Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
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		179,332,240
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Entity Public Float			$ 4,973,494,170

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES
Natural gas sales	$ 779.0	$ 667.4	$ 1,239.1
Oil sales	916.6	532.6	324.2
NGL sales	294.1	322.1	309.8
Gathering, processing and other	189.0	181.6	200.8
Purchased gas, oil and NGL sales	757.1	646.1	1,085.3
Total Revenues	2,935.8	2,349.8	3,159.2
OPERATING EXPENSES
Purchased gas, oil and NGL expense	765.9	655.6	1,077.1
Lease operating expense	177.8	172.3	145.2
Natural gas, oil and NGL transport and other handling costs	141.4	148.9	102.2
Gathering, processing and other	90.6	88.0	107.3
General and administrative	191.1	266.6	123.2
Production and property taxes	166.5	103.4	105.4
Depreciation, depletion and amortization	1,016.0	905.3	765.6
Exploration expenses	11.9	11.2	10.5
Asset Impairment Charges	93.0	133.0	218.2
Total Operating Expenses	2,654.2	2,484.3	2,654.7
Net gain from asset sales	103.0	1.2	1.4
OPERATING INCOME (LOSS)	384.6	(133.3)	505.9
Realized and unrealized gains on derivative contracts (Note 7)	58.9	441.9	0
Interest and other income	5.2	6.6	4.1
Income from unconsolidated affiliates	5.8	6.8	5.5
Loss from early extinguishment of debt	0	(0.6)	(0.7)
Interest expense	(163.3)	(122.9)	(90.0)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	291.2	198.5	424.8
Income taxes	(119.8)	(66.5)	(154.4)
NET INCOME	171.4	132.0	270.4
Net income attributable to noncontrolling interest	(12.0)	(3.7)	(3.2)
NET INCOME ATTRIBUTABLE TO QEP	$ 159.4	$ 128.3	$ 267.2
Earnings Per Common Share Attributable to QEP
Basic total	$ 0.89	$ 0.72	$ 1.51
Diluted total	$ 0.89	$ 0.72	$ 1.50
Weighted-average common shares outstanding
Used in basic calculation	179.2	177.8	176.5
Used in diluted calculation	179.5	178.7	178.4
Dividends per common share	$ 0.08	$ 0.08	$ 0.08

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Statement of Other Comprehensive Income [Abstract]

NET INCOME

$ 171.4

$ 132.0

$ 270.4

Other comprehensive (loss) income, net of tax:

Effect of derivative financial instruments

(77.6)

^[1]

(171.1)

^[1]

24.8

^[1]

Pension and other postretirement plans adjustments:

Current year net actuarial gain (loss)

13.5

^[2]

(10.0)

^[2]

(14.7)

^[2]

Amortization of net actuarial loss

1.5

^[3]

1.1

^[3]

Amortization of net prior service cost

3.3

^[4]

3.5

^[4]

3.5

^[4]

Net curtailment cost incurred

^[5]

1.4

^[5]

Total pension and other postretirement plans adjustments

18.3

(4.0)

(11.2)

Other comprehensive (loss) income

(59.3)

(175.1)

13.6

Comprehensive (loss) income

112.1

(43.1)

284.0

Comprehensive income attributable to noncontrolling interests

(12.0)

(3.7)

(3.2)

Comprehensive (loss) income attributable to QEP

$ 100.1

$ (46.8)

$ 280.8

[1]	Presented net of income tax benefit of $45.9 million and $101.3 million during the years ended December 31, 2013 and 2012, respectively, and net of income tax expense of $14.7 million during the year ended December 31, 2011.
[2]	Presented net of income tax expense of $8.3 million during the year ended December 31, 2013, and net of income tax benefit of $6.3 million and $9.2 million during the years ended December 31, 2012 and December 31, 2011
[3]	Presented net of income tax expense of $0.9 million and $0.9 million during the years ended December 31, 2013
[4]	Presented net of income tax expense of $2.1 million, $2.2 million and $2.1 million during the years ended December 31, 2013, 2012 and 2011, respectively.
[5]	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, 2013	Dec. 31, 2012	Dec. 31, 2011
Other comprehensive income (loss), tax
Tax benefit (expense) on gains (losses) on changes in unrealized fair value of derivatives designated as cash flow hedges	$ 45.9	$ 101.3	$ (14.7)
Pension and other postretirement plans adjustments:
Tax expense on prior service cost incurred	(2.1)	(2.2)	(2.1)
Tax Expense on Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans		0.8
Current year net actuarial gain loss [Member]
Pension and other postretirement plans adjustments:
Tax benefit (expense) on net unamortized gain (loss) incurred	(8.3)	6.3	9.2
Amortization net actuarial gain loss [Member] [Member]
Pension and other postretirement plans adjustments:
Tax benefit (expense) on net unamortized gain (loss) incurred	$ (0.9)	$ (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, 2013	Dec. 31, 2012
Current Assets
Cash and cash equivalents	$ 11.9	$ 0
Accounts receivable, net	408.5	387.5
Fair value of derivative contracts	0.2	188.7
Gas, oil and NGL inventories, at lower of average cost or market	13.4	13.1
Deferred Tax Assets, Net	30.6	0
Prepaid expenses and other	54.4	68.0
Total Current Assets	519.0	657.3
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	11,571.4	10,234.3
Unproved properties, net	665.1	937.9
Midstream field services	1,698.1	1,634.9
Marketing and other	85.5	64.6
Materials and supplies	59.0	61.9
Total Property, Plant and Equipment	14,079.1	12,933.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	4,930.9	4,258.1
Midstream field services	409.7	357.9
Marketing and other	22.1	18.1
Total Accumulated Depreciation, Depletion and Amortization	5,362.7	4,634.1
Net Property, Plant and Equipment	8,716.4	8,299.5
Investment in unconsolidated affiliates	39.0	41.2
Goodwill	0	59.5
Fair value of derivative contracts	1.0	4.1
Restricted Cash, Noncurrent	50.0	0
Other noncurrent assets	51.4	46.9
TOTAL ASSETS	9,376.8	9,108.5
Current Liabilities
Checks outstanding in excess of cash balances	90.9	39.7
Accounts payable and accrued expenses	434.9	643.4
Production and property taxes	51.8	41.8
Interest payable	37.2	36.9
Fair value of derivative contracts	26.7	2.6
Deferred income taxes	0	5.0
Total Current Liabilities	641.5	769.4
Long-term debt	2,997.5	3,206.9
Deferred income taxes	1,560.6	1,493.5
Asset retirement obligations	191.8	191.4
Fair value of derivative contracts	0	3.6
Other long-term liabilities	108.6	130.0
Commitments and contingencies (Note 10)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 179.3 million and 178.5 million shares issued, respectively	1.8	1.8
Treasury stock - 0.4 million and 0.1 million shares, respectively	(14.9)	(3.7)
Additional paid-in capital	498.4	462.1
Retained earnings	2,917.8	2,773.0
Accumulated other comprehensive (loss)income	(26.5)	32.8
Total Common Shareholders' Equity	3,376.6	3,266.0
Noncontrolling interest	500.2	47.7
Total Equity	3,876.8	3,313.7
TOTAL LIABILITIES AND EQUITY	$ 9,376.8	$ 9,108.5

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
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)	179.3	178.5
Treasury stock (in shares)	0.4	0.1

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, 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				267.2		3.2
Dividends	(14.1)				(14.1)
Equity-based compensation	24.1		(9.2)	33.3
Stock Issued During Period, Shares, Equity-based Compensation, Net of Forfeitures		1.3
Stock Issued During Period, Shares, Treasury Stock Reissued			(0.3)
Proceeds from Issuance Initial Public Offering	0
Payments to Noncontrolling Interests	(5.4)						(5.4)
Equity from Questar	0.4				0.4
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	24.8					24.8
Total pension and other postretirement plans adjustments	(11.2)					(11.2)
Treasury stock (in shares)			(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				128.3		3.7
Dividends	(14.2)				(14.2)
Equity-based compensation	23.2		7.1	30.7	(14.6)
Stock Issued During Period, Shares, Equity-based Compensation, Net of Forfeitures		1.3
Stock Issued During Period, Shares, Treasury Stock Reissued			0.2
Distribution to QEP Education Foundation	2.3		2.3
Proceeds from Issuance Initial Public Offering	0
Payments to Noncontrolling Interests	(6.6)						6.6
TreasuryStockIssuedCharitableContribution			0.1
Gain reclassified from AOCI into income for effective portion of hedge	(171.1)					(171.1)
Total pension and other postretirement plans adjustments	(4.0)					(4.0)
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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
NET INCOME	171.4				159.4		12.0
Dividends	(14.3)				(14.3)
Equity-based compensation	25.0		(11.2)	36.3	(0.3)		0.2
Stock Issued During Period, Shares, Equity-based Compensation, Net of Forfeitures		0.8
Stock Issued During Period, Shares, Treasury Stock Reissued			(0.3)
Proceeds from Issuance Initial Public Offering	449.6						449.6
Payments to Noncontrolling Interests	(9.3)						(9.3)
Gain reclassified from AOCI into income for effective portion of hedge	(77.6)					(77.6)
Total pension and other postretirement plans adjustments	18.3					18.3
Treasury stock (in shares)	0.4		(0.4)
Balance at Dec. 31, 2013	$ 3,876.8	$ 1.8	$ (14.9)	$ 498.4	$ 2,917.8	$ (26.5)	$ 500.2
Shares, Issued at Dec. 31, 2013		179.3

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OPERATING ACTIVITIES
NET INCOME	$ 171.4	$ 132.0	$ 270.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,016.0	905.3	765.6
Deferred income taxes	66.1	32.1	156.8
Asset Impairment Charges	93.0	133.0	218.2
Equity-based compensation	27.1	25.6	22.0
Amortization of debt issuance costs and discounts	6.4	5.3	4.1
Net gain from asset sales	(103.0)	(1.2)	(1.4)
Income from unconsolidated affiliates	(5.8)	(6.8)	(5.5)
Distributions from unconsolidated affiliates and other	7.9	7.9	8.1
Non-cash loss on early extinguishment of debt	0	0	0.7
Unrealized loss (gain) on derivative contracts	88.7	(63.2)	(117.7)
Changes in operating assets and liabilities
Accounts receivable	3.2	9.6	(144.6)
Inventories	2.6	28.7	(22.0)
Prepaid expenses	14.0	(16.8)	1.6
Accounts payable and accrued expenses	(179.7)	101.3	127.8
Federal income taxes	(27.4)	3.5	17.0
Other	11.2	(0.3)	(8.5)
Net Cash Provided by Operating Activities	1,191.7	1,296.0	1,292.6
INVESTING ACTIVITIES
Property acquisitions	(40.9)	(1,406.1)	(48.0)
Property, plant and equipment, including dry exploratory well expense	(1,561.7)	(1,393.6)	(1,383.1)
Proceeds from disposition of assets	211.1	5.2	8.2
Acquisition deposit held in escrow	(50.0)	0	0
Net Cash Used in Investing Activities	(1,441.5)	(2,794.5)	(1,422.9)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	51.2	10.3	9.9
Long-term debt issued	0	1,450.0	0
Long-term debt issuance costs paid	(3.2)	(17.8)	(10.6)
Long-term debt repaid	0	(6.7)	(58.5)
Proceeds from credit facility	3,085.0	2,739.0	1,950.3
Repayments of credit facility	(3,295.0)	(2,655.5)	(1,743.8)
Treasury stock repurchased	(9.3)	0	0
Other capital contributions	7.0	(2.2)	0.7
Dividends paid	(14.3)	(14.2)	(14.1)
Excess tax benefit on equity-based compensation	0	2.2	1.6
Distribution from Questar	0	0	0.2
Proceeds from Issuance Initial Public Offering	449.6	0	0
Distribution to noncontrolling interest	(9.3)	(6.6)	(5.4)
Net Cash Provided by Financing Activities	261.7	1,498.5	130.3
Change in cash and cash equivalents	11.9	0	0
Beginning cash and cash equivalents	0	0	0
Ending cash and cash equivalents	$ 11.9	$ 0	$ 0

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

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: oil and gas 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 gas, oil, and NGL;


•	QEP Field Services Company (QEP Field Services), which includes the ownership and operations of QEP Midstream Partners, LP (QEP Midstream), provides midstream field services, including gathering of natural gas, oil and NGL, natural gas processing, compression, and treating services, for affiliates and third parties, and;


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

QEP's operations are focused in two major regions: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Oklahoma, Louisiana and the Texas Panhandle) of the United States. QEP's corporate headquarters are located in Denver, Colorado.

Shares of QEP’s 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, including QEP Midstream (see Note 3 - QEP Midstream). 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.

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, 2013 and 2012, were Uintah Basin Field Services, LLC in which QEP owned (38%) and Three Rivers Gathering, LLC in which QEP Midstream currently owns (50%), which was previously owned by QEP prior to QEP Midstream's initial public offering (see Note 3 - QEP Midstream). Both are limited liability companies engaged in gathering and compressing natural gas.

Reclassifications

In 2012 and 2011, QEP presented certain credit facility payments and borrowings net on the Consolidated Statements of Cash Flow. These borrowings and payments were reclassified to be presented gross on the Consolidated Statement of Cash Flow in order to conform with the current period presentation. This reclassification is entirely within "Financing Activities" and has no effect on other categories or total cash on the Consolidated Statements of Cash Flows or net income or earnings per share on the Consolidated Statements of Operations.

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 gas, oil and NGL reserves which are used in the calculation of depreciation, depletion and amortization rates of its oil and gas 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 oil and gas 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 oil and gas are accounted for using the sales method, whereby revenue is recognized as oil and gas is sold to purchasers. A liability is recorded in the event that the Company has sold volumes in excess of its share of remaining oil and gas reserves in an underlying property. QEP's imbalance obligations at December 31, 2013 and 2012, were $18.6 million and $13.2 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 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.

QEP Field Services provides gathering and transportation services, primarily under fee-based contracts, as well as processing services, under keep-whole and fee-based contracts. Under fee-based arrangements, QEP Field Services receives a fee or fees for one or more of the following services: firm and interruptible gathering, processing or transmission of natural gas, oil, condensate, and water. The revenue QEP Field Services earns from the fee-based arrangements is generally directly related to the volume of gas, oil, or water that flows through QEP Field Services’ systems and is not directly dependent on commodity prices. A portion of the fee-based agreements provide for minimum annual payments or fixed demand charges which are recognized as revenue pursuant to the contract terms. In addition, under the majority of gas gathering agreements, QEP Field Services retains and sells condensate that falls out of the natural gas stream during the gathering process. Under keep-whole arrangements, QEP Field Services processes the natural gas for a customer and takes title to the resulting NGL, which are sold to third parties at market prices. Because the extraction of the NGL from the natural gas during processing reduces the Btu content of the natural gas, QEP Field Services must either purchase gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this gas.

Cash and Cash Equivalents and Restricted Cash

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

As of December 31, 2013, QEP's restricted cash balance was $50.0 million, which consists of a deposit paid by QEP that was held in escrow for the acquisition that closed in the first quarter of 2014 (see Note 15 - Subsequent Event for further discussion on the acquisition). The cash payment is shown in investing activities on the Consolidated Statements of Cash Flow.

Supplemental cash flow information is shown in the below table:



	Year Ended December 31,
	2013			2012	2011
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	156.7		105.1	$	90.5
Cash paid (received) for income taxes	77.9			30.0	(28.5		)
Non-cash investing activities
Change in capital expenditure accrual balance	$	(25.2	)	88.5	$	14.7

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, 2013, 2012 and 2011, was $3.5 million, $1.4 million, and $0.2 million, respectively. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad debt expenses was $5.1 million at December 31, 2013 and $2.8 million at December 31, 2012.

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:

Oil and gas properties

QEP Energy uses the successful efforts method to account for oil and gas 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 to 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 oil and gas 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 oil and gas reserves. Capitalized costs of exploratory wells that have found proved oil and gas reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves for a successful effort field. The Company capitalizes an estimate of the fair value of future abandonment costs.

Depreciation, depletion and amortization for the Company's remaining 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 oil and gas 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 oil and gas reserves caused by mechanical problems, faster-than-expected decline of reserves, lease ownership issues, declines in gas, NGL and 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, 2013, QEP recorded impairment charges of $93.0 million, of which $1.2 million relates to price-related impairment charges on proved properties and $32.3 million relates to impairment on unproved properties due to lease expirations and changes in drilling plans. An additional $59.5 million of impairment was recorded due to the write-off of goodwill (see Goodwill section within this note for additional information). Of the $33.5 million property impairment charges incurred during the year ended December 31, 2013, $17.5 million related to oil and gas properties in the Southern Region and $16.0 million related to oil and gas properties in the Northern Region.

During the year ended December 31, 2012, QEP recorded impairment charges of $133.0 million on its oil and gas properties. Of the $133.0 million charges during the year ended December 31, 2012, $107.6 million related to price-related impairment charges on proved properties and $25.4 million related to impairment on unproved properties. The impairment charges reflect the reduced value of certain fields resulting from lower gas, oil and NGL prices and impairments of unproven leasehold acquisition costs. Of the $133.0 million impairment charges during the year ended December 31, 2012, $104.7 million related to oil and gas properties in the Southern Region and $28.3 million related to oil and gas properties in the Northern Region.

During the year ended December 31, 2011, QEP recorded impairment charges of $218.2 million, of which $173.1 million related to properties in the Northern Region with the remaining $45.1 million related to properties in the Southern Region. Proved property impairments were $195.5 million and unproved property impairments were $22.7 million during the year ended December 31, 2011.

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 $2.0 million, $3.4 million and $3.0 million during the years ended December 31, 2013, 2012 and 2011, 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 10 - 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, 2013, goodwill was reduced to zero from $59.5 million in 2012 due to the recognition of impairment during 2013. Goodwill related to the Company's Uinta Basin reporting unit within QEP Energy. Goodwill is tested for impairment under a two-step quantitative test on an annual basis or when a triggering event occurs. Under the first step, the estimated fair value of the reporting unit is compared with its carrying value (including goodwill). QEP determines fair value of its reporting units in which goodwill is allocated using the income approach in which 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 oil, NGL and gas reserves, including both proved reserves and risk-adjusted unproved reserves, including probable and possible reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of capital costs. If the fair value of the reporting unit exceeds its carrying value, step two does not need to be performed. If the estimated fair value of the reporting unit is less than its carrying value, an indication of goodwill impairment exists for the reporting unit and the enterprise must perform step two of the impairment test (measurement). Under step two, an impairment loss is recognized for any excess of the carrying amount of the reporting unit’s goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation in acquisition accounting. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. Fair value of the reporting unit under the two-step assessment is determined using a discounted cash flow analysis.

During the performance of QEP's annual goodwill impairment test, QEP failed the first step of the goodwill impairment test as described above. This was due primarily to lower forecasted oil and NGL prices. QEP performed the second step test described above resulting in a full write down of the Uinta reporting unit's goodwill of $59.5 million as of December 31, 2013.

Derivative Instruments

Effective January 1, 2012, the Company elected to de-designate all of its gas, oil and NGL derivative contracts that were previously designated as cash flow hedges and the Company 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 years ended December 31, 2013 and 2012, an unrealized gain of $88.7 million and an unrealized loss of $63.2 million, respectively, were included in income that, prior to January 1, 2012, would have been deferred in Accumulated Other Comprehensive Income (AOCI) under hedge accounting (Refer to Note 7 - Derivative Contracts, for additional information). 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 were reclassified into earnings as the original hedged transactions occurred and affected earnings. QEP fully reclassified all unrealized gains in AOCI into earnings during 2012 and 2013.

All of QEP's derivative contracts are net settled in cash without delivery of product. These contracts also have a nominal quantity, 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 of the United States of America 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 35%, 37%, and 32% of QEP's revenues for the years ended December 31, 2013, 2012 and 2011, respectively. During the year ended December 31, 2013, Freepoint Commodities, LLC made up 12% of the Company's total revenues. 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. During the year ended December 31, 2011, no customer had sales accounting for 10% or more of QEP's total revenues. All of the these customers represent QEP Energy's customers and management believes that the loss of any of these customers, 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.

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 end of the twelve-month periods ended December 31, 2013, 2012 and 2011. The federal income tax returns for 2012 and 2011 are currently under examination by the Internal Revenue Service. Income tax returns for 2013 have not yet been filed. Most state tax returns for 2010 and subsequent years remain subject to examination.

Treasury Stock

We record treasury stock purchases at cost, 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 11 - Equity-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 equity-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company's unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:



	December 31,
	2013	2012	2011
	(in millions)
Weighted-average basic common shares outstanding	179.2	177.8	176.5
Potential number of shares issuable under the Long-Term Stock Incentive Plan	0.3	0.9	1.9
Average diluted common shares outstanding	179.5	178.7	178.4

Equity-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 equity-based compensation costs with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term 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. The Company also awards performance share units under its Cash Incentive Plan (CIP) that are paid out in cash depending 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. Additionally, QEP Midstream maintains an equity-based compensation plan for officers, directors and employees of the general partner of QEP Midstream and its affiliates. For a summary of LTSIP and CIP transactions see Note 11 - Equity-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 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 for which the Company previously applied hedge accounting. Income or loss associated with such commodity-based derivative instruments was realized when the gas, oil or NGL underlying the derivative instrument was sold. Comprehensive income also includes changes in the under-funded portion of the Company's defined benefit pension plans and other postretirement benefits plans and changes in deferred income taxes on such amounts. These transactions do not represent 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.

Noncontrolling Interests

Noncontrolling interest represent third-party ownership in the net assets of the Company's consolidated subsidiaries and are presented as a component of equity and net income. Changes in QEP's ownership interest in subsidiaries that do not result in deconsolidation are recognized in equity. On August 14, 2013, QEP completed the initial public offering of QEP Midstream. Prior to the IPO QEP's noncontrolling interest related to the outside ownership of Rendezvous Gas Services, L.L.C. Subsequent to the IPO, QEP Midstream's results (which include Rendezvous Gas Services, L.L.C) are consolidated into QEP as it is a majority-owned and controlled subsidiary and the portion not owned by QEP reflected as noncontrolling interest. See Note 3 - QEP Midstream for further information regarding the IPO.

Recent Accounting Developments

In February of 2013, the FASB issued ASU 2013-02, Other Comprehensive Income (Topic 220: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income), which seeks to improve the reporting of entities by requiring an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under GAAP to be reclassified in its entirety to net income. For other amounts that are not required under GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under GAAP that provide additional detail about those amounts. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2012. The Company adopted this standard in the first quarter of 2013 and noted that it did not have a significant impact on the Company's consolidated financial statements.

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. Additionally, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies the implementation of ASU 2011-01. The amendments are required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. The Company adopted this standard effective January 1, 2013. It did not have a significant impact on the Company's consolidated financial statements.

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 to performing the quantitative impairment test, while retaining the ability to 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 Company adopted this standard January 1, 2013, which allows the Company to more efficiently complete the annual goodwill impairment test but has not had 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 and Divestitures

12 Months Ended

Dec. 31, 2013

Acquisitions [Abstract]

Acquisitions and divestitures [Text Block]

On September 27, 2012, QEP Energy completed an acquisition of oil and gas properties in the Williston Basin for an aggregate purchase price of $1.4 billion (the 2012 Acquisition). The properties are located in Williams and McKenzie counties of North Dakota, approximately 12 miles west of QEP's then-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 $300.0 million and $63.7 million and net income of $67.0 million and $14.9 million were generated from the acquired properties during the years ended December 31, 2013 and 2012, respectively, and are included in QEP's Consolidated Statements of Operations. 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. The following table presents a summary of the purchase accounting entries:



	As of December, 2013
Consideration given:	(in millions)
Cash consideration	$	1,392.7

Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	713.8
Unproved properties	683.4
Asset retirement obligations	(0.9		)
Liabilities assumed	(4.4		)
Other assets acquired	0.8
Total fair value	$	1,392.7

The following unaudited, pro forma results of operations are provided for the years ended December 31, 2012 and 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 acquired properties for the periods presented or that may be achieved by such 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 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

Divestitures

In June 2013, QEP Energy sold its interests in several non-core oil and gas properties located in QEP's Northern Region for total cash proceeds of $138.5 million and recorded a pre-tax gain on sale of $96.2 million. In September 2013, QEP Energy sold its interests in several non-core properties located in QEP's Southern Region for total cash proceeds of $67.3 million and recorded a pre-tax gain on sale of $9.5 million. Both the cash proceeds and gains on sales are subject to post-closing adjustments. During the year ended December 31, 2013, QEP Energy recorded these gains on its Consolidated Statements of Operations in "Net gain from asset sales".

QEP Midstream

12 Months Ended

Dec. 31, 2013

QEP Midstream [Abstract]

Noncontrolling Interest Disclosure [Text Block]

Note 3 - QEP Midstream

QEP Midstream is a publicly traded master limited partnership that was formed by QEP to own, operate, acquire and develop midstream energy assets. QEP Midstream's assets currently consist of ownership interests in four gathering systems and two FERC regulated pipelines, which provide oil and gas gathering and transportation services. These assets are located in, or within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota.

Initial Public Offering

On August 14, 2013, QEP Midstream completed its initial public offering (the IPO) of 20,000,000 common units, representing limited partner interests in QEP Midstream, at a price to the public of $21.00 per common unit. QEP Midstream received net proceeds of $390.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of approximately $29.3 million. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit, providing additional net proceeds of $58.9 million, after deducting $4.1 million of underwriters' discounts and commissions and structuring fees, to QEP Midstream.

QEP Midstream used the net proceeds to repay its outstanding debt balance with QEP, which was assumed with the assets contributed to QEP Midstream, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to QEP Midstream. The following table is a reconciliation of proceeds from the IPO (in millions):



Total proceeds from the IPO	$	483.0
IPO costs	(33.4		)
Net proceeds from the IPO	449.6
QEPM revolving credit facility origination fees	(3.0		)
QEPM repayment of outstanding debt with QEP	(95.5		)
Net proceeds distributed to QEP from the Offering	$	351.1

QEP Midstream Partners GP, LLC (the General Partner), a wholly owned subsidiary of QEP, serves as the general partner of QEP Midstream. QEP owns a 57.8% interest in QEP Midstream and consolidates QEP Midstream for financial reporting purposes with the portion not owned by QEP reflected as a reduction to net income and equity as a noncontrolling interest.

The following agreements were entered into between QEP and QEP Midstream in connection with the IPO.

Contribution, Conveyance and Assumption Agreement

On August 14, 2013, in connection with the closing of the IPO, QEP entered into a Contribution, Conveyance and Assumption Agreement (the Contribution Agreement) with QEP Field Services, the General Partner and QEP Midstream Partners Operating, LLC (the Operating Company). Immediately prior to the closing of the IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:


•	QEP Field Services contributed to the General Partner, as a capital contribution, a limited liability company interest in the Operating Company with a value equal to 2.0% of the equity value of QEP Midstream at the closing of the IPO;


•	the General Partner contributed to QEP Midstream, as a capital contribution, the limited liability company interest in the Operating Company in exchange for (a) 1,090,000 general partner units representing the continuation of an aggregate 2.0% general partner interest in QEP Midstream and (b) all the incentive distribution rights of QEP Midstream;

•

QEP Field Services contributed to QEP Midstream, as a capital contribution, its remaining limited liability company interests in the Operating Company in exchange for (a) 6,701,750 common units representing a 12.3% limited partner interest in QEP Midstream, (b) 26,705,000 subordinated units representing a 49.0% limited partner interest in QEP Midstream and (c) the right to receive a distribution from QEP Midstream; and


•	the public, through the underwriters, contributed $420.0 million in cash (or $390.7 million, net of the underwriters' discounts and commissions, structuring fees and offering expenses of approximately $29.3 million) to QEP Midstream in exchange for the issuance of 20,000,000 common units.

Subsequent to the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units in QEP Midstream, which reduced QEP's limited partner common unit interest in QEP Midstream from 12.3% to 6.8% and QEP's total ownership interest from 63.3% to 57.8%.

Omnibus Agreement

In connection with the IPO, QEP entered into an Omnibus Agreement (the Omnibus Agreement) with QEP Midstream on August 14, 2013, that addresses the following matters:

•

QEP Midstream's payment of an annual amount to QEP, initially in the amount of approximately $13.8 million, for the provision of certain general and administrative services by QEP and its affiliates to QEP Midstream, including a fixed annual fee of approximately $1.4 million for providing certain executive management services by certain officers of the General Partner. The remaining portion of this annual amount reflects an estimate of the costs that QEP and its affiliates expect to incur in providing the services;

•

QEP Midstream's obligation to reimburse QEP for any out-of-pocket costs and expenses incurred by QEP in providing general and administrative services (which reimbursement is in addition to certain expenses of the General Partner and its affiliates that are reimbursed under QEP Midstream's partnership agreement), as well as any other out-of-pocket expenses incurred by QEP on QEP Midstream's behalf; and


•	an indemnity by QEP for certain environmental and other liabilities, and QEP Midstream's obligation to indemnify QEP and its subsidiaries for events and conditions associated with the operation of QEP Midstream's assets that occur after the closing of the IPO.

As long as QEP controls the General Partner, the Omnibus Agreement will remain in full force and effect. If QEP ceases to control the General Partner, either party may terminate the Omnibus Agreement, but the indemnification obligations will remain in full force and effect in accordance with their terms.

- Definition

The entire disclosure for noncontrolling interest in consolidated subsidiaries, which could include the name of the subsidiary, the ownership percentage held by the parent, the ownership percentage held by the noncontrolling owners, the amount of the noncontrolling interest, the location of this amount on the balance sheet (when not reported separately), an explanation of the increase or decrease in the amount of the noncontrolling interest, the noncontrolling interest share of the net Income or Loss of the subsidiary, the location of this amount on the income statement (when not reported separately), the nature of the noncontrolling interest such as background information and terms, the amount of the noncontrolling interest represented by preferred stock, a description of the preferred stock, and the dividend requirements of the preferred stock.

+ References+ Details

Capitalized Exploratory Well Costs

12 Months Ended

Dec. 31, 2013

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 balances at December 31, 2013, 2012 and 2011, represent the amount of capitalized exploratory well costs that are pending the determination of proved reserves.



	2013			2012			2011
	(in millions)
Balance at January 1,	$	2.1		$	5.0		$	13.6
Additions to capitalized exploratory well costs pending the determination of proved reserves	2.7			12.7			—
Reclassifications to proved properties after the determination of proved reserves	(2.2		)	(15.6		)	(8.3		)
Capitalized exploratory well costs charged to expense	—			—			(0.3		)
Balance at December 31,	$	2.6		$	2.1		$	5.0

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

QEP records asset retirement obligations 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 oil and gas wells, production facilities, midstream assets, 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 estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $193.6 million and $193.1 million ARO liability for both the years ended December 31, 2013 and 2012, $1.8 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 Company's ARO for the periods specified below:



	Asset Retirement Obligations
	2013			2012
	(in millions)
ARO liability at January 1,	$	193.1		$	163.9
Accretion	8.9			10.5
Liabilities incurred	11.0			8.5
Revisions	(4.4		)	11.1
Liabilities related to assets sold	(11.4		)	—
Liabilities settled	(3.6		)	(0.9		)
ARO liability at December 31,	$	193.6		$	193.1

- 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, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

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

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (see Note 7 - Derivative Contracts) is based on market prices posted on the respective commodity exchange 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.

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 financial instruments. 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, 2013 and 2012, is shown in the tables below:



	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
			(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.5	$	—	$	(5.3	)	$	0.2
Commodity derivative instruments - long-term	—		0.4		—		—			0.4
Interest rate swaps - long-term	—		0.6		—		—			0.6
Total financial assets	$	—	$	6.5	$	—	$	(5.3	)	$	1.2

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	29.4	$	—	$	(5.3	)	$	24.1
Interest rate swaps - short-term	—		2.6		—		—			2.6
Total financial liabilities	$	—	$	32.0	$	—	$	(5.3	)	$	26.7

____________________________


⁽¹⁾	The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets as the contracts contain netting provisions. Refer to Note 7 - Derivative Contracts, for additional information regarding the Company's derivative contracts.



	Fair Value Measurements
	December 31, 2012
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
			(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

____________________________


⁽¹⁾	The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Condensed Consolidated Balance Sheet as the contracts contain netting provisions. Refer to Note 7 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

Fair values related to the Company's 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.

During the year ended December 31, 2013, there were no derivative instruments assets or liabilities classified as Level 3. The change in the fair value of Level 3 assets and liabilities for the year ended December 31, 2012 is shown below.



	Year Ended December 31,
	2012
	(in millions)
Balance at January 1,	$	—
Realized gains and losses	0.6
Unrealized gains and losses	3.8
Settlements	(0.6		)
Transfers out of Level 3	(3.8		)
Balance at 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, 2013				December 31, 2012
	(in millions)
Financial assets
Cash and cash equivalents	$	11.9	$	11.9	$	—	$	—
Financial liabilities
Checks outstanding in excess of cash balances	$	90.9	$	90.9	$	39.7	$	39.7
Long-term debt	$	2,997.5	$	3,034.9	$	3,206.9	$	3,420.7

The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. 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 cost estimates and reserve lives. A reconciliation of the Company's asset retirement obligations is presented in Note 5 - Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring, non-financial measurements. The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties and its 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, 2013 and 2012, 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, 2013 and 2012, the Company recorded $1.2 million and $107.6 million, respectively, of impairments related to certain of its proved properties. The proved properties were written down to their estimated fair values of zero and $71.9 million at the time of the impairments during December 31, 2013 and 2012, 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 estimate 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 oil, 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 - Acquisitions and Divestitures 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.

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+ Details

Derivative Contracts

12 Months Ended

Dec. 31, 2013

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 price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, 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 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 to realize a known price for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of gas, oil, or NGL between the parties at settlement. Swap 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. 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. QEP also has oil price derivative swaps that use Intercontinental Exchange, Inc. (ICE), Brent oil prices as the reference price. NGL price derivative instruments are typically structured as Mont Belvieu, Texas fixed-price swaps.

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

Effective January 1, 2012, QEP elected to de-designate all of its gas, 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 reclassified into the Consolidated Statement of Operations as the transactions settled and affected earnings. During the year ended December 31, 2013, the remaining portion of unrealized gains fixed in AOCI of $77.6 million, net of tax, were settled and reclassified to the Consolidated Statements of Operations. All realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012, are presented in the Consolidated Statements 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 of 1.07% in exchange for a variable interest rate indexed to the one-month LIBOR rate. The interest rate swaps settle monthly and will mature in March of 2017.

QEP Energy's Derivative Contracts

The following table sets forth QEP Energy's quantities and average prices for its commodity derivative contracts as of December 31, 2013:



				Swaps
Year	Type of Contract	Index	Total Volumes	Average price per unit
			(in millions)
Gas sales			(MMBtu)
2014	Swap	IFNPCR	58.4	$	3.98
2014	Swap	NYMEX	25.6	$	4.19
2015	Swap	NYMEX	3.7	$	4.16
Oil sales			(Bbls)
2014	Swap	NYMEX WTI	12.1	$	93.68
2015	Swap	NYMEX WTI	0.7	$	88.60

The following table sets forth QEP Energy's oil basis swaps as of December 31, 2013:



Year	Index	Index Less Differential	Bbls Per Day	Weighted Average Differential
Oil basis swaps
2014	NYMEX WTI	ICE Brent	2,000.0	$	13.78

QEP Marketing Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage and for marketing transactions in which QEP Marketing sells 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, 2013:



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	Swap	IFNPCR	4.7	$	3.77
Gas purchases			(MMBtu)
2014	Swap	IFNPCR	1.0	$	3.78

QEP's Derivative Contracts

The following table sets forth QEP's notional amounts and interest rates for its interest rate swaps outstanding as of December 31, 2013:



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	2013		2012		2013		2012
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	5.5	$	189.7	$	29.4	$	1.0
Interest rate swaps	Fair value of derivative contracts	—		—		2.6		2.6
Long-term:
Commodity	Fair value of derivative contracts	0.4		4.2		—		0.1
Interest rate swaps	Fair value of derivative contracts	0.6		—		—		3.6
Total derivative instruments		$	6.5	$	193.9	$	32.0	$	7.3

The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and Unrealized gains on derivatives" on the Consolidated Statements of Operations are summarized in the following tables:



Derivative instruments not designated as cash flow hedges	Year Ended December 31,
Derivative instruments not designated as cash flow hedges	2013			2012			2011
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	152.0		$	341.9		$	(117.7	)
Oil derivative contracts	(2.2		)	14.4			—
NGL derivative contracts	—			10.2			—
QEP Field Services
NGL derivative contracts	—			8.4			—
QEP Marketing
Gas derivative contracts	0.5			5.1			—
Total realized gains (losses) on commodity derivative contracts	150.3			380.0			(117.7		)
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	(42.6		)	37.8			117.7
Oil derivative contracts	(48.1		)	29.0			—
NGL derivative contracts	—			1.6			—
QEP Field Services
NGL derivative contracts	—			—			—
QEP Marketing
Gas derivative contracts	(2.1		)	0.9			—
Total unrealized (losses) gains on commodity derivative contracts	(92.8		)	69.3			117.7
Total realized and unrealized gains on commodity derivative contracts	$	57.5		$	449.3		$	—
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(2.7	)	$	(1.3	)	$	—
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	4.1			(6.1		)	—
Total realized and unrealized gains (losses) on interest rate swaps	$	1.4		$	(7.4	)	$	—
Total net realized gains (losses) on derivative contracts	$	147.6		$	378.7		$	(117.7	)
Total net unrealized (losses) gains on derivative contracts	$	(88.7	)	$	63.2		$	117.7
Grand Total	$	58.9		$	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:



Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	Year Ended December 31,
Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	2013		2012		2011
Commodity derivatives
Gain on derivative instruments for the effective portion of hedge recognized in AOCI	Accumulated other comprehensive income	$	—	$	—	$	350.8
Gain reclassified from AOCI into income for effective portion of hedge	Gas sales	—		—		305.5
Gain reclassified from AOCI into income for effective portion of hedge	Oil sales	—		—		1.6
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
Gain recognized in income for the ineffective portion of hedges	Interest and other income	—		—		0.1

- 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, 2013

Restructuring Costs [Abstract]

Restructuring Costs

During the first quarter of 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 the consolidation of corporate and accounting functions was intended to increase efficiency, team-based collaboration and organizational productivity over the long term. As part of the reorganization, QEP incurred 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. All remaining restructuring costs related to the office consolidations were incurred during 2013.

In December 2013, QEP announced its plan to pursue a separation of its midstream business, QEP Field Services. In connection with this announcement, the Board of Directors approved an employee retention plan to provide substantially all QEP Field Services' employees as of December 1, 2013, with a one-time lump sum cash payment on December 31, 2014, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated without cause prior to such date.

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



	Total Restructuring Costs
	Total Expected to be Incurred		Recognized in Income
			Period from Inception to December 31, 2013		Year ended December 31,
			Period from Inception to December 31, 2013		2013		2012
QEP Energy	(in millions)
One-time termination benefits	$	3.3	$	3.3	$	0.4	$	2.9
Retention & relocation expense	3.7		3.7		0.4		3.3
Lease termination costs	0.6		0.6		—		0.6
Total restructuring costs	$	7.6	$	7.6	$	0.8	$	6.8

QEP Field Services
One-time termination benefits	$	—	$	—	$	—	$	—
Retention & relocation expense	10.2		0.9		0.9		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	10.2	$	0.9	$	0.9	$	—

QEP Marketing
One-time termination benefits	$	0.3	$	0.3	$	0.1	$	0.2
Retention & relocation expense	—		—		—		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	0.3	$	0.3	$	0.1	$	0.2

Total QEP
One-time termination benefits	$	3.6	$	3.6	$	0.5	$	3.1
Retention & relocation expense	13.9		4.6		1.3		3.3
Lease termination costs	0.6		0.6		—		0.6
Total restructuring costs	$	18.1	$	8.8	$	1.8	$	7.0

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, 2012	$	1.0		$	—		$	—		$	1.0
Costs incurred and charged to expense	0.8			0.9			0.1			1.8
Costs paid or otherwise settled	(1.8		)	(0.1		)	(0.1		)	(2.0		)
Balance at December 31, 2013	$	—		0.8			—			$	0.8

- 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, 2013

Debt Disclosure [Abstract]

Debt

As of the indicated dates, the principal amount of QEP’s debt, including amounts outstanding under its and QEP Midstream's revolving credit facilities, QEP's term loan and QEP's senior notes consisted of the following:



	December 31,
	2013			2012
	(in millions)
QEP's revolving credit facility due 2016	$	480.0		$	690.0
QEP Midstream's revolving credit facility due 2018	—			—
Term loan due 2017	300.0			300.0
6.05% Senior Notes due 2016	176.8			176.8
6.80% Senior Notes due 2018	134.0			134.0
6.80% Senior Notes due 2020	136.0			136.0
6.875% Senior Notes due 2021	625.0			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
Total principal amount of debt	3,001.8			3,211.8
Less unamortized discount	(4.3		)	(4.9		)
Total long-term debt outstanding	$	2,997.5		$	3,206.9

Of the total debt outstanding on December 31, 2013, the revolving credit facility due August 25, 2016, QEP's Midstream's revolving credit facility due August 14, 2018, the term loan due April 18, 2017, the 6.05% Senior Notes due September 1, 2016, and the 6.80% Senior notes due April 1, 2018 will mature within the next five years.

Credit Facilities

QEP's Credit Facility

QEP's revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit facility 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, 2013 and 2012, QEP's weighted-average interest rate on borrowings from its credit facility was 2.22% and 2.08%, respectively. At December 31, 2013 and 2012, QEP was in compliance with the covenants under the credit agreement. At December 31, 2013, there was $480.0 million outstanding and QEP had $3.8 million in letters of credit outstanding under the credit facility. 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.

QEP Midstream's Credit Facility

On August 14, 2013, QEP Midstream entered into a $500.0 million senior secured revolving credit facility with a group of financial institutions, which matures on August 14, 2018. QEP Midstream's credit facility contains an accordion provision that allows for the amount of the facility to be increased to $750.0 million with the agreement of the lenders. QEP Midstream's credit facility is available for QEP Midstream's working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of QEP Midstream's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries, are pledged as collateral under the credit facility. In addition, the credit facility contains restrictions and events of default customary for agreements of this nature.

There have been no borrowings under QEP Midstream's credit facility, and at December 31, 2013, QEP Midstream was in compliance with the covenants under the QEP Midstream credit facility agreement.

QEP is not a borrower or guarantor of QEP Midstream's credit facility. In addition, QEP is not subject to any of the restrictions or covenants contained in QEP Midstream's credit agreement. Outstanding indebtedness under QEP Midstream's credit facility is not included in the definition of indebtedness under QEP's credit facility.

Term Loan

QEP's $300.0 million term loan facility provides for borrowings at short-term interest rates and contains covenants, restrictions and interest rates that are substantially the same as QEP’s revolving credit facility. The term loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. During the years ended December 31, 2013 and 2012, QEP's weighted-average interest rate on borrowings from the term loan was 2.22% and 2.05%, respectively. At December 31, 2013 and December 31, 2012, QEP was in compliance with the covenants under the term loan credit agreement.

Senior Notes

At December 31, 2013, 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

Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

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 matter. QEP's litigation loss contingencies are discussed below. QEP is unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. QEP believes, however, that the resolution of pending proceedings will not have a material effect on QEP's consolidated financial position, results of operations or cash flows.

Environmental Claims

In October 2009, QEP 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. Region 6 of the U.S. Environmental Protection Agency (EPA) 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. On June 28, 2013, the EPA issued to QEP an Administrative Complaint for the alleged violations. QEP and the EPA reached an agreement to settle the alleged violations through an Administrative Order, under the terms of which QEP paid an administrative penalty of $0.2 million. The Administrative Order is final. In 2012, QEP 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. QEP has disclosed each of these instances to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. QEP 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 QEP to pay a monetary penalty.

In July 2010, QEP received a Notice of Potential Penalty (NOPP) from the Louisiana Department of Environmental Quality (LDEQ) regarding the assumption of ownership and operatorship of a single facility in Louisiana prior to transferring the facility's air quality permit. In 2011, QEP completed an internal audit, which identified 424 facilities in Louisiana for which QEP both failed to submit a complete permit application and to receive approval from the LDEQ prior to construction, modification, or operation. QEP has corrected and disclosed all instances of non-compliance to the LDEQ and is working with the LDEQ to resolve the NOPP. The LDEQ has assumed lead responsibility for enforcement of the NOPP and may require the Company to pay a monetary penalty.

Litigation

Chieftain Royalty Company v. QEP Energy Company, Case No CIV-11-0212-R, U. S. District Court for the Western District of Oklahoma. This statewide class action was filed in January 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 received a full release of all claims regarding the calculation, reporting and payment of royalties from the sale of 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. On May 31, 2013, the Court issued its order approving the settlement, which is now final.

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, and an accounting and declaratory judgment related to a 1993 gathering agreement (the 1993 Agreement) executed when the parties were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of QEP Field Services' systems provide gathering services to QGC charging an annual gathering rate which is based on cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of the IPO, the assets and agreement discussed above were assigned to QEP Midstream. QGC netted the disputed amount from its monthly payments of the gathering fees to QEP Field Services and has continued to net such amounts from its monthly payment to QEP Midstream. As of December 31, 2013, QEP Midstream has deferred revenue of $8.5 million related to the QGC disputed amount. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add QEP Midstream as a defendant in the litigation. QEP Midstream has been indemnified by QEP for costs, expenses and other losses incurred by QEP Midstream in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement (defined above in "Note 3 - QEP Midstream").

Rocky Mountain Resources, LLC v. QEP Energy Company, Wexpro Company, Ultra Resources, Inc. and Lance Oil & Gas Company, Inc., Civil No. 2011-7816, District Court of Sublette County, Wyoming. Rocky Mountain Resources, LLC (“Rocky Mountain”) filed its Complaint on March 30, 2011 seeking determination of the existence of a 4% overriding royalty interest in State of Wyoming oil and gas Lease No. 79-0645 covering Section 16, T32-N R-109-W, Sublette County, Wyoming. QEP and the other defendants are current lessees of Lease 79-0645. Rocky Mountain alleges that the Defendants have received benefits from Lease 79-0645 and have failed to pay Rocky Mountain monies associated with the claimed 4% overriding royalty interest since the issuance of the lease by the State of Wyoming in 1980. Rocky Mountain asserts claims for quiet title, declaratory judgment, breach of contract, breach of duty of good faith, conversion, constructive trust and prejudgment interest. Specific monetary damages are not asserted.

Gatti et al v. State of Louisiana et al, 589,350 (19th JDC, Parish of East Baton Rouge, Louisiana). In this putative class action arising out of the unitization practices and orders of the Louisiana Commissioner of Conservation ("Commissioner"), Plaintiffs seek to represent a class of all Haynesville Shale mineral owners (alleged to be over 50,000 in number) against the Commissioner and all Haynesville Shale unit operators. Plaintiffs filed their complaint on April 8, 2010, and claim that the Commissioner exceeded his statutory authority in creating and perpetuating units larger than the area that can be efficiently and economically drained by a single well. They seek declaratory relief that would nullify all such improper orders, along with an unspecified amount of monetary damages from the unit operators sufficient to compensate the putative class members for the alleged dilution of their true interest in unit production as a result of "oversized" units and the "cloud on title" caused by having excessive and improperly sized units purport to hold their mineral leases via unit operations. All defendants filed exceptions to the Plaintiffs' petition on the primary ground that Plaintiffs had failed to comply with the exclusive statutory judicial review procedure (Louisiana Revised Statutes 30:12), which the trial court granted, dismissing the action in its entirety. On January 15, 2014, the Louisiana First Circuit Court of Appeal reversed and reinstated Plaintiffs' claims. Defendants intend to seek review of the Louisiana Supreme Court, which review is discretionary.

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
2014	$	154.2
2015	$	103.7
2016	$	99.9
2017	$	99.2
2018	$	97.3
After 2018	$	290.5

QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $7.8 million, $7.3 million and $5.0 million during the years ended December 31, 2013, 2012 and 2011, 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
2014	$	7.2
2015	$	6.5
2016	$	6.6
2017	$	6.8
2018	$	5.3
After 2018	$	23.7

- Definition

The entire disclosure for commitments and contingencies.

+ References

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

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+ Details

Equity-Based Compensation

12 Months Ended

Dec. 31, 2013

Share-based Compensation [Abstract]

Share-Based Compensation

QEP issues stock options and restricted shares under its LTSIP and awards performance-based share units under its 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 equity-based compensation is included in additional paid-in capital in the Consolidated Balance Sheets. There were 12.0 million shares available for future grants under the LTSIP at December 31, 2013. Equity-based compensation expense is recognized in "General and administrative" on the Consolidated Statements of Operations. During the year ended December 31, 2013, QEP recognized $27.1 million in total compensation expense related to equity-based compensation compared to $25.6 million and $22.0 million during the years ended December 31, 2012 and 2011, respectively.

QEP Midstream maintains a unit-based compensation plan for officers, directors and employees of the general partner of QEP Midstream and its affiliates and any consultants, affiliates of the General Partner, or other individuals who perform services for QEP Midstream. The QEP Midstream 2013 Long-Term Incentive Plan (the QEP Midstream LTIP) permits various types of awards, including awards of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Awards granted during 2013 under the QEP Midstream LTIP will be settled with QEP Midstream units. During the year ended December 31, 2013, QEP's equity-based compensation expense included $0.5 million in equity-based compensation related to QEP Midstream's LTIP.

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option 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. To fulfill options exercised, QEP either reissues treasury stock or issues new shares.

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,
	2013			2012			2011
Weighted-average grant-date fair value of awards granted during the period	$	15.16		$	14.29		$	18.80
Risk-free interest rate range	0.97%-1.84%			0.63% - 1.04%			n/a
Weighted-average risk-free interest rate	1.0		%	0.8		%	2.1		%
Expected price volatility range	51.5%-58.5%			55.9% - 56.5%			n/a
Weighted-average expected price volatility	58.3		%	55.9		%	54.7		%
Expected dividend yield	0.27		%	0.26		%	0.21		%
Expected term in years at the date of grant	5.5			5.0			5.0

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, 2012	1,697,471		$	25.23
Granted	330,592		30.06
Exercised	(224,833	)	10.77
Forfeited	(9,043	)	30.41
Outstanding at December 31, 2013	1,794,187		$	27.90	3.67	$	6.5
Options Exercisable at December 31, 2013	1,288,844		$	26.63	2.90	$	6.4
Unvested Options at December 31, 2013	505,343		$	31.14	5.88	$	0.1

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $4.3 million, $9.6 million and $2.7 million during the years ended December 31, 2013, 2012 and 2011, respectively. The Company realized $1.4 million, $4.6 million, and $0.4 million of income tax benefits for the years ended December 31, 2013, 2012 and 2011. respectively, which increased its Additional Paid-in-Capital (APIC) pool by $6.5 million as of December 31, 2013. As of December 31, 2013, $2.9 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 1.95 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, 2013, QEP received $2.0 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, 2013, 2012 and 2011, was $19.8 million, $16.7 million and $11.7 million, respectively. The Company realized income tax expense of $0.1 million and $0.3 million for the years ended December 31, 2013 and 2012, respectively, and income tax benefit of $1.0 million during 2011. Restricted stock increased the Company's APIC pool by $0.8 million as of December 31, 2013. The weighted average grant-date fair value of restricted stock granted during the years was $30.06 per share, $30.54 per share and $38.50 per share for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, $17.4 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 1.99 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, 2012	1,300,588		$	31.78
Granted	862,669		30.06
Vested	(665,963	)	31.42
Forfeited	(108,341	)	30.77
Unvested balance at December 31, 2013	1,388,953		$	30.96

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 values of the performance share units granted during the years ended December 31, 2013, 2012 and 2011, were $30.12, $30.75, and $39.07 per unit, respectively. As of December 31, 2013, $6.4 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 1.83 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, 2012	283,484		$	33.91
Granted	223,844		30.12
Vested	—		—
Forfeited	(26,668	)	30.69
Unvested balance at December 31, 2013	480,660		$	32.33

- 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

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 718

-SubTopic 10

-Section 50

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5047-113901

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 718

-SubTopic 10

-Section 50

-Paragraph 2

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

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-Name Accounting Standards Codification

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-Paragraph 1

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 123R

-Paragraph 64, 65, A240

-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 718

-SubTopic 40

-Section 50

-Paragraph 1

-URI http://asc.fasb.org/extlink&oid=6418621&loc=d3e17540-113929

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 718

-SubTopic 10

-Section 50

-Paragraph 4

-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5444-113901

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

-Publisher SEC

-Name Staff Accounting Bulletin (SAB)

-Number Topic 14

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

-Publisher AICPA

-Name Statement of Position (SOP)

-Number 93-6

-Paragraph 53

-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

Employee Benefits

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Employee Benefits

Defined Benefit Pension Plans and Other Postretirement Benefits

The Company maintains a closed, defined-benefit pension plan providing coverage to 128, or 13%, of QEP's active employees and to 86 participants that are retired, or terminated and vested. 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. Of the 128 active, pension eligible employees, 90 are also eligible for the postretirement medical and life insurance plans when they retire. Currently, 29 retirees are enrolled in this plan. The Company has capped its exposure to increasing medical costs by paying a fixed dollar monthly contribution toward these retiree benefits. The Company's 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, 2013 and 2012, QEP's accumulated benefit obligation exceeded the fair value of its qualified retirement plan assets. At December 31, 2013 and 2012, QEP's nonqualified retirement plan was unfunded.

During the year ended December 31, 2012, the Company recognized a $2.2 million loss on curtailment as part of its restructuring 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 see Note 8 - Restructuring Costs. During the year ended December 31, 2013, the Company made contributions of $8.1 million to its funded qualified pension plan. Contributions to funded qualified plans increase plan assets. During the year ended December 31, 2013, the Company made payments of $3.4 million of benefits pursuant to its unfunded nonqualified retirement plan. Payments to the unfunded nonqualified plans are used to fund current benefit payments. During 2014, the Company expects to contribute approximately $8.1 million to its funded pension plan, pay approximately $5.5 million of benefits under its unfunded nonqualified pension plan and pay approximately $0.2 million for retiree health care and life insurance benefits. The accumulated postretirement benefit obligation for all defined-benefit pension plans was $101.0 million and $106.9 million at December 31, 2013 and 2012, 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, 2013 and 2012, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2013 and 2012:



	Pension benefits						Other postretirement benefits
	2013			2012			2013			2012
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$	129.7		$	104.1		$	6.7		$	5.9
Service cost	3.3			4.0			0.1			0.1
Interest cost	4.8			5.1			0.3			0.3
Change in plan assumptions	—			8.4			—			—
Benefit payments	(5.5		)	(2.7		)	(0.1		)	—
Actuarial loss (gain)	(14.3		)	10.8			(1.1		)	0.4
Benefit obligation at December 31,	$	118.0		$	129.7		$	5.9		$	6.7
Change in plan assets
Fair value of plan assets at January 1,	$	55.3		$	44.2		$	—		$	—
Actual gain on plan assets	10.4			6.9			—			—
Company contributions to the plan	11.5			6.9			0.1			—
Benefit payments	(5.5		)	(2.7		)	(0.1		)	—
Fair value of plan assets at December 31,	71.7			55.3			—			—
Underfunded status (current and long-term)	$	(46.3	)	$	(74.4	)	$	(5.9	)	$	(6.7	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(5.5	)	$	(3.2	)	$	(0.2	)	$	(0.2	)
Other long-term liabilities	(40.8		)	(71.2		)	(5.7		)	(6.5		)
Total amount recognized in balance sheet	$	(46.3	)	$	(74.4	)	$	(5.9	)	$	(6.7	)
Amounts recognized in AOCI
Net actuarial loss	$	9.5		$	32.6		$	0.2		$	1.3
Prior service cost	30.1			35.1			3.0			3.4
Total amount recognized in AOCI	$	39.6		$	67.7		$	3.2		$	4.7

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
	2013			2012			2011			2013			2012			2011

Components of net periodic benefit cost
Service cost	$	3.3		$	4.0		$	2.9		$	0.1		$	0.1		$	0.1
Interest cost	4.8			5.1			4.5			0.3			0.3			0.3
Expected return on plan assets	(3.9		)	(3.6		)	(2.6		)				—			—
Curtailment loss	—			2.2			—			—			—			—
Amortization of prior service costs	5.0			5.3			5.3			0.3			0.3			0.3
Amortization of actuarial loss	2.3			1.9			—			0.1			0.1			—
Periodic expense	$	11.5		$	14.9		$	10.1		$	0.8		$	0.8		$	0.7
Components recognized in accumulated other comprehensive income
Current period actuarial loss (gain)	$	(20.8	)	$	15.9		$	22.9		$	(1.0	)	$	0.4		$	1.0
Amortization of actuarial loss	(2.3		)	(1.9		)	—			(0.1		)	(0.1		)	—
Current period prior service cost	—			—									—			—
Amortization of prior service cost	(5.0		)	(5.3		)	(5.3		)	(0.4		)	(0.4		)	(0.3		)
Loss on curtailment in current period				(2.2		)	—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	(28.1	)	$	6.5		$	17.6		$	(1.5	)	$	(0.1	)	$	0.7

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 2014 is $5.0 million, which represents amortization of prior service cost recognition. The estimated portion to be recognized in net periodic cost for other postretirement benefits from AOCI in 2014 is $0.4 million, which represents amortization of prior service cost recognition. Amortization of prior service costs and actuarial losses/gains out of AOCI are recognized in the Consolidated Statements of Operations in "General and administrative."

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, 2013 and 2012:



	Pension benefits				Other postretirement benefits
	2013		2012		2013		2012
Discount rate	4.75	%	3.88	%	5.00	%	4.10	%
Rate of increase in compensation	4.00	%	3.60	%	4.00	%	3.60	%

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
	2013		2012		2011		2013		2012		2011
Discount rate	3.69	%	4.38	%	5.80	%	4.10	%	4.70	%	5.80	%
Expected long-term return on plan assets	6.75	%	7.25	%	7.50	%	n/a		n/a		n/a
Rate of increase in compensation	3.60	%	3.60	%	3.60	%	3.60	%	4.00	%	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 2014. Historical health 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 qualified 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 and significant to the fair value measurement. 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:



	December 31, 2013								Percentage of total
	Level 1		Level 2		Level 3		Total		Percentage of total
	(in millions except percentages)
Cash and short-term investments	$	—	$	—	$	0.3	$	0.3	—		%
Equity securities:
Domestic	—		—		29.3		29.3		41		%
International	—		—		21.3		21.3		30		%
Fixed income	—		—		20.8		20.8		29		%
Total investments	—		—		$	71.7	$	71.7	100		%
	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	—		—		16.6		16.6		30		%
Fixed income	—		—		16.2		16.2		30		%
Total investments	—		—		$	55.2	$	55.2	100		%

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



	Year ended December 31,
	2013			2012
	(in millions)
Balance at January 1,	$	55.2		44.2
Employer contributions	8.1			5.6
Unrealized gains (losses)	9.8			6.3
Realized gains	0.9			0.7
Administrative fees	(0.3		)	(0.2		)
Benefits paid	(2.1		)	(1.4		)
Balance at December 31,	$	71.6		$	55.2

Expected Benefit Payments

As of December 31, 2013, the following future benefit payments are expected to be paid:



	Pension		Postretirement benefits
	(in millions)
2014	$	8.1	$	0.2
2015	5.8		0.2
2016	6.1		0.3
2017	4.7		0.3
2018	5.8		0.3
2019 through 2021	40.0		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. For the year ended December 31, 2013, the Company made discretionary matching contributions equal to 100% of employees' contributions up to a maximum of 8% of their qualifying earnings. Employees in the closed QEP Resources, Inc. Retirement Plan (pension) are eligible for a 6% match. For the years ended December 31, 2012 and 2011, the Company made discretionary matching contributions equal to 100% of employees' contributions up to a maximum of 6% of their qualifying earnings. The Company may contribute a discretionary portion beyond the Company's discretionary matching contribution to employees not in the QEP Resources, Inc. Retirement Plan (pension), and for the years ended December 31, 2012 and 2011, the Company made such discretionary contributions equal to 2% of each eligible employee's compensation. The Company recognizes expense equal to its yearly contributions, which amounted to $6.9 million, $6.4 million and $5.8 million during the years ended December 31, 2013, 2012 and 2011, respectively.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 715

-URI http://asc.fasb.org/topic&trid=2235017

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

-Publisher FASB

-Name Implementation Guide (Q and A)

-Number FAS88

-Paragraph 63

-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 132R

-Paragraph 5, 6, 7, 8

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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Tax Disclosure [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,
	2013			2012			2011
	(in millions)
Federal income tax expense (benefit)
Current	$	47.9		$	33.7		$	(5.3	)
Deferred	69.1			36.5			153.0
State income tax expense (benefit)
Current	5.7			0.7			2.9
Deferred	(2.9		)	(4.4		)	3.8
Total income tax expense	$	119.8		$	66.5		$	154.4

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,
	2013		2012		2011
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	0.6	%	(1.2	)%	1.0	%
Penalties	0.2	%	(0.6	)%	—	%
Return to provision adjustment	(0.2	)%	0.4	%	1.3	%
Noncontrolling interest	(1.4	)%	(0.7	)%	(0.3	)%
Book impairment of goodwill	7.2	%	—	%	—	%
Other	(0.3	)%	0.6	%	(0.7	)%
Effective income tax rate	41.1	%	33.5	%	36.3	%

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



	December 31,
	2013		2012
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$	1,651.1	$	1,606.6
Commodity price and interest rate derivatives	—		69.4
Total deferred tax liabilities	1,651.1		1,676
Deferred tax assets
Commodity price and interest rate derivatives	9.7		—
Net operating loss and tax credit carryforwards	54.6		65.6
Employee benefits and compensation costs	36.1		47.7
Accrued litigation loss contingency	0.8		42.8
Bonus and vacation accrual	10.6		11.8
Other	9.3		9.6
Total deferred tax assets	121.1		177.5
Net deferred income tax liability	$	1,530.0	$	1,498.5
Balance sheet classification
Deferred income tax asset - current	$	30.6	$	—
Deferred income tax liability -current	—		$	5.0
Deferred income tax liability - non-current	1,560.6		1,493.5
Net deferred income tax liability	$	1,530.0	$	1,498.5

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2013 are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2014-2032	$	26.5
U.S. alternative minimum tax credit	Indefinite	28.1
Total		$	54.6

- 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

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 740

-SubTopic 10

-Section 50

-Paragraph 15

-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32718-109319

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 235

-SubTopic 10

-Section S99

-Paragraph 1

-Subparagraph (SX 210.4-08.(h))

-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

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

-Publisher SEC

-Name Regulation S-X (SX)

-Number 210

-Section 08

-Paragraph h

-Article 4

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

-Publisher FASB

-Name Accounting Standards Codification

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-Name Accounting Standards Codification

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-Name Accounting Standards Codification

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-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 109

-Paragraph 136, 172

-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 109

-Paragraph 43, 44, 45, 46, 47, 48, 49

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+ Details

Operations by Line of Business

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Operations by Line of Business

QEP’s lines of business include oil and gas exploration and production (QEP Energy), midstream field services (QEP Field Services), which includes the ownership and operation of QEP Midstream, and marketing and corporate (QEP Marketing & Resources). 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. QEP owns a 57.8% ownership interest in QEP Midstream and it is consolidated under the voting interest model in QEP Field Services' operating results. The outside ownership interest in QEP Midstream is presented separately as a noncontrolling interest.

The following table is a summary of operating results for the year ended December 31, 2013, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	2,092.8		$	282.4		$	560.6		$	—		$	2,935.8
From affiliated customers	—			121.0			1,012.6			(1,133.6		)	—
Total Revenues	2,092.8			403.4			1,573.2			(1,133.6		)	2,935.8
Operating expenses
Purchased gas, oil and NGL expense	197.1			8.9			1,570.5			(1,010.6		)	765.9
Lease operating expense	181.3			—			—			(3.5		)	177.8
Gas, oil and NGL transportation and other handling costs	242.2			13.9			—			(114.7		)	141.4
Gathering, processing and other	—			88.9			1.7			—			90.6
General and administrative	139.7			51.6			4.6			(4.8		)	191.1
Production and property taxes	159.8			6.6			0.1			—			166.5
Depreciation, depletion and amortization	954.2			60.9			0.9			—			1,016.0
Impairment and exploration expenses	104.9			—			—			—			104.9
Total operating expenses	1,979.2			230.8			1,577.8			(1,133.6		)	2,654.2
Net gain (loss) from asset sales	104.1			(0.5		)	(0.6		)	—			103.0
Operating income ⁽¹⁾	217.7			172.1			(5.2		)	—			384.6
Realized and unrealized gains (losses) on derivative contracts	59.1			—			(0.2		)	—			58.9
Interest and other income	3.6			1.2			206.9			(206.5		)	5.2
Income from unconsolidated affiliates	0.2			5.6			—			—			5.8
Loss on early extinguishment of debt	—			—			—			—			—
Interest expense	(192.6		)	(13.1		)	(164.1		)	206.5			(163.3		)
Income before income taxes	88.0			165.8			37.4			—			291.2
Income tax	(49.1		)	(55.4		)	(15.3		)	—			(119.8		)
Net income	38.9			110.4			22.1			—			171.4
Net income attributable to noncontrolling interest	—			(12.0		)	—						(12.0		)
Net income attributable to QEP ⁽²⁾	$	38.9		$	98.4		$	22.1		$	—		$	159.4
Identifiable total assets	$	7,930.6		$	1,455.1		$	250.7		$	(259.6	)	$	9,376.8
Investment in unconsolidated affiliates				39.0			—			—			39.0
Cash capital expenditures	1,488.6			89.8			24.2			—			1,602.6
Accrued capital expenditures	1,467.2			86.0			24.2			—			1,577.4

____________________________


⁽¹⁾	The impact of QEP's settled derivative contracts, for the year ended December 31, 2013, is reflected below operating income.


⁽²⁾	Net income attributable to QEP for the year ended December 31, 2013, 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, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Resources			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
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	236.3			34.4			2.0			(6.1		)	266.6
Production and property taxes	97.2			6.0			0.2			—			103.4
Depreciation, depletion and amortization	838.4			63.2			3.7			—			905.3
Impairment and exploration expenses	144.2			—			—			—			144.2
Total operating expenses	1,944.7			236.1			1,028.2			(724.7		)	2,484.3
Net gain from asset sales	1.2			—			—			—			1.2
Operating (loss) income	(328.1		)	203.1			(8.3		)	—			(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 extinguishment of debt	—			—			(0.6		)	—			(0.6		)
Interest expense	(116.8		)	(13.6		)	(124.4		)	131.9			(122.9		)
(Loss) income before income taxes	(3.7		)	204.8			(2.6		)	—			198.5
Income taxes benefit (provision)	4.3			(71.8		)	1.0			—			(66.5		)
Net income (loss)	0.6			133.0			(1.6		)	—			132.0
Net income attributable to noncontrolling interest	—			(3.7		)	—			—			(3.7		)
Net income (loss) attributable to QEP	$	0.6		$	129.3		$	(1.6	)	$	—		$	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, was 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 & Resources			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
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	707.4			55.7			2.5			—			765.6
Impairment and exploration expenses	228.7			—			—			—			228.7
Total operating expenses	1,974.2			206.3			1,150.6			(676.4		)	2,654.7
Net gain 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	1,338.8			101.6			5.5			—			1,445.9
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 7 - Derivative Contracts, for detailed 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.

- 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

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 131

-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

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+ Details

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2013
Subsequent Events [Abstract]
Subsequent Events [Text Block]	In February 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $950.0 million, subject to customary purchase price adjustments (the Permian Basin Acquisition). The acquired properties consist of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 260 vertical producing wells in the Permian Basin, which creates a new core area of operation for QEP Energy. The Permian Basin Acquisition was funded with cash on hand, $300.0 million from the Company’s expanded Term Loan and approximately $600.0 million from its revolving credit facility. Based on the timing of the Permian Basin Acquisition, QEP has not completed its initial accounting for the Permian Basin Acquisition and thus full disclosures required under GAAP will not be included until the first quarter 2014. In February 2014, to fund a portion of the purchase price for the Permian Basin Acquisition, the Company increased the term loan from $300.0 million to $600.0 million. There were no changes to the maturity date, pricing or covenants in the term loan credit agreement.

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2013

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)
2013
Revenues	$	696.5		$	751.0	$	772.8	$	715.5		$	2,935.8
Operating income (loss)	64.8			207.3		128.2		(15.7		)	384.6
Income (loss) before income taxes	(5.9		)	284.6		63.5		(51.0		)	291.2
Net income (loss) attributable to QEP	(4.3		)	178.4		37.3		(52.0		)	159.4
Non-recurring operating income (loss) ⁽¹⁾	(0.2		)	100.2		9.0		(99.0		)	10.0
Per share information attributable to QEP
Basic EPS attributable to QEP	$	(0.02	)	$	0.99	$	0.21	$	(0.29	)	$	0.89
Diluted EPS attributable to QEP	(0.02		)	0.99		0.21		(0.29		)	0.89



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
Non-recurring operating income (loss) ⁽¹⁾	(5.0		)	(55.4		)	(9.0		)	(62.4		)	(131.8		)
Per share information attributable to QEP
Basic EPS from continuing operations	$	0.87		$	—		$	(0.02	)	$	(0.13	)	$	0.72
Basic EPS attributable to QEP	0.87			—			(0.02		)	(0.13		)	0.72

____________________________


⁽¹⁾	Includes net gains/losses from asset sales and losses due to impairments.

- 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, 2013

Supplemental Gas and Oil Information (Unaudited) [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

The Company is making the following supplemental disclosures of oil and gas 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 oil and gas exploration and development activities. All properties are located in the United States.

Capitalized Costs

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



	December 31,
	2013			2012
	(in millions)
Proved properties	$	11,571.4		$	10,234.3
Unproved properties, net	665.1			937.9
Total proved and unproved properties	12,236.5			11,172.2
Accumulated depreciation, depletion and amortization	(4,930.9		)	(4,258.1		)
Net capitalized costs	$	7,305.6		$	6,914.1

Costs Incurred

The costs incurred in oil and gas exploration and development activities are displayed in the table below. Development costs are net of the change in accrued capital costs for $21.4 million and ARO additions and revisions of $17.2 million during the year ended December 31, 2013. The costs incurred to advance the development of reserves that were classified as proved undeveloped were approximately $645.9 million in 2013, $513.0 million in 2012, and $533.6 million in 2011.



	Year Ended December 31,
	2013		2012		2011
	(in millions)
Property acquisitions
Unproved	$	9.3	$	692.6	$	48.0
Proved	31.6		714.4		0.1
Total property acquisitions	40.9		1,407.0		48.1
Exploration (capitalized and expensed)	14.6		14.3		36.5
Development	1,440.8		1,310.0		1,267.8
Total costs incurred	$	1,496.3	$	2,731.3	$	1,352.4

Results of Operations

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



	Year Ended December 31,
	2013			2012			2011
	(in millions)
Revenues ⁽¹⁾	$	1,901.2		$	1,393.4		$	1,703.4
Production costs	583.3			501.1			433.3
Exploration expenses	11.9			11.2			10.5
Depreciation, depletion and amortization	954.2			838.4			707.4
Impairment	93.0			133.0			218.2
Total expenses	1,642.4			1,483.7			1,369.4
Income (loss) before income taxes	258.8			(90.3		)	334.0
Income tax benefit (expense)	(96.3		)	33.6			(119.0		)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	162.5		$	(56.7	)	$	215.0

___________________________


⁽¹⁾	Revenue for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts which during the years ended December 31, 2013 and 2012, are reflected below operating income (loss) on the Consolidated Statements of Operations. See Note 7 - Derivative Contracts.

Estimated Quantities of Proved Oil and Gas Reserves

Estimates of proved oil and gas 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, 2013, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves, except for 120 Bcfe located within the northern portion of the Company's Pinedale Anticline leasehold in western Wyoming. Long-term development of 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, 2013, 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, 2011, 2012 and 2013 are as follows:



	Gas		Oil		NGL		Total
	(Bcf)		(MMbbl)		(MMbbl)		(Bcfe)
Balance at December 31, 2010	2,612.9		52.3		17.4		3,030.7
Revisions of previous estimates⁽⁶⁾	(270.1	)	1.7		39.3		(23.5	)
Extensions and discoveries ⁽⁷⁾	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 ⁽³⁾	(240.6	)	(1.5	)	0.7		(244.8	)
Extensions and discoveries ⁽⁴⁾	330.6		17.3		23.0		572.5
Purchase of reserves in place ⁽⁵⁾	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
Revisions of previous estimates ⁽¹⁾	(288.3	)	1.3		(8.0	)	(328.5	)
Extensions and discoveries ⁽²⁾	455.6		38.3		16.4		783.8
Purchase of reserves in place	1.0		1.9		0.2		13.4
Sale of reserves in place	(16.9	)	(1.7	)	(1.1	)	(33.9	)
Production	(218.9	)	(10.2	)	(4.8	)	(309.0	)
Balance at December 31, 2013	2,554.9		148.6		102.6		4,061.9
Proved developed reserves
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
Balance at December 31, 2013	1,406.3		71.8		52.8		2,154.0
Proved undeveloped reserves
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
Balance at December 31, 2013	1,148.6		76.8		49.8		1,907.9

____________________________

⁽¹⁾

Revisions of previous estimates in 2013 include positive impacts due to 80.0 Bcfe pricing revisions, negative performance revisions of 265.5 Bcfe, 42.0 Bcfe negative operating cost revisions and 101.0 Bcfe other negative revisions. Pricing revisions were primarily due to increased gas prices which increased reserves by 68.4 Bcfe. Negative performance revisions were driven by a 129.5 Bcfe decrease in Pinedale reserves and 112.7 Bcfe decrease in Haynesville reserves related to reserve adjustments based on additional production history, well performance and current pricing causing a revised future development plan which includes lower density drilling in some areas and a change in well spacing assumptions in these areas.

⁽²⁾

Extensions and discoveries in 2013 increased proved reserves by 783.8 Bcfe, primarily related to extensions and discoveries in the Williston Basin of 217.6 Bcfe, in Pinedale of 265.3 Bcfe, and 175.9 Bcfe in Haynesville. Extension and discoveries in Pinedale and Haynesville relate to certain less densely spaced wells with higher estimates of recoverable oil and gas, which were booked to replace wells removed from the Company's reserves through negative revisions caused by a change in well spacing assumptions in these areas. Of these extensions and discoveries 687.6 Bcfe related to new PUD locations.

⁽³⁾

Revisions of previous estimates in 2012 include negative impacts due to 80.0 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 gas prices which reduced 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.

⁽⁴⁾

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.


⁽⁵⁾	Purchase of reserves in place primarily relate to the Company's $1.4 billion 2012 Acquisition as discussed in Note 2 - Acquisitions and Divestitures.

⁽⁶⁾

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 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 gas reserve related to shrink of about 59.6 Bcf. The remaining performance related reduction in the 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.

⁽⁷⁾

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, 2013, 2012 and 2011, by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for each of the 12 months during 2013, 2012 and 2011, 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,
	2013		2012		2011
Average benchmark price per unit:
Gas price (per MMbtu)	$	3.67	$	2.76	$	4.12
Oil price (per Bbl)	96.94		94.71		96.19

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 $852.6 million in 2014, $1,183.8 million in 2015 and $1,094.4 million in 2016.

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 likely differ from those required to be used in these calculations.


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


•	Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and gas 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,
	2013			2012			2011
	(in millions)
Future cash inflows	$	24,805.7		$	18,200.2		$	18,300.6
Future production costs	(8,400.3		)	(5,027.2		)	(4,276.1		)
Future development costs	(4,056.7		)	(3,927.3		)	(3,250.0		)
Future income tax expenses	(3,284.6		)	(2,269.0		)	(2,837.1		)
	9,064.1			6,976.7			7,937.4
10% annual discount for estimated timing of net cash flows	(4,680.2		)	(3,942.0		)	(4,411.8		)
Standardized measure of discounted future net cash flows	$	4,383.9		$	3,034.7		$	3,525.6

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,
	2013			2012			2011
	(in millions)
Balance at January 1,	$	3,034.7		$	3,525.6		$	2,705.6
Sales of gas, oil and NGL produced during the period, net of production costs	(1,317.9		)	(892.3		)	(1,779.9		)
Net change in sales prices and in production (lifting) costs related to future production	1,236.3			(2,083.5		)	1,472.5
Net change due to extensions, discoveries and improved recovery	2,230.7			948.5			1,806.4
Net change due to revisions of quantity estimates	(709.6		)	(387.8		)	(48.2		)
Changes due to purchases of reserves in place	36.8			831.4			0.1
Changes due to sales of reserves in place	(73.2		)	—			(8.0		)
Previously estimated development costs incurred during the period	722.7			513.0			533.6
Changes in estimated future development costs	(596.5		)	(209.3		)	(1,110.4		)
Accretion of discount	402.2			499.4			355.4
Net change in income taxes	(601.7		)	273.6			(411.4		)
Other	19.4			16.1			9.9
Net change	1,349.2			(490.9		)	820.0
Balance at December 31,	$	4,383.9		$	3,034.7		$	3,525.6

Schedule of Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2013

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, 2013
Allowance for bad debts	$	2.8	$	3.5	$	(1.2	)	$	5.1
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

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies [Abstract]

Consolidation, Policy [Policy Text Block]

Noncontrolling Interests

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 and Restricted Cash

Receivables, Policy [Policy Text Block]

Accounts Receivable Trade

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

Property, Plant and Equipment

Oil and gas properties

Capitalized costs of unproved properties are reclassified to 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

Inc

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]

Equity-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, 2013

Earnings Per Share [Abstract]

Cash Flow, Supplemental Disclosures [Text Block]

Supplemental cash flow information is shown in the below table:



	Year Ended December 31,
	2013			2012	2011
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	156.7		105.1	$	90.5
Cash paid (received) for income taxes	77.9			30.0	(28.5		)
Non-cash investing activities
Change in capital expenditure accrual balance	$	(25.2	)	88.5	$	14.7

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,
	2013	2012	2011
	(in millions)
Weighted-average basic common shares outstanding	179.2	177.8	176.5
Potential number of shares issuable under the Long-Term Stock Incentive Plan	0.3	0.9	1.9
Average diluted common shares outstanding	179.5	178.7	178.4

- 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 and Divestitures (Tables)

12 Months Ended

Dec. 31, 2013

Acquisitions [Abstract]

Schedule of Purchase Price Allocation [Table Text Block]

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



	As of December, 2013
Consideration given:	(in millions)
Cash consideration	$	1,392.7

Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	713.8
Unproved properties	683.4
Asset retirement obligations	(0.9		)
Liabilities assumed	(4.4		)
Other assets acquired	0.8
Total fair value	$	1,392.7

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, 2013

Fair Value Disclosures [Abstract]

Fair value of financial assets and liabilities

The fair value of financial assets and liabilities at December 31, 2013 and 2012, is shown in the tables below:



	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
			(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.5	$	—	$	(5.3	)	$	0.2
Commodity derivative instruments - long-term	—		0.4		—		—			0.4
Interest rate swaps - long-term	—		0.6		—		—			0.6
Total financial assets	$	—	$	6.5	$	—	$	(5.3	)	$	1.2

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	29.4	$	—	$	(5.3	)	$	24.1
Interest rate swaps - short-term	—		2.6		—		—			2.6
Total financial liabilities	$	—	$	32.0	$	—	$	(5.3	)	$	26.7

____________________________


⁽¹⁾	The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets as the contracts contain netting provisions. Refer to Note 7 - Derivative Contracts, for additional information regarding the Company's derivative contracts.



	Fair Value Measurements
	December 31, 2012
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
			(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

Change in fair value of Level 3 assets and liabilities

The change in the fair value of Level 3 assets and liabilities for the year ended December 31, 2012 is shown below.



	Year Ended December 31,
	2012
	(in millions)
Balance at January 1,	$	—
Realized gains and losses	0.6
Unrealized gains and losses	3.8
Settlements	(0.6		)
Transfers out of Level 3	(3.8		)
Balance at 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, 2013				December 31, 2012
	(in millions)
Financial assets
Cash and cash equivalents	$	11.9	$	11.9	$	—	$	—
Financial liabilities
Checks outstanding in excess of cash balances	$	90.9	$	90.9	$	39.7	$	39.7
Long-term debt	$	2,997.5	$	3,034.9	$	3,206.9	$	3,420.7

- 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.

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 157

-Paragraph 32

-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 820

-SubTopic 10

-Section 50

-Paragraph 3

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 820

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-Paragraph 1

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 157

-Paragraph 6

-Footnote 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 5: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 820

-SubTopic 10

-Section 50

-Paragraph 2

-Subparagraph (a,b,bb)

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

-Publisher FASB

-Name Accounting Standards Codification

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-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 157

-Paragraph 33

-Subparagraph a, b

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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.

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- 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.

+ References

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

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 107

-Paragraph 15

-Subparagraph b-d

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-Name Statement of Financial Accounting Standard (FAS)

-Number 159

-Paragraph 18

-Subparagraph c(2), d, e, f

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-Number 157

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-Subparagraph a, c(1), c(2), c(3), d

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-Name Accounting Standards Codification

-Topic 820

-SubTopic 10

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+ Details

Derivative Contracts (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Volumes and Average Prices

QEP Energy's Derivative Contracts

The following table sets forth QEP Energy's quantities and average prices for its commodity derivative contracts as of December 31, 2013:



				Swaps
Year	Type of Contract	Index	Total Volumes	Average price per unit
			(in millions)
Gas sales			(MMBtu)
2014	Swap	IFNPCR	58.4	$	3.98
2014	Swap	NYMEX	25.6	$	4.19
2015	Swap	NYMEX	3.7	$	4.16
Oil sales			(Bbls)
2014	Swap	NYMEX WTI	12.1	$	93.68
2015	Swap	NYMEX WTI	0.7	$	88.60

The following table sets forth QEP Energy's oil basis swaps as of December 31, 2013:



Year	Index	Index Less Differential	Bbls Per Day	Weighted Average Differential
Oil basis swaps
2014	NYMEX WTI	ICE Brent	2,000.0	$	13.78

QEP Marketing Derivative Contracts



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	Swap	IFNPCR	4.7	$	3.77
Gas purchases			(MMBtu)
2014	Swap	IFNPCR	1.0	$	3.78

QEP's Derivative Contracts

The following table sets forth QEP's notional amounts and interest rates for its interest rate swaps outstanding as of December 31, 2013:



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	2013		2012		2013		2012
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	5.5	$	189.7	$	29.4	$	1.0
Interest rate swaps	Fair value of derivative contracts	—		—		2.6		2.6
Long-term:
Commodity	Fair value of derivative contracts	0.4		4.2		—		0.1
Interest rate swaps	Fair value of derivative contracts	0.6		—		—		3.6
Total derivative instruments		$	6.5	$	193.9	$	32.0	$	7.3

Effects of Derivative Transactions



Derivative instruments not designated as cash flow hedges	Year Ended December 31,
Derivative instruments not designated as cash flow hedges	2013			2012			2011
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	152.0		$	341.9		$	(117.7	)
Oil derivative contracts	(2.2		)	14.4			—
NGL derivative contracts	—			10.2			—
QEP Field Services
NGL derivative contracts	—			8.4			—
QEP Marketing
Gas derivative contracts	0.5			5.1			—
Total realized gains (losses) on commodity derivative contracts	150.3			380.0			(117.7		)
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	(42.6		)	37.8			117.7
Oil derivative contracts	(48.1		)	29.0			—
NGL derivative contracts	—			1.6			—
QEP Field Services
NGL derivative contracts	—			—			—
QEP Marketing
Gas derivative contracts	(2.1		)	0.9			—
Total unrealized (losses) gains on commodity derivative contracts	(92.8		)	69.3			117.7
Total realized and unrealized gains on commodity derivative contracts	$	57.5		$	449.3		$	—
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(2.7	)	$	(1.3	)	$	—
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	4.1			(6.1		)	—
Total realized and unrealized gains (losses) on interest rate swaps	$	1.4		$	(7.4	)	$	—
Total net realized gains (losses) on derivative contracts	$	147.6		$	378.7		$	(117.7	)
Total net unrealized (losses) gains on derivative contracts	$	(88.7	)	$	63.2		$	117.7
Grand Total	$	58.9		$	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:



Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	Year Ended December 31,
Derivative instruments classified as cash flow hedges	Location of gain (loss) recognized in earnings	2013		2012		2011
Commodity derivatives
Gain on derivative instruments for the effective portion of hedge recognized in AOCI	Accumulated other comprehensive income	$	—	$	—	$	350.8
Gain reclassified from AOCI into income for effective portion of hedge	Gas sales	—		—		305.5
Gain reclassified from AOCI into income for effective portion of hedge	Oil sales	—		—		1.6
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
Gain recognized in income for the ineffective portion of hedges	Interest and other income	—		—		0.1

- 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, 2013

Restructuring Costs [Abstract]

Reconciliation of QEP Energy's restructuring cost



	Total Restructuring Costs
	Total Expected to be Incurred		Recognized in Income
			Period from Inception to December 31, 2013		Year ended December 31,
			Period from Inception to December 31, 2013		2013		2012
QEP Energy	(in millions)
One-time termination benefits	$	3.3	$	3.3	$	0.4	$	2.9
Retention & relocation expense	3.7		3.7		0.4		3.3
Lease termination costs	0.6		0.6		—		0.6
Total restructuring costs	$	7.6	$	7.6	$	0.8	$	6.8

QEP Field Services
One-time termination benefits	$	—	$	—	$	—	$	—
Retention & relocation expense	10.2		0.9		0.9		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	10.2	$	0.9	$	0.9	$	—

QEP Marketing
One-time termination benefits	$	0.3	$	0.3	$	0.1	$	0.2
Retention & relocation expense	—		—		—		—
Lease termination costs	—		—		—		—
Total restructuring costs	$	0.3	$	0.3	$	0.1	$	0.2

Total QEP
One-time termination benefits	$	3.6	$	3.6	$	0.5	$	3.1
Retention & relocation expense	13.9		4.6		1.3		3.3
Lease termination costs	0.6		0.6		—		0.6
Total restructuring costs	$	18.1	$	8.8	$	1.8	$	7.0

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

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, 2012	$	1.0		$	—		$	—		$	1.0
Costs incurred and charged to expense	0.8			0.9			0.1			1.8
Costs paid or otherwise settled	(1.8		)	(0.1		)	(0.1		)	(2.0		)
Balance at December 31, 2013	$	—		0.8			—			$	0.8

- 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.

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- 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 (Tables)

12 Months Ended

Dec. 31, 2013

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
2014	$	154.2
2015	$	103.7
2016	$	99.9
2017	$	99.2
2018	$	97.3
After 2018	$	290.5

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
2014	$	7.2
2015	$	6.5
2016	$	6.6
2017	$	6.8
2018	$	5.3
After 2018	$	23.7

- 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

Equity-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2013

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,
	2013			2012			2011
Weighted-average grant-date fair value of awards granted during the period	$	15.16		$	14.29		$	18.80
Risk-free interest rate range	0.97%-1.84%			0.63% - 1.04%			n/a
Weighted-average risk-free interest rate	1.0		%	0.8		%	2.1		%
Expected price volatility range	51.5%-58.5%			55.9% - 56.5%			n/a
Weighted-average expected price volatility	58.3		%	55.9		%	54.7		%
Expected dividend yield	0.27		%	0.26		%	0.21		%
Expected term in years at the date of grant	5.5			5.0			5.0

Summary of stock option transactions under the terms of LTSIP

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



	Options Outstanding		Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2012	1,697,471		$	25.23
Granted	330,592		30.06
Exercised	(224,833	)	10.77
Forfeited	(9,043	)	30.41
Outstanding at December 31, 2013	1,794,187		$	27.90	3.67	$	6.5
Options Exercisable at December 31, 2013	1,288,844		$	26.63	2.90	$	6.4
Unvested Options at December 31, 2013	505,343		$	31.14	5.88	$	0.1

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, 2012	1,300,588		$	31.78
Granted	862,669		30.06
Vested	(665,963	)	31.42
Forfeited	(108,341	)	30.77
Unvested balance at December 31, 2013	1,388,953		$	30.96

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, 2012	283,484		$	33.91
Granted	223,844		30.12
Vested	—		—
Forfeited	(26,668	)	30.69
Unvested balance at December 31, 2013	480,660		$	32.33

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2013

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
	2013			2012			2013			2012
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$	129.7		$	104.1		$	6.7		$	5.9
Service cost	3.3			4.0			0.1			0.1
Interest cost	4.8			5.1			0.3			0.3
Change in plan assumptions	—			8.4			—			—
Benefit payments	(5.5		)	(2.7		)	(0.1		)	—
Actuarial loss (gain)	(14.3		)	10.8			(1.1		)	0.4
Benefit obligation at December 31,	$	118.0		$	129.7		$	5.9		$	6.7
Change in plan assets
Fair value of plan assets at January 1,	$	55.3		$	44.2		$	—		$	—
Actual gain on plan assets	10.4			6.9			—			—
Company contributions to the plan	11.5			6.9			0.1			—
Benefit payments	(5.5		)	(2.7		)	(0.1		)	—
Fair value of plan assets at December 31,	71.7			55.3			—			—
Underfunded status (current and long-term)	$	(46.3	)	$	(74.4	)	$	(5.9	)	$	(6.7	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(5.5	)	$	(3.2	)	$	(0.2	)	$	(0.2	)
Other long-term liabilities	(40.8		)	(71.2		)	(5.7		)	(6.5		)
Total amount recognized in balance sheet	$	(46.3	)	$	(74.4	)	$	(5.9	)	$	(6.7	)
Amounts recognized in AOCI
Net actuarial loss	$	9.5		$	32.6		$	0.2		$	1.3
Prior service cost	30.1			35.1			3.0			3.4
Total amount recognized in AOCI	$	39.6		$	67.7		$	3.2		$	4.7

Pension and Other Postretirement Benefit Costs



	Pension benefits									Other postretirement benefits
	2013			2012			2011			2013			2012			2011

Components of net periodic benefit cost
Service cost	$	3.3		$	4.0		$	2.9		$	0.1		$	0.1		$	0.1
Interest cost	4.8			5.1			4.5			0.3			0.3			0.3
Expected return on plan assets	(3.9		)	(3.6		)	(2.6		)				—			—
Curtailment loss	—			2.2			—			—			—			—
Amortization of prior service costs	5.0			5.3			5.3			0.3			0.3			0.3
Amortization of actuarial loss	2.3			1.9			—			0.1			0.1			—
Periodic expense	$	11.5		$	14.9		$	10.1		$	0.8		$	0.8		$	0.7
Components recognized in accumulated other comprehensive income
Current period actuarial loss (gain)	$	(20.8	)	$	15.9		$	22.9		$	(1.0	)	$	0.4		$	1.0
Amortization of actuarial loss	(2.3		)	(1.9		)	—			(0.1		)	(0.1		)	—
Current period prior service cost	—			—									—			—
Amortization of prior service cost	(5.0		)	(5.3		)	(5.3		)	(0.4		)	(0.4		)	(0.3		)
Loss on curtailment in current period				(2.2		)	—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	(28.1	)	$	6.5		$	17.6		$	(1.5	)	$	(0.1	)	$	0.7

Schedule of Assumptions Used [Table Text Block]



	Pension benefits				Other postretirement benefits
	2013		2012		2013		2012
Discount rate	4.75	%	3.88	%	5.00	%	4.10	%
Rate of increase in compensation	4.00	%	3.60	%	4.00	%	3.60	%



	Pension benefits						Other postretirement benefits
	2013		2012		2011		2013		2012		2011
Discount rate	3.69	%	4.38	%	5.80	%	4.10	%	4.70	%	5.80	%
Expected long-term return on plan assets	6.75	%	7.25	%	7.50	%	n/a		n/a		n/a
Rate of increase in compensation	3.60	%	3.60	%	3.60	%	3.60	%	4.00	%	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:



	December 31, 2013								Percentage of total
	Level 1		Level 2		Level 3		Total		Percentage of total
	(in millions except percentages)
Cash and short-term investments	$	—	$	—	$	0.3	$	0.3	—		%
Equity securities:
Domestic	—		—		29.3		29.3		41		%
International	—		—		21.3		21.3		30		%
Fixed income	—		—		20.8		20.8		29		%
Total investments	—		—		$	71.7	$	71.7	100		%
	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	—		—		16.6		16.6		30		%
Fixed income	—		—		16.2		16.2		30		%
Total investments	—		—		$	55.2	$	55.2	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,
	2013			2012
	(in millions)
Balance at January 1,	$	55.2		44.2
Employer contributions	8.1			5.6
Unrealized gains (losses)	9.8			6.3
Realized gains	0.9			0.7
Administrative fees	(0.3		)	(0.2		)
Benefits paid	(2.1		)	(1.4		)
Balance at December 31,	$	71.6		$	55.2

Schedule of Expected Benefit Payments [Table Text Block]

Expected Benefit Payments

As of December 31, 2013, the following future benefit payments are expected to be paid:



	Pension		Postretirement benefits
	(in millions)
2014	$	8.1	$	0.2
2015	5.8		0.2
2016	6.1		0.3
2017	4.7		0.3
2018	5.8		0.3
2019 through 2021	40.0		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

-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e2417-114920

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

-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.

+ Details

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

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,
	2013			2012			2011
	(in millions)
Federal income tax expense (benefit)
Current	$	47.9		$	33.7		$	(5.3	)
Deferred	69.1			36.5			153.0
State income tax expense (benefit)
Current	5.7			0.7			2.9
Deferred	(2.9		)	(4.4		)	3.8
Total income tax expense	$	119.8		$	66.5		$	154.4

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,
	2013		2012		2011
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	0.6	%	(1.2	)%	1.0	%
Penalties	0.2	%	(0.6	)%	—	%
Return to provision adjustment	(0.2	)%	0.4	%	1.3	%
Noncontrolling interest	(1.4	)%	(0.7	)%	(0.3	)%
Book impairment of goodwill	7.2	%	—	%	—	%
Other	(0.3	)%	0.6	%	(0.7	)%
Effective income tax rate	41.1	%	33.5	%	36.3	%

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



	December 31,
	2013		2012
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$	1,651.1	$	1,606.6
Commodity price and interest rate derivatives	—		69.4
Total deferred tax liabilities	1,651.1		1,676
Deferred tax assets
Commodity price and interest rate derivatives	9.7		—
Net operating loss and tax credit carryforwards	54.6		65.6
Employee benefits and compensation costs	36.1		47.7
Accrued litigation loss contingency	0.8		42.8
Bonus and vacation accrual	10.6		11.8
Other	9.3		9.6
Total deferred tax assets	121.1		177.5
Net deferred income tax liability	$	1,530.0	$	1,498.5
Balance sheet classification
Deferred income tax asset - current	$	30.6	$	—
Deferred income tax liability -current	—		$	5.0
Deferred income tax liability - non-current	1,560.6		1,493.5
Net deferred income tax liability	$	1,530.0	$	1,498.5

Summary of Operating Loss Carryforwards [Table Text Block]

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2013 are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2014-2032	$	26.5
U.S. alternative minimum tax credit	Indefinite	28.1
Total		$	54.6

Operations by Line of Business (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Resources			Eliminations			QEP Consolidated
	(in millions)
Revenues ⁽¹⁾
From unaffiliated customers	$	2,092.8		$	282.4		$	560.6		$	—		$	2,935.8
From affiliated customers	—			121.0			1,012.6			(1,133.6		)	—
Total Revenues	2,092.8			403.4			1,573.2			(1,133.6		)	2,935.8
Operating expenses
Purchased gas, oil and NGL expense	197.1			8.9			1,570.5			(1,010.6		)	765.9
Lease operating expense	181.3			—			—			(3.5		)	177.8
Gas, oil and NGL transportation and other handling costs	242.2			13.9			—			(114.7		)	141.4
Gathering, processing and other	—			88.9			1.7			—			90.6
General and administrative	139.7			51.6			4.6			(4.8		)	191.1
Production and property taxes	159.8			6.6			0.1			—			166.5
Depreciation, depletion and amortization	954.2			60.9			0.9			—			1,016.0
Impairment and exploration expenses	104.9			—			—			—			104.9
Total operating expenses	1,979.2			230.8			1,577.8			(1,133.6		)	2,654.2
Net gain (loss) from asset sales	104.1			(0.5		)	(0.6		)	—			103.0
Operating income ⁽¹⁾	217.7			172.1			(5.2		)	—			384.6
Realized and unrealized gains (losses) on derivative contracts	59.1			—			(0.2		)	—			58.9
Interest and other income	3.6			1.2			206.9			(206.5		)	5.2
Income from unconsolidated affiliates	0.2			5.6			—			—			5.8
Loss on early extinguishment of debt	—			—			—			—			—
Interest expense	(192.6		)	(13.1		)	(164.1		)	206.5			(163.3		)
Income before income taxes	88.0			165.8			37.4			—			291.2
Income tax	(49.1		)	(55.4		)	(15.3		)	—			(119.8		)
Net income	38.9			110.4			22.1			—			171.4
Net income attributable to noncontrolling interest	—			(12.0		)	—						(12.0		)
Net income attributable to QEP ⁽²⁾	$	38.9		$	98.4		$	22.1		$	—		$	159.4
Identifiable total assets	$	7,930.6		$	1,455.1		$	250.7		$	(259.6	)	$	9,376.8
Investment in unconsolidated affiliates				39.0			—			—			39.0
Cash capital expenditures	1,488.6			89.8			24.2			—			1,602.6
Accrued capital expenditures	1,467.2			86.0			24.2			—			1,577.4

____________________________


⁽¹⁾	The impact of QEP's settled derivative contracts, for the year ended December 31, 2013, is reflected below operating income.


⁽²⁾	Net income attributable to QEP for the year ended December 31, 2013, 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, 2012, by line of business:



	QEP Energy			QEP Field Services			QEP Marketing & Resources			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
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	236.3			34.4			2.0			(6.1		)	266.6
Production and property taxes	97.2			6.0			0.2			—			103.4
Depreciation, depletion and amortization	838.4			63.2			3.7			—			905.3
Impairment and exploration expenses	144.2			—			—			—			144.2
Total operating expenses	1,944.7			236.1			1,028.2			(724.7		)	2,484.3
Net gain from asset sales	1.2			—			—			—			1.2
Operating (loss) income	(328.1		)	203.1			(8.3		)	—			(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 extinguishment of debt	—			—			(0.6		)	—			(0.6		)
Interest expense	(116.8		)	(13.6		)	(124.4		)	131.9			(122.9		)
(Loss) income before income taxes	(3.7		)	204.8			(2.6		)	—			198.5
Income taxes benefit (provision)	4.3			(71.8		)	1.0			—			(66.5		)
Net income (loss)	0.6			133.0			(1.6		)	—			132.0
Net income attributable to noncontrolling interest	—			(3.7		)	—			—			(3.7		)
Net income (loss) attributable to QEP	$	0.6		$	129.3		$	(1.6	)	$	—		$	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, was 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 & Resources			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
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	707.4			55.7			2.5			—			765.6
Impairment and exploration expenses	228.7			—			—			—			228.7
Total operating expenses	1,974.2			206.3			1,150.6			(676.4		)	2,654.7
Net gain 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	1,338.8			101.6			5.5			—			1,445.9
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 7 - Derivative Contracts, for detailed 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.

- 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, 2013

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)
2013
Revenues	$	696.5		$	751.0	$	772.8	$	715.5		$	2,935.8
Operating income (loss)	64.8			207.3		128.2		(15.7		)	384.6
Income (loss) before income taxes	(5.9		)	284.6		63.5		(51.0		)	291.2
Net income (loss) attributable to QEP	(4.3		)	178.4		37.3		(52.0		)	159.4
Non-recurring operating income (loss) ⁽¹⁾	(0.2		)	100.2		9.0		(99.0		)	10.0
Per share information attributable to QEP
Basic EPS attributable to QEP	$	(0.02	)	$	0.99	$	0.21	$	(0.29	)	$	0.89
Diluted EPS attributable to QEP	(0.02		)	0.99		0.21		(0.29		)	0.89



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
Non-recurring operating income (loss) ⁽¹⁾	(5.0		)	(55.4		)	(9.0		)	(62.4		)	(131.8		)
Per share information attributable to QEP
Basic EPS from continuing operations	$	0.87		$	—		$	(0.02	)	$	(0.13	)	$	0.72
Basic EPS attributable to QEP	0.87			—			(0.02		)	(0.13		)	0.72

____________________________


⁽¹⁾	Includes net gains/losses from asset sales and losses due to impairments.

Supplemental Gas and Oil Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Supplemental Gas and Oil Information (Unaudited) [Abstract]

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



	December 31,
	2013			2012
	(in millions)
Proved properties	$	11,571.4		$	10,234.3
Unproved properties, net	665.1			937.9
Total proved and unproved properties	12,236.5			11,172.2
Accumulated depreciation, depletion and amortization	(4,930.9		)	(4,258.1		)
Net capitalized costs	$	7,305.6		$	6,914.1

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



	Year Ended December 31,
	2013		2012		2011
	(in millions)
Property acquisitions
Unproved	$	9.3	$	692.6	$	48.0
Proved	31.6		714.4		0.1
Total property acquisitions	40.9		1,407.0		48.1
Exploration (capitalized and expensed)	14.6		14.3		36.5
Development	1,440.8		1,310.0		1,267.8
Total costs incurred	$	1,496.3	$	2,731.3	$	1,352.4

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

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



	Year Ended December 31,
	2013			2012			2011
	(in millions)
Revenues ⁽¹⁾	$	1,901.2		$	1,393.4		$	1,703.4
Production costs	583.3			501.1			433.3
Exploration expenses	11.9			11.2			10.5
Depreciation, depletion and amortization	954.2			838.4			707.4
Impairment	93.0			133.0			218.2
Total expenses	1,642.4			1,483.7			1,369.4
Income (loss) before income taxes	258.8			(90.3		)	334.0
Income tax benefit (expense)	(96.3		)	33.6			(119.0		)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	162.5		$	(56.7	)	$	215.0

___________________________


⁽¹⁾	Revenue for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts which during the years ended December 31, 2013 and 2012, are reflected below operating income (loss) on the Consolidated Statements of Operations. See Note 7 - Derivative Contracts.

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



	Year Ended December 31,
	2013			2012			2011
	(in millions)
Revenues ⁽¹⁾	$	1,901.2		$	1,393.4		$	1,703.4
Production costs	583.3			501.1			433.3
Exploration expenses	11.9			11.2			10.5
Depreciation, depletion and amortization	954.2			838.4			707.4
Impairment	93.0			133.0			218.2
Total expenses	1,642.4			1,483.7			1,369.4
Income (loss) before income taxes	258.8			(90.3		)	334.0
Income tax benefit (expense)	(96.3		)	33.6			(119.0		)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	162.5		$	(56.7	)	$	215.0

___________________________


⁽¹⁾	Revenue for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts which during the years ended December 31, 2013 and 2012, are reflected below operating income (loss) on the Consolidated Statements of Operations. See Note 7 - Derivative Contracts.

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



	Gas		Oil		NGL		Total
	(Bcf)		(MMbbl)		(MMbbl)		(Bcfe)
Balance at December 31, 2010	2,612.9		52.3		17.4		3,030.7
Revisions of previous estimates⁽⁶⁾	(270.1	)	1.7		39.3		(23.5	)
Extensions and discoveries ⁽⁷⁾	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 ⁽³⁾	(240.6	)	(1.5	)	0.7		(244.8	)
Extensions and discoveries ⁽⁴⁾	330.6		17.3		23.0		572.5
Purchase of reserves in place ⁽⁵⁾	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
Revisions of previous estimates ⁽¹⁾	(288.3	)	1.3		(8.0	)	(328.5	)
Extensions and discoveries ⁽²⁾	455.6		38.3		16.4		783.8
Purchase of reserves in place	1.0		1.9		0.2		13.4
Sale of reserves in place	(16.9	)	(1.7	)	(1.1	)	(33.9	)
Production	(218.9	)	(10.2	)	(4.8	)	(309.0	)
Balance at December 31, 2013	2,554.9		148.6		102.6		4,061.9
Proved developed reserves
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
Balance at December 31, 2013	1,406.3		71.8		52.8		2,154.0
Proved undeveloped reserves
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
Balance at December 31, 2013	1,148.6		76.8		49.8		1,907.9

____________________________

⁽¹⁾

⁽²⁾

⁽³⁾

⁽⁴⁾


⁽⁵⁾	Purchase of reserves in place primarily relate to the Company's $1.4 billion 2012 Acquisition as discussed in Note 2 - Acquisitions and Divestitures.

⁽⁶⁾

⁽⁷⁾

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,
	2013		2012		2011
Average benchmark price per unit:
Gas price (per MMbtu)	$	3.67	$	2.76	$	4.12
Oil price (per Bbl)	96.94		94.71		96.19

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,
	2013			2012			2011
	(in millions)
Future cash inflows	$	24,805.7		$	18,200.2		$	18,300.6
Future production costs	(8,400.3		)	(5,027.2		)	(4,276.1		)
Future development costs	(4,056.7		)	(3,927.3		)	(3,250.0		)
Future income tax expenses	(3,284.6		)	(2,269.0		)	(2,837.1		)
	9,064.1			6,976.7			7,937.4
10% annual discount for estimated timing of net cash flows	(4,680.2		)	(3,942.0		)	(4,411.8		)
Standardized measure of discounted future net cash flows	$	4,383.9		$	3,034.7		$	3,525.6

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,
	2013			2012			2011
	(in millions)
Balance at January 1,	$	3,034.7		$	3,525.6		$	2,705.6
Sales of gas, oil and NGL produced during the period, net of production costs	(1,317.9		)	(892.3		)	(1,779.9		)
Net change in sales prices and in production (lifting) costs related to future production	1,236.3			(2,083.5		)	1,472.5
Net change due to extensions, discoveries and improved recovery	2,230.7			948.5			1,806.4
Net change due to revisions of quantity estimates	(709.6		)	(387.8		)	(48.2		)
Changes due to purchases of reserves in place	36.8			831.4			0.1
Changes due to sales of reserves in place	(73.2		)	—			(8.0		)
Previously estimated development costs incurred during the period	722.7			513.0			533.6
Changes in estimated future development costs	(596.5		)	(209.3		)	(1,110.4		)
Accretion of discount	402.2			499.4			355.4
Net change in income taxes	(601.7		)	273.6			(411.4		)
Other	19.4			16.1			9.9
Net change	1,349.2			(490.9		)	820.0
Balance at December 31,	$	4,383.9		$	3,034.7		$	3,525.6

- 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

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-Name Accounting Standards Codification

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-Name Statement of Financial Accounting Standard (FAS)

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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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-Name Accounting Standards Codification

-Topic 410

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-Paragraph 1

-Subparagraph (c)(3)

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-Name Accounting Standards Codification

-Topic 932

-SubTopic 10

-Section S99

-Paragraph 1

-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))

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-Name Accounting Standards Codification

-Topic 932

-SubTopic 235

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-SubTopic 235

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-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62352-109447

+ 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 Investment in Unconsolidated Affiliates (Details)	Dec. 31, 2013
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, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Goodwill, Impairment Loss	$ 59.5
Restricted Cash, Noncurrent	50.0	0
Cash paid for interest, net of capitalized interest	156.7	105.1	90.5
Cash paid (received) for income taxes	77.9	30.0	(28.5)
Change in capital expenditure accrual balance	$ (25.2)	$ 88.5	$ 14.7

- Definition

Loss recognized during the period that results from the write-down of goodwill after comparing the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. Goodwill is assessed at least annually for impairment.

+ References

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-Publisher FASB

-Name Accounting Standards Codification

-Topic 230

-SubTopic 10

-Section 45

-Paragraph 28

-Subparagraph (b)

-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

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-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.

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-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 141R

-Paragraph 72

-Subparagraph d

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-Paragraph 1

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-Name Statement of Financial Accounting Standard (FAS)

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-Subparagraph e

-Clause 5

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+ Details

- 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, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounts, Notes, Loans and Financing Receivable [Line Items]
Bad Debt Expense	$ 3.5	$ 1.4	$ 0.2
Allowance for Doubtful Accounts [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable	$ 5.1	$ 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, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Capitalized Interest Costs	$ 2.0	$ 3.4	$ 3.0
Building [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years
Building [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	30 years
Leasehold Improvements [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Leasehold Improvements [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years
Equipment [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Equipment [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	7 years
Furniture and Fixtures [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Furniture and Fixtures [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	7 years

Summary of Significant Accounting Policies Impairment of long-lived assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 33.5	$ 133.0	$ 218.2
Goodwill, Impairment Loss	59.5
Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	1.2	107.6	195.5
Unproved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	32.3	25.4	22.7
Southern Region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	17.5	104.7	45.1
Northern Region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 16.0	$ 28.3	$ 173.1

- Definition

+ References

+ Details

- 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	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill [Line Items]
Goodwill	$ 0	$ 59.5	$ 59.5
Goodwill, Impairment Loss	$ 59.5

- 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

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-Name Statement of Financial Accounting Standard (FAS)

-Number 141R

-Paragraph 68

-Subparagraph l

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-Paragraph 1

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-Paragraph 45

-Subparagraph e

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-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 142

-Paragraph 43

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-Number 141R

-Paragraph 72

-Subparagraph d

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+ Details

- Definition

+ References

+ Details

Summary of Significant Accounting Policies Derivative instruments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]
Unrealized (Loss) Gain on Derivatives	$ (88.7)	$ 63.2	$ 117.7
Accumulated Other Comprehensive Income Loss, Cumulative Changes In Gain Loss From Cash Flow Hedges Effect, Before Tax			395.9
Unrealized gains on derivative contracts, net of tax			$ 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, 2013	Dec. 31, 2012	Dec. 31, 2011
Concentration Risk [Line Items]
Concentration Risk, Percentage	35.00%	37.00%	32.00%
Freepoint Commodities [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%
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, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Used in basic calculation	179.2	177.8	176.5
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan	0.3	0.9	1.9
Average diluted common shares outstanding (in shares)	179.5	178.7	178.4

- 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

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-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

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-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 07-4

-Paragraph 4

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-Name Statement of Financial Accounting Standard (FAS)

-Number 128

-Paragraph 171

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-Publisher FASB

-Name Accounting Standards Codification

-Glossary Weighted-Average Number of Common Shares Outstanding

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

+ Details

Acquisitions and Divestitures (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 25, 2014
Acquisitions [Abstract]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual									$ 300.0	$ 63.7
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual									67.0	14.9
Business Acquisition, Cost of Acquired Entity, Transaction Costs					1.1					1.1
Business Combination, Consideration Given [Abstract]
Cash Paid at Closing	1,392.7								1,392.7
Total estimate consideration given	1,392.7								1,392.7			950.0
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net [Abstract]
Proved properties	713.8								713.8
Unproved Properties	683.4								683.4
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	715.5	772.8	751.0	696.5	704.9	542.4	499.3	603.2	2,935.8	2,349.8	3,159.2
Pro Forma Revenues										2,485.3	3,236.7
NET INCOME ATTRIBUTABLE TO QEP	(52.0)	37.3	178.4	(4.3)	(23.1)	(3.1)	(0.7)	155.2	159.4	128.3	267.2
Pro Forma Net Income										$ 143.0	$ 259.8
Actual Basic total	$ (0.29)	$ 0.21	$ 0.99	$ (0.02)	$ (0.13)	$ (0.02)	$ 0.00	$ 0.87	$ 0.89	$ 0.72	$ 1.51
Pro Forma Earnings Per Share, Basic										$ 0.80	$ 1.47
Actual Diluted total	$ (0.29)	$ 0.21	$ 0.99	$ (0.02)	$ (0.13)	$ (0.02)	$ 0.00	$ 0.87	$ 0.89	$ 0.72	$ 1.50
Pro Forma Earnings Per Share, Diluted										$ 0.80	$ 1.46

Acquisitions and Divestitures Divestitures (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Third Quarter Property Divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	$ 67.3
Gain (Loss) on Sale of Property	9.5
Second Quarter Property Divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	138.5
Gain (Loss) on Sale of Property	$ 96.2

- Definition

The cash inflow from the sale of long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale.

+ References+ Details

QEP Midstream (Details) (USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended		12 Months Ended
	Dec. 31, 2013	Aug. 14, 2013	Dec. 31, 2013
Noncontrolling Interest [Line Items]
Offering Costs, Partnership Interests		$ 29.3
Partners' Capital Account, Units, Sold to Underwriters		3,000,000
Partners Capital Account Units Sold In Public Offering Price Per Unit		$ 21.00
Partners' Capital Account, Public Sale of Units Net of Offering Costs		390.7	449.6
net proceeds from issuance of units to underwriters		58.9
Offering Costs from issuance of Units to Underwriters		4.1
Noncontrolling Interest, Ownership Percentage by Parent	57.80%	63.30%	57.80%
Affiliate Payment for General and Administrative Services		13.8
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest			2.00%
General Partners' Capital Account, Units Issued		1,090,000
Limited Partners' Capital Account, Units Issued		6,701,750
Membership Interest Related to Common Units		12.30%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	6.80%	49.00%
Other Ownership Interests, Units Issued		26,705,000
Proceeds from Issuance of Common Limited Partners Units		420.0	483.0
Payments of Stock Issuance Costs			(33.4)
Repayments of Related Party Debt			(95.5)
Net proceeds distributed to parent from the Offering			351.1
Partners' Capital Account, Units, Sold in Public Offering		20,000,000
541611 Administrative Management and General Management Consulting Services [Member]
Noncontrolling Interest [Line Items]
Affiliate Payment for General and Administrative Services		1.4
QEP Midstream's Credit Facility [Member]
Noncontrolling Interest [Line Items]
Payments of Debt Issuance Costs			$ (3.0)

Capitalized Exploratory Well Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capitalized Exploratory Well Costs [Abstract]
Beginning Balance	$ 2.1	$ 5.0	$ 13.6
Additions to capitalized exploratory well costs pending the determination of proved reserves	2.7	12.7	0
Reclassifications to proved properties after the determination of proved reserves	(2.2)	(15.6)	(8.3)
Capitalized exploratory well costs charged to expense	0	0	0
Ending Balance	$ 2.6	$ 2.1	$ 5.0

Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation, Current	$ 1.8
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	193.1	163.9
Accretion	8.9	10.5
Liabilities incurred	11.0	8.5
Revisions of Estimates	(4.4)	11.1
ARO Liabilities Transferred	11.4	0
Liabilities settled	(3.6)	0.9
ARO liability, Ending Balance	$ 193.6	$ 193.1

- 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, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 11.9	$ 0	$ 0	$ 0
Financial Assets
Derivative instruments - short-term
Derivative instruments - long-term
Financial liabilities
Derivative instruments - short-term
Derivative instruments - long-term	0	3.6
Level 3 Unobservable input reconciliation [Roll Forward]
Beginning Balance		0	0
Ending Balance		0	0
Impairment of Oil and Gas Properties	33.5	133.0	218.2
Proved properties, estimated fair values	0	71.9
Proved properties [Member]
Level 3 Unobservable input reconciliation [Roll Forward]
Impairment of Oil and Gas Properties	1.2	107.6	195.5
Fair Value, Measurements, Recurring [Member]
Financial Assets
Derivative Assets	1.2	192.8
Financial liabilities
Derivative Liabilities	26.7	6.2
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	0.2	188.7
Derivative instruments - long-term	0.4	4.1
Financial liabilities
Derivative instruments - short-term	24.1	0
Derivative instruments - long-term		0
Fair Value, Measurements, Recurring [Member] \| Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	0.6
Financial liabilities
Derivative instruments - short-term	2.6	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
Long-term debt	2,997.5	3,206.9
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
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member] \| Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	0
Financial liabilities
Derivative instruments - short-term	0	0
Derivative instruments - long-term		0
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	11.9	0
Financial liabilities
Checks outstanding in excess of cash balances	90.9	39.7
Long-term debt	3,034.9	3,420.7
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member]
Financial Assets
Derivative Assets	6.5	193.9
Financial liabilities
Derivative Liabilities	32.0	7.3
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	5.5	189.7
Derivative instruments - long-term	0.4	4.2
Financial liabilities
Derivative instruments - short-term	29.4	1.0
Derivative instruments - long-term		0.1
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member] \| Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	0.6
Financial liabilities
Derivative instruments - short-term	2.6	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
Change in Unrealized Gain (Loss)		3.8
Settlements		(0.6)
Transfers out of Level 3		(3.8)
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
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Netting Adjustments [Member]
Financial liabilities
Derivative instruments - long-term		(0.1)
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	0
Financial liabilities
Derivative instruments - short-term	0	0
Derivative instruments - long-term		0
Fair Value, Measurements, Recurring [Member] \| Netting Adjustments [Member]
Financial Assets
Derivative Assets	(5.3)	(1.1)
Financial liabilities
Derivative Liabilities	(5.3)	(1.1)
Fair Value, Measurements, Recurring [Member] \| Netting Adjustments [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments - short-term	(5.3)	(1.0)
Derivative instruments - long-term	0	(0.1)
Financial liabilities
Derivative instruments - short-term	(5.3)	(1.0)
Fair Value, Measurements, Recurring [Member] \| Netting Adjustments [Member] \| Interest Rate Swap [Member]
Financial Assets
Derivative instruments - long-term	0
Financial liabilities
Derivative instruments - short-term	0	0
Derivative instruments - long-term		$ 0

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Derivatives, Fair Value [Line Items]

Forecasted production from proved reserves (in hundredths)

100.00%

Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax

$ (77.6)

^[1]

$ (171.1)

^[1]

$ 24.8

^[1]

Unrealized gains on derivative contracts

395.9

Unrealized gains on derivative contracts, net of tax

248.6

Asset Retirement Obligation

Total principal amount of debt

3,001.8

3,211.8

Index

NYMEX

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

6.5

193.9

Derivative Liability, Fair Value, Gross

32.0

7.3

Derivative instruments - long-term

Derivative instruments - short-term

Derivative instruments - long-term

3.6

Commodity Contract [Member] | Oil Sales (Bbls) [Member] | Year 2015 [Member] [Domain] | NYMEX WTI [Member]

Derivatives, Fair Value [Line Items]

Year

2015

Index

NYMEX WTI

Derivative Contracts - Volumes and Prices

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

700,000

Average Swap price per unit ($ per unit)

88.60

Swap [Member] | Natural Gas Sales (MMbtu) [Member] | Year 2015 [Member] [Domain] | NYMEX [Member]

Derivatives, Fair Value [Line Items]

Year

2015

Derivative Contracts - Volumes and Prices

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

3,700,000

Average Swap price per unit ($ per unit)

4.16

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)

25,600,000

Average Swap price per unit ($ per unit)

4.19

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

58,400,000

Average Swap price per unit ($ per unit)

3.98

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

Derivatives, Fair Value [Line Items]

Year

2014

Index

ICE Brent

Derivative Contracts - Volumes and Prices

Average Swap price per unit ($ per unit)

13.78

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

Derivatives, Fair Value [Line Items]

Year

2014

Index

NYMEX WTI

Derivative Contracts - Volumes and Prices

Average Swap price per unit ($ per unit)

93.68

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

Derivative Contracts - Volumes and Prices

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

2,000

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

Derivative Contracts - Volumes and Prices

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

12,100,000

Swap [Member] | QEP Marketing [Member] | Year 2013 [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)

4,700,000

Average Swap price per unit ($ per unit)

3.77

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] | Year 2013 [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)

1,000,000

Average Swap price per unit ($ per unit)

3.78

Term Loan due 2017 [Member]

Derivatives, Fair Value [Line Items]

Total principal amount of debt

300.0

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

Fair Value of Derivative Contracts, Gross [Abstract]

Derivative Asset, Fair Value, Gross

Derivative Liability, Fair Value, Gross

2.6

Short term [Member] | Commodity Contract [Member]

Fair Value of Derivative Contracts, Gross [Abstract]

Derivative Asset, Fair Value, Gross

5.5

189.7

Derivative Liability, Fair Value, Gross

29.4

1.0

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

Fair Value of Derivative Contracts, Gross [Abstract]

Derivative Asset, Fair Value, Gross

0.6

Derivative Liability, Fair Value, Gross

3.6

Long term [Member] | Commodity Contract [Member]

Fair Value of Derivative Contracts, Gross [Abstract]

Derivative Asset, Fair Value, Gross

0.4

4.2

Derivative Liability, Fair Value, Gross

$ 0

$ 0.1

[1]	Presented net of income tax benefit of $45.9 million and $101.3 million during the years ended December 31, 2013 and 2012, respectively, and net of income tax expense of $14.7 million during the year ended December 31, 2011.

Derivative Contracts - Gain (Loss) in Statement of Financial Performance (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) derivative contracts not designated as hedging instruments	$ 147.6	$ 378.7	$ (117.7)
Unrealized gain (loss) derivative contracts not designated as hedging instruments	(88.7)	63.2	117.7
Total gain (loss) on commodity derivative instruments	58.9	441.9	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	(77.6)	(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	152.0	341.9	(117.7)
Unrealized gain (loss) on commodity derivative contracts	(42.6)	37.8	117.7
Natural gas derivative contracts [Member] \| QEP Marketing [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	0.5	5.1	0
Unrealized gain (loss) on commodity derivative contracts	(2.1)	0.9	0
Oil derivative contracts [Member] \| QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(2.2)	14.4	0
Unrealized gain (loss) on commodity derivative contracts	(48.1)	29.0	0
NGL derivative contracts [Member] \| QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	0	10.2	0
Unrealized gain (loss) on commodity derivative contracts	0	1.6	0
NGL derivative contracts [Member] \| QEP Field Services [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	0	8.4	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	(2.7)	(1.3)	0
Unrealized gain (loss) on commodity derivative contracts	4.1	(6.1)	0
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	1.4	(7.4)	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	0	350.8
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	0	305.5
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	(0.2)
Oil Sales (Bbls) [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net [Abstract]
Gain reclassified from AOCI into income for effective portion of hedge	0	0	1.6
Marketing Purchases [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net [Abstract]
Gain reclassified from AOCI into income for effective portion of hedge	0	0	4.3
Interest Income [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net [Abstract]
Gain recognized in income for the ineffective portion of hedges	0	0	0.1
Realized and unrealized gains on commodity derivative instruments [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	150.3	380.0	(117.7)
Unrealized gain (loss) on commodity derivative contracts	(92.8)	69.3	117.7
Total gain (loss) on commodity derivative instruments	$ 57.5	$ 449.3	$ 0

Restructuring Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended		24 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	$ 18.1
Restructuring Charges	1.8	7.0
Restructuring costs incurred to date			8.8
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	3.6
Restructuring Charges	0.5	3.1
Restructuring costs incurred to date			3.6
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	13.9
Restructuring Charges	1.3	3.3
Restructuring costs incurred to date			4.6
Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.6
Restructuring Charges	0	0.6
Restructuring costs incurred to date			0.6
QEP Energy [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	7.6
Restructuring Charges	0.8	6.8
Restructuring costs incurred to date	0.8		7.6
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2012	1.0
Costs paid or otherwise settled	(1.8)
Balance at December 31, 2013	0	1.0	0
QEP Energy [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.3
Restructuring Charges	0.4	2.9
Restructuring costs incurred to date			3.3
QEP Energy [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.7
Restructuring Charges	0.4	3.3
Restructuring costs incurred to date			3.7
QEP Energy [Member] \| Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.6
Restructuring Charges	0	0.6
Restructuring costs incurred to date			0.6
QEP Field Services [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	10.2
Restructuring Charges	0.9	0
Restructuring costs incurred to date	0.9		0.9
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2012	0
Costs paid or otherwise settled	(0.1)
Balance at December 31, 2013	0.8	0	0.8
QEP Field Services [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0
Restructuring Charges	0	0
Restructuring costs incurred to date			0
QEP Field Services [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	10.2
Restructuring Charges	0.9	0
Restructuring costs incurred to date			0.9
QEP Field Services [Member] \| Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0
Restructuring Charges	0	0
Restructuring costs incurred to date			0
QEP Marketing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.3
Restructuring Charges	0.1	0.2
Restructuring costs incurred to date	0.1		0.3
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2012	0
Costs paid or otherwise settled	(0.1)
Balance at December 31, 2013	0	0	0
QEP Marketing [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.3
Restructuring Charges	0.1	0.2
Restructuring costs incurred to date			0.3
QEP Marketing [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0
Restructuring Charges	0	0
Restructuring costs incurred to date			0
QEP Marketing [Member] \| Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0
Restructuring Charges	0	0
Restructuring costs incurred to date			0
QEP Resources [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred to date	1.8
Increase (Decrease) in Restructuring Liability [Roll Forward]
Balance at December 31, 2012	1.0
Costs paid or otherwise settled	(2.0)
Balance at December 31, 2013	$ 0.8		$ 0.8

- 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 charged against earnings in the period for incurred and estimated costs associated with exit from or disposal of business activities or restructurings pursuant to a duly authorized plan, excluding asset retirement obligations.

+ 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 $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Total principal amount of debt	$ 3,001.8	$ 3,211.8
Less unamortized discount	(4.3)	(4.9)
Total long-term debt outstanding	2,997.5	3,206.9
Proceeds from Issuance of Long-term Debt	0	1,450.0	0
Principal amount of senior notes outstanding	2,221.8
Debt Instrument, Maturity Date Range, Start	Sep. 01, 2016
Debt Instrument, Maturity Date Range, End	May 01, 2023
Non-cash loss on early extinguishment of debt	0	0.6	0.7
Senior Notes, stated interest rate, minimum (in hundredths)	5.25%
Senior Notes, stated interest rate, maximim (in hundredths)	6.875%
Revolving Credit Facility due 2016 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	480.0	690.0
Maturity date of long-term debt	Aug. 25, 2016
Borrowing capacity	1,500.0
Potential increased borrowing capacity	2,000.0
Number of maturity date extentions	2
Additional period with in which maturity to be extended	1 year
Weighted-average interest rate (in hundredths)	2.22%	2.08%
Amount outstanding	480.0	690.0
Letters of credit outstanding	3.8	4.1
QEP Midstream's Credit Facility [Member]
Debt Instrument [Line Items]
Maturity date of long-term debt	Aug. 14, 2018
Borrowing capacity	500.0
Potential increased borrowing capacity	750.0
Term Loan due 2017 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	300.0	300.0
Maturity date of long-term debt	Apr. 18, 2017
Additional period with in which maturity to be extended	1 year
Weighted-average interest rate (in hundredths)	2.22%	2.05%
6.05% Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	176.8	176.8
Long-term debt, interest rate (in hundredths)	6.05%
Maturity date of long-term debt	Sep. 01, 2016
Maturity period of long-term debt	5 years
6.80% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	134.0	134.0
Long-term debt, interest rate (in hundredths)	6.80%
Maturity date of long-term debt	Apr. 01, 2018
6.80% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	136.0	136.0
6.875% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	625.0	625.0
5.375% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	500.0	500.0
5.25% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	$ 650.0	$ 650.0

Commitments and Contingencies Litigation (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]
Loss Contingency, Settlement Agreement, Consideration		$ 115.0
Deferred Revenue	$ 8.5

Commitments and Contingencies Other Commitments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 154.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	103.7
Unrecorded Unconditional Purchase Obligation, Due within Three Years	99.9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	99.2
Unrecorded Unconditional Purchase Obligation, Due within Five Years	97.3
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 290.5

Commitments and Contingencies Long-term Operating lease commitments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating lease commitments [Abstract]
Operating Leases, Rent Expense	$ 7.8	$ 7.3	$ 5.0
Operating Leases, Future Minimum Payments Due, Next Twelve Months	7.2
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	6.8
Operating Leases, Future Minimum Payments, Due in Five Years	5.3
Operating Leases, Future Minimum Payments, Due Thereafter	$ 23.7

- 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

Equity-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation, Stock Options [Line Items]
Shares available for future grants	12,000,000
Equity-based compensation	$ 27.1	$ 25.6	$ 22.0
Total compensation expense related to share-based compensation	27.1	25.6	22.0
Stock Options [Member]
Share-based Compensation, Stock Options [Line Items]
Fair value of options at grant date	$ 15.16	$ 14.29	$ 18.80
Risk-free interest rate range, minimum	0.97%
Risk-free interest rate range, maximum	1.84%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum	51.50%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Weighted Average Volatility Rate	58.30%	55.90%	54.70%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum	58.50%
Weighted-average risk-free interest rate	1.00%	0.80%	2.10%
Expected dividend yield (in hundredths)	0.27%	0.26%	0.21%
Expected life in years	5 years 6 months	5 years	5 years
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning (in dollars per share)	$ 25.23
Weighted-Average Price, Granted (in dollars per share)	$ 30.06
Weighted-Average Price, Exercised (in dollars per share)	$ 10.77
Options Outstanding [RollForward]
Outstanding at December 31, 2012 (in shares)	1,697,471
Granted (in shares)	330,592
Exercised (in shares)	(224,833)
Forfeited (in shares)	9,043
Outstanding at December 31, 2013 (in shares)	1,794,187	1,697,471
Options Excercisable (in shares)	1,288,844
Unvested Options (in shares)	505,343
Weighted-Average Price, Forfeited (in dollars per share)	$ 30
Weighted-Average Price, Ending (in dollars per share)	$ 27.90	$ 25.23
Weighted-Average Price, Options Excercisable	$ 26.63
Weighted-Average Price, Unvested Options	$ 31.14
Weighted-Average Remaining Contractual Term, Outstanding	3 years 8 months 1 day
Aggregate Intrinsic Value, Outstanding	6.5
Weighted-Average Remaining Contractual Term, Options Excercisable	2 years 10 months 24 days
Aggregate Intrinsic Value, Options Excercisable	6.4
Weighted-Average Remaining Contractual Term, Unvested Options	5 years 10 months 16 days
Aggregate Intrinsic Value, Unvested Options	0.1
Intrinsic value of options exercised	4.3	9.6	2.7
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	1.4	4.6	0.4
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net	6.5
Unrecognized compensation cost	2.9
Weighted-average period for recognition of compensation costs	1 year 11 months 12 days
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options	2.0
Restricted Stock [Member]
Options Outstanding [RollForward]
Weighted-Average Price, beginning balance (in dollars per share)	$ 31.78
Weighted-Average Price, Granted (in dollars per share)	$ 30.06	$ 30.54	$ 38.50
Weighted-Average Price, Vested (in dollars per share)	$ 31.42
Weighted-Average Price, Forfeited (in dollars per share)	$ 30.77
Weighted-Average Price, Ending Balance (in dollars per share)	$ 30.96	$ 31.78
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net	0.8
Unrecognized compensation cost	17.4
Weighted-average period for recognition of compensation costs	1 year 11 months 28 days
Total fair value of stock that vested	19.8	16.7	11.7
Employee Service Share-Based Compensation Tax Expense	(0.1)	(0.3)	1.0
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)	1,300,588
Granted (in shares)	862,669
Vested (in shares)	(665,963)
Forfeited (in shares)	(108,341)
Balance, Ending (in shares)	1,388,953	1,300,588
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)	$ 33.91
Weighted-Average Price, Granted (in dollars per share)	$ 30.12	$ 30.75	$ 39.07
Weighted-Average Price, Vested (in dollars per share)	$ 0.00
Weighted-Average Price, Forfeited (in dollars per share)	$ (30.69)
Weighted-Average Price, Ending Balance (in dollars per share)	$ 32.33	$ 33.91
Unrecognized compensation cost	6.4
Weighted-average period for recognition of compensation costs	1 year 9 months 28 days
Restricted Shares Outstanding [Roll Forward]
Balance, beginning (in shares)	283,484
Granted (in shares)	223,844
Vested (in shares)	0
Forfeited (in shares)	(26,668)
Balance, Ending (in shares)	480,660	283,484
QEP Midstream Long-Term Incentive Plan [Member]
Share-based Compensation, Stock Options [Line Items]
Equity-based compensation	$ 0.5

Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$ 101.0	$ 106.9
Change in benefit obligation
Benefit payments	(2.1)	(1.4)
Change in plan assets
Beginning Balance	55.2	44.2
Company contributions to the plan	8.1	5.6
Ending Balance	71.6	55.2	44.2
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	(0.3)	(0.2)
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Contribution Plan, Cost Recognized	6.9	6.4	5.8
Pension [Member]
Change in benefit obligation
Benefit obligation at January 1,	118.0	129.7	104.1
Change in plan assumptions	0	8.4
Benefit payments	(5.5)	(2.7)
Actuarial loss (gain)	(14.3)	10.8
Change in plan assets
Beginning Balance	55.3	44.2
Actual gain (loss) on plan assets	10.4	6.9
Company contributions to the plan	11.5	6.9
Underfunded status (current and long-term)	(46.3)	(74.4)
Ending Balance	71.7	55.3	44.2
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(5.5)	(3.2)
Other long-term liabilities	(40.8)	(71.2)
Total amount recognized in balance sheet	(46.3)	(74.4)
Amounts recognized in AOCI
Net actuarial loss (gain)	9.5	32.6
Prior service cost	30.1	35.1
Total amount recognized in AOCI	39.6	67.7
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	3.3	4.0	2.9
Interest cost	4.8	5.1	4.5
Expected return on plan assets	(3.9)	(3.6)	(2.6)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	0	2.2	0
Amortization of prior service costs	5.0	5.3	5.3
Amortization of actuarial loss	2.3	1.9	0
Periodic expense	11.5	14.9	10.1
Pension and other postretirement plans adjustments:
Current period actuarial loss (gain)	(20.8)	15.9	22.9
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax	(2.3)	(1.9)	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Benefit Cost, before Tax	(5.0)	(5.3)	(5.3)
Defined Benefit Plan, Curtailments		(2.2)	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, before Tax	(28.1)	6.5	17.6
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	5.0
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Discount rate	4.75%	3.88%
Rate of increase in compensation	4.00%	3.60%
Discount rate	3.69%	4.38%	5.80%
Expected long-term return on plan assets	6.75%	7.25%	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	8.1
2014	5.8
2015	6.1
2016	4.7
2017	5.8
2018 through 2021	40.0
Pension [Member] \| Funded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan	8.1
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		3.4
Expected to contribute to pension plans		5.5
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,	5.9	6.7	5.9
Change in plan assumptions	0	0
Benefit payments	(0.1)	0
Actuarial loss (gain)	(1.1)	0.4
Change in plan assets
Beginning Balance	0	0
Actual gain (loss) on plan assets	0	0
Company contributions to the plan	0.1	0
Underfunded status (current and long-term)	(5.9)	(6.7)
Ending Balance	0	0	0
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(0.2)	(0.2)
Other long-term liabilities	(5.7)	(6.5)
Total amount recognized in balance sheet	(5.9)	(6.7)
Amounts recognized in AOCI
Net actuarial loss (gain)	0.2	1.3
Prior service cost	3.0	3.4
Total amount recognized in AOCI	3.2	4.7
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0.1	0.1	0.1
Interest cost	0.3	0.3	0.3
Expected return on plan assets		0	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	0	0	0
Amortization of prior service costs	0.3	0.3	0.3
Amortization of actuarial loss	0.1	0.1	0
Periodic expense	0.8	0.8	0.7
Pension and other postretirement plans adjustments:
Current period actuarial loss (gain)	(1.0)	0.4	1.0
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax	(0.1)	(0.1)	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax		0	0
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)	(0.4)	(0.3)
Defined Benefit Plan, Curtailments	0	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, before Tax	(1.5)	(0.1)	0.7
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	0.4
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Discount rate	5.00%	4.10%
Rate of increase in compensation	4.00%	3.60%
Discount rate	4.10%	4.70%	5.80%
Rate of increase in compensation	3.60%	4.00%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2013	0.2
2014	0.2
2015	0.3
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	128
Postretirement Health Care Benefits, Number of Eligible	90
Postretirement Health Care Benefits, Number of Employees Covered	29
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		86
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	71.7	55.2
Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	71.7	55.2
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	41.00%	40.00%
Domestic Equity Securities [Member] \| Level 1 [Member]
Change in plan assets
Ending Balance	0
Domestic Equity Securities [Member] \| Level 2 [Member]
Change in plan assets
Ending Balance	0
Domestic Equity Securities [Member] \| Level 3 [Member]
Change in plan assets
Ending Balance	29.3	22.2
Domestic Equity Securities [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	29.3	22.2
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
Cash and Cash Equivalents [Member] \| Level 2 [Member]
Change in plan assets
Ending Balance	0
Cash and Cash Equivalents [Member] \| Level 3 [Member]
Change in plan assets
Ending Balance	0.3	0.2
Cash and Cash Equivalents [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	0.3	0.2
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%	30.00%
Foreign Equity Securities [Member] \| Level 1 [Member]
Change in plan assets
Ending Balance	0
Foreign Equity Securities [Member] \| Level 2 [Member]
Change in plan assets
Ending Balance	0
Foreign Equity Securities [Member] \| Level 3 [Member]
Change in plan assets
Ending Balance	21.3	16.6
Foreign Equity Securities [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	21.3	16.6
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	29.00%	30.00%
Debt Securities [Member] \| Level 1 [Member]
Change in plan assets
Ending Balance	0
Debt Securities [Member] \| Level 2 [Member]
Change in plan assets
Ending Balance	0
Debt Securities [Member] \| Level 3 [Member]
Change in plan assets
Ending Balance	20.8	16.2
Debt Securities [Member] \| Estimate of Fair Value, Fair Value Disclosure [Member]
Change in plan assets
Ending Balance	20.8	16.2
Realized Gain (Loss) on Sale of Investments [Member]
Change in plan assets
Actual gain (loss) on plan assets	0.9	0.7
Unrealized Gain (Loss or Write-down) [Member]
Change in plan assets
Actual gain (loss) on plan assets	$ 9.8	$ 6.3

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Expense (Benefit) [Abstract]
Current federal income tax expense (benefit)	$ 47.9	$ 33.7	$ (5.3)
Deferred federal income tax expense (benefit)	69.1	36.5	153.0
Current state income tax expense (benefit)	5.7	0.7	2.9
Deferred state income tax expense (benefit)	(2.9)	(4.4)	3.8
Total income tax expense	119.8	66.5	154.4
Deferred tax liabilities
Property, plant and equipment	1,651.1	1,606.6
Commodity price and interest rate derivatives	0	69.4
Total deferred tax liabilities	1,651.1	1,676.0
Deferred tax assets
Deferred Tax Assets, Derivatives	9.7	0
NOL and tax credit carryforwards	54.6	65.6
Employee benefits and compensation costs	36.1	47.7
Accrued litigation loss contingency	0.8	42.8
Bonus and vacation accrual	10.6	11.8
Other	9.3	9.6
Total deferred tax assets	121.1	177.5
Net deferred income tax liability	1,530.0	1,498.5
Deferred income tax liability - current	30.6	0
Deferred income tax liability -current	0	5.0
Deferred income tax liability - non-current	1,560.6	1,493.5
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	0.60%	(1.20%)	1.00%
Penalties	0.20%	(0.60%)	0.00%
Return to provision adjustment	(0.20%)	0.40%	1.30%
Noncontrolling interest	(1.40%)	(0.70%)	(0.30%)
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses	7.20%	0.00%	0.00%
Other	(0.30%)	0.60%	(0.70%)
Effective income tax rate	41.10%	33.50%	36.30%
Domestic Tax Authority [Member]
Deferred tax assets
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	28.1
State and Local Jurisdiction [Member]
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]
Operating Loss Carryforwards	$ 26.5
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

Operations by Line of Business (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Aug. 14, 2013
Segment Reporting Information [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	57.80%								57.80%			63.30%
Revenues
Total Revenues	$ 715.5	$ 772.8	$ 751.0	$ 696.5	$ 704.9	$ 542.4	$ 499.3	$ 603.2	$ 2,935.8	$ 2,349.8	$ 3,159.2
Operating expenses
Purchased gas, oil and NGL expense									765.9	655.6	1,077.1
Lease operating expense									177.8	172.3	145.2
Natural gas, oil and NGL transportation and other handling costs									141.4	148.9	102.2
Gathering, processing and other									90.6	88.0	107.3
General and administrative									191.1	266.6	123.2
Production and property taxes									166.5	103.4	105.4
Results of Operations, Depreciation, Depletion, Amortization and Accretion									1,016.0	905.3	765.6
Other Expenses									104.9	144.2	228.7
Operating Expenses									2,654.2	2,484.3	2,654.7
Gain (Loss) on Sale of Property Plant Equipment									103.0	1.2	1.4
OPERATING (LOSS) INCOME	(15.7)	128.2	207.3	64.8	(114.7)	(12.6)	(55.5)	49.5	384.6	(133.3)	505.9
Realized and unrealized gains (losses) on derivative contracts									58.9	441.9	0
Interest and other income									5.2	6.6	4.1
Income from unconsolidated affiliates									5.8	6.8	5.5
Loss from early extinguishment of debt									0	(0.6)	(0.7)
Interest expense									(163.3)	(122.9)	(90.0)
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(51.0)	63.5	284.6	(5.9)	(42.1)	(4.4)	0.3	244.7	291.2	198.5	424.8
Income taxes									(119.8)	(66.5)	(154.4)
NET INCOME									171.4	132.0	270.4
Net income attributable to noncontrolling interest									(12.0)	(3.7)	(3.2)
NET INCOME ATTRIBUTABLE TO QEP	(52.0)	37.3	178.4	(4.3)	(23.1)	(3.1)	(0.7)	155.2	159.4	128.3	267.2
Assets	9,376.8				9,108.5				9,376.8	9,108.5	7,442.7
Equity Method Investments	39.0				41.2				39.0	41.2	42.2
Cash capital expenditures									1,602.6	2,799.7	1,431.1
Accrued capital expenditures									1,577.4	2,888.2	1,445.9
Goodwill	0				59.5				0	59.5	59.5
Unaffiliated customers [Member]
Revenues
Total Revenues									2,935.8	2,349.8	3,159.2
Affiliated customers [Member]
Revenues
Total Revenues									0	0	0
QEP Energy [Member]
Revenues
Total Revenues									2,092.8	1,615.4	2,213.2
Operating expenses
Purchased gas, oil and NGL expense									197.1	224.7	506.4
Lease operating expense									181.3	175.8	148.2
Natural gas, oil and NGL transportation and other handling costs									242.2	228.1	186.0
Gathering, processing and other									0	0	0
General and administrative									139.7	236.3	98.4
Production and property taxes									159.8	97.2	99.1
Results of Operations, Depreciation, Depletion, Amortization and Accretion									954.2	838.4	707.4
Other Expenses									104.9	144.2	228.7
Operating Expenses									1,979.2	1,944.7	1,974.2
Gain (Loss) on Sale of Property Plant Equipment									104.1	1.2	1.4
OPERATING (LOSS) INCOME									217.7	(328.1)	240.4
Realized and unrealized gains (losses) on derivative contracts									59.1	434.9
Interest and other income									3.6	6.2	4.0
Income from unconsolidated affiliates									0.2	0.1	0.1
Loss from early extinguishment of debt									0	0	0
Interest expense									(192.6)	(116.8)	(81.9)
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest									88.0	(3.7)	162.6
Income taxes									(49.1)	4.3	(57.9)
NET INCOME									38.9	0.6	104.7
Net income attributable to noncontrolling interest									0	0	0
NET INCOME ATTRIBUTABLE TO QEP									38.9	0.6	104.7
Assets	7,930.6				7,436.5				7,930.6	7,436.5	5,815.7
Equity Method Investments					0					0	0
Cash capital expenditures									1,488.6	2,621.1	1,295.5
Accrued capital expenditures									1,467.2	2,702.4	1,338.8
Goodwill					59.5					59.5	59.5
QEP Energy [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									2,092.8	1,615.4	2,213.2
QEP Energy [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									0	0	0
QEP Field Services [Member]
Revenues
Total Revenues									403.4	439.2	465.5
Operating expenses
Purchased gas, oil and NGL expense									8.9	12.1	0
Lease operating expense									0	0	0
Natural gas, oil and NGL transportation and other handling costs									13.9	33.6	9.3
Gathering, processing and other									88.9	86.8	106.0
General and administrative									51.6	34.4	29.2
Production and property taxes									6.6	6.0	6.1
Results of Operations, Depreciation, Depletion, Amortization and Accretion									60.9	63.2	55.7
Other Expenses									0	0	0
Operating Expenses									230.8	236.1	206.3
Gain (Loss) on Sale of Property Plant Equipment									(0.5)	0	0
OPERATING (LOSS) INCOME									172.1	203.1	259.2
Realized and unrealized gains (losses) on derivative contracts									0	8.4
Interest and other income									1.2	0.2	0.1
Income from unconsolidated affiliates									5.6	6.7	5.4
Loss from early extinguishment of debt									0	0	0
Interest expense									(13.1)	(13.6)	(13.6)
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest									165.8	204.8	251.1
Income taxes									(55.4)	(71.8)	(93.4)
NET INCOME									110.4	133.0	157.7
Net income attributable to noncontrolling interest									(12.0)	(3.7)	(3.2)
NET INCOME ATTRIBUTABLE TO QEP									98.4	129.3	154.5
Assets	1,455.1				1,399.7				1,455.1	1,399.7	1,312.7
Equity Method Investments	39.0				41.2				39.0	41.2	42.2
Cash capital expenditures									89.8	164.0	130.1
Accrued capital expenditures									86.0	171.2	101.6
Goodwill					0					0	0
QEP Field Services [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									282.4	320.2	369.3
QEP Field Services [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									121.0	119.0	96.2
QEP Marketing and Other [Member]
Revenues
Total Revenues									1,573.2	1,019.9	1,156.9
Operating expenses
Purchased gas, oil and NGL expense									1,570.5	1,021.1	1,144.5
Lease operating expense									0	0	0
Natural gas, oil and NGL transportation and other handling costs									0	0	0
Gathering, processing and other									1.7	1.2	1.3
General and administrative									4.6	2.0	2.1
Production and property taxes									0.1	0.2	0.2
Results of Operations, Depreciation, Depletion, Amortization and Accretion									0.9	3.7	2.5
Other Expenses									0	0	0
Operating Expenses									1,577.8	1,028.2	1,150.6
Gain (Loss) on Sale of Property Plant Equipment									(0.6)	0	0
OPERATING (LOSS) INCOME									(5.2)	(8.3)	6.3
Realized and unrealized gains (losses) on derivative contracts									(0.2)	(1.4)
Interest and other income									206.9	132.1	98.7
Income from unconsolidated affiliates									0	0	0
Loss from early extinguishment of debt									0	(0.6)	(0.7)
Interest expense									(164.1)	(124.4)	(93.2)
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest									37.4	(2.6)	11.1
Income taxes									(15.3)	1.0	(3.1)
NET INCOME									22.1	(1.6)	8.0
Net income attributable to noncontrolling interest									0	0	0
NET INCOME ATTRIBUTABLE TO QEP									22.1	(1.6)	8.0
Assets	250.7				272.3				250.7	272.3	314.3
Equity Method Investments	0				0				0	0	0
Cash capital expenditures									24.2	14.6	5.5
Accrued capital expenditures									24.2	14.6	5.5
Goodwill					0					0	0
QEP Marketing and Other [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									560.6	414.2	576.7
QEP Marketing and Other [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									1,012.6	605.7	580.2
Elimination [Member]
Revenues
Total Revenues									(1,133.6)	(724.7)	(676.4)
Operating expenses
Purchased gas, oil and NGL expense									(1,010.6)	(602.3)	(573.8)
Lease operating expense									(3.5)	(3.5)	(3.0)
Natural gas, oil and NGL transportation and other handling costs									(114.7)	(112.8)	(93.1)
Gathering, processing and other									0	0	0
General and administrative									(4.8)	(6.1)	(6.5)
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									(1,133.6)	(724.7)	(676.4)
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	0
Interest and other income									(206.5)	(131.9)	(98.7)
Income from unconsolidated affiliates									0	0	0
Loss from early extinguishment of debt									0	0	0
Interest expense									206.5	131.9	98.7
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest									0	0	0
Income taxes									0	0	0
NET INCOME									0	0	0
Net income attributable to noncontrolling interest										0	0
NET INCOME ATTRIBUTABLE TO QEP									0	0	0
Assets	(259.6)				0				(259.6)	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
Elimination [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									0	0	0
Elimination [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									$ (1,133.6)	$ (724.7)	$ (676.4)

Subsequent Events (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Feb. 25, 2014	Dec. 31, 2013
Subsequent Event Note 15 [Abstract]
Business Acquisition, Cost of Acquired Entity, Purchase Price		$ 950.0	$ 1,392.7
Debt Instrument, Increase, Additional Borrowings	300.0
Line of Credit Facility, Increase, Additional Borrowings	$ 600.0

Quarterly Financial Information (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effect of Fourth Quarter Events [Line Items]
Revenues	$ 715.5	$ 772.8	$ 751.0	$ 696.5	$ 704.9	$ 542.4	$ 499.3	$ 603.2	$ 2,935.8	$ 2,349.8	$ 3,159.2
OPERATING (LOSS) INCOME	(15.7)	128.2	207.3	64.8	(114.7)	(12.6)	(55.5)	49.5	384.6	(133.3)	505.9
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(51.0)	63.5	284.6	(5.9)	(42.1)	(4.4)	0.3	244.7	291.2	198.5	424.8
NET INCOME ATTRIBUTABLE TO QEP	(52.0)	37.3	178.4	(4.3)	(23.1)	(3.1)	(0.7)	155.2	159.4	128.3	267.2
Non-recurring income(loss)	$ (99.0)	$ 9.0	$ 100.2	$ (0.2)	$ (62.4)	$ (9.0)	$ (55.4)	$ (5.0)	$ 10.0	$ (131.8)
Basic total	$ (0.29)	$ 0.21	$ 0.99	$ (0.02)	$ (0.13)	$ (0.02)	$ 0.00	$ 0.87	$ 0.89	$ 0.72	$ 1.51
Diluted total	$ (0.29)	$ 0.21	$ 0.99	$ (0.02)	$ (0.13)	$ (0.02)	$ 0.00	$ 0.87	$ 0.89	$ 0.72	$ 1.50

- 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 Accounting Standards Codification

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Reference 2: 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 3: 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.

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-Section 04

-Paragraph 18

-Article 7

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

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-Name Regulation S-X (SX)

-Number 210

-Section 03

-Paragraph 20

-Article 5

Reference 9: 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 10: http://www.xbrl.org/2003/role/presentationRef

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-Name Accounting Standards Codification

-Topic 260

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

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-Name Accounting Standards Codification

-Glossary Other Comprehensive Income

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

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

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-Name Accounting Standards Codification

-Glossary Net Income

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

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

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-Name Accounting Research Bulletin (ARB)

-Number 51

-Paragraph A7

-Appendix A

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-Name Accounting Research Bulletin (ARB)

-Number 51

-Paragraph 38

-Subparagraph d

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-Name Accounting Standards Codification

-Topic 944

-SubTopic 225

-Section S99

-Paragraph 1

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-Publisher FASB

-Name Emerging Issues Task Force (EITF)

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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

Supplemental Gas and Oil Information (Unaudited) Capitalized costs (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Capitalized Cost [Abstract]
Proved properties	$ 11,571.4	$ 10,234.3
Unproved properties, net	665.1	937.9
Total proved and unproved properties	12,236.5	11,172.2
Accumulated depreciation, depletion and amortization	(4,930.9)	(4,258.1)
Net capitalized costs	$ 7,305.6	$ 6,914.1

- 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, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Gas and Oil Information (Unaudited) [Abstract]
Accrued capital costs included in development costs	$ 21.4
Costs Incurred, Asset Retirement Obligation Incurred	17.2
Costs Incurred To Advance The Development Of Proved Undeveloped Reserves	645.9	513.0	533.6
Unproved	9.3	692.6	48.0
Proved	31.6	714.4	0.1
Total Property Acqusitions	40.9	1,407.0	48.1
Costs Incurred, Exploration Costs	14.6	14.3	36.5
Costs Incurred, Development Costs	1,440.8	1,310.0	1,267.8
Costs Incurred, Acquisition of Oil and Gas Properties	$ 1,496.3	$ 2,731.3	$ 1,352.4

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Results of Operations [Abstract]

Revenues (1)

$ 1,901.2

^[1]

$ 1,393.4

^[1]

$ 1,703.4

^[1]

Production costs

583.3

501.1

433.3

Exploration expenses

11.9

11.2

10.5

Depreciation, depletion and amortization

954.2

838.4

707.4

Abandonment and impairment

93.0

133.0

218.2

Total expenses

1,642.4

1,483.7

1,369.4

Income before income taxes

258.8

(90.3)

334.0

Income taxes

(96.3)

33.6

(119.0)

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

$ 162.5

$ (56.7)

$ 215.0

[1]	Revenue for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts which during the years ended December 31, 2013 and 2012, are reflected below operating income (loss) on the Consolidated Statements of Operations. See Note 7 - Derivative Contracts.

Supplemental Gas and Oil Information (Unaudited) Estimated Quantities of Proved Gas and Oil Reserves (Details)	12 Months Ended
	Dec. 31, 2013 MMcf	Dec. 31, 2012 MMcf	Dec. 31, 2011 MMcf	Dec. 31, 2010 MMcf
Natural Gas [Member]
Reserve Quantities [Line Items]
Reserves, Unit of Measure	(Bcf)
Proved reserves balance	2,622,400,000	2,749,400,000	2,612,900,000
Extensions and discoveries	(288,300,000)	(240,600,000)	(270,100,000)
Extensions and discoveries	455,600,000	330,600,000	641,900,000
Purchase of reserves in place	1,000,000	32,300,000	1,900,000
Sale of reserves in place	(16,900,000)	0	(800,000)
Production	(218,900,000)	(249,300,000)	(236,400,000)
Proved reserves balance	2,554,900,000	2,622,400,000	2,749,400,000
Proved developed reserves	1,406,300,000	1,531,700,000	1,538,300,000	1,404,800,000
Proved undeveloped reserves	1,148,600,000	1,090,700,000	1,211,100,000	1,208,100,000
Oil [Member]
Reserve Quantities [Line Items]
Reserves, Unit of Measure	(MMbbl)
Proved reserves balance	119,000,000	67,500,000	52,300,000
Extensions and discoveries	1,300,000	(1,500,000)	1,700,000
Extensions and discoveries	38,300,000	17,300,000	17,400,000
Purchase of reserves in place	1,900,000	42,000,000	0
Sale of reserves in place	(1,700,000)	0	(200,000)
Production	(10,200,000)	(6,300,000)	(3,700,000)
Proved reserves balance	148,600,000	119,000,000	67,500,000
Proved developed reserves	71,800,000	47,400,000	33,000,000	25,100,000
Proved undeveloped reserves	76,800,000	71,600,000	34,600,000	27,200,000
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Reserves, Unit of Measure	(MMbbl)
Proved reserves balance	99,900,000	76,600,000	17,400,000
Extensions and discoveries	(8,000,000)	700,000	39,300,000
Extensions and discoveries	16,400,000	23,000,000	22,600,000
Purchase of reserves in place	200,000	4,900,000	0
Sale of reserves in place	(1,100,000)	0	0
Production	(4,800,000)	(5,300,000)	(2,700,000)
Proved reserves balance	102,600,000	99,900,000	76,600,000
Proved developed reserves	52,800,000	49,300,000	38,400,000	9,300,000
Proved undeveloped reserves	49,800,000	50,600,000	38,200,000	8,000,000
Total Reserves Natural Gas Equivalent [Member]
Reserve Quantities [Line Items]
Reserves, Unit of Measure	(Bcfe)
Proved reserves balance	3,936,100,000	3,613,800,000	3,030,700,000
Extensions and discoveries	(328,500,000)	(244,800,000)	(23,500,000)
Extensions and discoveries	783,800,000	572,500,000	881,600,000
Purchase of reserves in place	13,400,000	313,800,000	2,100,000
Sale of reserves in place	(33,900,000)	0	(1,900,000)
Production	(309,000,000)	(319,200,000)	(275,200,000)
Proved reserves balance	4,061,900,000	3,936,100,000	3,613,800,000
Proved developed reserves	2,154,000,000	2,111,900,000	1,966,300,000	1,611,500,000
Proved undeveloped reserves	1,907,900,000	1,824,200,000	1,647,500,000	1,419,200,000

Supplemental Gas and Oil Information (Unaudited) Future Development Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Future Development Costs [Abstract]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Next Twelve Months	$ 852.6
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Two	1,183.8
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Three	$ 1,094.4

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Standardized Measure of Future Net Cash Flows [Abstract]
Future cash inflows	$ 24,805.7	$ 18,200.2	$ 18,300.6
Future production costs	(8,400.3)	(5,027.2)	(4,276.1)
Future development costs	(4,056.7)	(3,927.3)	(3,250.0)
Future income tax expenses	(3,284.6)	(2,269.0)	(2,837.1)
Future net cash flows	9,064.1	6,976.7	7,937.4
10% annual discount for estimated timing of net cash flows	(4,680.2)	(3,942.0)	(4,411.8)
Standardized measure of discounted future net cash flows	$ 4,383.9	$ 3,034.7	$ 3,525.6

- 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.

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- 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.

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- 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.

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in Standardized Measure of Future Cash Flows [Abstract]
Beginning Balance	$ 3,034.7	$ 3,525.6	$ 2,705.6
Sales of gas, oil and NGL produced during the period, net of production costs	(1,317.9)	(892.3)	(1,779.9)
Net change in sales prices and in production (lifting) costs related to future production	1,236.3	(2,083.5)	1,472.5
Net change due to extensions, discoveries and improved recovery	2,230.7	948.5	1,806.4
Net change due to revisions of quantity estimates	(709.6)	(387.8)	(48.2)
Changes due to purchases of reserves in place	36.8	831.0	0
Changes due to sales of reserves in place	(73.0)	0	(8.0)
Previously estimated development costs incurred during the period	722.7	513.0	533.6
Changes in estimated future development costs	(596.5)	(209.3)	(1,110.4)
Accretion of discount	402.2	499.4	355.4
Net change in income taxes	(601.7)	273.6	(411.4)
Other	19.4	16.1	9.9
Net change	1,349.2	(490.9)	820.0
Ending Balance	$ 4,383.9	$ 3,034.7	$ 3,525.6

Schedule of Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Valuation and Qualifying Accounts Disclosure [Line Items]
Bad Debt Expense	$ 3.5	$ 1.4	$ 0.2
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	2.8	1.7	2.3
Valuation Allowances and Reserves, Balance		2.8	1.7
Valuation Allowances and Reserves, Deductions	(1.2)	(0.3)	(0.8)
Allowance for Doubtful Accounts Receivable	$ 5.1	$ 2.8	$ 1.7

- Definition

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Summary of Significant Accounting Policies Revenue Recognition (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Summary of Significant Accounting Policies [Abstract]
Gas Balancing Asset (Liability)	$ 18.6	$ 13.2

Environmental (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Environmental Exit Cost [Line Items]
Accrual for Environmental Loss Contingencies, Payments	$ 0.2