Contracts.

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]



	Natural Gas		Oil		NGL		Natural Gas Equivalents
	(Bcf)		(MMbbl)		(MMbbl)		(Bcfe)
Proved reserves
Balance at December 31, 2009	2,525.0		29.3		7.7		2,746.9
Revisions of previous estimates	46.3		0.7		4.8		78.6
Extensions and discoveries	248.4		26.1		6.1		441.8
Purchase of reserves in place	0.2		—		—		0.2
Sale of reserves in place	(3.2	)	(0.8	)	—		(7.8	)
Production	(203.8	)	(3.0	)	(1.2	)	(229.0	)
Balance at December 31, 2010	2,612.9		52.3		17.4		3,030.7
Revisions of previous estimates ⁽⁴⁾	(270.1	)	1.7		39.3		(23.5	)
Extensions and discoveries ⁽⁵⁾	641.9		17.4		22.6		881.6
Purchase of reserves in place	1.9		—		—		2.1
Sale of reserves in place	(0.8	)	(0.2	)	—		(1.9	)
Production	(236.4	)	(3.7	)	(2.7	)	(275.2	)
Balance at December 31, 2011	2,749.4		67.5		76.6		3,613.8
Revisions of previous estimates ⁽¹⁾	(240.6	)	(1.5	)	0.7		(244.8	)
Extensions and discoveries ⁽²⁾	330.6		17.3		23.0		572.5
Purchase of reserves in place ⁽³⁾	32.3		42.0		4.9		313.8
Sale of reserves in place	—		—		—		—
Production	(249.3	)	(6.3	)	(5.3	)	(319.2	)
Balance at December 31, 2012	2,622.4		119.0		99.9		3,936.1
Proved developed reserves
Balance at December 31, 2009	1,178.7		22.4		4.9		1,342.8
Balance at December 31, 2010	1,404.8		25.1		9.3		1,611.5
Balance at December 31, 2011	1,538.3		33.0		38.4		1,966.3
Balance at December 31, 2012	1,531.7		47.4		49.3		2,111.9
Proved undeveloped reserves
Balance at December 31, 2009	1,346.3		6.9		2.8		1,404.1
Balance at December 31, 2010	1,208.1		27.2		8.0		1,419.2
Balance at December 31, 2011	1,211.1		34.6		38.2		1,647.5
Balance at December 31, 2012	1,090.7		71.6		50.6		1,824.2

____________________________

⁽¹⁾

⁽²⁾


⁽³⁾	Purchase of reserves in place primarily relate to the Company's $1.4 billion 2012 Acquisition as discussed in Note 2 - Acquisition.

⁽⁴⁾

⁽⁵⁾

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure Price per Unit [Table Text Block]

The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:



	For the year ended December 31,
	2012		2011		2010
Average benchmark price per unit:
Natural gas price (per MMbtu)	$	2.76	$	4.12	$	4.38
Crude oil price (per Bbl)	94.71		96.19		79.43

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

The standardized measure of future net cash flows relating to proved reserves is presented in the table below:



	Year Ended December 31,
	2012			2011			2010
	(in millions)
Future cash inflows	$	18,200.2		$	18,300.6		$	14,174.8
Future production costs	(5,027.2		)	(4,276.1		)	(3,701.8		)
Future development costs	(3,927.3		)	(3,250.0		)	(2,275.9		)
Future income tax expenses	(2,269.0		)	(2,837.1		)	(1,957.6		)
Future net cash flows	6,976.7			7,937.4			6,239.5
10% annual discount for estimated timing of net cash flows	(3,942.0		)	(4,411.8		)	(3,533.9		)
Standardized measure of discounted future net cash flows	$	3,034.7		$	3,525.6		$	2,705.6

Principal Sources of Change in Standardized measure of Discounted Future Net Cash Flows [Table Text Block]

The principal sources of change in the standardized measure of future net cash flows relating to proved reserves is presented in the table below:



	Year Ended December 31,
	2012			2011			2010
	(in millions)
Balance at January 1,	$	3,525.6		$	2,705.6		$	1,443.0
Sales of gas, oil and NGL produced during the period, net of production costs	(892.3		)	(1,779.9		)	(1,125.7		)
Net change in sales prices and in production (lifting) costs related to future production	(2,083.5		)	1,472.5			1,775.8
Net change due to extensions, discoveries and improved recovery	948.5			1,806.4			789.1
Net change due to revisions of quantity estimates	(387.8		)	(48.2		)	140.4
Changes due to purchases of reserves in place	831.4			0.1			0.2
Changes due to sales of reserves in place	—			(8.0		)	(26.0		)
Previously estimated development costs incurred during the period	513.0			533.6			434.2
Changes in estimated future development costs	(209.3		)	(1,110.4		)	(325.4		)
Accretion of discount	499.4			355.4			170.9
Net change in income taxes	273.6			(411.4		)	(582.4		)
Other	16.1			9.9			11.5
Net change	(490.9		)	820.0			1,262.6
Balance at December 31,	$	3,034.7		$	3,525.6		$	2,705.6

- Definition

Tabular disclosure of aggregate capitalized costs relating to an enterprise's oil and gas producing activities and the aggregate related accumulated depreciation, depletion, amortization, and valuation allowances.

+ References+ Details

- Definition

Tabular disclosure of the aggregate of costs (whether the costs are capitalized or charged to expense at the time they are incurred ) incurred for the year in oil and gas property acquisition, exploration and development activities.

+ References+ Details

- Definition

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

+ References

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

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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.

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

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+ Details

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References+ Details

- Definition

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

+ References+ Details

Summary of Significant Accounting Policies Principles of Consolidation (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2010
Principles of Consolidation [Abstract]
Stockholders' Equity Note, Spinoff Transaction	$ 250.0

Summary of Significant Accounting Policies Investment in Unconsolidated Affiliates (Details)	Dec. 31, 2012
Uintah Basin Field Services, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	38.00%
Three Rivers Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

- Definition

The percentage of ownership of common stock or equity participation in the investee accounted for under the equity method of accounting.

+ References+ Details

Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policies [Abstract]
Cash paid for interest, net of capitalized interest	$ 105.1	$ 90.5	$ 80.2
Cash paid (received) for income taxes	30.0	(28.5)	14.0
Change in capital expenditure accrual balance	$ 88.5	$ 14.7	$ 16.9

- Definition

The amount of cash paid during the current period to foreign, federal, state, and local authorities as taxes on income, net of any cash received during the current period as refunds for the overpayment of taxes.

+ References+ Details

- Definition

The amount of cash paid for interest during the period net of cash paid for interest that is capitalized.

+ References+ Details

Summary of Significant Accounting Policies Accounts Receivable Trade (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounts, Notes, Loans and Financing Receivable [Line Items]
Provision for Doubtful Accounts	$ 1.4	$ 0.2	$ (0.3)
Allowance for Doubtful Accounts Receivable	$ 2.8	$ 1.7

- Definition

Amount of the current period expense charged against operations, the offset which is generally to the allowance for doubtful accounts for the purpose of reducing receivables, including notes receivable, to an amount that approximates their net realizable value (the amount expected to be collected).

+ References+ Details

Summary of Significant Accounting Policies Property, plant and equipment (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Capitalized Interest Costs	$ 3.4	$ 3.0	$ 3.1
Building [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Buildings	10 years
Building [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Buildings	30 years
Leasehold Improvements [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Buildings	3 years
Leasehold Improvements [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Buildings	10 years
Equipment [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Buildings	3 years
Equipment [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Buildings	7 years
Furniture and Fixtures [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Buildings	3 years
Furniture and Fixtures [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Buildings	7 years

Summary of Significant Accounting Policies Impairment of long-lived assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 133.4	$ 218.4	$ 46.1
Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	107.6	195.5	0.7
Unproved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	23.7	20.3	40.7
Southern Region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	104.8	45.3
Northern Region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 28.6	$ 173.1

- Definition

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

Summary of Significant Accounting Policies Goodwill (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Goodwill [Line Items]
Goodwill	$ 59.5	$ 59.5	$ 59.6

- Definition

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 141R

-Paragraph 68

-Subparagraph l

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 350

-SubTopic 20

-Section 50

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 350

-SubTopic 20

-Section 45

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 142

-Paragraph 45

-Subparagraph e

-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 Statement of Financial Accounting Standard (FAS)

-Number 142

-Paragraph 43

-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 141R

-Paragraph 72

-Subparagraph d

-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 Statement of Financial Accounting Standard (FAS)

-Number 142

-Paragraph 45

-Subparagraph e

-Clause 1

-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 141R

-Paragraph 34

-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

Summary of Significant Accounting Policies Derivative instruments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ 63.2	$ 117.7	$ 121.7
Accumulated Other Comprehensive Income Loss, Cumulative Changes In Gain Loss From Cash Flow Hedges Effect, Before Tax	123.5	395.9
Unrealized gains on derivative contracts, net of tax	$ 77.6	$ 248.6

- Definition

Accumulated change, net of tax, in accumulated gains and losses from derivative instruments designated and qualifying as the effective portion of cash flow hedges. Includes an entity's share of an equity investee's Increase or Decrease in deferred hedging gains or losses.

+ References+ Details

Summary of Significant Accounting Policies Credit Risk (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Concentration Risk [Line Items]
Concentration Risk, Percentage	37.00%	32.00%	27.00%
Chevron U.S.A., Inc. [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	13.00%
EnterpriseProductsOperatingLP [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%

Summary of Significant Accounting Policies Earnings Per Share (Details) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Used in basic calculation	177.8	176.5	175.3
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan	0.9	1.9	2.0
Average diluted common shares outstanding (in shares)	178.7	178.4	177.3

- Definition

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

- Definition

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.

+ References

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

-Section 45

-Paragraph 10

-URI http://asc.fasb.org/extlink&oid=7655603&loc=d3e1448-109256

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

Acquisitions (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Acquisitions [Abstract]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual									$ 63.7
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual									14.9
Business Acquisition, Cost of Acquired Entity, Transaction Costs	1.1								1.1
Business Combination, Consideration Given [Abstract]
Cash Paid at Closing	1,388.7								1,388.7
Total estimate consideration given	1,388.7								1,388.7
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net [Abstract]
Proved properties	713.8								713.8
Unproved Properties	679.4								679.4
Asset retirement obligations	(0.9)								(0.9)
Liabilities assumed	(4.4)								(4.4)
Other assets	0.8								0.8
Business Acquisition, Pro Forma Information [Abstract]
Revenues	704.9	542.4	499.3	603.2	853.3	879.9	808.1	617.9	2,349.8	3,159.2	2,300.6
Pro Forma Revenues									2,485.3	3,236.7
NET INCOME ATTRIBUTABLE TO QEP	(23.1)	(3.1)	(0.7)	155.2	(0.3)	101.5	92.8	73.2	128.3	267.2	326.2
Pro Forma Net Income									$ 143.0	$ 259.8
Actual Basic total	$ (0.13)	$ (0.02)	$ 0.00	$ 0.87	$ (0.01)	$ 0.58	$ 0.52	$ 0.42	$ 0.72	$ 1.51	$ 1.86
Pro Forma Earnings Per Share, Basic									$ 0.80	$ 1.47
Actual Diluted total	$ (0.13)	$ (0.02)	$ 0.00	$ 0.87	$ 0.00	$ 0.57	$ 0.52	$ 0.41	$ 0.72	$ 1.50	$ 1.84
Pro Forma Earnings Per Share, Diluted									$ 0.80	$ 1.46

Capitalized Exploratory Well Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Capitalized Exploratory Well Costs [Abstract]
Beginning Balance	$ 5.0	$ 13.6	$ 51.7
Additions to capitalized exploratory well costs pending the determination of proved reserves	12.7	0	12.2
Reclassifications to proved properties after the determination of proved reserves	(15.6)	(8.3)	(50.3)
Capitalized exploratory well costs charged to expense	0	(0.3)	0
Ending Balance	$ 2.1	$ 5.0	$ 13.6

Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation, Current	$ 1.7
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	163.9	148.3
Accretion	10.5	9.7
Liabilities incurred	8.5	7.9
Revisions of Estimates	11.1	0
Liabilities settled	(0.9)	(2.0)
ARO liability, Ending Balance	$ 193.1	$ 163.9

- Definition

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

- Definition

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	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Financial liabilities
Derivative instruments - long-term	$ 3.6	$ 0
Level 3 Unobservable input reconciliation [Roll Forward]
Beginning Balance	0	0	36.3
Ending Balance	0	0	36.3
Impairment of Oil and Gas Properties	133.4	218.4	46.1
Proved properties, estimated fair values	71.9	157.2
Proved properties [Member]
Level 3 Unobservable input reconciliation [Roll Forward]
Impairment of Oil and Gas Properties	107.6	195.5	0.7
Fair Value, Measurements, Recurring [Member]
Financial Assets
Derivative Assets	192.8	397.2
Financial liabilities
Derivative Liabilities	6.2	1.3
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	188.7	273.7
Derivative instruments - long-term	4.1	123.5
Financial liabilities
Derivative instruments - short-term	0	1.3
Derivative instruments - long-term	0	0
Fair Value, Measurements, Recurring [Member] \| Interest Rate Swap [Member]
Financial liabilities
Derivative instruments - short-term	2.6
Derivative instruments - long-term	3.6
Fair Value, Measurements, Recurring [Member] \| Carrying Amount [Member]
Financial liabilities
Checks outstanding in excess of cash balances	39.7	29.4
Long-term debt	3,206.9	1,679.4
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member]
Financial Assets
Derivative Assets	0	0
Financial liabilities
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	0	0
Derivative instruments - long-term	0	0
Financial liabilities
Derivative instruments - short-term	0	0
Derivative instruments - long-term	0	0
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member] \| Interest Rate Swap [Member]
Financial liabilities
Derivative instruments - short-term	0
Derivative instruments - long-term	0
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Financial liabilities
Checks outstanding in excess of cash balances	39.7	29.4
Long-term debt	3,420.7	1,754.9
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member]
Financial Assets
Derivative Assets	193.9	407.6
Financial liabilities
Derivative Liabilities	7.3	11.7
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	189.7	284.1
Derivative instruments - long-term	4.2	123.5
Financial liabilities
Derivative instruments - short-term	1.0	11.7
Derivative instruments - long-term	0.1	0
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member] \| Interest Rate Swap [Member]
Financial liabilities
Derivative instruments - short-term	2.6
Derivative instruments - long-term	3.6
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member]
Financial Assets
Derivative Assets	0	0
Financial liabilities
Derivative Liabilities	0	0
Level 3 Unobservable input reconciliation [Roll Forward]
Realized gains and losses	0.6	25.3
Change in Unrealized Gain (Loss)	3.8	(36.3)
Settlements	(0.6)	(25.3)
Transfers out of Level 3	(3.8)	0
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	0	0
Derivative instruments - long-term	0	0
Financial liabilities
Derivative instruments - short-term	0	0
Derivative instruments - long-term	0	0
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Interest Rate Swap [Member]
Financial liabilities
Derivative instruments - short-term	0
Derivative instruments - long-term	0
Fair Value, Measurements, Recurring [Member] \| Netting Adjustments [Member]
Financial Assets
Derivative Assets	(1.1)	(10.4)
Financial liabilities
Derivative Liabilities	(1.1)	(10.4)
Fair Value, Measurements, Recurring [Member] \| Netting Adjustments [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	(1.0)	(10.4)
Derivative instruments - long-term	(0.1)	0
Financial liabilities
Derivative instruments - short-term	(1.0)	(10.4)
Derivative instruments - long-term	(0.1)
Fair Value, Measurements, Recurring [Member] \| Netting Adjustments [Member] \| Interest Rate Swap [Member]
Financial liabilities
Derivative instruments - short-term	0
Derivative instruments - long-term	$ 0

Derivative Contracts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]
Forecasted production from proved reserves (in hundredths)	100.00%
Unrealized gains on derivative contracts	$ 123.5	$ 395.9
Unrealized gains on derivative contracts, net of tax	77.6	248.6
Fair value of frozen derivative to be settled and reclassified within twelve months	77.6
Total principal amount of debt	3,211.8	1,684.9
Derivative Contracts - Volumes and Prices
Notional amount of interest rate derivatives	300.0
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross	193.9	407.6
Derivative Liability, Fair Value, Gross	7.3	11.7
Derivative instruments - long-term	3.6	0
Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	171.1
Commodity Contract [Member] \| Oil Sales (Bbls) [Member] \| 2014 [Member] \| NYMEX WTI [Member]
Derivatives, Fair Value [Line Items]
Year	2014
Index	NYMEX WTI
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	1,800,000
Average Swap price per unit ($ per unit)	92.72
Swap [Member] \| Natural Gas Sales (MMbtu) [Member] \| 2013 [Member] \| NYMEX [Member]
Derivatives, Fair Value [Line Items]
Year	2013
Index	NYMEX
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	51,100,000
Average Swap price per unit ($ per unit)	3.79
Swap [Member] \| Natural Gas Sales (MMbtu) [Member] \| 2013 [Member] \| IFNPCR [Member]
Derivatives, Fair Value [Line Items]
Year	2013
Index	IFNPCR
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	65,700,000
Average Swap price per unit ($ per unit)	5.66
Swap [Member] \| Natural Gas Sales (MMbtu) [Member] \| 2014 [Member] \| NYMEX [Member]
Derivatives, Fair Value [Line Items]
Year	2014
Index	NYMEX
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	18,300,000
Average Swap price per unit ($ per unit)	4.21
Swap [Member] \| Oil Sales (Bbls) [Member] \| 2013 [Member] \| NYMEX WTI [Member]
Derivatives, Fair Value [Line Items]
Year	2013
Index	NYMEX WTI
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	5,100,000
Average Swap price per unit ($ per unit)	98.48
Swap [Member] \| QEP Marketing [Member] \| 2013 [Member] \| IFNPCR [Member]
Derivatives, Fair Value [Line Items]
Year	2013
Index	IFNPCR
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	4,000,000
Average Swap price per unit ($ per unit)	3.78
Swap [Member] \| QEP Resources [Member]
Derivative Contracts - Volumes and Prices
Notional amount of interest rate derivatives	300.0
Maturity	Mar. 31, 2017
Fixed Rate Paid (in hundredths)	1.07%
Variable Rate Received	One month LIBOR
Swap [Member] \| Purchased Gas and Oil Expense [Member] \| 2013 [Member] \| IFNPCR [Member]
Derivatives, Fair Value [Line Items]
Year	2013
Index	IFNPCR
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	200,000
Average Swap price per unit ($ per unit)	2.88
Swap [Member] \| Purchased Gas and Oil Expense [Member] \| 2014 [Member] \| IFNPCR [Member]
Derivatives, Fair Value [Line Items]
Year	2014
Index	IFNPCR
Derivative Contracts - Volumes and Prices
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)	100,000
Average Swap price per unit ($ per unit)	3.02
Term Loan due 2017 [Member]
Derivatives, Fair Value [Line Items]
Total principal amount of debt	300.0	0
Short term [Member] \| Interest Rate Swap [Member]
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross	0	0
Derivative Liability, Fair Value, Gross	2.6	0
Short term [Member] \| Commodity Contract [Member]
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross	189.7	284.1
Derivative Liability, Fair Value, Gross	1.0	11.7
Long term [Member] \| Interest Rate Swap [Member]
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross	0	0
Derivative Liability, Fair Value, Gross	3.6	0
Long term [Member] \| Commodity Contract [Member]
Fair Value of Derivative Contracts, Gross [Abstract]
Derivative Asset, Fair Value, Gross	4.2	123.5
Derivative Liability, Fair Value, Gross	$ 0.1	$ 0

Derivative Contracts - Gain (Loss) in Statement of Financial Performance (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) derivative contracts not designated as hedging instruments	$ 378.7	$ (117.7)	$ (121.7)
Unrealized gain (loss) derivative contracts not designated as hedging instruments	63.2	117.7	121.7
Total gain (loss) on commodity derivative instruments	441.9	0	0
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	(171.1)
Natural gas derivative contracts [Member] \| QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	341.9	(117.7)	(121.7)
Unrealized gain (loss) on commodity derivative contracts	37.8	117.7	121.7
Natural gas derivative contracts [Member] \| QEP Marketing [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	5.1	0	0
Unrealized gain (loss) on commodity derivative contracts	0.9	0	0
Oil derivative contracts [Member] \| QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	14.4	0	0
Unrealized gain (loss) on commodity derivative contracts	29.0	0	0
NGL derivative contracts [Member] \| QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	10.2	0	0
Unrealized gain (loss) on commodity derivative contracts	1.6	0	0
NGL derivative contracts [Member] \| QEP Field Services [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	8.4	0	0
Unrealized gain (loss) on commodity derivative contracts	0	0	0
Interest Rate Swap [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(1.3)	0	0
Unrealized gain (loss) on commodity derivative contracts	(6.1)	0	0
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	(7.4)	0	0
Other Comprehensive Income (Loss) [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net [Abstract]
Gain on derivative instruments for the effective portion of hedge recognized in AOCI	0	350.8	565.8
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	305.5	353.8
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	(0.2)	0
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	1.6	(8.7)
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	4.3	3.1
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	0.1	0.2
Realized and unrealized gains on commodity derivative instruments [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	380.0	(117.7)	(121.7)
Unrealized gain (loss) on commodity derivative contracts	69.3	117.7	121.7
Total gain (loss) on commodity derivative instruments	$ 449.3	$ 0	$ 0

Restructuring Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Restructuring Cost and Reserve [Line Items]
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	$ 2.2
Estimated restructuring costs	9.9
Restructuring costs incurred to date	7.0
Increase (Decrease) in Restructuring Liability [Roll Forward]
Number of regional offices created	1
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.5
Restructuring costs incurred to date	3.0
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	5.8
Restructuring costs incurred to date	3.4
Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.6
Restructuring costs incurred to date	0.6
QEP Energy [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	9.3
Restructuring costs incurred to date	6.9
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2011	0
Costs paid or otherwise settled	(5.9)
Balance at September 30, 2012	1.0
QEP Energy [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.3
Restructuring costs incurred to date	2.9
QEP Energy [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	5.4
Restructuring costs incurred to date	3.4
QEP Energy [Member] \| Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.6
Restructuring costs incurred to date	0.6
QEP Field Services [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.2
Restructuring costs incurred to date	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
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
QEP Field Services [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.2
Restructuring costs incurred to date	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
QEP Marketing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.4
Restructuring costs incurred to date	0.1
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2011	0
Costs paid or otherwise settled	(0.1)
Balance at September 30, 2012	0
QEP Marketing [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.2
Restructuring costs incurred to date	0.1
QEP Marketing [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.2
Restructuring costs incurred to date	0
QEP Marketing [Member] \| Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0
Restructuring costs incurred to date	0
QEP Resources [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred to date	7.0
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2011	0
Costs paid or otherwise settled	(6.0)
Balance at September 30, 2012	$ 1.0

- Definition

The amount of net gain (loss) recognized in net periodic benefit cost as a result of an event that significantly reduces the expected years of future service of present employees or eliminates for a significant number of employees the accrual of defined benefits for some or all of their future services.

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 87

-Paragraph 264

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 106

-Paragraph 518

-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 Accounting Standards Codification

-Topic 715

-SubTopic 20

-Section 50

-Paragraph 1

-Subparagraph (h)(7)

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

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph h

-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

-Glossary Plan Curtailment

-URI http://asc.fasb.org/extlink&oid=6520938

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-SubTopic 30

-Section 15

-Paragraph 6

-Subparagraph (a)(2)

-URI http://asc.fasb.org/extlink&oid=7577095&loc=d3e8001-114927

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 88

-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

- Definition

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

+ References+ Details

- Definition

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

+ References+ Details

- Definition

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 $)	12 Months Ended					12 Months Ended		12 Months Ended								12 Months Ended				3 Months Ended	12 Months Ended
Debt (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Revolving Credit Facility due 2016 [Member]	Dec. 31, 2011 Revolving Credit Facility due 2016 [Member]	Dec. 31, 2012 Term Loan due 2017 [Member]	Dec. 31, 2011 Term Loan due 2017 [Member]	Dec. 31, 2012 6.05% Senior Notes due 2016 [Member]	Dec. 31, 2011 6.05% Senior Notes due 2016 [Member]	Dec. 31, 2012 6.80% Senior Notes due 2018 [Member]	Dec. 31, 2011 6.80% Senior Notes due 2018 [Member]	Dec. 31, 2012 6.80% Senior Notes due 2020 [Member]	Dec. 31, 2011 6.80% Senior Notes due 2020 [Member]	Dec. 31, 2012 6.875% Senior Notes due 2021 [Member]	Dec. 31, 2011 6.875% Senior Notes due 2021 [Member]	Dec. 31, 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]	Dec. 31, 2012 Senior Notes [Member]	Sep. 30, 2012 5.25% Senior Notes Due 2023 [Member]	Dec. 31, 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	$ 3,211,800,000	$ 1,684,900,000		$ 690,000,000	$ 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	$ 0
Less unamortized discount	(4,900,000)	(5,500,000)
Total long-term debt outstanding	3,206,900,000	1,679,400,000
Long-term debt, interest rate (in hundredths)								6.05%								5.375%					5.25%
Maturity date of long-term debt				Aug. 25, 2016		Apr. 18, 2017		Sep. 01, 2016													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)				2.08%		2.05%
Debt Instrument, Face Amount																					650,000,000
Proceeds from Issuance of Long-term Debt	1,450,000,000	0	1,034,400,000																	641,000,000
Amount outstanding				690,000,000
Letters of credit outstanding				4,100,000
Proceeds from issuance of debt																493,100,000
Debt issuance costs																6,900,000					9,000,000
Senior notes repurchased																			6,700,000
Principal amount of senior notes outstanding	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	$ 600,000	$ 700,000	$ 13,300,000
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	12 Months Ended
	Dec. 31, 2012
Environmental Exit Cost [Line Items]
Environmental Exit Costs, Anticipated Cost	$ 2.4
Environmental Costs Recognized, Capitalized	1.2
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

- Definition

Name of the other party to the settlement agreement.

+ References+ Details

- Definition

The effective date of a duly executed litigation settlement agreement.

+ References+ Details

Commitments and Contingencies Other Commitments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 161.3
Unrecorded Unconditional Purchase Obligation, Due within Two Years	146.2
Unrecorded Unconditional Purchase Obligation, Due within Three Years	112.0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	107.7
Unrecorded Unconditional Purchase Obligation, Due within Five Years	107.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 385.7

Commitments and Contingencies Long-term Operating lease commitments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating lease commitments [Abstract]
Operating Leases, Rent Expense	$ 7.3	$ 5.0	$ 4.5
Operating Leases, Future Minimum Payments Due, Next Twelve Months	6.7
Operating Leases, Future Minimum Payments, Due in Two Years	6.5
Operating Leases, Future Minimum Payments, Due in Three Years	6.6
Operating Leases, Future Minimum Payments, Due in Four Years	6.5
Operating Leases, Future Minimum Payments, Due in Five Years	6.7
Operating Leases, Future Minimum Payments, Due Thereafter	$ 29.1

- Definition

Amount of required minimum rental payments maturing in the next fiscal year following the latest fiscal year for operating leases having an initial or remaining non-cancelable letter-terms in excess of one year.

+ References+ Details

- Definition

Amount of required minimum rental payments maturing in the fifth fiscal year following the latest fiscal year for operating leases having an initial or remaining non-cancelable letter-terms in excess of one year.

+ References+ Details

- Definition

Amount of required minimum rental payments maturing in the forth fiscal year following the latest fiscal year for operating leases having an initial or remaining non-cancelable letter-terms in excess of one year.

+ References+ Details

- Definition

Amount of required minimum rental payments maturing in the third fiscal year following the latest fiscal year for operating leases having an initial or remaining non-cancelable letter-terms in excess of one year.

+ References+ Details

- Definition

Amount of required minimum rental payments maturing in the second fiscal year following the latest fiscal year for operating leases having an initial or remaining non-cancelable letter-terms in excess of one year.

+ References+ Details

- Definition

Amount of required minimum rental payments maturing after the fifth fiscal year following the latest fiscal year for operating leases having an initial or remaining non-cancelable letter-terms in excess of one year.

+ References+ Details

Share-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation, Stock Options [Line Items]
Shares available for future grants	13,100,000
Share-based Compensation	$ 25.6	$ 22.0	$ 16.1
Total compensation expense related to share-based compensation		22.0	16.1
Stock Options [Member]
Share-based Compensation, Stock Options [Line Items]
Fair value of options at grant date	$ 14.29	$ 18.80	$ 27.55
Risk-free interest rate range, minimum	0.63%
Risk-free interest rate range, maximum	1.04%
Weighted-average risk-free interest rate	0.80%	2.10%	2.30%
Expected price volatility range, minimum	55.90%
Expected price volatility range, maximum	56.50%
Weighted-average expected price volatility	55.90%	54.70%	30.30%
Expected dividend yield (in hundredths)	0.26%	0.21%	1.18%
Expected life in years	5 years	5 years	5 years 2 months
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning (in dollars per share)	$ 21.23
Weighted-Average Price, Granted (in dollars per share)	$ 30.75
Weighted-Average Price, Exercised (in dollars per share)	$ 14.87
Options Outstanding [RollForward]
Outstanding at December 31, 2011 (in shares)	2,003,694
Granted (in shares)	304,660
Exercised (in shares)	(610,883)
Forfeited (in shares)	0
Outstanding at June 30, 2012 (in shares)	1,697,471	2,003,694
Options Excercisable (in shares)	1,230,843
Unvested Options (in shares)	466,628
Weighted-Average Price, Forfeited (in dollars per share)	$ 0
Weighted-Average Price, Ending (in dollars per share)	$ 25.23	$ 21.23
Weighted-Average Price, Options Excercisable	$ 22.50
Weighted-Average Price, Unvested Options	$ 32.40
Weighted-Average Remaining Contractual Term, Outstanding	3 years 7 months 20 days
Aggregate Intrinsic Value, Outstanding	10.5
Weighted-Average Remaining Contractual Term, Options Excercisable	2 years 10 months 17 days
Aggregate Intrinsic Value, Options Excercisable	10.3
Weighted-Average Remaining Contractual Term, Unvested Options	5 years 7 months 24 days
Aggregate Intrinsic Value, Unvested Options	0.2
Intrinsic value of options exercised	9.6	2.7	0.3
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	4.6	0.4
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net	5.1
Unrecognized compensation cost	2.7
Weighted-average period for recognition of compensation costs	1 year 11 months 27 days
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options	2.6
Restricted Stock [Member]
Options Outstanding [RollForward]
Weighted-Average Price, beginning balance (in dollars per share)	$ 32.80
Weighted-Average Price, Granted (in dollars per share)	$ 30.54	$ 38.50	$ 28.70
Weighted-Average Price, Vested (in dollars per share)	$ 31.90
Weighted-Average Price, Forfeited (in dollars per share)	$ 32.30
Weighted-Average Price, Ending Balance (in dollars per share)	$ 31.78	$ 32.80
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	0.3	1.0
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net	0.9
Unrecognized compensation cost	16.5
Weighted-average period for recognition of compensation costs	2 years 1 month 4 days
Total fair value of stock that vested	16.7	11.7
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)	1,099,752
Granted (in shares)	827,986
Vested (in shares)	(541,230)
Forfeited (in shares)	(85,920)
Balance, Ending (in shares)	1,300,588	1,099,752
Restricted Stock [Member] \| Minimum [Member]
Options Outstanding [RollForward]
Vesting period (in years)	3 years
Performance Share Units [Member]
Options Outstanding [RollForward]
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)	$ 34.01	$ 39.07
Unrecognized compensation cost	$ 3.2
Weighted-average period for recognition of compensation costs	1 year 10 months 25 days
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)	115,274
Granted (in shares)	180,923
Vested (in shares)	0
Forfeited (in shares)	(12,713)
Balance, Ending (in shares)	283,484	115,274

Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations Percentage of Total	100.00%	100.00%
Description of Defined Contribution Pension and Other Postretirement Plans	Pension-plan benefits are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding retirement.
Defined Benefit Plan, Accumulated Benefit Obligation	$ 106.9	$ 78.3
Change in benefit obligation
Benefit payments	(1.3)	(0.2)
Change in plan assets
Beginning Balance	44.2	30.9
Company contributions to the plan	5.6	14.8
Ending Balance	55.3	44.2	30.9
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	(0.2)	(0.2)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	(2.2)
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Contribution Plan, Cost Recognized	6.4	5.8	4.2
Pension [Member]
Change in benefit obligation
Benefit obligation at January 1,	129.7	104.1	78.0
Change in plan assumptions	8.4	19.6
Benefit payments	(2.7)	(0.2)
Actuarial loss (gain)	10.8	(0.7)
Change in plan assets
Beginning Balance	44.2	30.9
Actual gain (loss) on plan assets	6.9	(1.3)
Company contributions to the plan	6.9	14.8
Underfunded status (current and long-term)	(74.4)	(59.9)
Ending Balance	55.3	44.2	30.9
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(3.2)	(1.3)
Other long-term liabilities	(71.2)	(58.6)
Total amount recognized in balance sheet	(74.4)	(59.9)
Amounts recognized in AOCI
Net actuarial loss (gain)	32.6	18.6
Prior service cost	35.1	42.6
Total amount recognized in AOCI	67.7	61.2
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	4.0	2.9	1.3
Interest cost	5.1	4.5	2.1
Expected return on plan assets	(3.6)	(2.6)	(1.1)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	2.2	0	0
Amortization of prior service costs	5.3	5.3	2.6
Amortization of actuarial loss	1.9	0	0
Periodic expense	14.9	10.1	4.9
Pension and other postretirement plans adjustments:
Current period actuarial loss (gain)	15.9	22.9	(4.2)
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax	(1.9)	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	0	0	50.4
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Benefit Cost, before Tax	(5.3)	(5.3)	(2.6)
Defined Benefit Plan, Curtailments	(2.2)	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, before Tax	6.5	17.6	43.6
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	7.3
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)	5.0
Defined Benefit Plan, Amortization of Net Gains (Losses)	2.3
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Discount rate	3.88%	4.54%
Rate of increase in compensation	3.60%	3.60%
Discount rate	4.38%	5.80%	5.70%
Expected long-term return on plan assets	7.25%	7.50%	7.50%
Rate of increase in compensation	3.60%	3.60%	3.60%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2013	5.7
2014	5.3
2015	4.9
2016	5.6
2017	5.2
2018 through 2021	40.9
Pension [Member] \| Funded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan	5.6
Expected to contribute to pension plans	8.1
Pension [Member] \| Unfunded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan	1.3
Expected to contribute to pension plans	3.2
Postretirement benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected to contribute to pension plans	0.2
Change in benefit obligation
Benefit obligation at January 1,	6.7	5.9	4.5
Change in plan assumptions	0	0
Benefit payments	0	0
Actuarial loss (gain)	0.4	1.0
Change in plan assets
Beginning Balance	0	0
Actual gain (loss) on plan assets	0	0
Company contributions to the plan	0	0
Underfunded status (current and long-term)	(6.7)	(5.9)
Ending Balance	0	0	0
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(0.2)	0
Other long-term liabilities	(6.5)	(5.9)
Total amount recognized in balance sheet	(6.7)	(5.9)
Amounts recognized in AOCI
Net actuarial loss (gain)	1.3	1.0
Prior service cost	3.4	3.8
Total amount recognized in AOCI	4.7	4.8
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0.1	0.1	0.1
Interest cost	0.3	0.3	0.1
Expected return on plan assets	0	0	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	0	0	0
Amortization of prior service costs	0.3	0.3	0.2
Amortization of actuarial loss	0.1	0	0
Periodic expense	0.8	0.7	0.4
Pension and other postretirement plans adjustments:
Current period actuarial loss (gain)	0.4	1.0	0
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax	(0.1)	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	0	0	4.3
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Benefit Cost, before Tax	(0.4)	(0.3)	(0.1)
Defined Benefit Plan, Curtailments	0	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, before Tax	(0.1)	0.7	4.2
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	0.5
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)	0.4
Defined Benefit Plan, Amortization of Net Gains (Losses)	0
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Discount rate	4.10%	4.70%
Rate of increase in compensation	3.60%	4.00%
Discount rate	4.70%	5.80%	5.70%
Rate of increase in compensation	0.00%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2013	0.2
2014	0.2
2015	0.2
2016	0.3
2017	0.3
2018 through 2021	1.8
Active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Number of Employees Covered	145
Percent of Active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Number of Employees Covered	0
Non-active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Number of Employees Covered	70
Level 1 [Member]
Change in plan assets
Ending Balance	0	0
Level 2 [Member]
Change in plan assets
Ending Balance	0	0
Level 3 [Member]
Change in plan assets
Ending Balance	55.3	44.2
Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	55.3	44.2
Domestic Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations Percentage of Total	40.00%	40.00%
Domestic Equity Securities [Member] \| Level 1 [Member]
Change in plan assets
Ending Balance	0	0
Domestic Equity Securities [Member] \| Level 2 [Member]
Change in plan assets
Ending Balance	0	0
Domestic Equity Securities [Member] \| Level 3 [Member]
Change in plan assets
Ending Balance	22.2	17.6
Domestic Equity Securities [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	22.2	17.6
Cash and Cash Equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations Percentage of Total	0.00%	0.00%
Cash and Cash Equivalents [Member] \| Level 1 [Member]
Change in plan assets
Ending Balance	0	0
Cash and Cash Equivalents [Member] \| Level 2 [Member]
Change in plan assets
Ending Balance	0	0
Cash and Cash Equivalents [Member] \| Level 3 [Member]
Change in plan assets
Ending Balance	0.2	0
Cash and Cash Equivalents [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	0.2	0
Foreign Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations Percentage of Total	30.00%	29.00%
Foreign Equity Securities [Member] \| Level 1 [Member]
Change in plan assets
Ending Balance	0	0
Foreign Equity Securities [Member] \| Level 2 [Member]
Change in plan assets
Ending Balance	0	0
Foreign Equity Securities [Member] \| Level 3 [Member]
Change in plan assets
Ending Balance	16.7	13.0
Foreign Equity Securities [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	16.7	13.0
Debt Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Actual Plan Asset Allocations Percentage of Total	30.00%	31.00%
Debt Securities [Member] \| Level 1 [Member]
Change in plan assets
Ending Balance	0	0
Debt Securities [Member] \| Level 2 [Member]
Change in plan assets
Ending Balance	0	0
Debt Securities [Member] \| Level 3 [Member]
Change in plan assets
Ending Balance	16.2	13.6
Debt Securities [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	16.2	13.6
Realized Gain (Loss) on Sale of Investments [Member]
Change in plan assets
Actual gain (loss) on plan assets	0.7	0.3
Unrealized Gain (Loss or Write-down) [Member]
Change in plan assets
Actual gain (loss) on plan assets	$ 6.3	$ (1.4)

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Expense (Benefit) [Abstract]
Current federal income tax expense (benefit)	$ 33.7	$ (5.3)	$ (16.6)
Deferred federal income tax expense (benefit)	36.5	153.0	172.9
Current state income tax expense (benefit)	0.7	2.9	(4.7)
Deferred state income tax expense (benefit)	(4.4)	3.8	15.4
Total income tax expense	66.5	154.4	167.0
Deferred tax liabilities
Property, plant and equipment	1,606.6	1,714.6
Commodity price and interest rate derivatives	69.4	147.2
Total deferred tax liabilities	1,676.0	1,861.8
Deferred tax assets
NOL and tax credit carryforwards	65.6	232.9
Employee benefits and compensation costs	47.7	42.9
Accrued litigation loss contingency	42.8	0
Bonus and vacation accrual	11.8	10.7
Other	9.6	5.2
Total deferred tax assets	177.5	291.7
Net deferred income tax liability	1,498.5	1,570.1
Deferred income tax liability - current	5.0	85.4
Deferred income tax liability - non-current	1,493.5	1,484.7
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
Federal income taxes statutory rate	35.00%	35.00%	35.00%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	(1.20%)	1.00%	1.50%
Income tax rate reconciliation penalties	(0.60%)	0.00%	0.00%
Return to provision adjustment	0.40%	1.30%	0.20%
Noncontrolling interest	(0.70%)	(0.30%)	(0.20%)
Non-deductible Spin-off costs	0.00%	0.00%	0.50%
Other	0.60%	(0.70%)	(0.10%)
Effective income tax rate	33.50%	36.30%	36.90%
Domestic Tax Authority [Member]
Deferred tax assets
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	44.4
State and Local Jurisdiction [Member]
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]
Operating Loss Carryforwards	$ 21.2
State and Local Jurisdiction [Member] \| Minimum [Member]
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]
Operating Loss Carryforwards, Expiration Dates	2014
State and Local Jurisdiction [Member] \| Maximum [Member]
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]
Operating Loss Carryforwards, Expiration Dates	2032

Discontinued Operations (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Discontinued operations [Line Items]
Revenues	$ 0	$ 0	$ 131.2
Income before income taxes	0	0	67.4
Income taxes	0	0	(24.2)
Discontinued operations, net of income tax	$ 0	$ 0	$ 43.2
Earnings Per Share [Abstract]
Basic from discontinued operations	$ 0.00	$ 0.00	$ 0.25
Diluted from discontinued operations	$ 0.00	$ 0.00	$ 0.24

- Definition

Overall income (loss) from a disposal group that is classified as a component of the entity, before income tax, reported as a separate component of income before extraordinary items. Includes the following (before income tax): income (loss) from operations during the phase-out period, gain (loss) on disposal, provision (or any reversals of earlier provisions) for loss on disposal, and adjustments of a prior period gain (loss) on disposal.

+ References+ Details

- Definition

Tax effect allocated to a disposal group that is classified as a component of the entity reported as a separate component of income before extraordinary items. Includes the tax effects of the following: income (loss) from operations during the phase-out period, gain (loss) on disposal, provision (or any reversals of earlier provisions) for loss on disposal, and adjustments of a prior period gain (loss) on disposal.

+ References

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

-Publisher FASB

-Name Accounting Standards Codification

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

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

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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

- Definition

Amount of income (loss) from a disposal group, net of income tax before extraordinary items allocable to noncontrolling interests. Includes, net of tax, income (loss) from operations during the phase-out period, gain (loss) on disposal, provision (or any reversals of earlier provisions) for loss on disposal, and adjustments of a prior period gain (loss) on disposal.

+ References

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

-Publisher AICPA

-Name Accounting Research Bulletin (ARB)

-Number 51

-Paragraph 29

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

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

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

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+ Details

- Definition

The amount of net income (loss) derived from discontinued operations during the period, net of related tax effect, per each share of common stock or unit outstanding during the reporting period.

+ References

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

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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.

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-Section 03

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+ Details

- Definition

The amount of net income or loss derived from discontinued operations during the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

+ References+ Details

Operations by Line of Business (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues
Total Revenues	$ 704.9	$ 542.4	$ 499.3	$ 603.2	$ 853.3	$ 879.9	$ 808.1	$ 617.9	$ 2,349.8	$ 3,159.2	$ 2,300.6
Operating expenses
Purchased gas, oil and NGL expense									655.6	1,077.1	589.3
Lease operating expense									172.3	145.2	125.0
Natural gas, oil and NGL transportation and other handling costs									148.9	102.2	54.2
Gathering, processing and other									88.0	107.3	83.2
General and administrative									266.6	123.2	107.2
Separation costs									0	0	13.5
Production and property taxes									103.4	105.4	82.5
Results of Operations, Depreciation, Depletion, Amortization and Accretion									904.9	765.4	643.4
Other Expenses									144.6	228.9	69.1
Operating Expenses									2,484.3	2,654.7	1,767.4
Gain (Loss) on Sale of Property Plant Equipment									1.2	1.4	12.1
OPERATING (LOSS) INCOME	(114.7)	(12.6)	(55.5)	49.5	16.5	183.4	168.9	137.1	(133.3)	505.9	545.3
Realized and unrealized gains (losses) on derivative contracts									441.9	0	0
Interest and other income									6.6	4.1	2.3
Income from unconsolidated affiliates									6.8	5.5	3.0
Loss from early extinguishment of debt									(0.6)	(0.7)	(13.3)
Interest expense									(122.9)	(90.0)	(84.4)
Income (loss) before income taxes	(42.1)	(4.4)	0.3	244.7	(0.9)	161.5	147.7	116.5	198.5	424.8	452.9
Income taxes									(66.5)	(154.4)	(167.0)
Income from Continuing Operations									132.0	270.4	285.9
Discontinued operations, net of income tax									0	0	43.2
NET INCOME									132.0	270.4	329.1
Net income attributable to noncontrolling interest									(3.7)	(3.2)	(2.9)
NET INCOME ATTRIBUTABLE TO QEP	(23.1)	(3.1)	(0.7)	155.2	(0.3)	101.5	92.8	73.2	128.3	267.2	326.2
Assets	9,108.5				7,442.7				9,108.5	7,442.7	6,785.3
Equity Method Investments	41.2				42.2				41.2	42.2	44.5
Cash capital expenditures									2,799.7	1,431.1	1,469.0
Accrued capital expenditures									2,888.2	1,445.8	1,485.9
Goodwill	59.5				59.5				59.5	59.5	59.6
Unaffiliated customers [Member]
Revenues
Total Revenues									2,349.8	3,159.2	2,300.6
Affiliated customers [Member]
Revenues
Total Revenues									0	0	0
QEP Energy [Member]
Revenues
Total Revenues									1,615.4	2,213.2	1,456.3
Operating expenses
Purchased gas, oil and NGL expense									224.7	506.4	0
Lease operating expense									175.8	148.2	127.3
Natural gas, oil and NGL transportation and other handling costs									228.1	186.0	125.5
Gathering, processing and other									0	0	0
General and administrative									237.6	98.4	78.0
Separation costs											0
Production and property taxes									97.2	99.1	77.8
Results of Operations, Depreciation, Depletion, Amortization and Accretion									838.0	707.2	592.5
Other Expenses									144.6	228.9	69.1
Operating Expenses									1,946.0	1,974.2	1,070.2
Gain (Loss) on Sale of Property Plant Equipment									1.2	1.4	13.7
OPERATING (LOSS) INCOME									(329.4)	240.4	399.8
Realized and unrealized gains (losses) on derivative contracts									434.9
Interest and other income									6.2	4.0	2.1
Income from unconsolidated affiliates									0.1	0.1	0.2
Loss from early extinguishment of debt									0	0	0
Interest expense									(116.8)	(81.9)	(78.5)
Income (loss) before income taxes									(5.0)	162.6	323.6
Income taxes									4.3	(57.9)	(119.7)
Income from Continuing Operations											203.9
Discontinued operations, net of income tax											0
NET INCOME									(0.7)	104.7	203.9
Net income attributable to noncontrolling interest									0	0	0
NET INCOME ATTRIBUTABLE TO QEP									(0.7)	104.7	203.9
Assets	7,436.5				5,815.7				7,436.5	5,815.7	5,391.9
Equity Method Investments	0				0				0	0	0
Cash capital expenditures									2,621.1	1,295.5	1,205.0
Accrued capital expenditures									2,702.4	1,338.7	1,215.8
Goodwill	59.5				59.5				59.5	59.5	59.6
QEP Energy [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									1,615.4	2,213.2	1,456.3
QEP Energy [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									0	0	0
QEP Field Services [Member]
Revenues
Total Revenues									439.2	465.5	319.2
Operating expenses
Purchased gas, oil and NGL expense									12.1	0	0
Lease operating expense									0	0	0
Natural gas, oil and NGL transportation and other handling costs									33.6	9.3	0
Gathering, processing and other									86.8	106.0	82.1
General and administrative									34.7	29.2	31.6
Separation costs											0
Production and property taxes									6.0	6.1	4.4
Results of Operations, Depreciation, Depletion, Amortization and Accretion									63.2	55.7	48.9
Other Expenses									0	0	0
Operating Expenses									236.4	206.3	167.0
Gain (Loss) on Sale of Property Plant Equipment									0	0	(1.6)
OPERATING (LOSS) INCOME									202.8	259.2	150.6
Realized and unrealized gains (losses) on derivative contracts									8.4
Interest and other income									0.2	0.1	0.1
Income from unconsolidated affiliates									6.7	5.4	2.8
Loss from early extinguishment of debt									0	0	0
Interest expense									(13.6)	(13.6)	(7.6)
Income (loss) before income taxes									204.5	251.1	145.9
Income taxes									(71.8)	(93.4)	(51.9)
Income from Continuing Operations											94.0
Discontinued operations, net of income tax											0
NET INCOME									132.7	157.7	94.0
Net income attributable to noncontrolling interest									(3.7)	(3.2)	(2.9)
NET INCOME ATTRIBUTABLE TO QEP									129.0	154.5	91.1
Assets	1,399.7				1,312.7				1,399.7	1,312.7	1,197.5
Equity Method Investments	41.2				42.2				41.2	42.2	44.5
Cash capital expenditures									164.0	130.1	262.1
Accrued capital expenditures									171.2	101.6	268.2
Goodwill	0				0				0	0	0
QEP Field Services [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									320.2	369.3	245.5
QEP Field Services [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									119.0	96.2	73.7
QEP Marketing and Other [Member]
Revenues
Total Revenues									1,019.9	1,156.9	1,098.5
Operating expenses
Purchased gas, oil and NGL expense									1,021.1	1,144.5	1,082.8
Lease operating expense									0	0	0
Natural gas, oil and NGL transportation and other handling costs									0	0	0
Gathering, processing and other									1.2	1.3	1.1
General and administrative									0.4	2.1	3.9
Separation costs											13.5
Production and property taxes									0.2	0.2	0.3
Results of Operations, Depreciation, Depletion, Amortization and Accretion									3.7	2.5	2.0
Other Expenses									0	0	0
Operating Expenses									1,026.6	1,150.6	1,103.6
Gain (Loss) on Sale of Property Plant Equipment									0	0	0
OPERATING (LOSS) INCOME									(6.7)	6.3	(5.1)
Realized and unrealized gains (losses) on derivative contracts									(1.4)
Interest and other income									132.1	98.7	87.2
Income from unconsolidated affiliates									0	0	0
Loss from early extinguishment of debt									(0.6)	(0.7)	(13.3)
Interest expense									(124.4)	(93.2)	(85.4)
Income (loss) before income taxes									(1.0)	11.1	(16.6)
Income taxes									1.0	(3.1)	4.6
Income from Continuing Operations											(12.0)
Discontinued operations, net of income tax											(43.2)
NET INCOME									0	8.0	31.2
Net income attributable to noncontrolling interest									0	0	0
NET INCOME ATTRIBUTABLE TO QEP									0	8.0	31.2
Assets	272.3				314.3				272.3	314.3	195.9
Equity Method Investments	0				0				0	0	0
Cash capital expenditures									14.6	5.5	1.9
Accrued capital expenditures									14.6	5.5	1.9
Goodwill	0				0				0	0	0
QEP Marketing and Other [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									414.2	576.7	598.8
QEP Marketing and Other [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									605.7	580.2	499.7
Elimination [Member]
Revenues
Total Revenues									(724.7)	(676.4)	(573.4)
Operating expenses
Purchased gas, oil and NGL expense									(602.3)	(573.8)	(493.5)
Lease operating expense									(3.5)	(3.0)	(2.3)
Natural gas, oil and NGL transportation and other handling costs									(112.8)	(93.1)	(71.3)
Gathering, processing and other									0	0	0
General and administrative									(6.1)	(6.5)	(6.3)
Separation costs											0
Production and property taxes									0	0	0
Results of Operations, Depreciation, Depletion, Amortization and Accretion									0	0	0
Other Expenses									0	0	0
Operating Expenses									(724.7)	(676.4)	(573.4)
Gain (Loss) on Sale of Property Plant Equipment									0	0	0
OPERATING (LOSS) INCOME									0	0	0
Realized and unrealized gains (losses) on derivative contracts									0
Interest and other income									(131.9)	(98.7)	(87.1)
Income from unconsolidated affiliates									0	0	0
Loss from early extinguishment of debt									0	0	0
Interest expense									131.9	98.7	87.1
Income (loss) before income taxes									0	0	0
Income taxes									0	0	0
Income from Continuing Operations											0
Discontinued operations, net of income tax											0
NET INCOME									0	0	0
Net income attributable to noncontrolling interest									0	0	0
NET INCOME ATTRIBUTABLE TO QEP									0	0	0
Assets	0				0				0	0	0
Equity Method Investments	0				0				0	0	0
Cash capital expenditures									0	0	0
Accrued capital expenditures									0	0	0
Goodwill	0				0				0	0	0
Elimination [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									0	0	0
Elimination [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									$ (724.7)	$ (676.4)	$ (573.4)

Quarterly Financial Information (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Effect of Fourth Quarter Events [Line Items]
Revenues	$ 704.9	$ 542.4	$ 499.3	$ 603.2	$ 853.3	$ 879.9	$ 808.1	$ 617.9	$ 2,349.8	$ 3,159.2	$ 2,300.6
OPERATING (LOSS) INCOME	(114.7)	(12.6)	(55.5)	49.5	16.5	183.4	168.9	137.1	(133.3)	505.9	545.3
Income (loss) before income taxes	(42.1)	(4.4)	0.3	244.7	(0.9)	161.5	147.7	116.5	198.5	424.8	452.9
NET INCOME ATTRIBUTABLE TO QEP	$ (23.1)	$ (3.1)	$ (0.7)	$ 155.2	$ (0.3)	$ 101.5	$ 92.8	$ 73.2	$ 128.3	$ 267.2	$ 326.2
Basic total	$ (0.13)	$ (0.02)	$ 0.00	$ 0.87	$ (0.01)	$ 0.58	$ 0.52	$ 0.42	$ 0.72	$ 1.51	$ 1.86
Diluted total	$ (0.13)	$ (0.02)	$ 0.00	$ 0.87	$ 0.00	$ 0.57	$ 0.52	$ 0.41	$ 0.72	$ 1.50	$ 1.84

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 36, 37, 38

-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 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 Accounting Standards Codification

-Topic 260

-SubTopic 10

-Section 50

-Paragraph 1

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-Topic 225

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-Topic 260

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-Paragraph 2

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 04

-Paragraph 18

-Article 7

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 03

-Paragraph 20

-Article 5

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

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-Name Regulation S-X (SX)

-Number 210

-Section 04

-Paragraph 21

-Article 9

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 260

-SubTopic 10

-Section 55

-Paragraph 52

-URI http://asc.fasb.org/extlink&oid=16381557&loc=d3e4984-109258

Reference 10: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 944

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-Section S99

-Paragraph 1

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-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

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-Name Accounting Standards Codification

-Topic 942

-SubTopic 225

-Section S99

-Paragraph 1

-Subparagraph (SX 210.9-04.23)

-URI http://asc.fasb.org/extlink&oid=6879574&loc=d3e536633-122882

+ Details

- Definition

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

+ References+ Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 130

-Paragraph 10, 15

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 03

-Paragraph 19

-Article 5

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 04

-Paragraph 20

-Article 9

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 95

-Paragraph 28, 29, 30

-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 944

-SubTopic 225

-Section S99

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-Topic 220

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-Publisher FASB

-Name Accounting Standards Codification

-Glossary Other Comprehensive Income

-URI http://asc.fasb.org/extlink&oid=6519514

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

-Publisher FASB

-Name Accounting Standards Codification

-Glossary Net Income

-URI http://asc.fasb.org/extlink&oid=6518256

Reference 10: http://www.xbrl.org/2003/role/presentationRef

-Publisher AICPA

-Name Accounting Research Bulletin (ARB)

-Number 51

-Paragraph 38

-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 11: http://www.xbrl.org/2003/role/presentationRef

-Publisher AICPA

-Name Accounting Research Bulletin (ARB)

-Number 51

-Paragraph A7

-Appendix A

Reference 12: http://www.xbrl.org/2003/role/presentationRef

-Publisher AICPA

-Name Accounting Research Bulletin (ARB)

-Number 51

-Paragraph 38

-Subparagraph d

-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.

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-Name Accounting Standards Codification

-Topic 260

-SubTopic 10

-Section 50

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-Name Accounting Standards Codification

-Topic 944

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-Section S99

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-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 15: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 87-21

-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 16: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 225

-SubTopic 10

-Section S99

-Paragraph 2

-Subparagraph (SX 210.5-03.18)

-URI http://asc.fasb.org/extlink&oid=6880815&loc=d3e20235-122688

+ Details

Supplemental Gas and Oil Information (Unaudited) Capitalized costs (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Capitalized Cost [Abstract]
Proved properties	$ 10,234.3	$ 8,172.4
Unproved properties, net	937.9	326.8
Total proved and unproved properties	11,172.2	8,499.2
Accumulated depreciation, depletion and amortization	(4,258.1)	(3,339.2)
Net capitalized costs	$ 6,914.1	$ 5,160.0

- Definition

Capitalized costs of proved properties incurred for any combination mineral interests acquisitions; wells and related equipment; support equipment and facilities; and uncompleted wells and equipment and other costs not previously disclosed within this table.

+ References+ Details

- Definition

Capitalized costs of unproved properties incurred for any combination mineral interests acquisitions and other costs not previously disclosed within this table.

+ References+ Details

Supplemental Gas and Oil Information (Unaudited) Costs incurred (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Gas and Oil Information (Unaudited) [Abstract]
Accrued capital costs included in development costs	$ 81.3
Costs Incurred, Asset Retirement Obligation Incurred	17.7
Costs Incurred To Advance The Development Of Proved Undeveloped Reserves	513.0	533.6	434.2
Unproved	692.6	48.0	109.1
Proved	714.4	0.1	0.2
Total Property Acqusitions	1,407.0	48.1	109.3
Costs Incurred, Exploration Costs	14.3	36.5	146.4
Costs Incurred, Development Costs	1,310.0	1,267.8	988.8
Costs Incurred, Acquisition of Oil and Gas Properties	$ 2,731.3	$ 1,352.4	$ 1,244.5

Supplemental Gas and Oil Information (Unaudited) Results of Operations (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Results of Operations [Abstract]

Revenues (1)

$ 1,393.4

^[1]

$ 1,703.4

^[1]

$ 1,456.3

^[1]

Production costs

501.1

433.3

330.6

Exploration expenses

11.2

10.5

23.0

Depreciation, depletion and amortization

838.0

707.2

592.5

Abandonment and impairment

133.4

218.4

46.1

Total expenses

1,483.7

1,369.4

992.2

Income before income taxes

(90.3)

334.0

464.1

Income taxes

33.6

(119.0)

(171.8)

Results of operations from producing activities excluding allocated corporate overhead and interest expenses

$ (56.7)

$ 215.0

$ 292.3

[1]	Revenue for the years ended December 31, 2011 and 2010, reflect the impact of QEP's settled derivative contracts which during the year ended December 31, 2012, are reflected below operating (loss) income. See Note 6 - Derivative Contracts.

Supplemental Gas and Oil Information (Unaudited) Estimated Quantities of Proved Gas and Oil Reserves (Details)	12 Months Ended
	Dec. 31, 2012 MMcf	Dec. 31, 2011 MMcf	Dec. 31, 2010 MMcf	Dec. 31, 2009 MMcf
Natural Gas [Member]
Reserve Quantities [Line Items]
Reserves, Unit of Measure	(Bcf)
Proved reserves balance	2,749,400,000	2,612,900,000	2,525,000,000
Extensions and discoveries	(240,600,000)	(270,100,000)	46,300,000
Extensions and discoveries	330,600,000	641,900,000	248,400,000
Purchase of reserves in place	32,300,000	1,900,000	200,000
Sale of reserves in place	0	(800,000)	(3,200,000)
Production	(249,300,000)	(236,400,000)	(203,800,000)
Proved reserves balance	2,622,400,000	2,749,400,000	2,612,900,000
Proved developed reserves	1,531,700,000	1,538,300,000	1,404,800,000	1,178,700,000
Proved undeveloped reserves	1,090,700,000	1,211,100,000	1,208,100,000	1,346,300,000
Oil [Member]
Reserve Quantities [Line Items]
Reserves, Unit of Measure	(MMbbl)
Proved reserves balance	67,500,000	52,300,000	29,300,000
Extensions and discoveries	(1,500,000)	1,700,000	700,000
Extensions and discoveries	17,300,000	17,400,000	26,100,000
Purchase of reserves in place	42,000,000	0	0
Sale of reserves in place	0	(200,000)	(800,000)
Production	(6,300,000)	(3,700,000)	(3,000,000)
Proved reserves balance	119,000,000	67,500,000	52,300,000
Proved developed reserves	47,400,000	33,000,000	25,100,000	22,400,000
Proved undeveloped reserves	71,600,000	34,600,000	27,200,000	6,900,000
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Reserves, Unit of Measure	(MMbbl)
Proved reserves balance	76,600,000	17,400,000	7,700,000
Extensions and discoveries	700,000	39,300,000	4,800,000
Extensions and discoveries	23,000,000	22,600,000	6,100,000
Purchase of reserves in place	4,900,000	0	0
Sale of reserves in place	0	0	0
Production	(5,300,000)	(2,700,000)	(1,200,000)
Proved reserves balance	99,900,000	76,600,000	17,400,000
Proved developed reserves	49,300,000	38,400,000	9,300,000	4,900,000
Proved undeveloped reserves	50,600,000	38,200,000	8,000,000	2,800,000
Total Reserves Natural Gas Equivalent [Member]
Reserve Quantities [Line Items]
Reserves, Unit of Measure	(Bcfe)
Proved reserves balance	3,613,800,000	3,030,700,000	2,746,900,000
Extensions and discoveries	(244,800,000)	(23,500,000)	78,600,000
Extensions and discoveries	572,500,000	881,600,000	441,800,000
Purchase of reserves in place	313,800,000	2,100,000	200,000
Sale of reserves in place	0	(1,900,000)	(7,800,000)
Production	(319,200,000)	(275,200,000)	(229,000,000)
Proved reserves balance	3,936,100,000	3,613,800,000	3,030,700,000
Proved developed reserves	2,111,900,000	1,966,300,000	1,611,500,000	1,342,800,000
Proved undeveloped reserves	1,824,200,000	1,647,500,000	1,419,200,000	1,404,100,000

Supplemental Gas and Oil Information (Unaudited) Future Development Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Future Development Costs [Abstract]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Next Twelve Months	$ 1,042.5
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Two	871.1
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Three	$ 814.5

Supplemental Gas and Oil Information (Unaudited) Standardized Measure of Future Net cash Flows (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Standardized Measure of Future Net Cash Flows [Abstract]
Future cash inflows	$ 18,200.2	$ 18,300.6	$ 14,174.8
Future production costs	(5,027.2)	(4,276.1)	(3,701.8)
Future development costs	(3,927.3)	(3,250.0)	(2,275.9)
Future income tax expenses	(2,269.0)	(2,837.1)	(1,957.6)
Future net cash flows	6,976.7	7,937.4	6,239.5
10% annual discount for estimated timing of net cash flows	(3,942.0)	(4,411.8)	(3,533.9)
Standardized measure of discounted future net cash flows	$ 3,034.7	$ 3,525.6	$ 2,705.6

- Definition

This is the amount that is derived from using a discount rate of ten percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

+ References+ Details

- Definition

The estimated future income tax expenses that will be incurred based on the future income less future expenses derived from production and sale of proved oil and gas reserves in this geographic region.

+ References+ Details

- Definition

These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows for each geographic region where proved oil and gas reserves exist.

+ References+ Details

Supplemental Gas and Oil Information (Unaudited) Change in Standardized Measure of Future Cash Flows (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Change in Standardized Measure of Future Cash Flows [Abstract]
Beginning Balance	$ 3,525.6	$ 2,705.6	$ 1,443.0
Sales of gas, oil and NGL produced during the period, net of production costs	(892.3)	(1,779.9)	(1,125.7)
Net change in sales prices and in production (lifting) costs related to future production	(2,083.5)	1,472.5	1,775.8
Net change due to extensions, discoveries and improved recovery	948.5	1,806.4	789.1
Net change due to revisions of quantity estimates	(387.8)	(48.2)	140.4
Changes due to purchases of reserves in place	831.4	0	0
Changes due to sales of reserves in place	0	(8.0)	(26.0)
Previously estimated development costs incurred during the period	513.0	533.6	434.2
Changes in estimated future development costs	(209.3)	(1,110.4)	(325.4)
Accretion of discount	499.4	355.4	170.9
Net change in income taxes	273.6	(411.4)	(582.4)
Other	16.1	9.9	11.5
Net change	(490.9)	820.0	1,262.6
Ending Balance	$ 3,034.7	$ 3,525.6	$ 2,705.6

Schedule of Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Valuation and Qualifying Accounts Disclosure [Line Items]
Provision for Doubtful Accounts	$ 1.4	$ 0.2	$ (0.3)
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	1.7	2.3	3.0
Provision for Doubtful Accounts		0.2	(0.3)
Valuation Allowances and Reserves, Balance	2.8	1.7	2.3
Valuation Allowances and Reserves, Deductions	$ (0.3)	$ (0.8)	$ (0.4)

- Definition

+ References+ Details

Summary of Significant Accounting Policies Revenue Recognition (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Summary of Significant Accounting Policies [Abstract]
Gas Balancing Asset (Liability)	$ 13.2	$ 13.3

Commitments and Contingencies Litigation (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
Loss Contingency, Settlement Agreement, Consideration	$ 115.0