Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2014	Jan. 31, 2015	Jun. 30, 2014
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		175,549,934
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Entity Public Float			$ 6,213,156,302

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES
Gas sales	$ 776.4	$ 779.0	$ 667.4
Oil sales	1,368.5	916.6	532.6
NGL sales	223.3	192.2	184.2
Other revenues	11.1	22.4	27.5
Purchased gas, oil and NGL sales	1,035.0	774.9	660.0
Total Revenues	3,414.3	2,685.1	2,071.7
OPERATING EXPENSES
Purchased gas, oil and NGL expense	1,031.2	783.5	670.7
Lease operating expense	240.1	181.3	175.8
Gas, oil and NGL transportation and other handling costs	277.6	222.0	198.1
Gathering and other expense	6.7	8.4	8.2
General and administrative	204.4	160.4	248.4
Production and property taxes	205.2	161.3	98.5
Depreciation, depletion and amortization	994.7	963.8	850.2
Exploration expenses	9.9	11.9	11.2
Impairment	1,143.2	93.0	133.0
Total Operating Expenses	4,113.0	2,585.6	2,394.1
Net gain (loss) from asset sales	(148.6)	103.5	1.2
OPERATING INCOME (LOSS)	(847.3)	203.0	(321.2)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	363.3	58.9	433.5
Interest and other income	12.8	15.2	15.0
Income from unconsolidated affiliates	0.3	0.2	0.1
Loss from early extinguishment of debt	(2.0)	0	(0.6)
Interest expense	(169.1)	(165.1)	(126.3)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(642.0)	112.2	0.5
Income tax (provision) benefit	232.5	(60.1)	1.9
NET INCOME FROM CONTINUING OPERATIONS	(409.5)	52.1	2.4
Net income from discontinued operations, net of income tax	1,193.9	107.3	125.9
NET INCOME ATTRIBUTABLE TO QEP	$ 784.4	$ 159.4	$ 128.3
Earnings (Loss) Per Common Share Attributable to QEP
Basic total	$ 4.36	$ 0.89	$ 0.72
Diluted total	$ 4.36	$ 0.89	$ 0.72
Weighted-average common shares outstanding
Used in basic calculation	179.8	179.2	177.8
Used in diluted calculation	179.8	179.5	178.7
Dividends per common share	$ 0.08	$ 0.08	$ 0.08
Continuing Operations [Member]
Earnings (Loss) Per Common Share Attributable to QEP
Basic total	$ (2.28)	$ 0.29	$ 0.01
Diluted total	$ (2.28)	$ 0.29	$ 0.01
Discontinued Operations [Member]
Earnings (Loss) Per Common Share Attributable to QEP
Basic total	$ 6.64	$ 0.60	$ 0.71
Diluted total	$ 6.64	$ 0.60	$ 0.71

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

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Statement of Comprehensive Income [Abstract]

Net income attributable to QEP

$ 784.4

$ 159.4

$ 128.3

Other comprehensive income, (loss), net of tax:

Reclassification of previously deferred derivative (gains) losses

^[1]

(77.6)

^[1]

(171.1)

^[1]

Pension and other postretirement plans adjustments:

Current year net actuarial gain (loss)

(13.6)

^[2]

13.5

^[2]

(10.0)

^[2]

Amortization of net actuarial loss

0.5

^[3]

1.5

^[3]

1.1

^[3]

Amortization of net prior service cost

9.7

^[4]

3.3

^[4]

3.5

^[4]

Net curtailment and settlements cost incurred

5.6

^[5]

1.4

^[5]

Total pension and other postretirement plans adjustments

2.2

18.3

(4.0)

Other comprehensive income (loss)

2.2

(59.3)

(175.1)

Comprehensive income (loss) attributable to QEP

$ 786.6

$ 100.1

$ (46.8)

[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.
[2]	Presented net of income tax benefit of $8.5 million for the year ended December 31, 2014, 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 during the year ended December 31, 2012
[3]	Presented net of income tax expense of $0.3 million, $0.9 million and $0.9 million during the years ended December 31, 2014, 2013, and 2012, respectively.
[4]	Presented net of income tax expense of $6.0 million, $2.1 million and $2.2 million during the years ended December 31, 2014, 2013 and 2012, respectively.
[5]	Presented net of income tax expense of $3.5 million for the year ended December 31, 2014 and $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, 2014	Dec. 31, 2013	Dec. 31, 2012
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
Pension and other postretirement plans adjustments:
Tax expense on prior service cost incurred	(6.0)	(2.1)	(2.2)
Tax expense on net curtailment and settlements cost incurred	(3.5)		(0.8)
Current year net actuarial gain loss [Member]
Pension and other postretirement plans adjustments:
Tax benefit (expense) on net unamortized gain (loss) incurred	8.5	(8.3)	6.3
Amortization net actuarial gain loss [Member] [Member]
Pension and other postretirement plans adjustments:
Tax benefit (expense) on net unamortized gain (loss) incurred	$ (0.3)	$ (0.9)	$ (0.9)

CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current Assets
Cash and cash equivalents	$ 1,160.1	$ 11.9
Accounts receivable, net	441.9	330.3
Fair value of derivative contracts	339.0	0.2
Gas, oil and NGL inventories, at lower of average cost or market	13.7	13.4
Deferred income taxes - current	0	27.9
Prepaid expenses and other	46.8	45.4
Current assets of discontinued operations	0	122.0
Total Current Assets	2,001.5	551.1
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	12,278.7	11,571.4
Unproved properties	825.2	665.1
Marketing and other	293.8	282.8
Materials and supplies	54.3	54.3
Total Property, Plant and Equipment	13,452.0	12,573.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,153.0	4,930.9
Marketing and other	67.8	50.2
Total Accumulated Depreciation, Depletion and Amortization	6,220.8	4,981.1
Net Property, Plant and Equipment	7,231.2	7,592.5
Fair value of derivative contracts	9.9	1.0
Restricted cash	0	50.0
Other noncurrent assets	44.2	46.6
Noncurrent assets of discontinued operations	0	1,167.7
TOTAL ASSETS	9,286.8	9,408.9
Current Liabilities
Checks outstanding in excess of cash balances	54.7	109.1
Accounts payable and accrued expenses	575.4	361.9
Income taxes payable	532.1	8.7
Production and property taxes	61.7	54.7
Interest payable	36.4	37.2
Fair value of derivative contracts	0	26.7
Deferred income taxes	84.5	0
Current liabilities of discontinued operations	0	75.3
Total Current Liabilities	1,344.8	673.6
Long-term debt	2,218.1	2,997.5
Deferred income taxes	1,362.7	1,364.9
Asset retirement obligations	193.8	163.3
Other long-term liabilities	92.1	94.5
Noncurrent liabilities of discontinued operations	0	238.3
Commitments and contingencies (Note 10)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 176.2 million and 179.7 million shares issued, respectively	1.8	1.8
Treasury stock - 0.8 million and 0.4 million shares, respectively	(25.4)	(14.9)
Additional paid-in capital	535.3	498.4
Retained earnings	3,587.9	2,917.8
Accumulated other comprehensive (loss) income	(24.3)	(26.5)
Total Common Shareholders' Equity	4,075.3	3,376.6
Noncontrolling interest	0	500.2
Total Equity	4,075.3	3,876.8
TOTAL LIABILITIES AND EQUITY	$ 9,286.8	$ 9,408.9

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
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)	176.2	179.7
Treasury stock (in shares)	0.8	0.4

CONSOLIDATED STATEMENTS OF EQUITY (USD $) In Millions, unless otherwise specified	Total	Common Stock [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2011	$ 3,352.1	$ 1.8	$ (13.1)	$ 431.4	$ 2,673.5	$ 207.9	$ 50.6
Treasury Stock, Shares at Dec. 31, 2011			(0.4)
Shares, Issued at Dec. 31, 2011		177.2
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to QEP	128.3				128.3		3.7
Total net income including portion attributable to noncontrolling interest	132.0
Dividends	(14.2)				(14.2)
Equity-based compensation	23.2	0	7.1	30.7	(14.6)
Equity-based compensation, shares issued		1.3
Equity-based compensation, treasury shares reissued			0.2
Distribution to QEP Education Foundation	2.3		2.3
Distribution of noncontrolling interest	(6.6)						(6.6)
Net proceeds from QEP Midstream initial public offering	0
Distribution to QEP Education Foundation, treasury shares reissued			0.1
Reclassification of previously deferred derivative gains in OCI, net of tax	(171.1)					(171.1)
Change in pension and postretirement liability, net of tax	(4.0)					(4.0)
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
Treasury Stock, Shares at Dec. 31, 2012			(0.1)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to QEP	159.4				159.4		12.0
Total net income including portion attributable to noncontrolling interest	171.4
Dividends	(14.3)				(14.3)
Equity-based compensation	25.0	0	(11.2)	36.3	(0.3)		0.2
Equity-based compensation, shares issued		1.2
Equity-based compensation, treasury shares reissued			(0.3)
Distribution of noncontrolling interest	(9.3)						(9.3)
Net proceeds from QEP Midstream initial public offering	449.6						449.6
Reclassification of previously deferred derivative gains in OCI, net of tax	(77.6)					(77.6)
Change in pension and postretirement liability, net of tax	18.3					18.3
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		179.7
Treasury Stock, Shares at Dec. 31, 2013	(0.4)		(0.4)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to QEP	784.4				784.4		0
Total net income including portion attributable to noncontrolling interest	784.4
Dividends	(14.6)				(14.6)
Equity-based compensation	26.6	0	(10.5)	36.9	0		0.2
Equity-based compensation, shares issued		1.2
Equity-based compensation, treasury shares reissued			(0.4)
Distribution of noncontrolling interest	(31.9)						(31.9)
Net proceeds from QEP Midstream initial public offering	0
Reclassification of previously deferred derivative gains in OCI, net of tax						0
Common stock repurchased and retired	(99.7)				(99.7)
Common stock repurchased and retired, shares		(4.7)
Change in pension and postretirement liability, net of tax	2.2					2.2
Noncontrolling interest decrease from Midstream Sale	(468.5)						(468.5)
Balance at Dec. 31, 2014	$ 4,075.3	$ 1.8	$ (25.4)	$ 535.3	$ 3,587.9	$ (24.3)	$ 0
Shares, Issued at Dec. 31, 2014		176.2
Treasury Stock, Shares at Dec. 31, 2014	(0.8)		(0.8)

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OPERATING ACTIVITIES
Net income attributable to QEP	$ 784.4	$ 159.4	$ 128.3
Net income attributable to noncontrolling interest	21.6	12.0	3.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,040.6	1,016.0	905.3
Deferred income taxes	(84.1)	66.1	32.1
Impairment	1,143.2	93.0	133.0
Equity-based compensation	27.2	27.1	25.6
Amortization of debt issuance costs and discounts	6.7	6.4	5.3
Net gain from asset sales	(1,644.8)	(103.0)	(1.2)
Income from unconsolidated affiliates	(5.2)	(5.8)	(6.8)
Distributions from unconsolidated affiliates and other	9.4	7.9	7.9
Non-cash loss on early extinguishment of debt	4.4	0	0
Unrealized loss (gain) on derivative contracts	(374.4)	88.7	(63.2)
Changes in operating assets and liabilities
Accounts receivable	(160.5)	3.2	9.6
Inventories	(20.2)	2.6	28.7
Prepaid expenses	(7.3)	14.0	(16.8)
Accounts payable and accrued expenses	320.1	(179.7)	101.3
Federal income taxes	494.1	(27.4)	3.5
Other	(12.7)	11.2	(0.3)
Net Cash Provided by Operating Activities	1,542.5	1,191.7	1,296.0
INVESTING ACTIVITIES
Property acquisitions	(960.5)	(40.9)	(1,406.1)
Property, plant and equipment, including dry exploratory well expense	(1,765.9)	(1,561.7)	(1,393.6)
Proceeds from disposition of assets	3,296.6	211.1	5.2
Acquisition deposit held in escrow	50.0	(50.0)	0
Other investments	(42.0)	0	0
Net Cash Provided by (Used in) Investing Activities	578.2	(1,441.5)	(2,794.5)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(54.4)	69.3	10.3
Long-term debt issued	300.0	0	1,450.0
Long-term debt issuance costs paid	(9.3)	(3.2)	(17.8)
Long-term debt repaid	(600.0)	0	(6.7)
Proceeds from credit facility	5,455.0	3,085.0	2,739.0
Repayments of credit facility	(5,935.0)	(3,295.0)	(2,655.5)
Common stock repurchased and retired	(99.7)	0	0
Treasury stock repurchased	(6.2)	(9.3)	0
Other capital contributions	6.0	7.0	(2.2)
Dividends paid	(14.6)	(14.3)	(14.2)
Excess tax benefit on equity-based compensation	(0.5)	0	2.2
Net proceeds from the issuance of common units	0	449.6	0
Distribution to noncontrolling interest	(31.9)	(9.3)	(6.6)
Net Cash (Used in) Provided by Financing Activities	(990.6)	279.8	1,498.5
Change in cash and cash equivalents	1,130.1	30.0	0
Beginning cash and cash equivalents	30.0	0	0
Ending cash and cash equivalents	$ 1,160.1	$ 30.0	$ 0

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

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 two subsidiaries, QEP Energy Company and QEP Marketing Company, which are engaged in two primary lines of business: (i) oil and gas exploration and production (QEP Energy) and (ii) oil and gas marketing, operation of the Haynesville Gathering System and an underground gas storage reservoir (QEP Marketing and Other).

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

In October 2014, the Company announced that its wholly owned subsidiary, QEP Field Services Company (QEP Field Services), had entered into a definitive agreement to sell substantially all of its midstream business, including the Company's ownership interest in QEP Midstream Partners, LP (QEP Midstream), to Tesoro Logistics LP (Tesoro). On December 2, 2014, QEP closed the sale of its midstream business to Tesoro (Midstream Sale) for total cash proceeds of $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, subject to post-closing adjustments, and QEP recorded a pre-tax gain of $1.8 billion on its Consolidated Statements of Operations in "Net income from discontinued operations, net of income tax" for the year ended December 31, 2014. The decision to sell the midstream business was the result of the Company’s ongoing review of strategic alternatives to maximize shareholder value. QEP Marketing retained ownership of the Haynesville Gathering System. As a result of the Midstream Sale, the QEP Field Services reporting segment, excluding the retained ownership of the Haynesville Gathering System, has been classified as a discontinued operation on the Consolidated Statement of Operations and the Notes accompanying the Consolidated Financial Statements. For reporting purposes, the Haynesville Gathering System, which was retained by QEP Marketing, has been combined with QEP Marketing and Other.

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. The Consolidated Financial Statements were prepared in accordance with 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 Annual Report on Form 10-K are in millions, except per-share information and where otherwise noted.

Reclassifications

The 2013 and 2012 financial information has been recast so that the basis of presentation is consistent with that of the 2014 financial information. This recast reflects the financial condition and results of operations of QEP Field Services, excluding the Haynesville Gathering System, as discontinued operations for all periods presented. For reporting purposes, the retained Haynesville Gathering System has been combined with QEP Marketing and Other. For a summary of discontinued operations see Note 3 - Discontinued 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, 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.

Risks and Uncertainties

The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for gas, oil and NGL, each of which depend on numerous factors beyond the Company’s control such as economic conditions, regulatory developments, global supply and demand and competition from other energy sources. The energy markets historically have been volatile and oil and gas prices at the end of 2014 and during the first part of 2015 have been substantially lower than recent historical averages, and may be subject to significant fluctuations in the future. The Company’s derivative contracts serve to mitigate a portion of the effect of this price volatility on the Company’s cash flows, and the Company has derivative contracts in place for a portion of its expected 2015 and 2016 oil and gas production. See Note 7 - Derivative Contracts for the Company’s open oil and gas commodity derivative contracts. The Company is dependent on cash on hand, availability under its credit facility, along with cash flows from operating activities, to fund its capital expenditures. Based on its current cash on hand, anticipated oil and gas prices and availability under its credit facility, the Company expects to be able to fund its planned capital expenditures and operating expenses for 2015. However, a substantial or extended decline in oil and gas prices could have an adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and gas reserves that may be economically produced, and could impact the Company’s ability to comply with the financial covenants under the credit facility and could limit further borrowings to fund capital expenditures. Additionally, as forward prices have continued to decline during 2015, there could be additional impairment charges to our oil and gas assets or other investments.

Revenue Recognition

QEP subsidiaries recognize revenues in the period that services are provided or products are delivered. Revenues associated with the sale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized as oil, gas and NGL 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, 2014 and 2013, were $7.9 million and $10.7 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.

In most states in which QEP Energy operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume based.

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, 2014, none of QEP's cash and cash equivalents were restricted. As of December 31, 2013, QEP's restricted cash balance was $50.0 million, which consisted of a deposit paid by QEP that was held in escrow for an acquisition (see Note 2 - Acquisitions and Divestitures for further discussion on the acquisition). The cash payment is shown in investing activities on the Consolidated Statements of Cash Flows.

Supplemental cash flow information is shown in the below table:



	Year Ended December 31,
	2014		2013			2012
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	163.2	$	156.7		$	105.1
Cash paid for income taxes	0.3		77.9			30.0
Non-cash investing activities
Change in capital expenditure accrual balance	$	8.4	$	(25.2	)	$	88.5

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, 2014, 2013 and 2012, was $2.1 million, $0.1 million, and $1.3 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 $4.6 million at December 31, 2014 and $2.2 million at December 31, 2013.

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. Significant accounting policies for our property, plant and equipment are as follows:

Oil and gas properties

The Company follows the successful efforts method of accounting for oil and gas property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as 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 that have been 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 generally based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using the straight-line method. 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, and other than temporary declines in gas, oil and NGL prices. 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, 2014, QEP recorded impairment charges of $1,143.2 million, of which $1,041.4 million related to price-related impairment charges on proved properties and $101.8 million related to impairment on unproved properties due to lower future prices, lease expirations and changes in drilling plans. Of the $1,143.2 million property impairment charges incurred during the year ended December 31, 2014, $1,116.8 million related to oil and gas properties in the Southern Region and $26.4 million related to oil and gas properties in the Northern Region.

During the year ended December 31, 2013, QEP recorded impairment charges of $93.0 million, of which $1.2 million was related to price-related impairment charges on proved properties and $32.3 million was related 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 of 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.

Asset Retirement Obligations

QEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The majority of QEP's asset retirement obligations (ARO) relate to the plugging of wells and the related abandonment of oil and gas properties. 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.

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 related to the Company's Uinta Basin reporting unit within QEP Energy was reduced to zero from $59.5 million in 2012 due to the recognition of impairment during 2013. Goodwill was tested for impairment under a two-step quantitative test on an annual basis or when a triggering event occurred. Under the first step, the estimated fair value of the reporting unit was compared with its carrying value (including goodwill). QEP determined fair value of its reporting units in which goodwill was allocated using the income approach in which the fair value was estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model considered 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 exceeded its carrying value, step two did not need to be performed. If the estimated fair value of the reporting unit was less than its carrying value, an indication of goodwill impairment existed for the reporting unit and the enterprise performed step two of the impairment test (measurement). Under step two, an impairment loss was 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 was 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 was the implied fair value of the reporting unit goodwill. Fair value of the reporting unit under the two-step assessment was determined using a discounted cash flow analysis.

During the performance of QEP's annual goodwill impairment test at December 31, 2013, 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, 2014, 2013 and 2012, an unrealized gain of $374.4 million, an unrealized loss of $88.7 million and an unrealized gain 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. 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

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 33%, 38%, and 27% of QEP's revenues for the years ended December 31, 2014, 2013 and 2012, respectively. During the year ended December 31, 2014, Valero Marketing and Supply Company made up 10% of the Company's total revenues. During the year ended December 31, 2013, Freepoint Commodities, LLC and Arrow Midstream Holdings, LLC accounted for 13% and 11%, respectively, of the Company's total revenues. During the year ended December 31, 2012, no customer accounted 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. During the year ended December 31, 2014, the Company recorded a valuation allowance of $18.4 million against the state net operation loss deferred tax asset, because the sale of properties in Oklahoma in 2014 will preclude its utilization in the future. There were no unrecognized tax benefits at the beginning or end of the twelve-month periods ended December 31, 2013 and 2012. All federal income tax returns prior to 2014 have been examined by the Internal Revenue Service and are closed. Income tax returns for 2014 have not yet been filed. Most state tax returns for 2011 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. QEP acquires treasury stock from stock forfeitures and withholdings and uses the acquired treasury stock for option exercises and certain stock grants to employees; refer to Note 11 - Equity-Based Compensation for additional information.

Share Repurchases and Retirements

In January 2014, QEP's Board of Directors authorized the repurchase of up to $500.0 million of the Company's outstanding shares of common stock. This program was extended through December 2015. The timing and amount of any QEP share repurchases will depend upon a number of factors, including general market conditions, the Company’s financial position and the estimated intrinsic value of the Company’s shares. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time. Shares repurchased under the plan represent common stock and are retired after repurchase. During December 2014, QEP repurchased 4,731,438 shares at a weighted average price of $21.08 per share, including commission of $0.02 per share, for $99.7 million under this program.

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, have a minimal historical forfeiture rate and 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. For the twelve months ended December 31, 2014, 0.3 million shares were not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss from continuing operations. A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:



	December 31,
	2014	2013	2012
	(in millions)
Weighted-average basic common shares outstanding	179.8	179.2	177.8
Potential number of shares issuable under the Long-Term Stock Incentive Plan	—	0.3	0.9
Average diluted common shares outstanding	179.8	179.5	178.7

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), which 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. 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) and the rate of future compensation increases. 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 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 and QEP Marketing and Other. QEP's former reporting segment, QEP Field Services, excluding the retained ownership of the Haynesville Gathering System, was sold in 2014 and has been classified as a discontinued operation on the Consolidated Statement of Operations and the Notes accompanying the Consolidated Financial Statements. The Haynesville Gathering System, which was retained by QEP Marketing, is included the reporting segment QEP Marketing and Other.

Recent Accounting Developments

In August 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Topic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This guidance provides additional information to guide management's evaluation of whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. The update is effective for annual periods beginning on or after December 15, 2016. The Company is currently evaluating the impact of this standard on the Company's Consolidated Financial Statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments are effective prospectively for reporting periods beginning after December 15, 2016 and early adoption is not permitted. The Company is currently assessing the impact on the Company's Consolidated Financial Statements.

In April 2014, the FASB issued Accounting Standards Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which broadened the reporting of discontinued operations to a component of an entity that has operations and cash flows that can be clearly distinguished from the rest of the entity. Under this guidance, to be a discontinued operation, a component or group of components must represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2014 and early adoption is permitted. The Company chose to early adopt ASU 2014-08 and implemented the amendments during the quarter ended September 30, 2014.

- Definition

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

+ References+ Details

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Acquisitions and divestitures [Text Block]

Permian Basin Acquisition

On February 25, 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $941.8 million, subject to post-closing 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 270 vertical producing wells in the Permian Basin, which created a new core area of operation for QEP Energy. The acquisition was funded with $50.0 million of restricted cash, $300.0 million from the Company's expanded term loan and the remainder was funded from its revolving credit facility.

The Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included significant proved properties. QEP allocated the cost of the Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $159.5 million and a net loss of $438.3 million were generated from the acquired properties from February 25, 2014, to December 31, 2014, and are included in QEP's Consolidated Statements of Operations. The net loss is primarily due to an impairment on proved properties of $467.7 million recognized in 2014 due to the decrease in the future oil prices. During the year ended December 31, 2014, QEP Energy incurred acquisition-related costs of $0.6 million, which are included in "General and administrative" on the Consolidated Statement of Operations for the year ended December 31, 2014. QEP incurred $1.1 million of debt issuance costs associated with increasing the size of term loan borrowings to fund a portion of the acquisition, which was subsequently written off when the term loan was repaid in December 2014 with proceeds from the Midstream Sale.

The Consolidated Balance Sheet as of December 31, 2014 includes the Permian Basin Acquisition. The following table presents a summary of the Company's purchase accounting entries:



	As of December 31, 2014
	(in millions)
Consideration:
Total consideration paid	$	941.8

Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	472.1
Unproved properties	480.6
Asset retirement obligations	(9.7		)
Liabilities assumed	(1.2		)
Total fair value	$	941.8

The following unaudited, pro forma results of operations are provided for the years ended December 31, 2014 and 2013. 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 period 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, 2014 and 2013, the acquired properties' historical results of operations, and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the preliminary purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.



	Year ended December 31,
	2014				2013
	Actual		Pro forma		Actual		Pro forma
	(in millions, except per share data)

Revenues	$	3,414.3	$	3,440.4	$	2,685.1	$	2,858.8
Net income attributable to QEP	$	784.4	$	791.4	$	159.4	$	195.3
Earnings per common share attributable to QEP
Basic	$	4.36	$	4.40	$	0.89	$	1.09
Diluted	$	4.36	$	4.40	$	0.89	$	1.09

Williston Basin Acquisition

On September 27, 2012, QEP Energy acquired oil and gas properties in the Williston Basin for an aggregate purchase price of $1.4 billion (the Williston Basin 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 Williston Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included proved properties. QEP allocated the cost of the Williston Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $767.3 million, $300.0 million and $63.7 million and net income of $402.1 million, $67.0 million and $14.9 million were generated from the acquired properties during the years ended December 31, 2014, 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.

The following unaudited, pro forma results of operations are provided for the year ended December 31, 2012. 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 year ended December 31, 2012, the acquired properties' historical results of operations and 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 Williston Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.



	Year ended December 31,
	2012
	Actual		Pro forma
	(in millions, except per share data)
Revenues	$	2,071.7	$	2,207.2
Net income attributable to QEP	$	128.3	$	143.0
Earnings per common share attributable to QEP
Basic	$	0.72	$	0.80
Diluted	$	0.72	$	0.80

Divestitures

In June 2014, QEP Energy sold its interests in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for aggregate proceeds of $692.9 million, subject to post-closing purchase price adjustments, and recorded a pre-tax loss of $199.4 million. In December 2014, QEP sold its interest in certain non-core properties in southern Oklahoma for aggregate proceeds of $94.9 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $53.3 million.

In June 2013, QEP Energy sold its interests in several non-core oil and gas properties located in QEP's Northern Region for aggregate 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 aggregate proceeds of $67.3 million and recorded a pre-tax gain on sale of $9.5 million.

These gains and losses are reported on the Consolidated Statements of Operations in "Net gain (loss) from asset sales".

Discontinued Operations

12 Months Ended

Dec. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

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

In December 2013, QEP's Board of Directors authorized the Company to develop a plan to separate its midstream business, QEP Field Services, including the Company's interest in QEP Midstream, from QEP. Between December 2013 and September 2014, the Company evaluated transaction alternatives, including selling or merging the midstream business or spinning the midstream business off to its shareholders. In June 2014, QEP filed a registration statement on Form 10 with the U.S. Securities and Exchange Commission (SEC) in preparation for a potential spinoff of QEP Field Services as a separate publicly traded company. Concurrently, the Company evaluated selling or merging its midstream business. In September 2014, based on the proposals received, the Company's Board of Directors authorized QEP's management to engage in the negotiation of terms of a definitive transaction with Tesoro.

In October 2014, the Company announced that its wholly owned subsidiary, QEP Field Services, had entered into a definitive agreement to sell substantially all of its midstream business, including the Company's ownership interest in QEP Midstream. On December 2, 2014, QEP closed the Midstream Sale for total cash proceeds of $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, and QEP recorded a pre-tax gain of $1.8 billion on its Consolidated Statements of Operations in "Net income from discontinued operations, net of income tax" for the year ended December 31, 2014. Subsequent to the Midstream Sale, QEP withdrew its registration statement on Form 10 with the SEC.

As of December 31, 2014, the operating results of QEP Field Services, excluding the Haynesville Gathering System, were classified as discontinued operations on its Consolidated Statements of Operations. QEP will have continuing cash outflows to the entities sold as a part of the Midstream Sale for gathering, processing and water handling costs in Pinedale, the Uinta Basin and a portion of its Williston Basin operations. The contracts related to these cash flows vary in length from month-to-month to over a year and will be reviewed periodically in the normal course of business. Historically, these transactions were eliminated in consolidation, as they represented transactions between two related entities but are now reflected as part of the continuing operations for QEP. For the years ended December 31, 2014, 2013 and 2012, cash outflows for these transactions included in continuing operations were $145.3 million, $124.6 million and $113.5 million, respectively.

Consolidated Statement of Operations

The discontinued operations of QEP Field Services (excluding results of the Haynesville Gathering System) are summarized below:



	Year Ended December 31,
	2014			2013			2012
	(in millions)
REVENUES
NGL sales	$	109.3		$	101.9		$	137.9
Other revenues	140.9			166.6			154.1
Purchased gas, oil and NGL sales⁽¹⁾	(47.1		)	(17.8		)	(13.9		)
Total Revenues	203.1			250.7			278.1
OPERATING EXPENSES
Purchased gas, oil and NGL expense⁽¹⁾	(48.5		)	(17.6		)	(15.1		)
Lease operating expense⁽¹⁾	(5.5		)	(3.5		)	(3.5		)
Natural gas, oil and NGL transport & other handling costs⁽¹⁾	(55.4		)	(80.6		)	(49.2		)
Gathering, processing, and other	85.9			82.2			79.8
General and administrative	42.1			30.7			17.9
Production and property taxes	7.3			5.2			5.1
Depreciation, depletion and amortization	45.9			52.2			55.1
Total Operating Expenses	71.8			68.6			90.1
Net gain (loss) from asset sales	1,793.4			(0.5		)	—
OPERATING INCOME	1,924.7			181.6			188.0
Realized derivative gains	—			—			8.4
Interest and other income (expense)	0.3			(10.0		)	(8.2		)
Income from unconsolidated affiliates	4.9			5.6			6.7
Loss on early extinguishment of debt	(2.4		)	—			—
Interest expense (income)	(3.8		)	1.8			3.4
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES ⁽²⁾	1,923.7			179.0			198.3
Income tax provision	(708.2		)	(59.7		)	(68.7		)
NET INCOME FROM DISCONTINUED OPERATIONS	1,215.5			119.3			129.6
Net income attributable to noncontrolling interest	(21.6		)	(12.0		)	(3.7		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	1,193.9		$	107.3		$	125.9

___________________________


⁽¹⁾	Includes discontinued intercompany eliminations.


⁽²⁾	Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owned 57.8%) of $28.9 million, $33.5 million and $38.9 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Consolidated Balance Sheet

The current and noncurrent assets and liabilities of QEP Field Services (excluding the retained Haynesville Gathering System) are as follows:



	December 31, 2013

Cash and cash equivalents	$	18.1
Accounts receivable, net	53.9
Income taxes receivable	38.4
Deferred income taxes - current	2.7
Prepaid expenses and other	8.9
Current assets of discontinued operations	$	122.0

Property, Plant and Equipment
Midstream field services	$	1,500.8
Material and supplies	4.8
Total Property, Plant and Equipment	1,505.6
Less Accumulated Depreciation, Depletion and Amortization	(381.6		)
Net Property, Plant and Equipment	1,124.0
Investment in unconsolidated affiliates	39.0
Other noncurrent assets	4.7
Noncurrent assets of discontinued operations	$	1,167.7

Accounts payable and accrued expenses	$	74.1
Production and property taxes	1.2
Current liabilities of discontinued operations	$	75.3

Deferred income taxes	$	195.7
Asset retirement obligations	28.5
Other long-term liabilities	14.1
Noncurrent liabilities of discontinued operations	$	238.3

Consolidated Statement of Cash Flows

The impact of QEP Field Services discontinued operations (excluding the Haynesville Gathering System) on the Consolidated Statements of Cash Flows for "Depreciation, depletion and amortization" contained in "Cash flows from operating activities" was $45.9 million, $52.2 million and $55.1 million for the years ended December 31, 2014, 2013, and 2012, respectively. The impact on cash used for "Property, plant and equipment, including dry hole exploratory well expense" contained in "Cash flows from investing activities" was $55.2 million, $88.9 million and $156.2 million for the years ended December 31, 2014, 2013, and 2012, respectively.

- Definition

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

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+ Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2014

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 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 $195.1 million and $165.1 million ARO liability for the years ended December 31, 2014 and 2013, respectively, $1.3 million and $1.8 million was included as a liability in "Accounts payable and accrued expenses" on the Consolidated Balance Sheets.

The following is a reconciliation of the changes in the Company's ARO for the periods specified below:



	Asset Retirement Obligations
	2014			2013
	(in millions)
ARO liability at January 1,⁽¹⁾	$	165.1		$	155.6
Accretion	6.7			5.6
Additions⁽²⁾	17.1			6.9
Revisions	33.6			11.8
Liabilities related to assets sold	(24.7		)	(11.8		)
Liabilities settled	(2.7		)	(3.0		)
ARO liability at December 31,	$	195.1		$	165.1

____________________________


⁽¹⁾	Excludes $28.5 million and $37.5 million of ARO as of January 1, 2014 and 2013, respectively, classified as "Noncurrent liabilities of discontinued operations" on the Consolidated Balance Sheets.


⁽²⁾	Additions include $9.7 million related to the Permian Basin Acquisition (see Note 2 - Acquisitions and Divestitures).

Fair Value Measurements

12 Months Ended

Dec. 31, 2014

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, during 2013 QEP had interest rate swaps that it determined were Level 2 financial instruments. As of December 31, 2014, the interest rate swaps were terminated. The fair values of the interest rate swaps were 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 were based on an expectation of future interest rates derived from observable market interest rate curves. QEP incorporated 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 were not observable inputs, they were not significant to the overall valuation and the other inputs used to value the interest rate swaps were observable Level 2 inputs.

The fair value of financial assets and liabilities at December 31, 2014 and 2013, is shown in the tables below:



	Fair Value Measurements
	December 31, 2014
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheet
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	339.3	$	—	$	(0.3	)	$	339.0
Commodity derivative instruments - long-term	—		9.9		—		—			9.9
Total financial assets	$	—	$	349.2	$	—	$	(0.3	)	$	348.9

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	0.3	$	—	$	(0.3	)	$	—
Total financial liabilities	$	—	$	0.3	$	—	$	(0.3	)	$	—

____________________________


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



	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheet
	(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 for the contracts that contain netting provisions. Refer to Note 7 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

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, 2014				December 31, 2013
	(in millions)
Financial assets
Cash and cash equivalents	$	1,160.1	$	1,160.1	$	11.9	$	11.9
Financial liabilities
Checks outstanding in excess of cash balances	$	54.7	$	54.7	$	109.1	$	109.1
Long-term debt	2,218.1		$	2,171.6	2,997.5		$	3,034.9

The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company's debt at the end of the year. 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 ARO 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 ARO including 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 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, 2014 and 2013, 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, 2014 and 2013, the Company recorded $1,041.4 million and $1.2 million, respectively, of impairments related to certain of its proved properties. The proved properties were written down to their estimated fair values at the time of the impairments during December 31, 2014 and 2013, 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. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the properties is 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.

+ References+ Details

Derivative Contracts

12 Months Ended

Dec. 31, 2014

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 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 or collars to realize a known price or price range 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 or oil price swaps that use Intercontinental Exchange, Inc. (ICE) Brent oil prices as the reference price. QEP also enters into crude oil basis swaps to achieve a fixed price swap for a portion of its oil it sells at prices that reference ICE Brent and Light Louisiana Sweet (LLS).

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. QEP fully reclassified all unrealized gains in AOCI into earnings during 2012 and 2013. 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 (losses) on derivative contracts" below operating income.

QEP also used interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk associated with QEP's former $600.0 million term loan. For the $300.0 million term loan issued during 2012, QEP locked in a fixed interest rate of 1.07% in exchange for a variable interest rate indexed to the one-month LIBOR. For the incremental $300.0 million borrowed under the term loan during 2014, QEP locked in a fixed interest rate of 0.86%. The average effective interest rate on the $600.0 million term loan when combined with the fixed interest rate swaps for the year ended December 31, 2014, was 3.24%. These interest rate swaps were terminated in December 2014 along with the extinguishment of QEP's term loan.

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, 2014:



				Swaps
Year	Type of Contract	Index	Total Volumes	Average price per unit
			(in millions)
Gas sales			(MMBtu)
2015	Swap	NYMEX HH	29.2	$	4.11
2015	Swap	IFNPCR	40.2	$	3.70

Oil sales			(Bbls)
2015	Swap	NYMEX WTI	7.7	$	90.04
2015	Swap	ICE Brent	0.4	$	104.95
2016	Swap	NYMEX WTI	0.4	$	90.00

The following table sets forth QEP Energy's crude oil sales costless collars as of December 31, 2014:

Total Volume

Average Price

Year

Index

Bbls

Floor

Ceiling

(in millions)

2015

NYMEX WTI

0.5

50.00

63.34

The following table sets forth QEP Energy's oil basis swaps as of December 31, 2014:



Year	Index	Index Less Differential	Total Volumes Bbls	Weighted Average Differential
Oil basis swaps			(in millions)
2015	NYMEX WTI	LLS	0.1	$	4.03

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, 2014:



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2015	Swap	IFNPCR	2.8	$	4.03
2016	Swap	IFNPCR	0.9	$	3.58
Gas purchases			(MMBtu)
2015	Swap	IFNPCR	0.9	$	3.06

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	2014		2013		2014		2013
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	339.3	$	5.5	$	0.3	$	29.4
Interest rate swaps	Fair value of derivative contracts	—		—		—		2.6
Long-term:
Commodity	Fair value of derivative contracts	9.9		0.4		—		—
Interest rate swaps	Fair value of derivative contracts	—		0.6		—		—
Total derivative instruments		$	349.2	$	6.5	$	0.3	$	32.0

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	2014			2013			2012
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	(16.7	)	$	152.0		$	341.9
Oil derivative contracts	15.7			(2.2		)	14.4
NGL derivative contracts	—			—			10.2
QEP Marketing
Gas derivative contracts	(2.5		)	0.5			5.1
Total realized gains (losses) on commodity derivative contracts	(3.5		)	150.3			371.6
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	68.4			(42.6		)	37.8
Oil derivative contracts	299.8			(48.1		)	29.0
NGL derivative contracts	—			—			1.6
QEP Marketing
Gas derivative contracts	4.2			(2.1		)	0.9
Total unrealized gains (losses) on commodity derivative contracts	372.4			(92.8		)	69.3
Total realized and unrealized gains (losses) on commodity derivative contracts	$	368.9		$	57.5		$	440.9
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(7.6	)	$	(2.7	)	$	(1.3	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	2.0			4.1			(6.1		)
Total realized and unrealized gains (losses) on interest rate swaps	(5.6		)	1.4			(7.4		)
Total net realized gains (losses) on derivative contracts	(11.1		)	147.6			370.3
Total net unrealized gains (losses) on derivative contracts	374.4			(88.7		)	63.2
Grand Total	$	363.3		$	58.9		$	433.5

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41641-113959

Reference 18: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 4

-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41638-113959

Reference 19: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Accounting Standards Codification

-Topic 815

-SubTopic 10

-Section 50

-Paragraph 4C

-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624171-113959

+ Details

Restructuring Costs

12 Months Ended

Dec. 31, 2014

Restructuring Costs [Abstract]

Restructuring Costs

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 the earlier of December 31, 2014, or whenever the separation of QEP Field Services occurs, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated prior to such date. In December 2014, QEP paid the retention bonus to eligible employees in connection with the Midstream Sale. QEP recognized $10.4 million of costs under this retention plan, which is included in "Discontinued operations, net of income tax" on the Consolidated Statements of Operations.

During 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. Additionally, during 2012, QEP began incurring 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 increased efficiency, team-based collaboration and organizational productivity. 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 restructuring costs related to the 2012 office consolidations and continued operations were incurred and settled by December 31, 2013.

The following table summarizes, by line of business, each major type of restructuring 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, 2014		Year ended December 31,
			Period from Inception to December 31, 2014		2014		2013		2012
Continuing Operations:	(in millions)
QEP Energy
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 Marketing and Other
One-time termination benefits	$	0.3	$	0.3	$	—	$	0.1	$	0.2
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	3.7		3.7		—		0.4		3.3
Lease termination costs	0.6		0.6		—		—		0.6
Total restructuring costs	$	7.9	$	7.9	$	—	$	0.9	$	7.0

- Definition

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

+ References+ Details

Debt

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt

As of the indicated dates, the principal amount of QEP’s senior notes consisted of the following:



	December 31,
	2014			2013
	(in millions)
Revolving Credit Facility due 2019	$	—		$	480.0
Term Loan due 2017	—			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	2,221.8			3,001.8
Less unamortized discount	(3.7		)	(4.3		)
Total long-term debt outstanding	$	2,218.1		$	2,997.5

Of the total debt outstanding on December 31, 2014, 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. The revolving credit facility matures on December 2, 2019.

QEP's Credit Facility

QEP’s unsecured revolving credit facility, which matures in December 2019, provides for loan commitments of $1.8 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions.

On December 2, 2014, QEP entered into the Fourth Amendment to its Credit Agreement, which increased the aggregate principal amount of commitments to $1.8 billion, extended the maturity date to December 2, 2019, and made minor adjustments to other provisions and covenants.

During the years ended December 31, 2014 and 2013, QEP's weighted-average interest rates on borrowings from its credit facility were 2.23% and 2.22%, respectively. At December 31, 2014, QEP had no borrowings outstanding and had $3.7 million in letters of credit outstanding under the credit facility. At December 31, 2013, QEP had $480.0 million outstanding and QEP had $3.8 million in letters of credit outstanding under the credit facility. At December 31, 2014 and 2013, QEP was in compliance with the covenants under the credit facility.

Term Loan

On December 2, 2014, QEP repaid and terminated its $600.0 million term loan with a portion of the proceeds from the Midstream Sale. The term loan facility provided borrowings at short-term interest rates and contained covenants, restrictions and interest rates that were substantially the same as QEP’s revolving credit facility. During the years ended December 31, 2014 and 2013, QEP's weighted-average interest rates on borrowings from the term loan were 2.28% and 2.22%, respectively.

Senior Notes

At December 31, 2014, 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 indentures governing QEP's senior notes contain 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, 2014

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 are reasonably estimable 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 can 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, the ongoing discovery and/or development of information important to the matter. QEP's litigation loss contingencies are discussed below. Except for the Rocky Mountain Resources matter discussed below, QEP is unable to estimate reasonably possible losses (in excess of recorded accruals, if any) for these contingencies for the reasons set forth above. QEP believes, however, that the resolution of pending proceedings (after accruals, insurance coverage, and indemnification arrangements) will not be material to QEP's financial position, but could be material to results of operations in a particular quarter or year.

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 department prior to construction, modification, or operation. QEP has corrected and disclosed all instances of non-compliance to the LDEQ and is working with the department 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

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. On May 7, 2014, the trial court entered its order granting plaintiff's motion for summary judgment on the issue of whether the overriding royalty interest burdens QEP's lease. On June 17, 2014, the Supreme Court of Wyoming denied QEP's Petition for Writ of Review. On August 21, 2014, the trial court denied QEP’s Motion to Certify Questions of Law to the Wyoming Supreme Court. At the conclusion of a trial in February 2015, and after being instructed by the Court that the overriding royalty interest burdened QEP’s lease, a jury rendered a verdict against QEP and awarded Rocky Mountain damages in the amount of $16.7 million, including interest. QEP believes that the Court’s ruling on summary judgment and the resulting jury instructions are in error and will appeal to the Wyoming Supreme Court. While the appeal is pending, post-judgment interest accrues at the statutory rate of 10%. QEP estimates that, notwithstanding the verdict, the range of reasonably possible losses is still zero to $20 million.

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 asked for review by the Louisiana Supreme Court and on August 25, 2014, the Supreme Court reversed the Court of Appeals and dismissed the plaintiffs’ claim without prejudice as originally ordered by the District Court.

Yannick Gagné and others similarly situated v. QEP Resources, Inc., No. 480-06-1-132, Superior Court, Province of Quebec, Canada. Plaintiffs seek to represent a class of all persons who sustained damages as a result of the July 6, 2013 train derailment in Lac-Mégantic, Quebec, which resulted in substantial loss of life and property. The fourth amended motion to authorize the bringing of a class action was filed on February 19, 2014, and names numerous defendants. The plaintiffs contend that QEP, and other producer defendants, sold Bakken crude oil to third-party purchasers in North Dakota, who resold the oil and transported it on the derailed train. Plaintiffs alleged that QEP and the producer defendants, among other things, failed to ensure that the oil was adequately processed to remove volatile gases and vapors, knowingly added volatile light end petroleum liquids and/or vapors or blended the crude with condensate, failed to conduct adequate well site testing to determine the proper hazard classification of the oil, failed to properly classify the shipping requirements for the oil, failed to take reasonable care to ensure that the oil was properly labeled and shipped, failed to identify the risk of the train derailment and take action to prevent it, and failed to adopt, implement and enforce rules and procedures pertaining to the safe shipment of the oil. The plaintiffs seek damages, but specific monetary damages are not asserted. Class certification hearings took place in June 2014, and a court order regarding class certification is pending.

Litigation related to discontinued operations:

In accordance with the terms of the Membership Interest Purchase Agreement, dated October 19, 2014, by and between QEP Field Services and Tesoro, Tesoro agreed to assume the defense of, and indemnify, defend and hold harmless QEP Field Services and its affiliates, including QEP, from and against all liability, loss, cost, expense, claim, award or judgment associated with the following litigation matters previously disclosed: Questar Gas Company v. QEP Field Services Company and XTO Energy Inc. v. QEP Field Services Company. Therefore, in light of Tesoro’s indemnification obligations and after assessing Tesoro’s ability to satisfy its indemnification obligations, QEP believes it is not reasonably likely to have liability for these matters.

Commitments

Subsidiaries of QEP have contracted for gathering, processing, firm transportation and storage 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. Annual payments and the corresponding years for gathering, processing, transportation, storage, drilling, and fractionation contracts are as follows (in millions):



Year	Amount
2015	$	130.7
2016	$	120.6
2017	$	120.0
2018	$	117.1
2019	$	112.0
After 2019	$	407.4

QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $8.2 million, $7.8 million, and $7.3 million during the years ended December 31, 2014, 2013 and 2012, 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
2015	$	8.4
2016	$	8.2
2017	$	8.4
2018	$	6.9
2019	$	6.8
After 2019	$	23.9

- Definition

The entire disclosure for commitments and contingencies.

+ References+ Details

Equity-Based Compensation

12 Months Ended

Dec. 31, 2014

Share-based Compensation [Abstract]

Share-Based Compensation

QEP issues stock options and restricted shares under its LTSIP and awards performance 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 share units vest. Deferred equity-based compensation is included in additional paid-in capital in the Consolidated Balance Sheets. There were 10.8 million shares available for future grants under the LTSIP at December 31, 2014. Equity-based compensation expense is recognized in "General and administrative" on the Consolidated Statements of Operations, and expenses related to discontinued operations (including compensation expense related to the QEP Midstream Long Term Incentive Plan) are reflected in "Discontinued operations, net of income tax". During the year ended December 31, 2014 for continuing operations, QEP recognized $21.4 million in total compensation expense related to equity-based compensation compared to $25.7 million and $25.6 million during the years ended December 31, 2013 and 2012, respectively. For discontinued operations during the year ended December 31, 2014, QEP recognized $5.8 million in total compensation expense related to equity based compensation, compared to $1.4 million during the year ended December 31, 2013.

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,
	2014			2013			2012
Weighted-average grant-date fair value of awards granted during the period	$	10.11		$	15.16		$	14.29
Risk-free interest rate range	1.31% - 1.34%			0.97% - 1.84%			0.63% - 1.04%
Weighted-average risk-free interest rate	1.3		%	1.0		%	0.8		%
Expected price volatility range	36.1% - 37.3%			51.5% - 58.5%			55.9% - 56.5%
Weighted-average expected price volatility	37.1		%	58.3		%	55.9		%
Expected dividend yield	0.25		%	0.27		%	0.26		%
Expected term in years at the date of grant	4.5			5.5			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, 2013	1,794,187		$	27.90
Granted	282,236		31.67
Exercised	(65,366	)	22.24
Forfeited	(14,842	)	30.53
Outstanding at December 31, 2014	1,996,215		$	28.60	3.18	$	0.1
Options Exercisable at December 31, 2014	1,494,061		$	27.80	2.39	$	0.1
Unvested Options at December 31, 2014	502,154		$	30.98	5.51	$	—

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.6 million, $4.3 million and $9.6 million during the years ended December 31, 2014, 2013 and 2012, respectively. The Company realized no income tax benefit for the year ended December 31, 2014, and $1.4 million, and $4.6 million of income tax benefits for the years ended December 31, 2013 and 2012, respectively, which increased its Additional Paid-in-Capital (APIC) pool by $6.5 million as of December 31, 2014. As of December 31, 2014, $2.0 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 1.87 years. During the year ended December 31, 2014, QEP issued shares for stock option exercises from its treasury stock and received $1.5 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, 2014, 2013 and 2012, was $26.8 million, $19.8 million and $16.7 million, respectively. The Company realized an income tax expense of $0.5 million, $0.1 million and $0.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. Restricted stock increased the Company's APIC pool by $0.3 million as of December 31, 2014. The weighted average grant-date fair value of restricted stock granted during the years was $31.40 per share, $30.06 per share and $30.54 per share for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014, $18.3 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.10 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, 2013	1,388,953		$	30.96
Granted	1,033,023		31.40
Vested	(855,720	)	31.39
Forfeited	(139,803	)	31.00
Unvested balance at December 31, 2014	1,426,453		$	31.02

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, 2014, 2013 and 2012, were $31.57, $30.12, and $30.75 per unit, respectively. As of December 31, 2014, $2.3 million of unrecognized compensation cost classified as a liability, or the fair market value, related to performance shares granted under the CIP is expected to be recognized over a weighted-average vesting period of 1.90 years.

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



	Performance Share Units Outstanding		Weighted- Average Grant-Date Fair Value
Unvested balance at December 31, 2013	480,660		$	32.33
Granted	256,101		31.57
Vested	(73,956	)	37.17
Canceled	(83,545	)	35.84
Forfeited	(27,051	)	30.60
Unvested balance at December 31, 2014	552,209		$	30.85

- 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+ Details

Employee Benefits

12 Months Ended

Dec. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Employee Benefits

Defined Benefit Pension Plans and Other Postretirement Benefits

The Company maintains the QEP Resources, Inc. Retirement Plan, a closed, defined-benefit pension plan providing coverage to 62 active and suspended participants, or 8%, of QEP's active employees and to 152 participants that are retired or terminated and vested (the Pension Plan). QEP also sponsors an unfunded Supplemental Executive Retirement Plan. 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 62 active, pension eligible employees, 39 are also eligible for the postretirement medical and life insurance plans when they retire. As of December 31, 2014, 36 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, 2014 and 2013, QEP's accumulated benefit obligation exceeded the fair value of its qualified retirement plan assets. At December 31, 2014 and 2013, QEP's nonqualified retirement plan was unfunded.

During the year ended December 31, 2014, the Company recognized a $9.3 million loss on curtailment and $1.9 million in expenses for special termination benefits in connection with the Midstream Sale (see Note 3 - Discontinued Operations) and the 2014 property sales in the Midcontinent area (see Note 2 - Acquisitions and Divestitures). The Pension Plan was amended to provide certain termination benefits for participants impacted by the Midstream Sale and the 2014 Midcontinent property sales who were aged 50-54 as of the date of their separation from the Company. These expenses are included within "Net income from discontinued operations, net of income tax" and "Net gain (loss) from asset sales" for the year ended December 31, 2014, on the Consolidated Statements of Operations. 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 (see Note 8 - Restructuring Costs). A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services. During the year ended December 31, 2014, 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, 2014, the Company made payments of $4.9 million of benefits pursuant to its unfunded nonqualified retirement plan. Payments to the unfunded nonqualified plans are used to fund current benefit payments. During 2015, the Company expects to contribute approximately $4.0 million to its funded pension plan, pay approximately $4.4 million of benefits under its unfunded nonqualified pension plan and pay approximately $0.3 million for retiree health care and life insurance benefits. The accumulated benefit obligation for all defined-benefit pension plans was $121.8 million and $101.0 million at December 31, 2014 and 2013, 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, 2014 and 2013, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2014 and 2013:



	Pension benefits						Other postretirement benefits
	2014			2013			2014			2013
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$	118.0		$	129.7		$	5.9		$	6.7
Service cost	2.6			3.3			—			0.1
Interest cost	5.3			4.8			0.3			0.3
Special termination benefits	1.9			—			—			—
Curtailments	(8.2		)	—			(0.2		)	—
Plan settlements	(2.3		)	—			—			—
Benefit payments	(5.5		)	(5.5		)	—			(0.1		)
Actuarial loss (gain)	20.8			(14.3		)	0.6			(1.1		)
Benefit obligation at December 31,	$	132.6		$	118.0		$	6.6		$	5.9
Change in plan assets
Fair value of plan assets at January 1,	$	71.7		$	55.3		$	—		$	—
Actual gain on plan assets	4.5			10.4			—			—
Company contributions to the plan	13.0			11.5			—			0.1
Benefit payments	(5.5		)	(5.5		)	—			(0.1		)
Plan settlements	(2.3		)	—			—			—
Fair value of plan assets at December 31,	81.4			71.7			—			—
Underfunded status (current and long-term)	$	(51.2	)	$	(46.3	)	$	(6.6	)	$	(5.9	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(4.3	)	$	(5.5	)	$	(0.3	)	$	(0.2	)
Other long-term liabilities	(46.9		)	(40.8		)	(6.3		)	(5.7		)
Total amount recognized in balance sheet	$	(51.2	)	$	(46.3	)	$	(6.6	)	$	(5.9	)
Amounts recognized in AOCI
Net actuarial loss	$	21.2		$	9.5		$	0.6		$	0.2
Prior service cost	16.1			30.1			1.4			3.0
Total amount recognized in AOCI	$	37.3		$	39.6		$	2.0		$	3.2

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
	2014			2013			2012			2014			2013			2012

Components of net periodic benefit cost
Service cost	$	2.6		$	3.3		$	4.0		$	—		$	0.1		$	0.1
Interest cost	5.3			4.8			5.1			0.3			0.3			0.3
Expected return on plan assets	(5.1		)	(3.9		)	(3.6		)	—			—			—
Curtailment loss	9.3			—			2.2			1.4			—			—
Special termination benefits	1.9			—			—			—			—			—
Settlements	0.7			—			—			—			—			—
Amortization of prior service costs	4.7			5.0			5.3			0.3			0.3			0.3
Amortization of actuarial loss	0.8			2.3			1.9			—			0.1			0.1
Periodic expense	$	20.2		$	11.5		$	14.9		$	2.0		$	0.8		$	0.8
Components recognized in accumulated other comprehensive income
Current period actuarial loss (gain)	$	21.5		$	(20.8	)	$	15.9		$	0.6		$	(1.0	)	$	0.4
Amortization of actuarial loss	(0.8		)	(2.3		)	(1.9		)	—			(0.1		)	(0.1		)
Amortization of prior service cost	(14.0		)	(5.0		)	(5.3		)	(1.7		)	(0.4		)	(0.4		)
Loss on curtailment in current period	(8.2		)	—			(2.2		)	(0.2		)	—			—
Settlements	(0.7		)	—			—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	(2.2	)	$	(28.1	)	$	6.5		$	(1.3	)	$	(1.5	)	$	(0.1	)

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 2015 is $4.1 million, which represents amortization of prior service cost recognition and actuarial losses. The estimated portion to be recognized in net periodic cost for other postretirement benefits from AOCI in 2015 is $0.2 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, 2014 and 2013:



	Pension benefits				Other postretirement benefits
	2014		2013		2014		2013
Discount rate	3.94	%	4.75	%	4.00	%	5.00	%
Rate of increase in compensation	4.00	%	4.00	%	4.00	%	4.00	%

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

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



	Pension benefits						Other postretirement benefits
	2014		2013		2012		2014		2013		2012
Discount rate	4.40	%	3.69	%	4.38	%	5.00	%	4.10	%	4.70	%
Expected long-term return on plan assets	7.00	%	6.75	%	7.25	%	n/a		n/a		n/a
Rate of increase in compensation	4.00	%	3.60	%	3.60	%	4.00	%	3.60	%	4.00	%

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 2015. 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 increases 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 invested in a combination of index funds and actively managed products, 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. High yield and bank loan assets are held in funds holding a diversified portfolio of these instruments with an average maturity of 5 to 7 years.

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, 2014								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	—		—		36.7		36.7		45	%
International	—		—		20.2		20.2		25	%
Fixed income	—		—		24.2		24.2		30	%
Total investments	—		—		$	81.4	$	81.4	100	%
	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	%

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



	Year ended December 31,
	2014			2013
	(in millions)
Balance at January 1,	$	71.7		55.2
Employer contributions	8.1			8.1
Unrealized gains (losses)	(1.0		)	9.8
Realized gains	5.9			1.0
Administrative fees	(0.4		)	(0.3		)
Benefits paid	(2.9		)	(2.1		)
Balance at December 31,	$	81.4		$	71.7

Expected Benefit Payments

As of December 31, 2014, the following future benefit payments are expected to be paid:



	Pension		Postretirement benefits
	(in millions)
2015	$	8.3	$	0.3
2016	7.0		0.4
2017	6.3		0.4
2018	6.3		0.4
2019	7.2		0.4
2020 through 2024	41.8		1.8

Employee Investment Plan

QEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (the 401(k) Plan). The 401(k) Plan allows eligible employees to make investments, including purchasing shares of QEP common stock, through payroll deduction at the current fair market value on the transaction date. For the years ended December 31, 2014 and 2013, the Company made matching contributions for employees not covered by the Pension Plan equal to 100% of employees' contributions up to a maximum of 8% of their qualifying earnings. Employees in the Pension Plan are eligible for a 6% match. For the year ended December 31, 2012, the Company made 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 matching contribution to employees not in the Pension Plan, and for the year ended December 31, 2012, 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 $7.6 million, $6.9 million and $6.4 million during the years ended December 31, 2014, 2013 and 2012, respectively.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References+ Details

Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

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



	Year Ended December 31,
	2014			2013			2012
	(in millions)
Federal income tax provision (benefit)
Current	$	(324.0	)	$	(92.2	)	$	(10.3	)
Deferred	110.3			152.3			15.6
State income tax provision (benefit)
Current	(15.5		)	(1.4		)	(1.8		)
Deferred	(3.3		)	1.4			(5.4		)
Total income tax provision (benefit)	$	(232.5	)	$	60.1		$	(1.9	)

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,
	2014		2013		2012
Federal income taxes statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	(1.5	)%	(5.0	)%	(2,220.0	)%
State rate change	3.4	%	—	%	—	%
Penalties	—	%	0.4	%	80.0	%
Return to provision adjustment	(0.4	)%	5.0	%	1,400.0	%
Book impairment of goodwill	—	%	18.6	%	—	%
Other	(0.3	)%	(0.4	)%	325.0	%
Effective income tax rate	36.2	%	53.6	%	(380.0	)%

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



	December 31,
	2014		2013
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$	1,402.9	$	1,455.6
Commodity price and interest rate derivatives	127.7		—
Total deferred tax liabilities	1,530.6		1,455.6
Deferred tax assets
Commodity price and interest rate derivatives	—		9.8
Net operating loss and tax credit carryforwards	11.7		54.4
Employee benefits and compensation costs	43.0		36.1
Accrued litigation loss contingency	—		0.8
Bonus and vacation accrual	16.3		9.0
Other	12.4		8.5
Total deferred tax assets	83.4		118.6
Net deferred income tax liability	$	1,447.2	$	1,337.0
Balance sheet classification
Deferred income tax asset - current	$	—	$	27.9
Deferred income tax liability - current	84.5		—
Deferred income tax liability - non-current	1,362.7		1,364.9
Net deferred income tax liability	$	1,447.2	$	1,337.0

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2014 are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2015-2033	$	30.1
State net operating loss valuation allowance		(18.4		)
U.S. alternative minimum tax credit	Indefinite	—
Total		$	11.7

The valuation allowance of $18.4 million was established in 2014 against the available state net operating loss and is related primarily to losses incurred in Oklahoma. Due to the 2014 Midcontinent property sales in which the Company sold its interests in most of its properties in Oklahoma, the Company does not forecast sufficient taxable income to utilize the net operating loss in Oklahoma.

- 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+ Details

Operations by Line of Business

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Operations by Line of Business

QEP’s lines of business include oil and gas exploration and production (QEP Energy); and marketing, the Haynesville Gathering System, an underground storage reservoir, and corporate (QEP Marketing and Other). The lines of business are managed separately and therefore the financial information is presented separately due to the distinct differences in the nature of operations of each line of business, among other factors.

Our financial results for 2014 and for prior periods have been revised, in accordance with GAAP, to reflect the impact of the Midstream Sale. See Note 3 - Discontinued Operations for detailed information on the Midstream Sale.

The following table is a summary of operating results for the year ended December 31, 2014, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			Discontinued Operations		QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	2,524.6		$	889.7		$	—		$	—	$	3,414.3
From affiliated customers	—			1,492.6			(1,492.6		)	—		—
Total Revenues	2,524.6			2,382.3			(1,492.6		)	—		3,414.3
OPERATING EXPENSES
Purchased gas, oil and NGL expense	150.0			2,356.6			(1,475.4		)	—		1,031.2
Lease operating expense	240.1			—			—			—		240.1
Gas, oil and NGL transportation and other handling costs	291.5			—			(13.9		)	—		277.6
Gathering and other expense	—			6.8			(0.1		)	—		6.7
General and administrative	201.3			6.3			(3.2		)	—		204.4
Production and property taxes	204.0			1.2			—			—		205.2
Depreciation, depletion and amortization	984.4			10.3			—			—		994.7
Impairment and exploration expenses	1,153.1			—			—			—		1,153.1
Total Operating Expenses	3,224.4			2,381.2			(1,492.6		)	—		4,113.0
Net gain (loss) from asset sales	(148.6		)	—			—			—		(148.6		)
OPERATING INCOME (LOSS)	(848.4		)	1.1			—			—		(847.3		)
Realized and unrealized gains (losses) on derivative contracts	367.2			(3.9		)	—			—		363.3
Interest and other income	11.8			209.7			(208.7		)	—		12.8
Income from unconsolidated affiliates	0.3			—			—			—		0.3
Loss from early extinguishment of debt	—			(2.0		)	—			—		(2.0		)
Interest expense	(210.3		)	(167.5		)	208.7			—		(169.1		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(679.4		)	37.4			—			—		(642.0		)
Income tax (provision) benefit	246.9			(14.4		)	—			—		232.5
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(432.5		)	23.0			—			—		(409.5		)
Net income from discontinued operations, net of income tax	—			—			—			1,193.9		1,193.9
NET INCOME (LOSS) ATTRIBUTABLE TO QEP	$	(432.5	)	$	23.0		$	—		$	1,193.9	$	784.4
Identifiable total assets	$	8,001.1		$	1,285.7		$	—		$	—	$	9,286.8
Cash capital expenditures	2,660.3			10.9			—			55.2		$	2,726.4
Accrued capital expenditures	2,670.5			13.6			—			50.7		$	2,734.8

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



	QEP Energy			QEP Marketing and Other			Eliminations			Discontinued Operations		QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	2,092.8		$	592.3		$	—		$	—	$	2,685.1
From affiliated customers	—			1,008.9			(1,008.9		)	—		—
Total Revenues	2,092.8			1,601.2			(1,008.9		)	—		2,685.1
OPERATING EXPENSES
Purchased gas, oil and NGL expense	197.1			1,570.5			(984.1		)	—		783.5
Lease operating expense	181.3			—			—			—		181.3
Gas, oil and NGL transportation and other handling costs	242.2			—			(20.2		)	—		222.0
Gathering and other expense	—			8.4			—			—		8.4
General and administrative	160.6			4.4			(4.6		)	—		160.4
Production and property taxes	159.8			1.5			—			—		161.3
Depreciation, depletion and amortization	954.2			9.6			—			—		963.8
Impairment and exploration expenses	104.9			—			—			—		104.9
Total Operating Expenses	2,000.1			1,594.4			(1,008.9		)	—		2,585.6
Net gain (loss) from asset sales	104.1			(0.6		)	—			—		103.5
OPERATING INCOME (LOSS)	196.8			6.2			—			—		203.0
Realized and unrealized gains (losses) on derivative contracts	59.1			(0.2		)	—			—		58.9
Interest and other income	3.6			206.9			(195.3		)	—		15.2
Income from unconsolidated affiliates	0.2			—			—			—		0.2
Interest expense	(192.6		)	(167.8		)	195.3			—		(165.1		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	67.1			45.1			—			—		112.2
Income tax provision	(41.5		)	(18.6		)	—			—		(60.1		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	25.6			26.5			—			—		52.1
Net income from discontinued operations, net of income tax	—			—			—			107.3		107.3
NET INCOME (LOSS ATTRIBUTABLE TO QEP	$	25.6		$	26.5		$	—		$	107.3	$	159.4
Identifiable total assets	$	7,937.0		$	182.2		$	—		$	1,289.7	$	9,408.9
Cash capital expenditures	1,488.6			25.1			—			88.9		$	1,602.6
Accrued capital expenditures	1,467.2			24.6			—			85.6		$	1,577.4

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



	QEP Energy			QEP Marketing and Other			Eliminations			Discontinued Operations		QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	1,615.4		$	456.3		$	—		$	—	$	2,071.7
From affiliated customers	—			611.2			(611.2		)	—		—
Total Revenues	1,615.4			1,067.5			(611.2		)	—		2,071.7
OPERATING EXPENSES
Purchased gas, oil and NGL expense	224.7			1,021.1			(575.1		)	—		670.7
Lease operating expense	175.8			—			—			—		175.8
Gas, oil and NGL transportation and other handling costs	228.1			—			(30.0		)	—		198.1
Gathering and other expense	—			8.2			—			—		8.2
General and administrative	252.8			1.7			(6.1		)	—		248.4
Production and property taxes	97.2			1.3			—			—		98.5
Depreciation, depletion and amortization	838.4			11.8						—		850.2
Impairment and exploration expenses	144.2			—			—			—		144.2
Total Operating Expenses	1,961.2			1,044.1			(611.2		)	—		2,394.1
Net gain from asset sales	1.2			—			—			—		1.2
OPERATING INCOME (LOSS)	(344.6		)	23.4			—			—		(321.2		)
Realized and unrealized gains (losses) on derivative contracts	434.9			(1.4		)	—			—		433.5
Interest and other income	6.2			132.3			(123.5		)	—		15.0
Income from unconsolidated affiliates	0.1			—			—			—		0.1
Loss on extinguishment of debt	—			(0.6		)	—			—		(0.6		)
Interest expense	(116.8		)	(133.0		)	123.5			—		(126.3		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(20.2		)	20.7			—			—		0.5
Net Income tax benefit (provision)	12.1			(10.2		)	—			—		1.9
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(8.1		)	10.5			—			—		2.4
Net income from discontinued operations, net of income tax	—			—			—			125.9		125.9
NET INCOME (LOSS) ATTRIBUTABLE TO QEP	$	(8.1	)	$	10.5		$	—		$	125.9	$	128.3
Identifiable assets	$	7,436.5		$	244.6		$	—		$	1,427.4	$	9,108.5
Cash capital expenditures	2,621.1			22.4			—			156.2		2,799.7
Accrued capital expenditures	2,702.4			21.6			—			164.2		2,888.2
Goodwill	59.5			—			—			—		59.5

- 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 Accounting Standards Codification

-Topic 280

-SubTopic 10

-Section 50

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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8380-108599

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 280

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 280

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-Section 50

-Paragraph 10

-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8538-108599

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 280

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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8844-108599

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 280

-SubTopic 10

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-Paragraph 29

-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8864-108599

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 280

-SubTopic 10

-Section 50

-Paragraph 34

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+ Details

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

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



	First Quarter		Second Quarter			Third Quarter			Fourth Quarter			Year
	(in millions, except per share information)
2014
Revenues	$	817.5	$	887.2		$	910.0		$	799.6		$	3,414.3
Operating income (loss)	140.8		(35.9		)	115.1			(1,067.3		)	(847.3		)
Income (loss) from continuing operations	12.7		(106.1		)	153.7			(469.8		)	(409.5		)
Discontinued operations, net of income taxes ⁽¹⁾	27.0		13.8			17.4			1,135.7			1,193.9
Net income (loss) attributable to QEP	39.7		(92.3		)	171.1			665.9			784.4
Non-recurring items in operating income (loss) ⁽²⁾	0.4		(202.5		)	(11.9		)	(1,077.8		)	(1,291.8		)
Per share information attributable to QEP
Basic EPS from continuing operations	$	0.07	$	(0.59	)	$	0.85		$	(2.62	)	$	(2.28	)
Basic EPS from discontinued operations	0.15		0.08			0.10			6.34			6.64
Diluted EPS from continuing operations	0.07		(0.59		)	0.84			(2.62		)	(2.28		)
Diluted EPS from discontinued operations	0.15		0.08			0.10			6.34			6.64



2013
Revenues	$	651.3		$	694.0	$	719.5	$	620.3		2,685.1
Operating income (loss)	27.3			159.1		83.3		(66.7		)	203.0
Income (loss) from continuing operations	(24.8		)	149.2		12.1		(84.4		)	52.1
Discontinued operations, net of income taxes ⁽¹⁾	20.5			29.2		25.2		32.4			107.3
Net income (loss) attributable to QEP	(4.3		)	178.4		37.3		(52.0		)	$	159.4
Non-recurring items in operating income (loss) ⁽²⁾	(0.2		)	100.2		9.0		$	(98.5	)	10.5
Per share information attributable to QEP
Basic EPS from continuing operations	$	(0.14	)	$	0.83	$	0.07	$	(0.47	)	$	0.29
Basic EPS from discontinued operations	0.12			0.16		0.14		0.18			0.60
Diluted EPS from continuing operations	(0.14		)	0.83		0.07		(0.47		)	0.29
Diluted EPS from discontinued operations	0.12			0.16		0.14		0.18			0.60

____________________________


⁽¹⁾	In December 2014, QEP completed the Midstream Sale. QEP Field Services' financial results (excluding results of the Haynesville Gathering System) have been reflected as discontinued operations and all prior periods have been reclassified.


⁽²⁾	Includes net gains and losses from asset sales and losses due to asset 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, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

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,
	2014			2013
	(in millions)
Proved properties	$	12,278.7		$	11,571.4
Unproved properties, net	825.2			665.1
Total proved and unproved properties	13,103.9			12,236.5
Accumulated depreciation, depletion and amortization	(6,153.0		)	(4,930.9		)
Net capitalized costs	$	6,950.9		$	7,305.6

Costs Incurred

The costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Development costs are net of the change in accrued capital costs of $10.2 million and ARO additions and revisions of $51.1 million during the year ended December 31, 2014. The costs incurred to advance the development of reserves that were classified as proved undeveloped were approximately $796.7 million in 2014, $645.9 million in 2013, and $513.0 million in 2012.



	Year Ended December 31,
	2014		2013		2012
	(in millions)
Property acquisitions
Unproved	$	496.3	$	9.3	$	692.6
Proved	465.4		31.6		714.4
Total property acquisitions	961.7		40.9		1,407.0
Exploration (capitalized and expensed)	23.6		14.6		14.3
Development	1,695.1		1,440.8		1,310.0
Total costs incurred	$	2,680.4	$	1,496.3	$	2,731.3

Results of Operations

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



	Year Ended December 31,
	2014			2013			2012
	(in millions)
Revenues	$	2,374.6		$	1,901.2		$	1,393.4
Production costs	735.6			583.3			501.1
Exploration expenses	9.9			11.9			11.2
Depreciation, depletion and amortization	984.4			954.2			838.4
Impairment	1,143.2			93.0			133.0
Total expenses	2,873.1			1,642.4			1,483.7
Income (loss) before income taxes	(498.5		)	258.8			(90.3		)
Income tax benefit (expense)	182.5			(96.3		)	33.6
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(316.0	)	$	162.5		$	(56.7	)

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. and DeGolyer and MacNaughton, 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, 2014, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves; however, long-term development of gas reserves in Pinedale 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. The ROD contains additional requirements and restrictions on the sequence of development, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development that is beyond the control of the Company. The Company has an ongoing development plan and the financial capability to continue development in the manner estimated. Additionally, QEP Energy plans to develop its PUD reserves prior to lease expiration or extend the term of the lease.

As of December 31, 2014, 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, 2012, 2013 and 2014 are as follows:



	Gas		Oil		NGL		Total
	(Bcf)		(MMbbl)		(MMbbl)		(Bcfe)
Balance at December 31, 2011	2,749.4		67.5		76.6		3,613.8
Revisions of previous estimates⁽¹⁾	(240.6	)	(1.5	)	0.7		(244.8	)
Extensions and discoveries⁽²⁾	330.6		17.3		23.0		572.5
Purchase of reserves in place⁽³⁾	32.3		42.0		4.9		313.8
Sale of reserves in place	—		—		—		—
Production	(249.3	)	(6.3	)	(5.3	)	(319.2	)
Balance at December 31, 2012	2,622.4		119.0		99.9		3,936.1
Revisions of previous estimates⁽⁴⁾	(288.3	)	1.3		(8.0	)	(328.5	)
Extensions and discoveries⁽⁵⁾	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
Revisions of previous estimates⁽⁶⁾	27.1		(4.0	)	1.4		11.3
Extensions and discoveries⁽⁷⁾	141.4		16.8		8.6		294.1
Purchase of reserves in place⁽⁸⁾	72.5		35.7		12.3		360.7
Sale of reserves in place⁽⁹⁾	(299.4	)	(7.5	)	(21.5	)	(473.4	)
Production	(179.3	)	(17.1	)	(6.8	)	(322.7	)
Balance at December 31, 2014	2,317.2		172.5		96.6		3,931.9
Proved developed reserves
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
Balance at December 31, 2014	1,288.4		99.3		52.2		2,197.5
Proved undeveloped reserves
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
Balance at December 31, 2014	1,028.8		73.2		44.4		1,734.4

___________________________

⁽¹⁾

Revisions of previous estimates in 2012 include negative impacts due to 152.4 Bcfe pricing revisions, 35.6 Bcfe performance revisions, 27.6 Bcfe operating cost revisions and 29.1 Bcfe other revisions. The 152.4 Bcfe pricing revisions were due to lower 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.

⁽²⁾

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


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

⁽⁴⁾

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.

⁽⁵⁾

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.

⁽⁶⁾

Revisions of previous estimates in 2014 include 248.5 Bcfe negative performance revisions partially offset by positive other revisions of 197.7 Bcfe, operating cost revisions of 39.2 Bcfe and pricing revisions of 22.9 Bcfe. Negative performance revisions were driven by a 194.0 Bcfe decrease in Pinedale reserves related to downward forecast revisions on proved developed (PDP) wells, additional production history on PUD to PDP performance and a downward adjustment in the number of PUD locations. Other negative revisions related to adjustments to shrink and lease operating expense deducts. Pricing revisions were primarily due to increased gas prices, which increased reserves by 21.9 Bcfe.


⁽⁷⁾	Extensions and discoveries in 2014 increased proved reserves by 294.1 Bcfe, primarily related to extensions and discoveries in Pinedale of 133.6 Bcfe and the Williston Basin of 123.3 Bcfe. 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 and new compression well projections in Pinedale.


⁽⁸⁾	Purchase of reserves in place in 2014 relate to the Company's Permian Basin Acquisition as discussed in Note 2 - Acquisitions and Divestitures.


⁽⁹⁾	Sale of reserves in place primarily related to property sales in the Midcontinent in the second and fourth quarters of 2014 as discussed in Note 2 - Acquisitions and Divestitures.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31, 2014, 2013 and 2012, 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 2014, 2013 and 2012, 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,
	2014		2013		2012
Average benchmark price per unit:
Gas price (per MMBtu)	$	4.35	$	3.67	$	2.76
Oil price (per bbl)	94.99		96.94		94.71

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 $925.7 million in 2015, $983.7 million in 2016 and $714.3 million in 2017.

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



	Year Ended December 31,
	2014			2013			2012
	(in millions)
Future cash inflows	$	28,167.3		$	24,805.7		$	18,200.2
Future production costs	(9,842.1		)	(8,400.3		)	(5,027.2		)
Future development costs	(3,521.3		)	(4,056.7		)	(3,927.3		)
Future income tax expenses	(4,304.0		)	(3,284.6		)	(2,269.0		)
Future net cash flows	10,499.9			9,064.1			6,976.7
10% annual discount for estimated timing of net cash flows	(5,159.9		)	(4,680.2		)	(3,942.0		)
Standardized measure of discounted future net cash flows	$	5,340.0		$	4,383.9		$	3,034.7

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



	Year Ended December 31,
	2014			2013			2012
	(in millions)
Balance at January 1,	$	4,383.9		$	3,034.7		$	3,525.6
Sales of gas, oil and NGL produced during the period, net of production costs	(1,639.0		)	(1,317.9		)	(892.3		)
Net change in sales prices and in production (lifting) costs related to future production	726.6			1,236.3			(2,083.5		)
Net change due to extensions, discoveries and improved recovery	979.9			2,230.7			948.5
Net change due to revisions of quantity estimates	35.9			(709.6		)	(387.8		)
Net change due to purchases of reserves in place	695.3			36.8			831.4
Net change due to sales of reserves in place	(1,153.7		)	(73.2		)	—
Previously estimated development costs incurred during the period	867.5			722.7			513.0
Changes in estimated future development costs	409.6			(596.5		)	(209.3		)
Accretion of discount	597.3			402.2			499.4
Net change in income taxes	(600.3		)	(601.7		)	273.6
Other	37.0			19.4			16.1
Net change	956.1			1,349.2			(490.9		)
Balance at December 31,	$	5,340.0		$	4,383.9		$	3,034.7

Schedule of Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2014

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, 2014
Allowance for bad debts	$	2.2	$	2.1	$	0.3		$	4.6
Year ended December 31, 2013
Allowance for bad debts	2.4		0.1		(0.3		)	2.2
Year ended December 31, 2012
Allowance for bad debts	1.3		1.3		(0.2		)	2.4

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies [Abstract]

Nature of Operations [Text Block]

Nature of Business

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

Consolidation, Policy [Policy Text Block]

Principles of Consolidation

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

Reclassification, Policy [Policy Text Block]

Reclassifications

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

Risks And Uncertainties [Policy Text Block]

Risks and Uncertainties

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

In most states in which QEP Energy operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume based.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents and Restricted Cash

Supplemental cash flow information is shown in the below table:



	Year Ended December 31,
	2014		2013			2012
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	163.2	$	156.7		$	105.1
Cash paid for income taxes	0.3		77.9			30.0
Non-cash investing activities
Change in capital expenditure accrual balance	$	8.4	$	(25.2	)	$	88.5

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

Commitments and Contingencies, Policy [Policy Text Block]

Litigation and Other Contingencies

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

Goodwill

Derivatives, Policy [Policy Text Block]

Derivative Instruments

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

Credit Risk

Income Tax, Policy [Policy Text Block]

Income Taxes

TreasuryStock [Policy Text Block]

Treasury Stock

Share Repurchases And Retirements [Policy Text Block]

Share Repurchases and Retirements

Earnings Per Share, Policy [Policy Text Block]

Earnings Per Share



	December 31,
	2014	2013	2012
	(in millions)
Weighted-average basic common shares outstanding	179.8	179.2	177.8
Potential number of shares issuable under the Long-Term Stock Incentive Plan	—	0.3	0.9
Average diluted common shares outstanding	179.8	179.5	178.7

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, 2014

Summary of Significant Accounting Policies [Abstract]

Cash Flow, Supplemental Disclosures [Text Block]

Supplemental cash flow information is shown in the below table:



	Year Ended December 31,
	2014		2013			2012
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	163.2	$	156.7		$	105.1
Cash paid for income taxes	0.3		77.9			30.0
Non-cash investing activities
Change in capital expenditure accrual balance	$	8.4	$	(25.2	)	$	88.5

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



	December 31,
	2014	2013	2012
	(in millions)
Weighted-average basic common shares outstanding	179.8	179.2	177.8
Potential number of shares issuable under the Long-Term Stock Incentive Plan	—	0.3	0.9
Average diluted common shares outstanding	179.8	179.5	178.7

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2014

Dec. 31, 2012

Business Combinations [Abstract]

Schedule of Purchase Price Allocation [Table Text Block]



	As of December 31, 2014
	(in millions)
Consideration:
Total consideration paid	$	941.8

Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	472.1
Unproved properties	480.6
Asset retirement obligations	(9.7		)
Liabilities assumed	(1.2		)
Total fair value	$	941.8

Business Acquisition, Pro Forma Information [Abstract]



	Year ended December 31,
	2014				2013
	Actual		Pro forma		Actual		Pro forma
	(in millions, except per share data)

Revenues	$	3,414.3	$	3,440.4	$	2,685.1	$	2,858.8
Net income attributable to QEP	$	784.4	$	791.4	$	159.4	$	195.3
Earnings per common share attributable to QEP
Basic	$	4.36	$	4.40	$	0.89	$	1.09
Diluted	$	4.36	$	4.40	$	0.89	$	1.09



	Year ended December 31,
	2012
	Actual		Pro forma
	(in millions, except per share data)
Revenues	$	2,071.7	$	2,207.2
Net income attributable to QEP	$	128.3	$	143.0
Earnings per common share attributable to QEP
Basic	$	0.72	$	0.80
Diluted	$	0.72	$	0.80

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Income Statement Impact Of Discontinued Operations [Table Text Block]



	Year Ended December 31,
	2014			2013			2012
	(in millions)
REVENUES
NGL sales	$	109.3		$	101.9		$	137.9
Other revenues	140.9			166.6			154.1
Purchased gas, oil and NGL sales⁽¹⁾	(47.1		)	(17.8		)	(13.9		)
Total Revenues	203.1			250.7			278.1
OPERATING EXPENSES
Purchased gas, oil and NGL expense⁽¹⁾	(48.5		)	(17.6		)	(15.1		)
Lease operating expense⁽¹⁾	(5.5		)	(3.5		)	(3.5		)
Natural gas, oil and NGL transport & other handling costs⁽¹⁾	(55.4		)	(80.6		)	(49.2		)
Gathering, processing, and other	85.9			82.2			79.8
General and administrative	42.1			30.7			17.9
Production and property taxes	7.3			5.2			5.1
Depreciation, depletion and amortization	45.9			52.2			55.1
Total Operating Expenses	71.8			68.6			90.1
Net gain (loss) from asset sales	1,793.4			(0.5		)	—
OPERATING INCOME	1,924.7			181.6			188.0
Realized derivative gains	—			—			8.4
Interest and other income (expense)	0.3			(10.0		)	(8.2		)
Income from unconsolidated affiliates	4.9			5.6			6.7
Loss on early extinguishment of debt	(2.4		)	—			—
Interest expense (income)	(3.8		)	1.8			3.4
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES ⁽²⁾	1,923.7			179.0			198.3
Income tax provision	(708.2		)	(59.7		)	(68.7		)
NET INCOME FROM DISCONTINUED OPERATIONS	1,215.5			119.3			129.6
Net income attributable to noncontrolling interest	(21.6		)	(12.0		)	(3.7		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	1,193.9		$	107.3		$	125.9

___________________________


⁽¹⁾	Includes discontinued intercompany eliminations.


⁽²⁾	Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owned 57.8%) of $28.9 million, $33.5 million and $38.9 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Assets And Liabilities Of Discontinued Operations [Table Text Block]



	December 31, 2013

Cash and cash equivalents	$	18.1
Accounts receivable, net	53.9
Income taxes receivable	38.4
Deferred income taxes - current	2.7
Prepaid expenses and other	8.9
Current assets of discontinued operations	$	122.0

Property, Plant and Equipment
Midstream field services	$	1,500.8
Material and supplies	4.8
Total Property, Plant and Equipment	1,505.6
Less Accumulated Depreciation, Depletion and Amortization	(381.6		)
Net Property, Plant and Equipment	1,124.0
Investment in unconsolidated affiliates	39.0
Other noncurrent assets	4.7
Noncurrent assets of discontinued operations	$	1,167.7

Accounts payable and accrued expenses	$	74.1
Production and property taxes	1.2
Current liabilities of discontinued operations	$	75.3

Deferred income taxes	$	195.7
Asset retirement obligations	28.5
Other long-term liabilities	14.1
Noncurrent liabilities of discontinued operations	$	238.3

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Fair value of financial assets and liabilities

The fair value of financial assets and liabilities at December 31, 2014 and 2013, is shown in the tables below:



	Fair Value Measurements
	December 31, 2014
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheet
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	339.3	$	—	$	(0.3	)	$	339.0
Commodity derivative instruments - long-term	—		9.9		—		—			9.9
Total financial assets	$	—	$	349.2	$	—	$	(0.3	)	$	348.9

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	0.3	$	—	$	(0.3	)	$	—
Total financial liabilities	$	—	$	0.3	$	—	$	(0.3	)	$	—

____________________________


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



	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheet
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheet
	(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

Fair value and related carrying amount of certain financial instruments



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2014				December 31, 2013
	(in millions)
Financial assets
Cash and cash equivalents	$	1,160.1	$	1,160.1	$	11.9	$	11.9
Financial liabilities
Checks outstanding in excess of cash balances	$	54.7	$	54.7	$	109.1	$	109.1
Long-term debt	2,218.1		$	2,171.6	2,997.5		$	3,034.9

- Definition

Tabular disclosure of financial instruments measured at fair value, including those classified in shareholders' equity measured on a recurring or nonrecurring basis. Disclosures include, but are not limited to, fair value measurements recorded and the reasons for the measurements, level within the fair value hierarchy in which the fair value measurements are categorized and transfers between levels 1 and 2. Nonrecurring fair value measurements are those that are required or permitted in the statement of financial position in particular circumstances.

+ References+ Details

- Definition

Tabular disclosure of the fair value of financial instruments, including financial assets and financial liabilities, and the measurements of those instruments, assets, and liabilities.

+ References+ Details

Derivative Contracts (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014:



				Swaps
Year	Type of Contract	Index	Total Volumes	Average price per unit
			(in millions)
Gas sales			(MMBtu)
2015	Swap	NYMEX HH	29.2	$	4.11
2015	Swap	IFNPCR	40.2	$	3.70

Oil sales			(Bbls)
2015	Swap	NYMEX WTI	7.7	$	90.04
2015	Swap	ICE Brent	0.4	$	104.95
2016	Swap	NYMEX WTI	0.4	$	90.00

The following table sets forth QEP Energy's crude oil sales costless collars as of December 31, 2014:

Total Volume

Average Price

Year

Index

Bbls

Floor

Ceiling

(in millions)

2015

NYMEX WTI

0.5

50.00

63.34

The following table sets forth QEP Energy's oil basis swaps as of December 31, 2014:



Year	Index	Index Less Differential	Total Volumes Bbls	Weighted Average Differential
Oil basis swaps			(in millions)
2015	NYMEX WTI	LLS	0.1	$	4.03

QEP Marketing Derivative Contracts



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2015	Swap	IFNPCR	2.8	$	4.03
2016	Swap	IFNPCR	0.9	$	3.58
Gas purchases			(MMBtu)
2015	Swap	IFNPCR	0.9	$	3.06

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	2014		2013		2014		2013
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	339.3	$	5.5	$	0.3	$	29.4
Interest rate swaps	Fair value of derivative contracts	—		—		—		2.6
Long-term:
Commodity	Fair value of derivative contracts	9.9		0.4		—		—
Interest rate swaps	Fair value of derivative contracts	—		0.6		—		—
Total derivative instruments		$	349.2	$	6.5	$	0.3	$	32.0

Effects of Derivative Transactions



Derivative instruments not designated as cash flow hedges	Year Ended December 31,
Derivative instruments not designated as cash flow hedges	2014			2013			2012
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	(16.7	)	$	152.0		$	341.9
Oil derivative contracts	15.7			(2.2		)	14.4
NGL derivative contracts	—			—			10.2
QEP Marketing
Gas derivative contracts	(2.5		)	0.5			5.1
Total realized gains (losses) on commodity derivative contracts	(3.5		)	150.3			371.6
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	68.4			(42.6		)	37.8
Oil derivative contracts	299.8			(48.1		)	29.0
NGL derivative contracts	—			—			1.6
QEP Marketing
Gas derivative contracts	4.2			(2.1		)	0.9
Total unrealized gains (losses) on commodity derivative contracts	372.4			(92.8		)	69.3
Total realized and unrealized gains (losses) on commodity derivative contracts	$	368.9		$	57.5		$	440.9
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(7.6	)	$	(2.7	)	$	(1.3	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	2.0			4.1			(6.1		)
Total realized and unrealized gains (losses) on interest rate swaps	(5.6		)	1.4			(7.4		)
Total net realized gains (losses) on derivative contracts	(11.1		)	147.6			370.3
Total net unrealized gains (losses) on derivative contracts	374.4			(88.7		)	63.2
Grand Total	$	363.3		$	58.9		$	433.5

Restructuring Costs (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014		Year ended December 31,
			Period from Inception to December 31, 2014		2014		2013		2012
Continuing Operations:	(in millions)
QEP Energy
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 Marketing and Other
One-time termination benefits	$	0.3	$	0.3	$	—	$	0.1	$	0.2
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	3.7		3.7		—		0.4		3.3
Lease termination costs	0.6		0.6		—		—		0.6
Total restructuring costs	$	7.9	$	7.9	$	—	$	0.9	$	7.0

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

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



Year	Amount
2015	$	130.7
2016	$	120.6
2017	$	120.0
2018	$	117.1
2019	$	112.0
After 2019	$	407.4

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
2015	$	8.4
2016	$	8.2
2017	$	8.4
2018	$	6.9
2019	$	6.8
After 2019	$	23.9

- 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

Equity-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2014

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,
	2014			2013			2012
Weighted-average grant-date fair value of awards granted during the period	$	10.11		$	15.16		$	14.29
Risk-free interest rate range	1.31% - 1.34%			0.97% - 1.84%			0.63% - 1.04%
Weighted-average risk-free interest rate	1.3		%	1.0		%	0.8		%
Expected price volatility range	36.1% - 37.3%			51.5% - 58.5%			55.9% - 56.5%
Weighted-average expected price volatility	37.1		%	58.3		%	55.9		%
Expected dividend yield	0.25		%	0.27		%	0.26		%
Expected term in years at the date of grant	4.5			5.5			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, 2013	1,794,187		$	27.90
Granted	282,236		31.67
Exercised	(65,366	)	22.24
Forfeited	(14,842	)	30.53
Outstanding at December 31, 2014	1,996,215		$	28.60	3.18	$	0.1
Options Exercisable at December 31, 2014	1,494,061		$	27.80	2.39	$	0.1
Unvested Options at December 31, 2014	502,154		$	30.98	5.51	$	—

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, 2013	1,388,953		$	30.96
Granted	1,033,023		31.40
Vested	(855,720	)	31.39
Forfeited	(139,803	)	31.00
Unvested balance at December 31, 2014	1,426,453		$	31.02

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, 2013	480,660		$	32.33
Granted	256,101		31.57
Vested	(73,956	)	37.17
Canceled	(83,545	)	35.84
Forfeited	(27,051	)	30.60
Unvested balance at December 31, 2014	552,209		$	30.85

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2014

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
	2014			2013			2014			2013
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$	118.0		$	129.7		$	5.9		$	6.7
Service cost	2.6			3.3			—			0.1
Interest cost	5.3			4.8			0.3			0.3
Special termination benefits	1.9			—			—			—
Curtailments	(8.2		)	—			(0.2		)	—
Plan settlements	(2.3		)	—			—			—
Benefit payments	(5.5		)	(5.5		)	—			(0.1		)
Actuarial loss (gain)	20.8			(14.3		)	0.6			(1.1		)
Benefit obligation at December 31,	$	132.6		$	118.0		$	6.6		$	5.9
Change in plan assets
Fair value of plan assets at January 1,	$	71.7		$	55.3		$	—		$	—
Actual gain on plan assets	4.5			10.4			—			—
Company contributions to the plan	13.0			11.5			—			0.1
Benefit payments	(5.5		)	(5.5		)	—			(0.1		)
Plan settlements	(2.3		)	—			—			—
Fair value of plan assets at December 31,	81.4			71.7			—			—
Underfunded status (current and long-term)	$	(51.2	)	$	(46.3	)	$	(6.6	)	$	(5.9	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(4.3	)	$	(5.5	)	$	(0.3	)	$	(0.2	)
Other long-term liabilities	(46.9		)	(40.8		)	(6.3		)	(5.7		)
Total amount recognized in balance sheet	$	(51.2	)	$	(46.3	)	$	(6.6	)	$	(5.9	)
Amounts recognized in AOCI
Net actuarial loss	$	21.2		$	9.5		$	0.6		$	0.2
Prior service cost	16.1			30.1			1.4			3.0
Total amount recognized in AOCI	$	37.3		$	39.6		$	2.0		$	3.2

Pension and Other Postretirement Benefit Costs



	Pension benefits									Other postretirement benefits
	2014			2013			2012			2014			2013			2012

Components of net periodic benefit cost
Service cost	$	2.6		$	3.3		$	4.0		$	—		$	0.1		$	0.1
Interest cost	5.3			4.8			5.1			0.3			0.3			0.3
Expected return on plan assets	(5.1		)	(3.9		)	(3.6		)	—			—			—
Curtailment loss	9.3			—			2.2			1.4			—			—
Special termination benefits	1.9			—			—			—			—			—
Settlements	0.7			—			—			—			—			—
Amortization of prior service costs	4.7			5.0			5.3			0.3			0.3			0.3
Amortization of actuarial loss	0.8			2.3			1.9			—			0.1			0.1
Periodic expense	$	20.2		$	11.5		$	14.9		$	2.0		$	0.8		$	0.8
Components recognized in accumulated other comprehensive income
Current period actuarial loss (gain)	$	21.5		$	(20.8	)	$	15.9		$	0.6		$	(1.0	)	$	0.4
Amortization of actuarial loss	(0.8		)	(2.3		)	(1.9		)	—			(0.1		)	(0.1		)
Amortization of prior service cost	(14.0		)	(5.0		)	(5.3		)	(1.7		)	(0.4		)	(0.4		)
Loss on curtailment in current period	(8.2		)	—			(2.2		)	(0.2		)	—			—
Settlements	(0.7		)	—			—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	(2.2	)	$	(28.1	)	$	6.5		$	(1.3	)	$	(1.5	)	$	(0.1	)

Schedule of Assumptions Used [Table Text Block]



	Pension benefits				Other postretirement benefits
	2014		2013		2014		2013
Discount rate	3.94	%	4.75	%	4.00	%	5.00	%
Rate of increase in compensation	4.00	%	4.00	%	4.00	%	4.00	%



	Pension benefits						Other postretirement benefits
	2014		2013		2012		2014		2013		2012
Discount rate	4.40	%	3.69	%	4.38	%	5.00	%	4.10	%	4.70	%
Expected long-term return on plan assets	7.00	%	6.75	%	7.25	%	n/a		n/a		n/a
Rate of increase in compensation	4.00	%	3.60	%	3.60	%	4.00	%	3.60	%	4.00	%

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, 2014								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	—		—		36.7		36.7		45	%
International	—		—		20.2		20.2		25	%
Fixed income	—		—		24.2		24.2		30	%
Total investments	—		—		$	81.4	$	81.4	100	%
	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	%

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,
	2014			2013
	(in millions)
Balance at January 1,	$	71.7		55.2
Employer contributions	8.1			8.1
Unrealized gains (losses)	(1.0		)	9.8
Realized gains	5.9			1.0
Administrative fees	(0.4		)	(0.3		)
Benefits paid	(2.9		)	(2.1		)
Balance at December 31,	$	81.4		$	71.7

Schedule of Expected Benefit Payments [Table Text Block]

Expected Benefit Payments

As of December 31, 2014, the following future benefit payments are expected to be paid:



	Pension		Postretirement benefits
	(in millions)
2015	$	8.3	$	0.3
2016	7.0		0.4
2017	6.3		0.4
2018	6.3		0.4
2019	7.2		0.4
2020 through 2024	41.8		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+ Details

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

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

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



	Year Ended December 31,
	2014			2013			2012
	(in millions)
Federal income tax provision (benefit)
Current	$	(324.0	)	$	(92.2	)	$	(10.3	)
Deferred	110.3			152.3			15.6
State income tax provision (benefit)
Current	(15.5		)	(1.4		)	(1.8		)
Deferred	(3.3		)	1.4			(5.4		)
Total income tax provision (benefit)	$	(232.5	)	$	60.1		$	(1.9	)

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,
	2014		2013		2012
Federal income taxes statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	(1.5	)%	(5.0	)%	(2,220.0	)%
State rate change	3.4	%	—	%	—	%
Penalties	—	%	0.4	%	80.0	%
Return to provision adjustment	(0.4	)%	5.0	%	1,400.0	%
Book impairment of goodwill	—	%	18.6	%	—	%
Other	(0.3	)%	(0.4	)%	325.0	%
Effective income tax rate	36.2	%	53.6	%	(380.0	)%

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



	December 31,
	2014		2013
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$	1,402.9	$	1,455.6
Commodity price and interest rate derivatives	127.7		—
Total deferred tax liabilities	1,530.6		1,455.6
Deferred tax assets
Commodity price and interest rate derivatives	—		9.8
Net operating loss and tax credit carryforwards	11.7		54.4
Employee benefits and compensation costs	43.0		36.1
Accrued litigation loss contingency	—		0.8
Bonus and vacation accrual	16.3		9.0
Other	12.4		8.5
Total deferred tax assets	83.4		118.6
Net deferred income tax liability	$	1,447.2	$	1,337.0
Balance sheet classification
Deferred income tax asset - current	$	—	$	27.9
Deferred income tax liability - current	84.5		—
Deferred income tax liability - non-current	1,362.7		1,364.9
Net deferred income tax liability	$	1,447.2	$	1,337.0

Summary of Operating Loss Carryforwards [Table Text Block]

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2014 are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2015-2033	$	30.1
State net operating loss valuation allowance		(18.4		)
U.S. alternative minimum tax credit	Indefinite	—
Total		$	11.7

Operations by Line of Business (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			Discontinued Operations		QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	2,524.6		$	889.7		$	—		$	—	$	3,414.3
From affiliated customers	—			1,492.6			(1,492.6		)	—		—
Total Revenues	2,524.6			2,382.3			(1,492.6		)	—		3,414.3
OPERATING EXPENSES
Purchased gas, oil and NGL expense	150.0			2,356.6			(1,475.4		)	—		1,031.2
Lease operating expense	240.1			—			—			—		240.1
Gas, oil and NGL transportation and other handling costs	291.5			—			(13.9		)	—		277.6
Gathering and other expense	—			6.8			(0.1		)	—		6.7
General and administrative	201.3			6.3			(3.2		)	—		204.4
Production and property taxes	204.0			1.2			—			—		205.2
Depreciation, depletion and amortization	984.4			10.3			—			—		994.7
Impairment and exploration expenses	1,153.1			—			—			—		1,153.1
Total Operating Expenses	3,224.4			2,381.2			(1,492.6		)	—		4,113.0
Net gain (loss) from asset sales	(148.6		)	—			—			—		(148.6		)
OPERATING INCOME (LOSS)	(848.4		)	1.1			—			—		(847.3		)
Realized and unrealized gains (losses) on derivative contracts	367.2			(3.9		)	—			—		363.3
Interest and other income	11.8			209.7			(208.7		)	—		12.8
Income from unconsolidated affiliates	0.3			—			—			—		0.3
Loss from early extinguishment of debt	—			(2.0		)	—			—		(2.0		)
Interest expense	(210.3		)	(167.5		)	208.7			—		(169.1		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(679.4		)	37.4			—			—		(642.0		)
Income tax (provision) benefit	246.9			(14.4		)	—			—		232.5
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(432.5		)	23.0			—			—		(409.5		)
Net income from discontinued operations, net of income tax	—			—			—			1,193.9		1,193.9
NET INCOME (LOSS) ATTRIBUTABLE TO QEP	$	(432.5	)	$	23.0		$	—		$	1,193.9	$	784.4
Identifiable total assets	$	8,001.1		$	1,285.7		$	—		$	—	$	9,286.8
Cash capital expenditures	2,660.3			10.9			—			55.2		$	2,726.4
Accrued capital expenditures	2,670.5			13.6			—			50.7		$	2,734.8

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



	QEP Energy			QEP Marketing and Other			Eliminations			Discontinued Operations		QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	2,092.8		$	592.3		$	—		$	—	$	2,685.1
From affiliated customers	—			1,008.9			(1,008.9		)	—		—
Total Revenues	2,092.8			1,601.2			(1,008.9		)	—		2,685.1
OPERATING EXPENSES
Purchased gas, oil and NGL expense	197.1			1,570.5			(984.1		)	—		783.5
Lease operating expense	181.3			—			—			—		181.3
Gas, oil and NGL transportation and other handling costs	242.2			—			(20.2		)	—		222.0
Gathering and other expense	—			8.4			—			—		8.4
General and administrative	160.6			4.4			(4.6		)	—		160.4
Production and property taxes	159.8			1.5			—			—		161.3
Depreciation, depletion and amortization	954.2			9.6			—			—		963.8
Impairment and exploration expenses	104.9			—			—			—		104.9
Total Operating Expenses	2,000.1			1,594.4			(1,008.9		)	—		2,585.6
Net gain (loss) from asset sales	104.1			(0.6		)	—			—		103.5
OPERATING INCOME (LOSS)	196.8			6.2			—			—		203.0
Realized and unrealized gains (losses) on derivative contracts	59.1			(0.2		)	—			—		58.9
Interest and other income	3.6			206.9			(195.3		)	—		15.2
Income from unconsolidated affiliates	0.2			—			—			—		0.2
Interest expense	(192.6		)	(167.8		)	195.3			—		(165.1		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	67.1			45.1			—			—		112.2
Income tax provision	(41.5		)	(18.6		)	—			—		(60.1		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	25.6			26.5			—			—		52.1
Net income from discontinued operations, net of income tax	—			—			—			107.3		107.3
NET INCOME (LOSS ATTRIBUTABLE TO QEP	$	25.6		$	26.5		$	—		$	107.3	$	159.4
Identifiable total assets	$	7,937.0		$	182.2		$	—		$	1,289.7	$	9,408.9
Cash capital expenditures	1,488.6			25.1			—			88.9		$	1,602.6
Accrued capital expenditures	1,467.2			24.6			—			85.6		$	1,577.4

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



	QEP Energy			QEP Marketing and Other			Eliminations			Discontinued Operations		QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	1,615.4		$	456.3		$	—		$	—	$	2,071.7
From affiliated customers	—			611.2			(611.2		)	—		—
Total Revenues	1,615.4			1,067.5			(611.2		)	—		2,071.7
OPERATING EXPENSES
Purchased gas, oil and NGL expense	224.7			1,021.1			(575.1		)	—		670.7
Lease operating expense	175.8			—			—			—		175.8
Gas, oil and NGL transportation and other handling costs	228.1			—			(30.0		)	—		198.1
Gathering and other expense	—			8.2			—			—		8.2
General and administrative	252.8			1.7			(6.1		)	—		248.4
Production and property taxes	97.2			1.3			—			—		98.5
Depreciation, depletion and amortization	838.4			11.8						—		850.2
Impairment and exploration expenses	144.2			—			—			—		144.2
Total Operating Expenses	1,961.2			1,044.1			(611.2		)	—		2,394.1
Net gain from asset sales	1.2			—			—			—		1.2
OPERATING INCOME (LOSS)	(344.6		)	23.4			—			—		(321.2		)
Realized and unrealized gains (losses) on derivative contracts	434.9			(1.4		)	—			—		433.5
Interest and other income	6.2			132.3			(123.5		)	—		15.0
Income from unconsolidated affiliates	0.1			—			—			—		0.1
Loss on extinguishment of debt	—			(0.6		)	—			—		(0.6		)
Interest expense	(116.8		)	(133.0		)	123.5			—		(126.3		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(20.2		)	20.7			—			—		0.5
Net Income tax benefit (provision)	12.1			(10.2		)	—			—		1.9
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(8.1		)	10.5			—			—		2.4
Net income from discontinued operations, net of income tax	—			—			—			125.9		125.9
NET INCOME (LOSS) ATTRIBUTABLE TO QEP	$	(8.1	)	$	10.5		$	—		$	125.9	$	128.3
Identifiable assets	$	7,436.5		$	244.6		$	—		$	1,427.4	$	9,108.5
Cash capital expenditures	2,621.1			22.4			—			156.2		2,799.7
Accrued capital expenditures	2,702.4			21.6			—			164.2		2,888.2
Goodwill	59.5			—			—			—		59.5

- 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, 2014

Quarterly Financial Information Disclosure [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, except per share information)
2014
Revenues	$	817.5	$	887.2		$	910.0		$	799.6		$	3,414.3
Operating income (loss)	140.8		(35.9		)	115.1			(1,067.3		)	(847.3		)
Income (loss) from continuing operations	12.7		(106.1		)	153.7			(469.8		)	(409.5		)
Discontinued operations, net of income taxes ⁽¹⁾	27.0		13.8			17.4			1,135.7			1,193.9
Net income (loss) attributable to QEP	39.7		(92.3		)	171.1			665.9			784.4
Non-recurring items in operating income (loss) ⁽²⁾	0.4		(202.5		)	(11.9		)	(1,077.8		)	(1,291.8		)
Per share information attributable to QEP
Basic EPS from continuing operations	$	0.07	$	(0.59	)	$	0.85		$	(2.62	)	$	(2.28	)
Basic EPS from discontinued operations	0.15		0.08			0.10			6.34			6.64
Diluted EPS from continuing operations	0.07		(0.59		)	0.84			(2.62		)	(2.28		)
Diluted EPS from discontinued operations	0.15		0.08			0.10			6.34			6.64



2013
Revenues	$	651.3		$	694.0	$	719.5	$	620.3		2,685.1
Operating income (loss)	27.3			159.1		83.3		(66.7		)	203.0
Income (loss) from continuing operations	(24.8		)	149.2		12.1		(84.4		)	52.1
Discontinued operations, net of income taxes ⁽¹⁾	20.5			29.2		25.2		32.4			107.3
Net income (loss) attributable to QEP	(4.3		)	178.4		37.3		(52.0		)	$	159.4
Non-recurring items in operating income (loss) ⁽²⁾	(0.2		)	100.2		9.0		$	(98.5	)	10.5
Per share information attributable to QEP
Basic EPS from continuing operations	$	(0.14	)	$	0.83	$	0.07	$	(0.47	)	$	0.29
Basic EPS from discontinued operations	0.12			0.16		0.14		0.18			0.60
Diluted EPS from continuing operations	(0.14		)	0.83		0.07		(0.47		)	0.29
Diluted EPS from discontinued operations	0.12			0.16		0.14		0.18			0.60

____________________________


⁽¹⁾	In December 2014, QEP completed the Midstream Sale. QEP Field Services' financial results (excluding results of the Haynesville Gathering System) have been reflected as discontinued operations and all prior periods have been reclassified.


⁽²⁾	Includes net gains and losses from asset sales and losses due to asset impairments.

Supplemental Gas and Oil Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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



	December 31,
	2014			2013
	(in millions)
Proved properties	$	12,278.7		$	11,571.4
Unproved properties, net	825.2			665.1
Total proved and unproved properties	13,103.9			12,236.5
Accumulated depreciation, depletion and amortization	(6,153.0		)	(4,930.9		)
Net capitalized costs	$	6,950.9		$	7,305.6

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



	Year Ended December 31,
	2014		2013		2012
	(in millions)
Property acquisitions
Unproved	$	496.3	$	9.3	$	692.6
Proved	465.4		31.6		714.4
Total property acquisitions	961.7		40.9		1,407.0
Exploration (capitalized and expensed)	23.6		14.6		14.3
Development	1,695.1		1,440.8		1,310.0
Total costs incurred	$	2,680.4	$	1,496.3	$	2,731.3

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 producing activities, before allocated corporate overhead and interest expenses.



	Year Ended December 31,
	2014			2013			2012
	(in millions)
Revenues	$	2,374.6		$	1,901.2		$	1,393.4
Production costs	735.6			583.3			501.1
Exploration expenses	9.9			11.9			11.2
Depreciation, depletion and amortization	984.4			954.2			838.4
Impairment	1,143.2			93.0			133.0
Total expenses	2,873.1			1,642.4			1,483.7
Income (loss) before income taxes	(498.5		)	258.8			(90.3		)
Income tax benefit (expense)	182.5			(96.3		)	33.6
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(316.0	)	$	162.5		$	(56.7	)

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, 2011	2,749.4		67.5		76.6		3,613.8
Revisions of previous estimates⁽¹⁾	(240.6	)	(1.5	)	0.7		(244.8	)
Extensions and discoveries⁽²⁾	330.6		17.3		23.0		572.5
Purchase of reserves in place⁽³⁾	32.3		42.0		4.9		313.8
Sale of reserves in place	—		—		—		—
Production	(249.3	)	(6.3	)	(5.3	)	(319.2	)
Balance at December 31, 2012	2,622.4		119.0		99.9		3,936.1
Revisions of previous estimates⁽⁴⁾	(288.3	)	1.3		(8.0	)	(328.5	)
Extensions and discoveries⁽⁵⁾	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
Revisions of previous estimates⁽⁶⁾	27.1		(4.0	)	1.4		11.3
Extensions and discoveries⁽⁷⁾	141.4		16.8		8.6		294.1
Purchase of reserves in place⁽⁸⁾	72.5		35.7		12.3		360.7
Sale of reserves in place⁽⁹⁾	(299.4	)	(7.5	)	(21.5	)	(473.4	)
Production	(179.3	)	(17.1	)	(6.8	)	(322.7	)
Balance at December 31, 2014	2,317.2		172.5		96.6		3,931.9
Proved developed reserves
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
Balance at December 31, 2014	1,288.4		99.3		52.2		2,197.5
Proved undeveloped reserves
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
Balance at December 31, 2014	1,028.8		73.2		44.4		1,734.4

___________________________

⁽¹⁾

⁽²⁾


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

⁽⁴⁾

⁽⁵⁾

⁽⁶⁾


⁽⁷⁾	Extensions and discoveries in 2014 increased proved reserves by 294.1 Bcfe, primarily related to extensions and discoveries in Pinedale of 133.6 Bcfe and the Williston Basin of 123.3 Bcfe. 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 and new compression well projections in Pinedale.


⁽⁸⁾	Purchase of reserves in place in 2014 relate to the Company's Permian Basin Acquisition as discussed in Note 2 - Acquisitions and Divestitures.


⁽⁹⁾	Sale of reserves in place primarily related to property sales in the Midcontinent in the second and fourth quarters of 2014 as discussed in Note 2 - Acquisitions and Divestitures.

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

he 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,
	2014		2013		2012
Average benchmark price per unit:
Gas price (per MMBtu)	$	4.35	$	3.67	$	2.76
Oil price (per bbl)	94.99		96.94		94.71

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

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



	Year Ended December 31,
	2014			2013			2012
	(in millions)
Future cash inflows	$	28,167.3		$	24,805.7		$	18,200.2
Future production costs	(9,842.1		)	(8,400.3		)	(5,027.2		)
Future development costs	(3,521.3		)	(4,056.7		)	(3,927.3		)
Future income tax expenses	(4,304.0		)	(3,284.6		)	(2,269.0		)
Future net cash flows	10,499.9			9,064.1			6,976.7
10% annual discount for estimated timing of net cash flows	(5,159.9		)	(4,680.2		)	(3,942.0		)
Standardized measure of discounted future net cash flows	$	5,340.0		$	4,383.9		$	3,034.7

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

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



	Year Ended December 31,
	2014			2013			2012
	(in millions)
Balance at January 1,	$	4,383.9		$	3,034.7		$	3,525.6
Sales of gas, oil and NGL produced during the period, net of production costs	(1,639.0		)	(1,317.9		)	(892.3		)
Net change in sales prices and in production (lifting) costs related to future production	726.6			1,236.3			(2,083.5		)
Net change due to extensions, discoveries and improved recovery	979.9			2,230.7			948.5
Net change due to revisions of quantity estimates	35.9			(709.6		)	(387.8		)
Net change due to purchases of reserves in place	695.3			36.8			831.4
Net change due to sales of reserves in place	(1,153.7		)	(73.2		)	—
Previously estimated development costs incurred during the period	867.5			722.7			513.0
Changes in estimated future development costs	409.6			(596.5		)	(209.3		)
Accretion of discount	597.3			402.2			499.4
Net change in income taxes	(600.3		)	(601.7		)	273.6
Other	37.0			19.4			16.1
Net change	956.1			1,349.2			(490.9		)
Balance at December 31,	$	5,340.0		$	4,383.9		$	3,034.7

- Definition

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

+ References+ Details

- Definition

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

+ References

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 932

-SubTopic 235

-Section 55

-Paragraph 5

-URI http://asc.fasb.org/extlink&oid=34713648&loc=d3e63071-109448

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 410

-SubTopic 20

-Section 50

-Paragraph 1

-Subparagraph (c)(3)

-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 932

-SubTopic 235

-Section 50

-Paragraph 23

-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62136-109447

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 932

-SubTopic 235

-Section 50

-Paragraph 24

-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62246-109447

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 932

-SubTopic 235

-Section 50

-Paragraph 27

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

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

-Publisher FASB

-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))

-URI http://asc.fasb.org/extlink&oid=27015464&loc=d3e511914-122862

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 932

-SubTopic 235

-Section 50

-Paragraph 25

-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62259-109447

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 932

-SubTopic 235

-Section 50

-Paragraph 26

-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62299-109447

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 932

-SubTopic 235

-Section 50

-Paragraph 22

-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62094-109447

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

-Publisher FASB

-Name Accounting Standards Codification

-Topic 932

-SubTopic 235

-Section 50

-Paragraph 28

-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62395-109447

+ 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 Nature of Business (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Nature Of Business [Abstract]
Value of business sold	$ 2,500.0
Debt refinanced in business sale	230.0
Pre-tax gain on sale of discontinued operations	$ 1,793.4

Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Restricted cash	$ 0	$ 50.0
Cash paid for interest, net of capitalized interest	163.2	156.7	105.1
Cash paid for income taxes	0.3	77.9	30.0
Change in capital expenditure accrual balance	$ 8.4	$ (25.2)	$ 88.5

Summary of Significant Accounting Policies Impairment of long-lived assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 1,143.2	$ 93.0	$ 133.0
Impairment of Oil and Gas Properties	1,143.2	33.5
Goodwill, Impairment Loss		59.5
Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	1,041.4	1.2	107.6
Unproved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	101.8	32.3	25.4
Southern Region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	1,116.8	17.5	104.7
Northern Region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 26.4	$ 16.0	$ 28.3

Summary of Significant Accounting Policies Goodwill (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Line Items]
Goodwill		$ 59.5
Goodwill, Impairment Loss	$ 59.5

Summary of Significant Accounting Policies Derivative instruments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]
Unrealized (Loss) Gain on Derivatives	$ 374.4	$ (88.7)	$ 63.2
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, 2014	Dec. 31, 2013	Dec. 31, 2012
Concentration Risk [Line Items]
Concentration Risk, Percentage	33.00%	38.00%	27.00%
Valero Marketing And Supply Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
Freepoint Commodities [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		13.00%
Arrow Midstream Holdings LLC [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		11.00%

Summary of Significant Accounting Policies Share Repurchases And Retirements (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Share Repurchases And Retirements [Abstract]
Stock repurchase program, authorized amount	$ 500.0
Number of shares of common stock repurchased and retired	4,731,438
Weighted average price of common stock repurchased and retired	$ 21.08
Commission paid per share of common stock repurchased and retired	$ 0.02
Value of stock repurchased and retired	$ 99.7

Summary of Significant Accounting Policies Earnings Per Share (Details) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive shares excluded from computation of EPS	0.3
Used in basic calculation	179.8	179.2	177.8
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan	0	0.3	0.9
Average diluted common shares outstanding (in shares)	179.8	179.5	178.7

- Definition

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

+ References+ Details

Acquisitions and Divestitures (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Impairment of Oil and Gas Properties	$ 1,143.2	$ 33.5
Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Aggregate purchase price	941.8
Net acres of producing and undeveloped oil and gas properties	26,500
Vertical producing oil and gas wells	270
Escrow Deposit	50.0
Borrowing from Company's expanded term loan	300.0
Revenue of acquired properties since acquisition date	159.5
Net income of acquired properties since acquisition date	(438.3)
Impairment of Oil and Gas Properties	467.7
Transaction costs	0.6
Debt issuance cost	1.1
Williston Basin Acquisition [Member]
Business Acquisition [Line Items]
Aggregate purchase price		1,392.7
Revenue of acquired properties since acquisition date	767.3	300.0	63.7
Net income of acquired properties since acquisition date	402.1	67.0	14.9
Transaction costs			$ 1.1

Acquisitions and Divestitures Schedule Of Purchase Accounting Entries (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended					12 Months Ended
	Dec. 31, 2014 Permian Basin Acquisition [Member]	Dec. 31, 2014 Permian Basin Acquisition [Member] Proved Property [Member]	Dec. 31, 2014 Permian Basin Acquisition [Member] Unproved Property [Member]	Dec. 31, 2014 Permian Basin Acquisition [Member] Asset Retirement Obligation Costs [Member]	Dec. 31, 2014 Permian Basin Acquisition [Member] Other Liabilities [Member]	Dec. 31, 2013 Williston Basin Acquisition [Member]
Business Acquisition [Line Items]
Aggregate purchase price	$ 941.8					$ 1,392.7
Recognized identifiable assets acquired and liabilities assumed, net	$ 941.8	$ 472.1	$ 480.6	$ (9.7)	$ (1.2)

Acquisitions and Divestitures Schedule of Pro Forma Results Of Operations (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Revenues	$ 799.6	$ 910.0	$ 887.2	$ 817.5	$ 620.3	$ 719.5	$ 694.0	$ 651.3	$ 3,414.3	$ 2,685.1	$ 2,071.7
Net income attributable to QEP	665.9	171.1	(92.3)	39.7	(52.0)	37.3	178.4	(4.3)	784.4	159.4	128.3
Earnings Per Share, Basic									$ 4.36	$ 0.89	$ 0.72
Diluted total									$ 4.36	$ 0.89	$ 0.72
Williston Basin Acquisition [Member]
Business Acquisition [Line Items]
Revenues											2,071.7
Net income attributable to QEP											128.3
Earnings Per Share, Basic											$ 0.72
Diluted total											$ 0.72
Business Acquisition, Pro Forma Revenue											2,207.2
Business Acquisition, Pro Forma Net Income (Loss)											143.0
Business Acquisition, Pro Forma Earnings Per Share, Basic											$ 0.80
Business Acquisition, Pro Forma Earnings Per Share, Diluted											$ 0.80
Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Revenues									3,414.3	2,685.1
Net income attributable to QEP									784.4	159.4
Earnings Per Share, Basic									$ 4.36	$ 0.89
Diluted total									$ 4.36	$ 0.89
Business Acquisition, Pro Forma Revenue									3,440.4	2,858.8
Business Acquisition, Pro Forma Net Income (Loss)									$ 791.4	$ 195.3
Business Acquisition, Pro Forma Earnings Per Share, Basic									$ 4.40	$ 1.09
Business Acquisition, Pro Forma Earnings Per Share, Diluted									$ 4.40	$ 1.09

- Definition

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

+ References+ 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+ Details

Acquisitions and Divestitures Divestitures (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Jun. 30, 2014 Midcontinent Divestitures [Member]	Jun. 30, 2013 Northern Region Divestitures [Member]	Dec. 31, 2014 Southern Region Divestitures [Member]	Sep. 30, 2013 Southern Region Divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	$ 692.9	$ 138.5	$ 94.9	$ 67.3
Gain (Loss) on Disposition of Oil and Gas and Timber Property	$ (199.4)	$ 96.2	$ 53.3	$ 9.5

Discontinued Operations (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Value of business sold	$ 2,500.0
Debt refinanced in business sale	230.0
Pre-tax gain on sale of discontinued operations	1,793.4
Continuing Cash Flows To Business Held For Sale	145.3	124.6	113.5
Depreciation, depletion and amortization	994.7	963.8	850.2
Midstream Business Held For Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Depreciation, depletion and amortization	45.9	52.2	55.1
Payments to Acquire Oil and Gas Property and Equipment	$ 55.2	$ 88.9	$ 156.2

Discontinued Operations Income Statement Impact Of Discontinued Operations (Details) (USD $)
In Millions, unless otherwise specified

3 Months Ended

12 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

NGL sales

$ 223.3

$ 192.2

$ 184.2

Other revenues

11.1

22.4

27.5

Purchased gas, oil and NGL sales

1,035.0

774.9

660.0

Total Revenues

799.6

910.0

887.2

817.5

620.3

719.5

694.0

651.3

3,414.3

2,685.1

2,071.7

Purchased gas, oil and NGL expense

1,031.2

783.5

670.7

Lease operating expense

240.1

181.3

175.8

Natural gas, oil and NGL transportation and other handling costs

277.6

222.0

198.1

Gathering and other expense

6.7

8.4

8.2

General and administrative

204.4

160.4

248.4

Production and property taxes

205.2

161.3

98.5

Depreciation, depletion and amortization

994.7

963.8

850.2

Total Operating Expenses

4,113.0

2,585.6

2,394.1

Net gain (loss) from asset sales

(148.6)

103.5

1.2

OPERATING INCOME (LOSS)

(1,067.3)

115.1

(35.9)

140.8

(66.7)

83.3

159.1

27.3

(847.3)

203.0

(321.2)

Realized and unrealized gains (losses) on derivative contracts

363.3

58.9

433.5

Interest and other income

12.8

15.2

15.0

Income from unconsolidated affiliates

0.3

0.2

0.1

Loss from early extinguishment of debt

2.0

0.6

Interest expense

(169.1)

(165.1)

(126.3)

Net income attributable to noncontrolling interest

21.6

12.0

3.7

NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX

1,135.7

17.4

13.8

27.0

32.4

25.2

29.2

20.5

1,193.9

107.3

125.9

Income from discontinued operations before income taxes attributable to QEP from QEP Midstream

28.9

33.5

38.9

Ownership Percentage

57.80%

Midstream Business Held For Sale [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Payments to Acquire Oil and Gas Property and Equipment

55.2

88.9

156.2

NGL sales

109.3

101.9

137.9

Other revenues

140.9

166.6

154.1

Purchased gas, oil and NGL sales

(47.1)

^[1]

(17.8)

^[1]

(13.9)

^[1]

Total Revenues

203.1

250.7

278.1

Purchased gas, oil and NGL expense

(48.5)

^[1]

(17.6)

^[1]

(15.1)

^[1]

Lease operating expense

(5.5)

^[1]

(3.5)

^[1]

(3.5)

^[1]

Natural gas, oil and NGL transportation and other handling costs

(55.4)

^[1]

(80.6)

^[1]

(49.2)

^[1]

Gathering and other expense

85.9

82.2

79.8

General and administrative

42.1

30.7

17.9

Production and property taxes

7.3

5.2

5.1

Depreciation, depletion and amortization

45.9

52.2

55.1

Total Operating Expenses

71.8

68.6

90.1

Net gain (loss) from asset sales

1,793.4

(0.5)

OPERATING INCOME (LOSS)

1,924.7

181.6

188.0

Realized and unrealized gains (losses) on derivative contracts

8.4

Interest and other income

0.3

(10.0)

(8.2)

Income from unconsolidated affiliates

4.9

5.6

6.7

Loss from early extinguishment of debt

(2.4)

Interest expense

(3.8)

1.8

3.4

INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES

1,923.7

^[2]

179.0

^[2]

198.3

^[2]

Income taxes

(708.2)

(59.7)

(68.7)

NET INCOME FROM DISCONTINUED OPERATIONS

1,215.5

119.3

129.6

Net income attributable to noncontrolling interest

(21.6)

(12.0)

(3.7)

NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX

$ 1,193.9

$ 107.3

$ 125.9

[1]	Includes discontinued intercompany eliminations.
[2]	Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owned 57.8%) of $28.9 million, $33.5 million and $38.9 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Discontinued Operations Assets And Liabilities Of Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 1,160.1	$ 30.0	$ 0	$ 0
Accounts receivable, net	441.9	330.3
Deferred income taxes - current	0	27.9
Prepaid expenses and other	46.8	45.4
Current assets of discontinued operations	0	122.0
Materials and supplies	54.3	54.3
Property, Plant and Equipment, Gross	13,452.0	12,573.6
Other noncurrent assets	44.2	46.6
Production and property taxes	61.7	54.7
Current liabilities of discontinued operations	0	75.3
Deferred Tax Liabilities, Net, Noncurrent	1,362.7	1,364.9
Asset retirement obligations	193.8	163.3
Other long-term liabilities	92.1	94.5
Noncurrent liabilities of discontinued operations	0	238.3
Midstream Business Held For Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and Cash Equivalents, at Carrying Value		18.1
Accounts receivable, net		53.9
Income Taxes Receivable, Current		38.4
Deferred income taxes - current		2.7
Prepaid expenses and other		8.9
Current assets of discontinued operations		122.0
Midstream Field Services Property		1,500.8
Materials and supplies		4.8
Property, Plant and Equipment, Gross		1,505.6
Accumulated Depreciation Midstream Field Services		(381.6)
Net Property, Plant and Equipment		1,124.0
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures		39.0
Other noncurrent assets		4.7
Noncurrent assets of discontinued operations		1,167.7
Accounts payable and accrued expenses		74.1
Production and property taxes		1.2
Current liabilities of discontinued operations		75.3
Deferred Tax Liabilities, Net, Noncurrent		195.7
Asset retirement obligations		28.5	37.5
Other long-term liabilities		14.1
Noncurrent liabilities of discontinued operations		$ 238.3

Capitalized Exploratory Well Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capitalized Exploratory Well Costs [Abstract]
Beginning Balance	$ 2.6	$ 2.1	$ 5.0
Additions to capitalized exploratory well costs pending the determination of proved reserves	13.7	2.7	12.7
Reclassifications to proved properties after the determination of proved reserves	0	(2.2)	(15.6)
Capitalized exploratory well costs charged to expense	(3.7)	0	0
Ending Balance	$ 12.6	$ 2.6	$ 2.1

Asset Retirement Obligations (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Midstream Business Held For Sale [Member]

Dec. 31, 2012

Midstream Business Held For Sale [Member]

Dec. 31, 2014

Permian Basin Acquisition [Member]

Dec. 31, 2014

Permian Basin Acquisition [Member]

Asset Retirement Obligation Costs [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Document Period End Date

Dec. 31, 2014

Asset retirement obligation, current

$ 1.3

$ 1.8

Asset retirement obligations, noncurrent

193.8

163.3

28.5

37.5

Recognized identifiable assets acquired and liabilities assumed, net

941.8

(9.7)

ARO Liability [Roll Forward]

ARO liability, Beginning Balance

165.1

^[1]

155.6

^[1]

Accretion

6.7

5.6

Liabilities incurred

17.1

^[2]

6.9

^[2]

Revisions of Estimates

33.6

11.8

ARO Liabilities Transferred

(24.7)

(11.8)

Liabilities settled

(2.7)

(3.0)

ARO liability, Ending Balance

$ 195.1

$ 165.1

^[1]

[1]	Excludes $28.5 million and $37.5 million of ARO as of January 1, 2014 and 2013, respectively, classified as "Noncurrent liabilities of discontinued operations" on the Consolidated Balance Sheets.
[2]	Additions include $9.7 million related to the Permian Basin Acquisition (see Note 2 - Acquisitions and Divestitures).

Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Option, Quantitative Disclosures [Line Items]
Impairment of Oil and Gas Properties	$ 1,143.2	$ 33.5
Proved properties [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Impairment of Oil and Gas Properties	$ 1,041.4	$ 1.2	$ 107.6

Fair Value of Financial Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2014 Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2014 Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2014 Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2014 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Dec. 31, 2013 Long term [Member] Interest Rate Swap [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Long term [Member] Interest Rate Swap [Member] Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2014 Long term [Member] Interest Rate Swap [Member] Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2013 Long term [Member] Interest Rate Swap [Member] Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2013 Long term [Member] Interest Rate Swap [Member] Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2013 Long term [Member] Interest Rate Swap [Member] Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Dec. 31, 2014 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2014 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2013 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2014 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2013 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2014 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2013 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2014 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Dec. 31, 2013 Long term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Dec. 31, 2013 Short term [Member] Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2013 Short term [Member] Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2013 Short term [Member] Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Dec. 31, 2013 Short term [Member] Interest Rate Swap [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2014 Short term [Member] Interest Rate Swap [Member] Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2013 Short term [Member] Interest Rate Swap [Member] Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2014 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2014 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2013 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 1 [Member]	Dec. 31, 2014 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2013 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 2 [Member]	Dec. 31, 2014 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2013 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Level 3 [Member]	Dec. 31, 2014 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]	Dec. 31, 2013 Short term [Member] Commodity Contract [Member] Fair Value, Measurements, Recurring [Member] Netting Adjustments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Document Period End Date	Dec. 31, 2014
Financial Assets
Derivative instruments				$ 0	$ 0	$ 349.2	$ 6.5	$ 0	$ 0	$ (0.3)	$ (5.3)		$ 0	$ 0	$ 0.6	$ 0	$ 0			$ 0	$ 0	$ 9.9	$ 0.4	$ 0	$ 0	$ 0	$ 0					$ 0	$ 0			$ 0	$ 0	$ 339.3	$ 5.5	$ 0	$ 0	$ (0.3)	$ (5.3)
Derivative Assets		348.9	1.2									0.6						9.9	0.4															339.0	0.2
Financial liabilities
Derivative instruments				0	0	0.3	32.0	0	0	(0.3)	(5.3)			0	0							0	0					0	0	0		0	2.6			0	0	0.3	29.4	0	0	(0.3)	(5.3)
Derivative Liabilities		$ 0	$ 26.7																												$ 2.6			$ 0	$ 24.1

Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 1,160.1	$ 11.9
Cash and cash equivalents	1,160.1	30.0	0	0
Checks outstanding in excess of cash balances	54.7	109.1
Long-term Debt, Excluding Current Maturities	2,218.1	2,997.5
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	1,160.1	11.9
Checks outstanding in excess of cash balances	54.7	109.1
Long-term debt	2,171.6	3,034.9
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	1,160.1	11.9
Checks outstanding in excess of cash balances	54.7	109.1
Long-term Debt, Excluding Current Maturities	$ 2,218.1	$ 2,997.5

- Definition

Amount of currency on hand as well as demand deposits with banks or financial institutions. Includes other kinds of accounts that have the general characteristics of demand deposits. Also includes short-term, highly liquid investments that are both readily convertible to known amounts of cash and so near their maturity that they present insignificant risk of changes in value because of changes in interest rates. Excludes cash and cash equivalents within disposal group and discontinued operation.

+ References+ Details

Derivative Contracts (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014 Term Loan due 2017 [Member]	Dec. 31, 2013 Term Loan due 2017 [Member]	Dec. 31, 2014 First Term Loan Tranche [Member] Interest Rate Swap [Member]	Dec. 31, 2014 Second Term Loan Tranche [Member] Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Forecasted production from proved reserves (in hundredths)	100.00%
Total principal amount of debt			$ 600.0
Notional amount of interest rate derivatives				$ 300.0	$ 300.0
Fixed Rate Paid (in hundredths)				1.07%	0.86%
Effective interest Rate Before Impact of Derivatives		3.24%

Derivative Contracts Schedule of Commodity Derivative Contracts (Details) (USD $)	12 Months Ended
	Dec. 31, 2014 MMBTU
Natural Gas Sales [Member] \| QEP Energy [Member] \| Year 2014 [Member] \| NYMEX [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	40,200,000
Underlying, Derivative Asset	3.70
Natural Gas Sales [Member] \| QEP Energy [Member] \| Year 2014 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	NYMEX HH
Derivative, Nonmonetary Notional Amount	29,200,000
Underlying, Derivative Asset	4.11
Natural Gas Sales [Member] \| QEP Marketing [Member] \| Year 2015 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	2,800,000
Underlying, Derivative Asset	4.03
Natural Gas Sales [Member] \| QEP Marketing [Member] \| Year2016 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2016
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	900,000
Underlying, Derivative Asset	3.58
Purchased Gas and Oil Expense [Member] \| QEP Marketing [Member] \| Year 2014 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	900,000
Underlying, Derivative Asset	3.06
Crude Oil Sales Costless Collars [Member] \| QEP Energy [Member] \| Year 2015 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	NYMEX WTI
Derivative, Nonmonetary Notional Amount	500,000
Derivative Average Price Floor	$ 50.00
Derivative Average Price Ceiling	$ 63.34
Oil Basis Swaps [Member] \| QEP Energy [Member] \| Year 2015 [Member] \| NYMEX WTI less LLS Differential [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	LLS
Derivative, Nonmonetary Notional Amount	100,000
Underlying, Derivative Asset	4.03
Oil Sales [Member] \| QEP Energy [Member] \| Year 2014 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	NYMEX WTI
Derivative, Nonmonetary Notional Amount	7,700,000
Underlying, Derivative Asset	90.04
Oil Sales [Member] \| QEP Energy [Member] \| Year 2015 [Member] \| BRENT ICE [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	ICE Brent
Derivative, Nonmonetary Notional Amount	400,000
Underlying, Derivative Asset	104.95
Oil Sales [Member] \| QEP Energy [Member] \| Year2016 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Contract Year	2016
Derivative, Underlying Basis	NYMEX WTI
Derivative, Nonmonetary Notional Amount	400,000
Underlying, Derivative Asset	90.00

Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) (Fair Value, Inputs, Level 2 [Member], Fair Value, Measurements, Recurring [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Derivative instruments - assets	$ 349.2	$ 6.5
Derivative instruments - liabilities	0.3	32.0
Interest Rate Swap [Member] \| Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	0	0
Derivative instruments - liabilities	0	2.6
Interest Rate Swap [Member] \| Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	0	0.6
Derivative instruments - liabilities	0	0
Commodity Contract [Member] \| Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	339.3	5.5
Derivative instruments - liabilities	0.3	29.4
Commodity Contract [Member] \| Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	9.9	0.4
Derivative instruments - liabilities	$ 0	$ 0

Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) derivative contracts not designated as hedging instruments	$ (11.1)	$ 147.6	$ 370.3
Unrealized gain (loss) derivative contracts not designated as hedging instruments	374.4	(88.7)	63.2
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	363.3	58.9	433.5
Realized and unrealized gains on commodity derivative instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	(3.5)	150.3	371.6
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	372.4	(92.8)	69.3
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	368.9	57.5	440.9
Natural gas derivative contracts [Member] \| Realized and unrealized gains on commodity derivative instruments [Member] \| QEP Energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	(16.7)	152.0	341.9
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	68.4	(42.6)	37.8
Natural gas derivative contracts [Member] \| Realized and unrealized gains on commodity derivative instruments [Member] \| QEP Marketing [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	(2.5)	0.5	5.1
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	4.2	(2.1)	0.9
NGL derivative contracts [Member] \| Realized and unrealized gains on commodity derivative instruments [Member] \| QEP Energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	0	0	10.2
Unrealized gain (loss) derivative contracts not designated as hedging instruments	0	0	1.6
Oil derivative contracts [Member] \| Realized and unrealized gains on commodity derivative instruments [Member] \| QEP Energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	15.7	(2.2)	14.4
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	299.8	(48.1)	29.0
Interest Rate Swap [Member] \| Realized And Unrealized Gains Losses On Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	(7.6)	(2.7)	(1.3)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	2.0	4.1	(6.1)
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	$ (5.6)	$ 1.4	$ (7.4)

Restructuring Costs (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Restructuring and Related Activities [Abstract]
Retention Bonuses Related To Discontinued Operations	$ 10.4
Estimated restructuring costs	$ 7.9

Restructuring Costs Schedule of Restructuring Costs by Line of Business (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	$ 7.9
Restructuring costs incurred to date	7.9
Restructuring Charges	0	0.9	7.0
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.6
Restructuring costs incurred to date	3.6
Restructuring Charges	0	0.5	3.1
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.7
Restructuring costs incurred to date	3.7
Restructuring Charges	0	0.4	3.3
Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.6
Restructuring costs incurred to date	0.6
Restructuring Charges	0	0	0.6
QEP Energy [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	7.6
Restructuring costs incurred to date	7.6
Restructuring Charges	0	0.8	6.8
QEP Energy [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.3
Restructuring costs incurred to date	3.3
Restructuring Charges	0	0.4	2.9
QEP Energy [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	3.7
Restructuring costs incurred to date	3.7
Restructuring Charges	0	0.4	3.3
QEP Energy [Member] \| Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.6
Restructuring costs incurred to date	0.6
Restructuring Charges	0	0	0.6
QEP Marketing [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.3
Restructuring costs incurred to date	0.3
Restructuring Charges	0	0.1	0.2
QEP Marketing [Member] \| One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs	0.3
Restructuring costs incurred to date	0.3
Restructuring Charges	$ 0	$ 0.1	$ 0.2

- Definition

Amount of expenses associated with exit or disposal activities pursuant to an authorized plan. Excludes expenses related to a discontinued operation or an asset retirement obligation.

+ References+ Details

Debt (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Total principal amount of debt	$ 2,221.8	$ 3,001.8
Debt Maturity Period	5 years
Senior Notes	2,221.8
Debt Instrument, Maturity Date Range, Start	Sep. 01, 2016
Debt Instrument, Maturity Date Range, End	May 01, 2023
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	5.25%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	6.875%
Line of Credit [Member]
Debt Instrument [Line Items]
Total principal amount of debt	0	480.0
Long-term Debt, Weighted Average Interest Rate	2.23%	2.22%
Long-term Line of Credit	1,800.0
Letters of Credit Outstanding, Amount	3.7	3.8
Long-term Line of Credit		480.0
Term Loan due 2017 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	0	300.0
Long-term Debt, Weighted Average Interest Rate	2.28%	2.22%
Long-term Line of Credit		600.0
Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	176.8	176.8
Debt Instrument, Maturity Date	Sep. 01, 2016
Debt Instrument, Interest Rate, Stated Percentage	6.05%
Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	$ 134.0	$ 134.0
Debt Instrument, Maturity Date	Apr. 01, 2018
Debt Instrument, Interest Rate, Stated Percentage	6.80%

Debt Schedule of Debt Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Total principal amount of debt	$ 2,221.8	$ 3,001.8
Less unamortized discount	(3.7)	(4.3)
Total long-term debt outstanding	2,218.1	2,997.5
Revolving Credit Facility due 2016 [Member]
Debt Disclosure [Abstract]
Long-term Debt, Weighted Average Interest Rate	2.23%	2.22%
Debt Instrument [Line Items]
Total principal amount of debt	0	480.0
Term Loan due 2017 [Member]
Debt Disclosure [Abstract]
Long-term Debt, Weighted Average Interest Rate	2.28%	2.22%
Debt Instrument [Line Items]
Total principal amount of debt	0	300.0
6.05% Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	176.8	176.8
6.80% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	134.0	134.0
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

- Definition

Carrying amount of long-term debt, net of unamortized discount or premium, including current and noncurrent amounts. Includes, but not limited to, notes payable, bonds payable, debentures, mortgage loans and commercial paper. Excludes capital lease obligations.

+ References+ Details

Commitments and Contingencies Litigation (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Loss Contingency, Settlement Agreement, Consideration	$ 16.7
Loss Contingency, Range of Possible Loss, Minimum	0
Loss Contingency, Range of Possible Loss, Maximum	$ 20.0

Commitments and Contingencies Other Commitments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 130.7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	120.6
Unrecorded Unconditional Purchase Obligation, Due within Three Years	120.0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	117.1
Unrecorded Unconditional Purchase Obligation, Due within Five Years	112.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 407.4

Commitments and Contingencies Long-term Operating lease commitments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating lease commitments [Abstract]
Operating Leases, Rent Expense	$ 8.2	$ 7.8	$ 7.3
Operating Leases, Future Minimum Payments Due, Next Twelve Months	8.4
Operating Leases, Future Minimum Payments, Due in Two Years	8.2
Operating Leases, Future Minimum Payments, Due in Three Years	8.4
Operating Leases, Future Minimum Payments, Due in Four Years	6.9
Operating Leases, Future Minimum Payments, Due in Five Years	6.8
Operating Leases, Future Minimum Payments, Due Thereafter	$ 23.9

Equity-Based Compensation (Narrative) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Curtailment loss		$ 0
Shares available for future grants	10.8
Equity-based compensation	27.2	27.1	25.6
Weighted average grant date fair value	$ 10.11	$ 15.16	$ 14.29
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of options exercised	0.6	4.3	9.6
Tax benefit from equity-based compensation expense		1.4	4.6
Adjustment to Additional Paid In Capital resulting from income tax effect of equity-based compensation	6.5
Unrecognized compensation costs	2.0
Weighted average period for recognition of equity-based compensation expense	1 year 10 months 13 days
Cash received in relation to stock options	1.5
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustment to Additional Paid In Capital resulting from income tax effect of equity-based compensation	0.3
Unrecognized compensation costs	18.3
Weighted average period for recognition of equity-based compensation expense	2 years 1 month 7 days
Award vesting period	3 years
Total fair value of stock that vested during the period	26.8	19.8	16.7
Income tax expense (benefit) related to restricted stock compensation	0.5	0.1	0.3
Weighted average grant date fair value	$ 31.40	$ 30.06	$ 30.54
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	2.3
Weighted average period for recognition of equity-based compensation expense	1 year 10 months 24 days
Weighted average grant date fair value	$ 31.57	$ 30.12	$ 30.75
Continuing Operations [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	21.4	25.7	25.6
Discontinued Operations [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 5.8	$ 1.4

Equity-Based Compensation Fair Value of Options Granted and Major Assumptions Used (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value	$ 10.11	$ 15.16	$ 14.29
Weighted average risk-free interest rate	1.31%	1.00%	0.80%
Weighted average expected price volatility	37.10%	58.30%	55.90%
Expected dividend yield	0.25%	0.27%	0.26%
Expected term in years at the date of grant	4 years 6 months	5 years 6 months	5 years
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate, minimum	1.31%	0.97%	0.63%
Risk free interest rate, maximum	1.34%	1.84%	1.04%
Expected price volatility range, minimum	36.10%	51.50%	55.90%
Expected price volatility range, maximum	37.30%	58.50%	56.50%
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value	$ 31.40	$ 30.06	$ 30.54
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value	$ 31.57	$ 30.12	$ 30.75

Equity-Based Compensation Schedule of Stock Option Transactions (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Stock options outstanding, beginning of year	1,794,187
Options granted	282,236
Options exercised	(65,366)
Options forfeited	(14,842)
Stock options outstanding, end of year	1,996,215
Share-based Compensation Arrangement by Share-based Payment Award, Additional General Disclosures [Abstract]
Weighted average exercise price, beginning of year	$ 27.90
Weighted average exercise price, granted in period	$ 31.67
Weighted average exercise price, exercised in period	$ 22.24
Weighted average exercise price, forfeited in period	$ 30.53
Weighted average exercise price, end of year	$ 28.60
Options exercisable, shares	1,494,061
Options exercisable, weighted average exercise price	$ 27.80
Unvested options, shares	502,154
Unvested options, weighted average exercise price	$ 30.98
Weighted average remaining contractual term, options outstanding	3 years 2 months 4 days
Weighted average remaining contractual term, options exercisable	2 years 4 months 22 days
Weighted average remaining contractual term, options unvested	5 years 6 months 2 days
Aggregate intrinsic value, options outstanding	$ 0.1
Aggregate intrinsic value, options exercisable	0.1
Aggregate intrinsic value, options unvested	$ 0

Equity-Based Compensation Schedule of Restricted Stock Transactions (Details) (Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2014
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	1,388,953
Shares granted	1,033,023
Shares vested	(855,720)
Shares forfeited	(139,803)
Unvested balance at end of period	1,426,453
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period	$ 30.96
Weighted average grant date fair value, grants	$ 31.40
Weighted average grant date fair value, vested	$ 31.39
Weighted average grant date fair value, forfeited	$ 31.00
Weighted average grant date fair value, end of period	$ 31.02

Equity-Based Compensation Schedule of Performance Share Unit Transactions (Details) (Performance Share Units [Member], USD $)	12 Months Ended
	Dec. 31, 2014
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	480,660
Shares granted	256,101
Shares vested and paid out	(73,956)
Shares vested and canceled	(83,545)
Shares forfeited	(27,051)
Unvested balance at end of period	552,209
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period	$ 32.33
Weighted average grant date fair value, grants	$ 31.57
Weighted average grant date fair value, vested and paid out	$ 37.17
Weighted average grant date fair value, vested and canceled	$ 35.84
Weighted average grant date fair value, forfeited	$ 30.60
Weighted average grant date fair value, end of period	$ 30.85

Employee Benefits (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Curtailment loss		$ 0
Special termination benefits		0
Defined Benefit Plan, Accumulated Benefit Obligation	121.8	101.0
Defined Contribution Plan, Cost Recognized	7.6	6.9	6.4
Active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Employees Covered	62
Non-active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Employees Covered	152
Employee Investment Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	8.00%
Defined Contribution Plan Employer Discretionary Contribution Percent			2.00%
Closed Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match			100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent			6.00%
Funded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension Contributions	8.1
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	4.0
Funded Pension Plan [Member] \| Active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan Percentage Of Employees Covered	8.00%
Unfunded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension Contributions	4.9
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	4.4
Other Postretirement Benefit Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Postretirement Health Care Benefits, Number of Eligible	39
Postretirement Health Care Benefits, Number of Employees Covered	36
Curtailment loss	1.4	0	0
Defined Benefit Plan, Curtailments	0.2	0	0
Special termination benefits	0	0	0
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	0.3
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year	0.2
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	(1.7)	(0.4)	(0.4)
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Curtailment loss	9.3		2.2
Defined Benefit Plan, Curtailments	8.2	0	2.2
Special termination benefits	1.9	0	0
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year	4.1
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	$ (14.0)	$ (5.0)	$ (5.3)

Employee Benefits Schedule of Changes in Benefit Obligations and Fair Value of Plan Assets (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Special termination benefits

$ 0

Benefit payments

(2.9)

(2.1)

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Fair value of plan assets, beginning of period

71.7

55.2

Company contributions to the plan

8.1

Benefit payments

(2.9)

(2.1)

Fair value of plan assets, end of period

81.4

71.7

55.2

Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]

Net actuarial loss recognized in AOCI

(13.6)

^[1]

13.5

^[1]

(10.0)

^[1]

Pension Plan [Member]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Benefit obligation, beginning of period

118.0

129.7

Service cost

2.6

3.3

4.0

Interest cost

5.3

4.8

5.1

Special termination benefits

1.9

Loss on curtailment in current period

(8.2)

(2.2)

Settlements

(2.3)

Benefit payments

(5.5)

Actuarial loss (gain)

20.8

(14.3)

Benefit obligation, end of period

132.6

118.0

129.7

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Fair value of plan assets, beginning of period

71.7

55.3

Actual gain on plan assets

4.5

10.4

Company contributions to the plan

13.0

11.5

Benefit payments

(5.5)

Settlements

(2.3)

Fair value of plan assets, end of period

81.4

71.7

55.3

Underfunded status (current and long-term)

(51.2)

(46.3)

Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]

Amounts included in accounts payable and accrued expenses

(4.3)

(5.5)

Amounts included in other long-term liabilities

(46.9)

(40.8)

Total amount recognized in balance sheets

(51.2)

(46.3)

Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]

Net actuarial loss recognized in AOCI

21.2

9.5

Prior service cost recognized in AOCI

16.1

30.1

Total amount recognized in AOCI

37.3

39.6

Other Postretirement Benefit Plan [Member]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Benefit obligation, beginning of period

5.9

6.7

Service cost

0.1

Interest cost

0.3

Special termination benefits

Loss on curtailment in current period

(0.2)

Settlements

Benefit payments

(0.1)

Actuarial loss (gain)

0.6

(1.1)

Benefit obligation, end of period

6.6

5.9

6.7

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Fair value of plan assets, beginning of period

Actual gain on plan assets

Company contributions to the plan

0.1

Benefit payments

(0.1)

Settlements

Fair value of plan assets, end of period

Underfunded status (current and long-term)

(6.6)

(5.9)

Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]

Amounts included in accounts payable and accrued expenses

(0.3)

(0.2)

Amounts included in other long-term liabilities

(6.3)

(5.7)

Total amount recognized in balance sheets

(6.6)

(5.9)

Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]

Net actuarial loss recognized in AOCI

0.6

0.2

Prior service cost recognized in AOCI

1.4

3.0

Total amount recognized in AOCI

$ 2.0

$ 3.2

[1]	Presented net of income tax benefit of $8.5 million for the year ended December 31, 2014, 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 during the year ended December 31, 2012

Employee Benefits Schedule of Net Periodic Benefit Cost and Other Comprehensive Income for Pension and Other Postretirement Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Curtailment loss		$ 0
Special termination benefits		0
Settlements		0
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Settlements		0
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	2.6	3.3	4.0
Interest cost	5.3	4.8	5.1
Expected return on plan assets	(5.1)	(3.9)	(3.6)
Curtailment loss	9.3		2.2
Special termination benefits	1.9	0	0
Settlements	(0.7)	0	0
Amortization of prior service costs	4.7	5.0	5.3
Amortization of actuarial loss	0.8	2.3	1.9
Periodic expense	20.2	11.5	14.9
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Current period actuarial loss (gain)	21.5	(20.8)	15.9
Amortization of actuarial loss	(0.8)	(2.3)	(1.9)
Amortization of prior service cost	(14.0)	(5.0)	(5.3)
Loss on curtailment in current period	(8.2)	0	(2.2)
Settlements	0.7	0	0
Total amount recognized in accumulated other comprehensive income	(2.2)	(28.1)	6.5
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0.1	0.1
Interest cost	0.3	0.3	0.3
Expected return on plan assets	0	0	0
Curtailment loss	1.4	0	0
Special termination benefits	0	0	0
Settlements	0	0	0
Amortization of prior service costs	0.3	0.3	0.3
Amortization of actuarial loss	0	0.1	0.1
Periodic expense	2.0	0.8	0.8
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Current period actuarial loss (gain)	0.6	(1.0)	0.4
Amortization of actuarial loss	0	(0.1)	(0.1)
Amortization of prior service cost	(1.7)	(0.4)	(0.4)
Loss on curtailment in current period	(0.2)	0	0
Settlements	0	0	0
Total amount recognized in accumulated other comprehensive income	$ (1.3)	$ (1.5)	$ (0.1)

Employee Benefits Schedule of Weighted Average Actuarial Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Costs (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate used in calculating benefit obligation	3.94%	4.75%
Rate of increase in compensation used for calculating benefit obligation	4.00%	4.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate used in calculating net periodic benefit cost	4.40%	3.69%	4.38%
Expected long-term return on plan assets used in calculating net periodic benefit cost	7.00%	6.75%	7.25%
Rate of increase in compensation used in calculating net periodic benefit cost	4.00%	3.60%	3.60%
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate used in calculating benefit obligation	4.00%	5.00%
Rate of increase in compensation used for calculating benefit obligation	4.00%	4.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate used in calculating net periodic benefit cost	5.00%	4.10%	4.70%
Rate of increase in compensation used in calculating net periodic benefit cost	4.00%	3.60%	4.00%

Employee Benefits Schedule of Fair Values of Pension and Postretirement Benefit Assets by Asset Class (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 81.4	$ 71.7	$ 55.2
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Cash and Cash Equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0.3	0.3
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%
Domestic Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	36.7	29.3
Defined Benefit Plan, Actual Plan Asset Allocations	45.00%	41.00%
Foreign Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	20.2	21.3
Defined Benefit Plan, Actual Plan Asset Allocations	25.00%	30.00%
Debt Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	24.2	20.8
Defined Benefit Plan, Actual Plan Asset Allocations	30.00%	29.00%
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] \| Cash and Cash Equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] \| Domestic Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] \| Foreign Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] \| Debt Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] \| Cash and Cash Equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] \| Domestic Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] \| Foreign Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] \| Debt Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	81.4	71.7
Fair Value, Inputs, Level 3 [Member] \| Cash and Cash Equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0.3	0.3
Fair Value, Inputs, Level 3 [Member] \| Domestic Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	36.7	29.3
Fair Value, Inputs, Level 3 [Member] \| Foreign Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	20.2	21.3
Fair Value, Inputs, Level 3 [Member] \| Debt Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 24.2	$ 20.8

Employee Benefits Schedule of Changes in Level 3 Assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of period	$ 71.7	$ 55.2
Employer contributions	8.1	8.1
Unrealized gains (losses)	(1.0)	9.8
Realized gains (losses)	5.9	1.0
Administration fees	(0.4)	(0.3)
Benefits paid	(2.9)	(2.1)
Fair value of plan assets, end of period	81.4	71.7
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, end of period	$ 81.4	$ 71.7

- Definition

The amount of payments made for which participants are entitled under a pension plan, including pension benefits, death benefits, and benefits due on termination of employment. Also includes payments made under a postretirement benefit plan, including prescription drug benefits, health care benefits, life insurance benefits, and legal, educational and advisory services. This item represents a periodic decrease to the plan obligations and a decrease to plan assets.

+ References+ Details

Employee Benefits Schedule of Expected Benefit Payments for Pension and Other Postretirement Benefits (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Pension Plan [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2015	$ 8.3
2016	7.0
2017	6.3
2018	6.3
2019	7.2
2020 through 2021	41.8
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2015	0.3
2016	0.4
2017	0.4
2018	0.4
2019	0.4
2020 through 2021	$ 1.8

Income Taxes Schedule of Income Tax Expense (Benefit) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Federal Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	$ (324.0)	$ (92.2)	$ (10.3)
Deferred Federal Income Tax Expense (Benefit)	110.3	152.3	15.6
State and Local Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current State and Local Tax Expense (Benefit)	(15.5)	(1.4)	(1.8)
Deferred State and Local Income Tax Expense (Benefit)	(3.3)	1.4	(5.4)
10% annual discount for estimated timing of net cash flows	5,159.9	4,680.2	3,942.0
Future production costs	9,842.1	8,400.3	5,027.2
Future net cash flows	10,499.9	9,064.1	6,976.7
Future income tax expenses	4,304.0	3,284.6	2,269.0
Income tax (provision) benefit	$ (232.5)	$ 60.1	$ (1.9)

Income Taxes Reconciliation of Statutory Federal Income Tax Rate and Effective Tax Rate (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal income taxes statutory rate	35.00%	35.00%	35.00%
State income taxes, net of federal income tax benefit	(1.50%)	(5.00%)	(2220.00%)
State rate change	3.40%	0.00%	0.00%
Penalties	0.00%	0.40%	80.00%
Return to provision adjustment	(0.40%)	5.00%	1400.00%
Book impairment of goodwill	0.00%	18.60%	0.00%
Other	(0.30%)	(0.40%)	325.00%
Effective income tax rate	36.20%	53.60%	(380.00%)

Income Taxes Schedule of Deferred Income Tax Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Components of Deferred Tax Assets and Liabilities [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	$ 1,402.9	$ 1,455.6
Deferred Tax Liabilities, Derivatives	127.7	0
Deferred Tax Liabilities, Net	1,530.6	1,455.6
Deferred Tax Assets, Derivative Instruments	0	9.8
Deferred Tax Assets Net Operating Loss And Tax Credit Carryforwards	11.7	54.4
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits	43.0	36.1
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	0	0.8
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Bonuses	16.3	9.0
Deferred Tax Assets, Other	12.4	8.5
Deferred Tax Assets, Gross	83.4	118.6
Deferred Tax Assets, Net of Valuation Allowance, Classification [Abstract]
Deferred Tax Assets, Net of Valuation Allowance, Current	0	27.9
Deferred income taxes	84.5	0
Deferred Tax Liabilities, Net, Noncurrent	1,362.7	1,364.9
Deferred Tax Liabilities, Net	$ 1,447.2	$ 1,337.0

Income Taxes Amounts and Expiration Dates of Net Operating Loss and Tax Credit Carryforwards (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
State net operating loss and tax credit carryforwards	$ 30.1
U.S. alternative minimum tax credit	0
Total tax credit carryforwards	11.7
State net operating loss valuation allowance	$ (18.4)
Operating Loss Carryforwards Minimum Expiration Date	2015
Operating Loss Carryforwards Maximum Expiration Date	2033

Operations by Line of Business (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues
Total Revenues	$ 799.6	$ 910.0	$ 887.2	$ 817.5	$ 620.3	$ 719.5	$ 694.0	$ 651.3	$ 3,414.3	$ 2,685.1	$ 2,071.7
Operating expenses
Purchased gas, oil and NGL expense									1,031.2	783.5	670.7
Lease operating expense									240.1	181.3	175.8
Natural gas, oil and NGL transportation and other handling costs									277.6	222.0	198.1
Gathering and other expense									6.7	8.4	8.2
General and administrative									204.4	160.4	248.4
Production and property taxes									205.2	161.3	98.5
Depreciation, depletion and amortization									994.7	963.8	850.2
Other Expenses									1,153.1	104.9	144.2
Operating Expenses									4,113.0	2,585.6	2,394.1
Net gain (loss) from asset sales									(148.6)	103.5	1.2
OPERATING INCOME (LOSS)	(1,067.3)	115.1	(35.9)	140.8	(66.7)	83.3	159.1	27.3	(847.3)	203.0	(321.2)
Realized and unrealized gains (losses) on derivative contracts									363.3	58.9	433.5
Interest and other income									12.8	15.2	15.0
Income from unconsolidated affiliates									0.3	0.2	0.1
Loss from early extinguishment of debt									(2.0)	0	(0.6)
Interest expense									(169.1)	(165.1)	(126.3)
Income (loss) from continuing operations before income taxes									(642.0)	112.2	0.5
Income tax (provision) benefit									232.5	(60.1)	1.9
NET INCOME FROM CONTINUING OPERATIONS	(469.8)	153.7	(106.1)	12.7	(84.4)	12.1	149.2	(24.8)	(409.5)	52.1	2.4
Net income from discontinued operations, net of income tax	1,135.7	17.4	13.8	27.0	32.4	25.2	29.2	20.5	1,193.9	107.3	125.9
NET INCOME ATTRIBUTABLE TO QEP	665.9	171.1	(92.3)	39.7	(52.0)	37.3	178.4	(4.3)	784.4	159.4	128.3
Assets	9,286.8				9,408.9				9,286.8	9,408.9	9,108.5
Cash capital expenditures									2,726.4	1,602.6	2,799.7
Accrued capital expenditures									2,734.8	1,577.4	2,888.2
Goodwill											59.5
Unaffiliated customers [Member]
Revenues
Total Revenues									3,414.3	2,685.1	2,071.7
Affiliated customers [Member]
Revenues
Total Revenues									0	0	0
QEP Energy [Member]
Revenues
Total Revenues									2,524.6	2,092.8	1,615.4
Operating expenses
Purchased gas, oil and NGL expense									150.0	197.1	224.7
Lease operating expense									240.1	181.3	175.8
Natural gas, oil and NGL transportation and other handling costs									291.5	242.2	228.1
Gathering and other expense									0	0	0
General and administrative									201.3	160.6	252.8
Production and property taxes									204.0	159.8	97.2
Depreciation, depletion and amortization									984.4	954.2	838.4
Other Expenses									1,153.1	104.9	144.2
Operating Expenses									3,224.4	2,000.1	1,961.2
Net gain (loss) from asset sales									(148.6)	104.1	1.2
OPERATING INCOME (LOSS)									(848.4)	196.8	(344.6)
Realized and unrealized gains (losses) on derivative contracts									367.2	59.1	434.9
Interest and other income									11.8	3.6	6.2
Income from unconsolidated affiliates									0.3	0.2	0.1
Loss from early extinguishment of debt											0
Interest expense									(210.3)	(192.6)	(116.8)
Income (loss) from continuing operations before income taxes									(679.4)	67.1	(20.2)
Income tax (provision) benefit									(246.9)	41.5	(12.1)
NET INCOME FROM CONTINUING OPERATIONS									(432.5)	25.6	(8.1)
Net income from discontinued operations, net of income tax									0	0	0
NET INCOME ATTRIBUTABLE TO QEP									(432.5)		(8.1)
Assets	8,001.1				7,937.0				8,001.1	7,937.0	7,436.5
Cash capital expenditures									2,660.3	1,488.6	2,621.1
Accrued capital expenditures									2,670.5	1,467.2	2,702.4
Goodwill											59.5
QEP Energy [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									2,524.6	2,092.8	1,615.4
QEP Energy [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									0	0	0
QEP Marketing and Other [Member]
Revenues
Total Revenues									2,382.3	1,601.2	1,067.5
Operating expenses
Purchased gas, oil and NGL expense									2,356.6	1,570.5	1,021.1
Lease operating expense									0	0	0
Natural gas, oil and NGL transportation and other handling costs									0	0	0
Gathering and other expense									6.8	8.4	8.2
General and administrative									6.3	4.4	1.7
Production and property taxes									1.2	1.5	1.3
Depreciation, depletion and amortization									10.3	9.6	11.8
Other Expenses									0	0	0
Operating Expenses									2,381.2	1,594.4	1,044.1
Net gain (loss) from asset sales									0	(0.6)	0
OPERATING INCOME (LOSS)									1.1	6.2	23.4
Realized and unrealized gains (losses) on derivative contracts									(3.9)	(0.2)	(1.4)
Interest and other income									209.7	206.9	132.3
Income from unconsolidated affiliates									0	0	0
Loss from early extinguishment of debt									(2.0)		(0.6)
Interest expense									(167.5)	(167.8)	(133.0)
Income (loss) from continuing operations before income taxes									37.4	45.1	20.7
Income tax (provision) benefit									14.4	18.6	10.2
NET INCOME FROM CONTINUING OPERATIONS									23.0	26.5	10.5
Net income from discontinued operations, net of income tax									0	0	0
NET INCOME ATTRIBUTABLE TO QEP									23.0		10.5
Assets	1,285.7				182.2				1,285.7	182.2	244.6
Cash capital expenditures									10.9	25.1	22.4
Accrued capital expenditures									13.6	24.6	21.6
Goodwill											0
QEP Marketing and Other [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									889.7	592.3	456.3
QEP Marketing and Other [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									1,492.6	1,008.9	611.2
Elimination [Member]
Revenues
Total Revenues									(1,492.6)	(1,008.9)	(611.2)
Operating expenses
Purchased gas, oil and NGL expense									(1,475.4)	(984.1)	(575.1)
Lease operating expense									0	0	0
Natural gas, oil and NGL transportation and other handling costs									(13.9)	(20.2)	(30.0)
Gathering and other expense									(0.1)	0	0
General and administrative									(3.2)	(4.6)	(6.1)
Production and property taxes									0	0	0
Depreciation, depletion and amortization									0	0
Other Expenses									0	0	0
Operating Expenses									(1,492.6)	(1,008.9)	(611.2)
Net gain (loss) from asset sales									0	0	0
OPERATING INCOME (LOSS)									0	0	0
Realized and unrealized gains (losses) on derivative contracts									0	0	0
Interest and other income									(208.7)	(195.3)	(123.5)
Income from unconsolidated affiliates									0	0	0
Loss from early extinguishment of debt									0		0
Interest expense									208.7	195.3	123.5
Income (loss) from continuing operations before income taxes									0	0	0
Income tax (provision) benefit									0	0	0
NET INCOME FROM CONTINUING OPERATIONS									0	0	0
Net income from discontinued operations, net of income tax									0	0	0
NET INCOME ATTRIBUTABLE TO QEP									0		0
Assets	0				0				0	0	0
Cash capital expenditures									0	0	0
Accrued capital expenditures									0	0	0
Goodwill											0
Elimination [Member] \| Unaffiliated customers [Member]
Revenues
Total Revenues									0	0	0
Elimination [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									(1,492.6)	(1,008.9)	(611.2)
Discontinued Operations [Member]
Revenues
Total Revenues									0	0	0
Operating expenses
Purchased gas, oil and NGL expense									0	0	0
Lease operating expense									0	0	0
Natural gas, oil and NGL transportation and other handling costs									0	0	0
Gathering and other expense									0	0	0
General and administrative									0	0	0
Production and property taxes									0	0	0
Depreciation, depletion and amortization									0	0	0
Other Expenses									0	0	0
Operating Expenses									0	0	0
Net gain (loss) from asset sales									0	0	0
OPERATING INCOME (LOSS)									0	0	0
Realized and unrealized gains (losses) on derivative contracts									0	0	0
Interest and other income									0	0	0
Income from unconsolidated affiliates									0	0	0
Loss from early extinguishment of debt									0		0
Interest expense									0	0	0
Income (loss) from continuing operations before income taxes									0	0	0
Income tax (provision) benefit									0	0	0
NET INCOME FROM CONTINUING OPERATIONS									0	0	0
Net income from discontinued operations, net of income tax									1,193.9	107.3	125.9
NET INCOME ATTRIBUTABLE TO QEP									1,193.9	107.3	125.9
Assets	0				1,289.7				0	1,289.7	1,427.4
Cash capital expenditures									55.2	88.9	156.2
Accrued capital expenditures									50.7	85.6	164.2
Discontinued Operations [Member] \| Affiliated customers [Member]
Revenues
Total Revenues									$ 0

Quarterly Financial Information (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Effect of Fourth Quarter Events [Line Items]
Revenues	$ 799.6	$ 910.0	$ 887.2	$ 817.5	$ 620.3	$ 719.5	$ 694.0	$ 651.3	$ 3,414.3	$ 2,685.1	$ 2,071.7
OPERATING INCOME (LOSS)	(1,067.3)	115.1	(35.9)	140.8	(66.7)	83.3	159.1	27.3	(847.3)	203.0	(321.2)
Income (loss) from continuing operations	(469.8)	153.7	(106.1)	12.7	(84.4)	12.1	149.2	(24.8)	(409.5)	52.1	2.4
Net income from discontinued operations, net of income tax	1,135.7	17.4	13.8	27.0	32.4	25.2	29.2	20.5	1,193.9	107.3	125.9
Net income attributable to QEP	665.9	171.1	(92.3)	39.7	(52.0)	37.3	178.4	(4.3)	784.4	159.4	128.3
Non-recurring income(loss)	$ (1,077.8)	$ (11.9)	$ (202.5)	$ 0.4	$ (98.5)	$ 9.0	$ 100.2	$ (0.2)	$ (1,291.8)	$ 10.5
Basic total									$ 4.36	$ 0.89	$ 0.72
Diluted total									$ 4.36	$ 0.89	$ 0.72
Continuing Operations [Member]
Effect of Fourth Quarter Events [Line Items]
Basic total	$ (2.62)	$ 0.85	$ (0.59)	$ 0.07	$ (0.47)	$ 0.07	$ 0.83	$ (0.14)	$ (2.28)	$ 0.29	$ 0.01
Diluted total	$ (2.62)	$ 0.84	$ (0.59)	$ 0.07	$ (0.47)	$ 0.07	$ 0.83	$ (0.14)	$ (2.28)	$ 0.29	$ 0.01
Discontinued Operations [Member]
Effect of Fourth Quarter Events [Line Items]
Basic total	$ 6.34	$ 0.10	$ 0.08	$ 0.15	$ 0.18	$ 0.14	$ 0.16	$ 0.12	$ 6.64	$ 0.60	$ 0.71
Diluted total	$ 6.34	$ 0.10	$ 0.08	$ 0.15	$ 0.18	$ 0.14	$ 0.16	$ 0.12	$ 6.64	$ 0.60	$ 0.71

- Definition

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

+ References+ Details

- Definition

+ References+ Details

- Definition

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

+ References+ Details

- Definition

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

+ References+ Details

Supplemental Gas and Oil Information (Unaudited) Capitalized costs (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
Proved properties	$ 12,278.7	$ 11,571.4
Unproved properties, net	825.2	665.1
Total proved and unproved properties	13,103.9	12,236.5
Accumulated depreciation, depletion and amortization	(6,153.0)	(4,930.9)
Net capitalized costs	$ 6,950.9	$ 7,305.6

Supplemental Gas and Oil Information (Unaudited) Costs incurred (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract]
Accrued capital costs included in development costs	$ 10.2
Costs Incurred, Asset Retirement Obligation Incurred	51.1
Costs Incurred To Advance The Development Of Proved Undeveloped Reserves	796.7	645.9	513.0
Unproved	496.3	9.3	692.6
Proved	465.4	31.6	714.4
Total property acquisitions	961.7	40.9	1,407.0
Exploration	23.6	14.6	14.3
Development	1,695.1	1,440.8	1,310.0
Total costs incurred	$ 2,680.4	$ 1,496.3	$ 2,731.3

Supplemental Gas and Oil Information (Unaudited) Results of Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Results of Operations, Income before Income Taxes [Abstract]
Revenues (1)	$ 2,374.6	$ 1,901.2	$ 1,393.4
Production costs	735.6	583.3	501.1
Exploration expenses	9.9	11.9	11.2
Depreciation, depletion and amortization	984.4	954.2	838.4
Abandonment and impairment	1,143.2	93.0	133.0
Total expenses	2,873.1	1,642.4	1,483.7
Income before income taxes	(498.5)	258.8	(90.3)
Income taxes	182.5	(96.3)	33.6
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$ (316.0)	$ 162.5	$ (56.7)

Supplemental Gas and Oil Information (Unaudited) Estimated Quantities of Proved Gas and Oil Reserves (Details)

12 Months Ended

Dec. 31, 2014

MMcf

Dec. 31, 2013

MMcf

Dec. 31, 2012

MMcf

Dec. 31, 2011

MMcf

Reserve Quantities [Line Items]

Proved reserves balance

Natural Gas [Member]

Reserve Quantities [Line Items]

Reserves, Unit of Measure

(Bcf)

Proved reserves balance

2,554,900,000

2,622,400,000

2,749,400,000

Extensions and discoveries

27,100,000

^[1]

(288,300,000)

^[2]

(240,600,000)

^[3]

Extensions and discoveries

141,400,000

^[4]

455,600,000

^[5]

330,600,000

^[6]

Purchase of reserves in place

72,500,000

^[7]

1,000,000

32,300,000

^[8]

Sale of reserves in place

(299,400,000)

^[9]

16,900,000

Production

(179,300,000)

218,900,000

(249,300,000)

Proved reserves balance

2,317,200,000

2,554,900,000

2,622,400,000

Proved developed reserves

1,288,400,000

1,406,300,000

1,531,700,000

1,538,300,000

Proved undeveloped reserves

1,028,800,000

1,148,600,000

1,090,700,000

1,211,100,000

Oil [Member]

Reserve Quantities [Line Items]

Reserves, Unit of Measure

(MMbbl)

Proved reserves balance

148,600,000

119,000,000

67,500,000

Extensions and discoveries

(4,000,000)

^[1]

1,300,000

^[2]

(1,500,000)

^[3]

Extensions and discoveries

16,800,000

^[4]

38,300,000

^[5]

17,300,000

^[6]

Purchase of reserves in place

35,700,000

^[7]

1,900,000

42,000,000

^[8]

Sale of reserves in place

(7,500,000)

^[9]

1,700,000

Production

(17,100,000)

(10,200,000)

(6,300,000)

Proved reserves balance

172,500,000

148,600,000

119,000,000

Proved developed reserves

99,300,000

71,800,000

47,400,000

33,000,000

Proved undeveloped reserves

73,200,000

76,800,000

100,000

34,600,000

Natural Gas Liquids [Member]

Reserve Quantities [Line Items]

Reserves, Unit of Measure

(MMbbl)

Proved reserves balance

102,600,000

99,900,000

76,600,000

Extensions and discoveries

1,400,000

^[1]

(8,000,000)

^[2]

700,000

^[3]

Extensions and discoveries

8,600,000

^[4]

16,400,000

^[5]

23,000,000

^[6]

Purchase of reserves in place

12,300,000

^[7]

200,000

4,900,000

^[8]

Sale of reserves in place

(21,500,000)

^[9]

1,100,000

Production

(6,800,000)

(4,800,000)

(5,300,000)

Proved reserves balance

96,600,000

102,600,000

99,900,000

Proved developed reserves

52,200,000

52,800,000

49,300,000

38,400,000

Proved undeveloped reserves

44,400,000

49,800,000

100,000

38,200,000

Total Reserves Natural Gas Equivalent [Member]

Reserve Quantities [Line Items]

Reserves, Unit of Measure

(Bcfe)

Proved reserves balance

4,061,900,000

3,936,100,000

3,613,800,000

Extensions and discoveries

11,300,000

^[1]

(328,500,000)

^[2]

(244,800,000)

^[3]

Extensions and discoveries

294,100,000

^[4]

783,800,000

^[5]

572,500,000

^[6]

Purchase of reserves in place

360,700,000

^[7]

13,400,000

313,800,000

^[8]

Sale of reserves in place

(473,400,000)

^[9]

33,900,000

Production

(322,700,000)

(309,000,000)

(319,200,000)

Proved reserves balance

3,931,900,000

4,061,900,000

3,936,100,000

Proved developed reserves

2,197,500,000

2,154,000,000

2,111,900,000

1,966,300,000

Proved undeveloped reserves

1,734,400,000

1,907,900,000

1,824,200,000

1,647,500,000

[1]	Revisions of previous estimates in 2014 include 248.5 Bcfe negative performance revisions partially offset by positive other revisions of 197.7 Bcfe, operating cost revisions of 39.2 Bcfe and pricing revisions of 22.9 Bcfe. Negative performance revisions were driven by a 194.0 Bcfe decrease in Pinedale reserves related to downward forecast revisions on proved developed (PDP) wells, additional production history on PUD to PDP performance and a downward adjustment in the number of PUD locations. Other negative revisions related to adjustments to shrink and lease operating expense deducts. Pricing revisions were primarily due to increased gas prices, which increased reserves by 21.9 Bcfe.
[2]	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.
[3]	Revisions of previous estimates in 2012 include negative impacts due to 152.4 Bcfe pricing revisions, 35.6 Bcfe performance revisions, 27.6 Bcfe operating cost revisions and 29.1 Bcfe other revisions. The 152.4 Bcfe pricing revisions were due to lower 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 2014 increased proved reserves by 294.1 Bcfe, primarily related to extensions and discoveries in Pinedale of 133.6 Bcfe and the Williston Basin of 123.3 Bcfe. 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 and new compression well projections in Pinedale.
[5]	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.
[6]	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 Northern 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.
[7]	Purchase of reserves in place in 2014 relate to the Company's Permian Basin Acquisition as discussed in Note 2 - Acquisitions and Divestitures.
[8]	Purchase of reserves in place in 2012 primarily relate to the Company's $1.4 billion Williston Basin Acquisition as discussed in Note 2 - Acquisitions and Divestitures.
[9]	Sale of reserves in place primarily related to property sales in the Midcontinent in the second and fourth quarters of 2014 as discussed in Note 2 - Acquisitions and Divestitures.

Supplemental Gas and Oil Information (Unaudited) Future Development Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Future Development Costs [Abstract]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Next Twelve Months	$ 925.7
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Two	983.7
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Three	$ 714.3

Supplemental Gas and Oil Information (Unaudited) Standardized Measure Of Future Net Cash Flows (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract]
Future cash inflows	$ 28,167.3	$ 24,805.7	$ 18,200.2
Future production costs	(9,842.1)	(8,400.3)	(5,027.2)
Future development costs	(3,521.3)	(4,056.7)	(3,927.3)
Future income tax expenses	(4,304.0)	(3,284.6)	(2,269.0)
Future net cash flows	10,499.9	9,064.1	6,976.7
10% annual discount for estimated timing of net cash flows	(5,159.9)	(4,680.2)	(3,942.0)
Standardized measure of discounted future net cash flows	$ 5,340.0	$ 4,383.9	$ 3,034.7	$ 3,525.6

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Change in Standardized Measure of Future Cash Flows [Abstract]
Beginning Balance	$ 4,383.9	$ 3,034.7	$ 3,525.6
Sales of gas, oil and NGL produced during the period, net of production costs	(1,639.0)	(1,317.9)	(892.3)
Net change in sales prices and in production (lifting) costs related to future production	726.6	1,236.3	(2,083.5)
Net change due to extensions, discoveries and improved recovery	979.9	2,230.7	948.5
Net change due to revisions of quantity estimates	35.9	(709.6)	(387.8)
Changes due to purchases of reserves in place	695.3	36.8	831.4
Changes due to sales of reserves in place	(1,153.7)	(73.2)	0
Previously estimated development costs incurred during the period	867.5	722.7	513.0
Changes in estimated future development costs	409.6	(596.5)	(209.3)
Accretion of discount	597.3	402.2	499.4
Net change in income taxes	(600.3)	(601.7)	273.6
Other	37.0	19.4	16.1
Net change	956.1	1,349.2	(490.9)
Ending Balance	$ 5,340.0	$ 4,383.9	$ 3,034.7

Schedule of Valuation and Qualifying Accounts (Details) (Allowance for Doubtful Accounts [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	$ 2.2	$ 2.4	$ 1.3
Bad Debt Expense	2.1	0.1	1.3
Valuation Allowances and Reserves, Balance		2.2	2.4
Valuation Allowances and Reserves, Deductions	(0.3)	(0.3)	(0.2)
Allowance for Doubtful Accounts Receivable	$ 4.6	$ 2.2	$ 2.4

Summary of Significant Accounting Policies Property, plant and equipment (Details)	12 Months Ended
	Dec. 31, 2014 Building [Member] Minimum [Member]	Dec. 31, 2013 Building [Member] Maximum [Member]	Dec. 31, 2014 Leasehold Improvements [Member] Minimum [Member]	Dec. 31, 2013 Leasehold Improvements [Member] Maximum [Member]	Dec. 31, 2014 Equipment [Member] Minimum [Member]	Dec. 31, 2013 Equipment [Member] Maximum [Member]	Dec. 31, 2014 Furniture and Fixtures [Member] Minimum [Member]	Dec. 31, 2013 Furniture and Fixtures [Member] Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years	30 years	3 years	10 years	3 years	7 years	3 years	7 years

Summary of Significant Accounting Policies Income Taxes (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Valuation Allowance	$ 18.4

Summary of Significant Accounting Policies Revenue Recognition (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Summary of Significant Accounting Policies [Abstract]
Gas Balancing Asset (Liability)	$ 7.9	$ 10.7

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