Net curtailment and settlements cost incurred

^[5]

(0.6)

0.0

^[6]

4.5

5.6

0.0

Total pension and other postretirement plans adjustments

11.9

2.2

18.3

Other comprehensive income (loss)

11.9

2.2

(59.3)

Comprehensive income (loss) attributable to QEP

$ (137.5)

$ 786.6

$ 100.1

[1]	Presented net of income tax benefit of $45.9 million for the year ended December 31, 2013.
[2]	Presented net of income tax benefit of $0.3 million for the year ended December 31, 2015, net of income tax benefit of $8.5 million for the year ended December 31, 2014, and net of income tax expense of $8.3 million for the year ended December 31, 2013
[3]	Presented net of income tax expense of $0.2 million, $0.3 million, and $0.9 million during the years ended December 31, 2015, 2014, and 2013, respectively.
[4]	Presented net of income tax expense of $4.9 million, $6.0 million, and $2.1 million during the years ended December 31, 2015, 2014, and 2013, respectively.
[5]	Presented net of income tax benefit of $0.3 million for the year ended December 31, 2015.
[6]	Presented net of income tax expense of $2.6 million and $3.5 million for the years ended December 31, 2015 and 2014, respectively.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Other comprehensive income (loss), tax

Tax benefit (expense) on gains (losses) on changes in unrealized fair value of derivatives designated as cash flow hedges

^[1]

$ 45.9

Pension and other postretirement plans adjustments:

Tax benefit (expense) on net unamortized gain (loss) incurred

^[2]

$ 0.3

$ 8.5

8.3

Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax

^[3]

(0.2)

(0.3)

(0.9)

Tax expense on prior service cost incurred

^[4]

(4.9)

(6.0)

$ (2.1)

Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax

^[5]

0.3

Tax expense on net curtailment and settlements cost incurred

^[6]

$ 2.6

$ 3.5

[1]	Presented net of income tax benefit of $45.9 million for the year ended December 31, 2013.
[2]	Presented net of income tax benefit of $0.3 million for the year ended December 31, 2015, net of income tax benefit of $8.5 million for the year ended December 31, 2014, and net of income tax expense of $8.3 million for the year ended December 31, 2013
[3]	Presented net of income tax expense of $0.2 million, $0.3 million, and $0.9 million during the years ended December 31, 2015, 2014, and 2013, respectively.
[4]	Presented net of income tax expense of $4.9 million, $6.0 million, and $2.1 million during the years ended December 31, 2015, 2014, and 2013, respectively.
[5]	Presented net of income tax benefit of $0.3 million for the year ended December 31, 2015.
[6]	Presented net of income tax expense of $2.6 million and $3.5 million for the years ended December 31, 2015 and 2014, respectively.

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 376.1	$ 1,160.1
Accounts receivable, net	278.2	441.9
Income Taxes Receivable, Current	87.3	0.0
Fair value of derivative contracts, current assets	146.8	339.0
Gas, oil and NGL inventories, at lower of average cost or market	13.3	13.7
Prepaid expenses and other	30.1	46.8
Total Current Assets	931.8	2,001.5
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	13,314.9	12,278.7
Unproved properties	691.0	825.2
Marketing and other	297.9	293.8
Materials and supplies	38.5	54.3
Total Property, Plant and Equipment	14,342.3	13,452.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,870.2	6,153.0
Marketing and other	87.5	67.8
Total Accumulated Depreciation, Depletion and Amortization	6,957.7	6,220.8
Net Property, Plant and Equipment	7,384.6	7,231.2
Fair value of derivative contracts, noncurrent assets	23.2	9.9
Other noncurrent assets	85.9	44.2
TOTAL ASSETS	8,425.5	9,286.8
Current Liabilities
Checks outstanding in excess of cash balances	29.8	54.7
Accounts payable and accrued expenses	351.7	575.4
Income taxes payable	0.0	532.1
Production and property taxes	46.1	61.7
Interest payable	36.4	36.4
Fair value of derivative contracts, current liability	0.8	0.0
Deferred income taxes	0.0	84.5
Long-term Debt, Current Maturities	176.8	0.0
Total Current Liabilities	641.6	1,344.8
Long-term debt	2,042.0	2,218.1
Long-term Debt, Gross	2,218.8	2,218.1
Deferred income taxes	1,479.8	1,362.7
Asset retirement obligations	204.9	193.8
Fair value of derivative contracts, noncurrent liability	4.0	0.0
Other long-term liabilities	$ 105.3	$ 92.1
Commitments and Contingencies (Note 10)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 177.3 million and 176.2 million shares issued, respectively	$ 1.8	$ 1.8
Treasury stock - 0.5 million and 0.8 million shares, respectively	(14.6)	(25.4)
Additional paid-in capital	554.8	535.3
Retained earnings	3,418.3	3,587.9
Accumulated other comprehensive (loss) income	(12.4)	(24.3)
Total Common Shareholders' Equity	3,947.9	4,075.3
Total Equity	3,947.9	4,075.3
TOTAL LIABILITIES AND EQUITY	$ 8,425.5	$ 9,286.8

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares shares in Millions	Dec. 31, 2015	Dec. 31, 2014
EQUITY
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500.0	500.0
Common stock, shares issued (in shares)	177.3	176.2
Treasury stock (in shares)	0.5	0.8

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Millions, $ in Millions	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, 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 (loss)	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		$ (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
Treasury Stock, Shares at Dec. 31, 2013			(0.4)
Shares, Issued at Dec. 31, 2013		179.7
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	784.4				784.4
Total net income including portion attributable to noncontrolling interest	784.4
Dividends	(14.6)				(14.6)
Equity-based compensation	26.6		$ (10.5)	36.9			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	0.0
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)	0.0
Treasury Stock, Shares at Dec. 31, 2014	(0.8)		(0.8)
Shares, Issued at Dec. 31, 2014		176.2
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ (149.4)				(149.4)
Total net income including portion attributable to noncontrolling interest	(149.4)
Dividends	(14.1)				(14.1)
Equity-based compensation	24.2		$ 10.8	19.5	(6.1)
Equity-based compensation, shares issued		1.1
Equity-based compensation, treasury shares reissued			0.3
Net proceeds from QEP Midstream initial public offering	0.0
Change in pension and postretirement liability, net of tax	11.9					11.9
Balance at Dec. 31, 2015	$ 3,947.9	$ 1.8	$ (14.6)	$ 554.8	$ 3,418.3	$ (12.4)	$ 0.0
Treasury Stock, Shares at Dec. 31, 2015	(0.5)		(0.5)
Shares, Issued at Dec. 31, 2015		177.3

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING ACTIVITIES
Net income (loss)	$ (149.4)	$ 784.4	$ 159.4
Net income attributable to noncontrolling interest	0.0	21.6	12.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, Depletion and Amortization Including Discontinued Operations	881.1	1,040.6	1,016.0
Deferred income taxes	25.3	(84.1)	66.1
Impairment	55.6	1,143.2	93.0
Equity-based compensation	34.7	27.2	27.1
Other Operating Activities, Curtailment Loss	11.2	0.0	0.0
Amortization of debt issuance costs and discounts	6.2	6.7	6.4
Net gain from asset sales	(4.6)	(1,644.8)	(103.0)
Income from unconsolidated affiliates	0.0	(5.2)	(5.8)
Distributions from unconsolidated affiliates and other	0.0	9.4	7.9
Non-cash loss on early extinguishment of debt	0.0	4.4	0.0
Marketable Securities, Unrealized Gain (Loss)	0.2	0.0	0.0
Unrealized loss (gain) on derivative contracts	$ 183.7	$ (374.4)	$ 88.7
Changes in operating assets and liabilities
Accounts receivable	$ 165.5	$ (160.5)	$ 3.2
Inventories	15.5	(20.2)	2.6
Prepaid expenses	16.7	(7.3)	14.0
Accounts payable and accrued expenses	(71.3)	320.1	(179.7)
Federal income taxes	(619.4)	494.1	(27.4)
Other	(69.7)	(12.7)	11.2
Net Cash Provided by Operating Activities	481.3	1,542.5	1,191.7
INVESTING ACTIVITIES
Property acquisitions	(98.3)	(960.5)	(40.9)
Property, plant and equipment, including dry exploratory well expense	(1,141.1)	(1,765.9)	(1,561.7)
Proceeds from Sale of Oil and Gas Property and Equipment	21.8	3,296.6	211.1
Acquisition deposit held in escrow	0.0	50.0	(50.0)
Other investments	0.0	(42.0)	0.0
Net Cash Provided by (Used in) Investing Activities	(1,217.6)	578.2	(1,441.5)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(24.9)	(54.4)	69.3
Long-term debt issued	0.0	300.0	0.0
Long-term debt issuance costs paid	(2.6)	(9.3)	(3.2)
Long-term debt repaid	0.0	(600.0)	0.0
Proceeds from credit facility	0.0	5,455.0	3,085.0
Repayments of credit facility	0.0	(5,935.0)	(3,295.0)
Common stock repurchased and retired	0.0	(99.7)	0.0
Treasury stock repurchased	(2.7)	(6.2)	(9.3)
Other capital contributions	(0.2)	6.0	7.0
Dividends paid	(14.1)	(14.6)	(14.3)
Excess Tax Benefit (provision) from Share-based Compensation, Financing Activities	(3.2)	(0.5)	0.0
Net proceeds from the issuance of common units	0.0	0.0	449.6
Distribution to noncontrolling interest	0.0	(31.9)	(9.3)
Net Cash Provided by (Used in) Financing Activities	(47.7)	(990.6)	279.8
Change in cash and cash equivalents	(784.0)	1,130.1	30.0
Beginning cash and cash equivalents	1,160.1	30.0	0.0
Ending cash and cash equivalents	$ 376.1	$ 1,160.1	$ 30.0

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

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 principal 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 a gas gathering system and an underground gas storage facility and corporate activities (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.

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.

Revision of Financial Statements

In the fourth quarter of 2015, the Company determined that certain transactions that had been reported on a gross basis and included in "Purchased gas and oil sales" and "Purchased gas and oil expense" on the Consolidated Statement of Operations for certain periods in 2014 and the first three quarters of 2015 should have been reported net, as the transactions were with the same counterparty and were entered into in contemplation of one another. The Company revised its financial statements to reflect the net accounting treatment and assessed the cumulative impact of the revisions on each period affected. The revisions had no effect on the Company’s operating income, net income, earnings per share or cash flows. The Company determined that the impact of the change from gross to net accounting was not material, either individually or in the aggregate, to previously issued financial statements. The Company has, however, recast its Consolidated Statement of Operations for the year ended December 31, 2014, to report “Purchased gas and oil sales” and “Purchased gas and oil expense” on a net basis to conform to presentation for the year ended December 31, 2015.

The following table details the impact of these revisions for the year ended December 31, 2014, on the Consolidated Statement of Operations.



	Year Ended December 31, 2014
	As reported		As revised		Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	1,035.0	$	913.9	$	(121.1	)
Total Revenues	3,414.3		3,293.2		(121.1		)
OPERATING EXPENSES
Purchased gas and oil expense	$	1,031.2	$	910.1	$	(121.1	)
Total Operating Expenses	4,113.0		3,991.9		(121.1		)

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 depends 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. Oil and gas prices throughout 2015 and in early 2016 have been substantially lower than historical averages. Prices will be subject to significant fluctuations in the future. The Company’s derivative contracts serve to mitigate in part 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 future oil and gas production. See Note 7 – Derivative Contracts for the Company’s open oil and gas commodity derivative contracts. In response to the current commodity price environment, we have reduced drilling and completion activity, slowed production growth and preserved liquidity and plan to continue these strategies in 2016.

The Company utilizes cash on hand, availability under its credit facility and cash flows from operating activities to fund its capital expenditures. Based on its current cash on hand, expected cash flow from operations and availability under its credit facility, the Company expects to be able to fund its planned capital expenditures, operating expenses and repayment of maturing debt during the next 12 months and the foreseeable future. However, continued low oil and gas prices could have an adverse effect on the Company’s financial position, results of operations, cash flows, credit ratings and quantities of oil and gas reserves that may be economically produced, which could impact the Company’s ability to comply with the financial covenants under the credit facility and limit further borrowings to fund capital expenditures. Additionally, if forward prices remain low or decline further, the Company could incur additional impairment of its oil and gas assets or other investments.

Revenue Recognition

Revenues are recognized in the period that services are provided or products are delivered. Revenues associated with the sale of gas, oil and NGL are accounted for using the sales method, whereby revenue is recognized as gas, oil and NGL is sold to purchasers. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liability is recorded to the extent that QEP Energy has sold volumes in excess of its share of remaining reserves in an underlying property. QEP's imbalance obligations at December 31, 2015 and 2014, were $3.5 million and $7.9 million, respectively.

QEP Marketing reports revenues gross in accordance with principal-agent considerations. 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.

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, 2015, QEP had unrestricted cash of $376.1 million. In addition, QEP had restricted cash of $18.1 million, which is included in "Other noncurrent assets" and "Prepaid expenses and other" on the Consolidated Balance Sheet. As of December 31, 2014, none of QEP's cash and cash equivalents were restricted.

Supplemental cash flow information is shown in the table below:



	Year Ended December 31,
	2015			2014		2013
Supplemental Disclosures	(in millions)
Cash paid for interest, net of capitalized interest	$	139.4		$	163.2	$	156.7
Cash paid for income taxes	487.8			0.3		77.9
Non-cash investing activities
Change in capital expenditure accrual balance	$	(129.2	)	$	8.4	$	(25.2	)

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. However, if commodity prices remain low for an extended period of time, the Company could incur increased levels of bad debt expense. Bad debt expense associated with accounts receivable for the years ended December 31, 2015, 2014 and 2013, was $0.5 million, $2.1 million, and $0.1 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 $3.9 million at December 31, 2015, and $4.6 million at December 31, 2014.

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:

Successful Efforts Accounting for Oil and Gas Operations

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 (DD&A)

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.

DD&A 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. Other properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, an impairment of 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, 2015, QEP recorded impairment charges of $55.6 million, of which $39.3 million was related to proved properties due to lower future oil and gas prices, $2.0 million was related to expiring leaseholds on unproved properties and $14.3 million was related to the impairment of goodwill. Of the $39.3 million impairment on proved properties, $20.2 million related to impairments on QEP's remaining Midcontinent properties, $18.4 million related to impairments on the Other Northern properties and $0.7 million related to impairments on Permian Basin properties.

During the year ended December 31, 2014, QEP recorded impairment charges of $1,143.2 million, of which $1,041.4 million was related to proved properties due to lower future oil and gas prices and $101.8 million was related to impairment on unproved properties due to lower future prices, lease expirations and changes in drilling plans. Of the $1,041.4 million impairment on proved properties, $532.1 million related to impairments on Haynesville properties, $467.7 million related to impairments on Permian Basin properties, $18.7 million related to impairments on QEP's remaining Midcontinent properties, $13.5 million related to impairments on the Other Northern properties, $5.8 million related to impairments on Williston Basin properties, and $3.6 million related to impairments on Uinta Basin properties.

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

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. See Note 5 – Asset Retirement Obligations for additional information.

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. Goodwill is tested for impairment under a two-step quantitative test on an annual basis or when a triggering event occurs. Under the first step, the estimated fair value of the reporting unit is compared with its carrying value (including goodwill). QEP determines fair value of its reporting units in which goodwill is allocated using the income approach in which the fair value is estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model considered estimated quantities of gas, oil and NGL reserves, including both proved reserves and risk-adjusted unproved reserves, and including probable and possible reserves; estimates of market prices considering forward commodity price curves as of the measurement date; estimates of revenue and operating costs over a multi-year period; and estimates of capital costs. If the fair value of the reporting unit exceeds its carrying value, step two does not need to be performed. If the estimated fair value of the reporting unit is less than its carrying value, an indication of goodwill impairment exists for the reporting unit and the Company performs step two of the impairment test (measurement). Under step two, an impairment loss is recognized for any excess of the carrying amount of the reporting unit’s goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation in acquisition accounting. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. Fair value of the reporting unit under the two-step assessment is determined using a discounted cash flow analysis.

During the year ended December 31, 2015, QEP recorded $14.3 million of goodwill related to an acquisition in December 2015. During the performance of QEP's annual goodwill impairment test at December 31, 2015, QEP failed the first step of the goodwill impairment test as described above, primarily due to lower forecasted oil prices. QEP performed the second step test described above, which resulted in a full write down of goodwill of $14.3 million as of December 31, 2015.

During the year ended December 31, 2014, QEP recorded no goodwill impairments. 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, primarily due to lower forecasted oil and NGL prices. QEP performed the second step test described above, which resulted in a full write down of goodwill of $59.5 million as of December 31, 2013.

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.

Derivative Instruments

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. 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 or oil between the parties at settlement. All 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. QEP does not enter into commodity derivative instruments for speculative purposes. Additionally, QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates.

These derivative contracts are recorded in net income in the month of settlement. These contracts are also marked-to-market monthly with any change in the valuation also recognized in net income. See Note 7 – Derivative Contracts for additional information.

Credit Risk

Exposure to credit risk may be affected by extended periods of low commodity prices as well as the concentration of customers in certain 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 derivative contracts 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 30%, 33%, and 38% of QEP's revenues for the years ended December 31, 2015, 2014 and 2013, respectively. During the year ended December 31, 2015, no customer accounted for 10% or more of the Company's total revenues. During the year ended December 31, 2014, Valero Marketing and Supply Company accounted for 10% of the Company's total revenues. During the year ended December 31, 2013, Freepoint Commodities, LLC accounted for 13% of the Company's total revenues. 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

The amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. 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.

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. As of December 31, 2015, the Company has a valuation allowance of $20.3 million against the state net operation loss deferred tax asset, because the sale of properties in Oklahoma will preclude its utilization in the future. All federal income tax returns prior to 2015 have been examined by the Internal Revenue Service and are closed. Income tax returns for 2015 have not yet been filed. Most state tax returns for 2012 and subsequent years remain subject to examination.

The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest earned on income tax refunds in "Interest and other income" on the Consolidated Statement of Operations, any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statement of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. As of December 31, 2015, QEP had $15.6 million of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which was included within "Other long-term liabilities" on the Consolidated Balance Sheet. As of December 31, 2014, no uncertain tax positions had been recorded. During the year ended December 31, 2015, the Company incurred $0.5 million of interest expense and $2.2 million of penalties related to uncertain tax positions.

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 – Share-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 expired on December 31, 2015. During the year ended December 31, 2015, no shares were repurchased under this program. During the year ended December 31, 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, the historical forfeiture rate is minimal and the restricted shares receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company's unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. For the year ended December 31, 2015, there were no anti-dilutive shares. For the year 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,
	2015	2014	2013
	(in millions)
Weighted-average basic common shares outstanding	176.6	179.8	179.2
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	0.3
Average diluted common shares outstanding	176.6	179.8	179.5

Share-Based Compensation

QEP issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The granting of restricted shares results in recognition of compensation cost measured at the grant-date market price. QEP uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have 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 denominated in share units but have historically been delivered 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. See Note 11 – Share-Based Compensation for additional information.

Pension and Other Postretirement Benefits

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. QEP recognizes a pension curtailment immediately when there is a significant reduction in, or an elimination of, defined-benefit accruals for present employees' future services. See Note 12 – Employee Benefits for additional information.

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. 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 (Haynesville Gathering), 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. Haynesville Gathering is included in the reporting segment QEP Marketing and Other.

Recent Accounting Developments

In November 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) No. 2015-17, Income Taxes (Topic 740), which requires that deferred income tax liabilities and assets be classified as noncurrent on the consolidated balance sheet to simplify the presentation of deferred income taxes. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company implemented this amendment effective December 31, 2015, and it did not have a significant impact on the Company's Consolidated Financial Statements.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805), which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact 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. In July 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606), in which the FASB delayed the effective date of the new revenue standard by one year and the amendments are now effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is not permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820), which allows reporting entities to exclude investments measured at net asset value per share under the existing practical expedient in ASC 820 from the fair value hierarchy. It also limits disclosures to investments for which the entity has elected to measure the fair value using the practical expedient. The amendment will be effective retrospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

In April 2015, the FASB issued ASU No. 2015-05, Intangibles — Goodwill and Other — Internal-Use Software (Subtopic 350-40), which assists entities in evaluating the accounting for fees paid by a customer in a "cloud computing arrangement" by providing guidance as to whether an arrangement includes the sale or license of software. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

In April 2015, the FASB issued ASU No. 2015-03, Interest — Imputation of Interest (Subtopic 835-30), which simplifies the presentation of debt issuance costs by requiring that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The amendments will be effective retrospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company plans to implement the ASU effective January 1, 2016, and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810), which amends the current consolidation guidance. The amendment affects both the variable interest entity and voting interest entity consolidation models. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

In January 2015, the FASB issued ASU No. 2015-01, Income Statement — Extraordinary and Unusual Items (Subtopic 225-20), which eliminates the concept of extraordinary items from GAAP. The amendment will be effective for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. Additionally, a reporting entity also may apply the amendment retrospectively for all periods presented in the financial statements. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2015

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 (the Permian Basin Acquisition). The acquired properties consisted 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 Permian Basin Acquisition met 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 $149.9 million and a net loss of $2.8 million were generated from the acquired properties during the year ended December 31, 2015. 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 significant net loss in 2014 was primarily due to an impairment of proved properties of $467.7 million recognized in 2014 due to the decrease in the future oil prices.

The following table presents a summary of the Company's purchase accounting entries (in millions):



Consideration:
Total consideration	$	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. Pro forma results are not provided for the year ended December 31, 2015, because the Permian Basin Acquisition occurred during the first quarter of 2014, and therefore the Permian Basin results are included in QEP's results for this period. 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 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 amounts)
Revenues	$	3,293.2	$	3,319.3	$	2,685.1	$	2,858.8
Net income	784.4		791.4		159.4		195.3
Earnings per common share
Basic	$	4.36	$	4.40	$	0.89	$	1.09
Diluted	4.36		4.40		0.89		1.09

Other Acquisitions

During the year ended December 31, 2015, QEP acquired various oil and gas properties primarily in the Williston and Permian basins for a total purchase price of $98.3 million, which included an acquisition of additional interests in QEP's operated wells and undeveloped acreage. As a part of the purchase price allocation, the Company recorded $14.3 million of goodwill.

Divestitures

During 2015, QEP sold its interest in certain non-core properties for aggregate proceeds of $31.7 million and a recorded a pre-tax gain on sale of $21.0 million.

During 2014, QEP sold its interest in certain non-core properties in the Midcontinent and Williston Basin for aggregate proceeds of $783.8 million. For the year ended December 31, 2014, QEP recorded a pre-tax loss on sale of $147.0 million. QEP recorded a pre-tax loss on sale of $9.3 million for the year ended December 31, 2015, due to post-closing purchase price adjustments from the sale of such properties.

During 2013, QEP Energy sold its interests in several non-core properties for aggregate proceeds of $205.8 million and recorded a pre-tax gain on sale of $105.7 million.

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

Discontinued Operations

12 Months Ended

Dec. 31, 2015

Discontinued Operations and Disposal Groups [Abstract]

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

On December 2, 2014, the Company closed the sale of substantially all of its midstream business, including its ownership interest in QEP Midstream Partners, LP (QEP Midstream) to Tesoro Logistics LP for total cash proceeds of approximately $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, and QEP recorded a pre-tax gain of approximately $1.8 billion for the year ended December 31, 2014 (Midstream Sale).

The operating results of QEP Field Services Company (QEP Field Services), excluding Haynesville Gathering (the Discontinued Operations of QEP Field Services), was classified as discontinued operations on the Consolidated Statements of Operations and Notes accompanying the Consolidated Financial Statements for the years ended December 31, 2014 and 2013. 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, 2015, 2014 and 2013, cash outflows for these transactions included in continuing operations were $131.8 million, $145.3 million and $124.6 million, respectively.

In 2013, in connection with QEP's plan to separate its midstream business, 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 occurred, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated prior to such date. QEP recognized $10.4 million of costs under this retention plan during the year ended December 31, 2014, which is included within "Discontinued operations, net of income tax" on the Consolidated Statements of Operations.

Consolidated Statement of Operations

The Discontinued Operations of QEP Field Services are summarized below:



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

___________________________


⁽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 and $33.5 million for the years ended December 31, 2014 and 2013, respectively.

Consolidated Statement of Cash Flows

The impact of the Discontinued Operations of QEP Field Services on the Consolidated Statements of Cash Flows for "Depreciation, depletion and amortization" contained in "Cash flows from operating activities" was $45.9 million and $52.2 million for the years ended December 31, 2014 and 2013, 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 and $88.9 million for the years ended December 31, 2014 and 2013, respectively.

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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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligations

QEP records ARO when there are legal obligations associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with 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 $206.8 million and $195.1 million ARO liability for the years ended December 31, 2015 and 2014, respectively, $1.9 million and $1.3 million, respectively, 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
	2015			2014
	(in millions)
ARO liability at January 1,⁽¹⁾	$	195.1		$	165.1
Accretion	8.7			6.7
Additions⁽²⁾	3.8			17.1
Revisions	17.2			33.6
Liabilities related to assets sold	(16.0		)	(24.7		)
Liabilities settled	(2.0		)	(2.7		)
ARO liability at December 31,	$	206.8		$	195.1

____________________________


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


⁽²⁾	Additions for the year ended December 31, 2014, include $9.7 million related to the Permian Basin Acquisition (see Note 2 – Acquisitions and Divestitures).

Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

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.

The fair value of financial assets and liabilities at December 31, 2015 and 2014, is shown in the table below:



	Fair Value Measurements
	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)
	December 31, 2015
Financial Assets
Commodity derivative instruments - short-term	$	—	$	147.8	$	—	$	(1.0	)	$	146.8
Commodity derivative instruments - long-term	—		23.2		—		—			23.2
Total financial assets	$	—	$	171.0	$	—	$	(1.0	)	$	170.0

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	1.8	$	—	$	(1.0	)	$	0.8
Commodity derivative instruments - long-term	—		4.0		—		—			4.0
Total financial liabilities	$	—	$	5.8	$	—	$	(1.0	)	$	4.8

	December 31, 2014
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. See 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, 2015				December 31, 2014
	(in millions)
Financial Assets
Cash and cash equivalents	$	376.1	$	376.1	$	1,160.1	$	1,160.1
Financial Liabilities
Checks outstanding in excess of cash balances	$	29.8	$	29.8	$	54.7	$	54.7
Long-term debt	2,218.8		1,784.6		2,218.1		2,171.6

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 used in the calculation of ARO include plugging costs and reserve lives. A reconciliation of the Company's ARO 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 nonrecurring 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, 2015 and 2014, 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, 2015 and 2014, the Company recorded $39.3 million and $1,041.4 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, 2015 and 2014, 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 gas, oil 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. See Note 2 – Acquisitions and Divestitures for additional information on the fair value of acquired properties.

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

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Contracts

12 Months Ended

Dec. 31, 2015

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, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. In addition, QEP may enter into commodity derivative contracts on a portion of its storage and 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 or oil between the parties at settlement. All 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 or collars 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 and natural gas basis swaps to achieve a fixed-price swap for a portion of its oil and gas it sells at prices that reference specific regional index prices.

QEP does not currently have any commodity derivative transactions that 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.

During 2014 and 2013, QEP also used interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk associated with its $600.0 million term loan. These interest rate swaps were terminated in December 2014 in conjunction with the extinguishment of QEP's term loan.

QEP Energy Derivative Contracts

The following table sets forth QEP Energy's quantities and average prices for its commodity derivative swap contracts as of December 31, 2015:



Year	Index	Total Volumes	Average Swap Price per unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2016	NYMEX HH	51.2	$	2.83
2016	IFNPCR	65.9	$	2.57
2017	NYMEX HH	40.2	$	2.83
2017	IFNPCR	21.9	$	2.52
Oil sales		(bbls)	($/bbl)
2016	NYMEX WTI	6.6	$	58.00
2017	NYMEX WTI	2.6	$	54.39

The following table sets forth QEP Energy's gas collars as of December 31, 2015:

Year

Index

Total Volume

Average Price Floor

Average Price Ceiling

(in millions)

(MMBtu)

($/MMBtu)

2016

NYMEX HH

7.3

2.75

3.89

QEP uses gas basis swaps, combined with NYMEX HH fixed price swaps, to achieve fixed price swaps at the location at which it sells its physical production.

The following table sets forth QEP Energy's gas basis swaps as of December 31, 2015:



Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2016	NYMEX HH	IFNPCR	29.3	$	(0.15	)
2017	NYMEX HH	IFNPCR	7.3	$	(0.20	)

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, 2015:



Year	Type of Contract	Index	Total Volumes	Average Swap Price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2016	SWAP	IFNPCR	2.3	$	2.87
Gas purchases			(MMBtu)
2016	SWAP	IFNPCR	0.2	$	2.11

QEP Derivative Financial Statement Presentation

The following table identifies the consolidated 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	2015		2014		2015		2014
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	147.8	$	339.3	$	1.8	$	0.3
Long-term:
Commodity	Fair value of derivative contracts	23.2		9.9		4.0		—
Total derivative instruments		$	171.0	$	349.2	$	5.8	$	0.3

The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations are summarized in the following table:



Derivative instruments not designated as cash flow hedges	Year Ended December 31,
Derivative instruments not designated as cash flow hedges	2015			2014			2013
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	103.4		$	(16.7	)	$	152.0
Oil derivative contracts	353.7			15.7			(2.2		)
QEP Marketing
Gas derivative contracts	3.8			(2.5		)	0.5
Total realized gains (losses) on commodity derivative contracts	460.9			(3.5		)	150.3
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	62.0			68.4			(42.6		)
Oil derivative contracts	(244.9		)	299.8			(48.1		)
QEP Marketing
Gas derivative contracts	(0.8		)	4.2			(2.1		)
Total unrealized gains (losses) on commodity derivative contracts	(183.7		)	372.4			(92.8		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	277.2		$	368.9		$	57.5

Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	—		$	(7.6	)	$	(2.7	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	—			2.0			4.1
Total realized and unrealized gains (losses) on interest rate swaps	—			(5.6		)	1.4
Total net realized gains (losses) on derivative contracts	460.9			(11.1		)	147.6
Total net unrealized gains (losses) on derivative contracts	(183.7		)	374.4			(88.7		)
Grand Total	$	277.2		$	363.3		$	58.9

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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Restructuring and Related Activities [Abstract]

Restructuring Costs

12 Months Ended

Dec. 31, 2015

Restructuring Costs

In the third quarter of 2015, QEP announced the closure of its regional office in Tulsa, Oklahoma. As a part of this reorganization, QEP incurred costs associated with termination benefits, relocation of certain employees and other expenses. The Company estimates that the total costs related to the Tulsa office closure will be approximately $5.4 million, of which approximately $2.6 million is related to one-time termination benefits and approximately $2.8 million is related to relocation of certain employees. During the year ended December 31, 2015, restructuring costs of $5.0 million were incurred related to the Tulsa office closure, of which $2.6 million was related to one-time termination benefits and $2.4 million was related to relocation of certain employees. QEP also incurred restructuring costs related to one-time termination benefits of approximately $2.7 million in the first quarter of 2015 as a result of work force reductions unrelated to the closure of its Tulsa office. All of the costs were incurred by QEP Energy and reported within QEP Energy's financial statements. These restructuring costs were recorded within "General and administrative" expense on the Consolidated Statement of Operations. The Company estimates that the remaining $0.4 million of restructuring costs related to the Tulsa office closure will be incurred in 2016.

The following table is a reconciliation of QEP's restructuring liability, which is included within "Accounts payable and accrued expenses" on the Consolidated Balance Sheets.



	Restructuring Liability
	(in millions)
Balance at December 31, 2014	$	—
Costs incurred and charged to expense	7.7
Costs paid or otherwise settled	(7.7		)
Balance at December 31, 2015	$	—

Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Debt

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



	December 31,
	2015			2014
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
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
Less: unamortized discount	(3.0		)	(3.7		)
Total principal amount of debt (including current portion)	2,218.8			2,218.1
Less: current portion of long-term debt	(176.8		)	—
Total long-term debt outstanding	$	2,042.0		$	2,218.1

Of the total debt outstanding on December 31, 2015, the 6.05% Senior Notes due September 1, 2016, the 6.80% Senior Notes due April 1, 2018 and the 6.80% Senior Notes due March 1, 2020, will mature within the next five years. In addition, the revolving credit facility matures on December 2, 2019.

Credit Facility

QEP’s 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 provisions and restrictions. The credit agreement contains financial covenants (as defined in the credit agreement) that limit the amount of debt the Company can incur which includes: (i) a net funded debt to capitalization ratio than may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarters ending on and prior to December 31, 2017, and 3.75 times thereafter and (iii) a present value coverage ratio under which, during a ratings trigger period, require that the present value of the Company’s proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2018, and 1.50 times at any time on or after January 1, 2018. At December 31, 2015 and 2014, QEP was in compliance with the covenants under the credit agreement.

During the year ended December 31, 2015, QEP had no borrowings outstanding under the credit facility. During the year ended December 31, 2014, QEP's weighted-average interest rate on borrowings from its credit facility was 2.23%. At December 31, 2015 and 2014, QEP had no borrowings outstanding and had $3.4 million and $3.7 million, respectively, in letters of credit outstanding under the credit facility.

Senior Notes

At December 31, 2015, 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.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

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 material 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.

Litigation

Rocky Mountain Resources Lawsuit – Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint in March 2011, seeking determination of the existence of a 4% overriding royalty interest in an oil and gas lease. Rocky Mountain alleges that the defendants 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. In February 2015, a jury rendered a verdict against QEP and awarded Rocky Mountain damages in the amount of $16.7 million, including interest. QEP is appealing the verdict to the Wyoming Supreme Court, and, in connection with such appeal, has posted a bond for approximately $20.0 million (representing the amount of the verdict and two years of accrued interest at the statutory rate of 10%). In accordance with the Court’s order, QEP is depositing the future monthly revenues attributable to the 4% overriding royalty interest with the Court as it becomes due and owing. The overriding royalty payments will be subject to the direction of the Court following the conclusion of the appeal. QEP estimates that, notwithstanding the verdict, the range of reasonably possible losses is still zero to approximately $20.0 million.

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
2016	$	126.4
2017	$	129.4
2018	$	111.8
2019	$	105.0
2020	$	87.8
After 2020	$	259.0

QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $8.0 million, $8.2 million, and $7.8 million during the years ended December 31, 2015, 2014 and 2013, respectively. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations and utilities are as follows (in millions):



Year	Amount
2016	$	9.7
2017	$	9.8
2018	$	8.5
2019	$	7.6
2020	$	7.4
After 2020	$	18.6

Equity-Based Compensation

12 Months Ended

Dec. 31, 2015

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 the vesting periods for the stock options, restricted shares and performance share units. There were 9.3 million shares available for future grants under the LTSIP at December 31, 2015. Share-based compensation expense related to continuing operations is recognized within "General and administrative" expense 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 within "Net income from discontinued operations, net of income tax" on the Consolidated Statement of Operations. During the year ended December 31, 2015, QEP recognized $34.7 million in total compensation expense related to share-based compensation for continuing operations, compared to $21.4 million and $25.7 million during the years ended December 31, 2014 and 2013, respectively. In addition, during the year ended December 31, 2014, QEP recognized $5.8 million in total compensation expense related to discontinued operations, 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 Assumptions
	Year Ended December 31,
	2015			2014			2013
Weighted-average grant date fair value of awards granted during the period	$	6.82		$	10.11		$	15.16
Risk-free interest rate range	1.38% - 1.38%			1.31% - 1.34%			0.97% - 1.84%
Weighted-average risk-free interest rate	1.4		%	1.3		%	1.0		%
Expected price volatility range	36.8% - 36.8%			36.1% - 37.3%			51.5% - 58.5%
Weighted-average expected price volatility	36.8		%	37.1		%	58.3		%
Expected dividend yield	0.37		%	0.25		%	0.27		%
Expected term in years at the date of grant	4.5			4.5			5.5

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, 2014	1,996,215		$	28.60
Granted	425,877		21.69
Exercised	(15,000	)	19.37
Forfeited	(2,817	)	31.31
Canceled	(203,499	)	21.87
Outstanding at December 31, 2015	2,200,776		$	27.94	3.19	$	—
Options Exercisable at December 31, 2015	1,522,326		$	29.17	2.10	$	—
Unvested Options at December 31, 2015	678,450		$	25.20	5.63	$	—

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.1 million, $0.6 million and $4.3 million during the years ended December 31, 2015, 2014 and 2013, respectively. The Company realized an income tax expense of $6.4 million for the year ended December 31, 2015, no income tax impact for the year ended December 31, 2014, and $1.4 million of income tax benefits for the year ended December 31, 2013, which increased its Additional Paid-in-Capital (APIC) pool by $0.1 million as of December 31, 2015. As of December 31, 2015, $1.9 million of unrecognized compensation cost related to stock options granted under the LTSIP, which is included within "Additional paid-in capital" on the Consolidated Balance Sheet, is expected to be recognized over a weighted-average period of 1.96 years. During the year ended December 31, 2015, QEP issued shares for stock option exercises from its treasury stock and issued new shares. In addition, QEP received $0.3 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, 2015, 2014 and 2013, was $22.7 million, $26.8 million and $19.8 million, respectively. The Company realized an income tax benefit of $3.2 million for the year ended December 31, 2015, and income tax expense of $0.5 million and $0.1 million for the years ended December 31, 2014, and 2013, respectively. Restricted stock increased the Company's APIC pool by $3.5 million as of December 31, 2015. The weighted-average grant date fair value of restricted stock granted was $20.92 per share, $31.40 per share and $30.06 per share for the years ended December 31, 2015, 2014 and 2013, respectively. As of December 31, 2015, $20.3 million of unrecognized compensation cost related to restricted shares granted under the LTSIP, which is included within "Additional paid-in capital" on the Consolidated Balance Sheet, is expected to be recognized over a weighted-average vesting period of 2.04 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, 2014	1,426,453		$	31.02
Granted	1,509,384		20.92
Vested	(748,157	)	30.33
Forfeited	(179,470	)	25.45
Unvested balance at December 31, 2015	2,008,210		$	24.18

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 and have historically been delivered in cash. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of December 31, 2015, the Company expects to settle all awards in cash. The weighted-average grant date fair values of the performance share units granted during the years ended December 31, 2015, 2014 and 2013, were $21.69, $31.57, and $30.12 per share, respectively. As of December 31, 2015, $4.5 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 1.75 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
			(per share)
Unvested balance at December 31, 2014	552,209		$	30.85
Granted	234,085		21.69
Vested and paid out	(131,665	)	30.77
Canceled ⁽¹⁾	(14,612	)	30.77
Forfeited	(9,231	)	29.19
Unvested balance at December 31, 2015	630,786		$	27.50

____________________________


⁽¹⁾	Represents units that were not paid out due to performance under the Plan.

Employee Benefits

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Employee Benefits

Pension and other postretirement benefits

The Company provides pension and other postretirement benefits to certain employees through three retirement benefit plans: the QEP Resources, Inc. Retirement Plan (the Pension Plan), the Supplemental Executive Retirement Plan (SERP), and a postretirement medical plan (the Medical Plan).

The Pension Plan is a closed, qualified defined-benefit pension plan that is funded and provides coverage to 50 active and suspended participants, or 7%, of QEP's active employees, and to 164 participants that are retired or terminated and vested. Pension Plan benefits are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding retirement. During the year ended December 31, 2015, the Company made contributions of $4.0 million to the Pension Plan and expects to contribute approximately $4.0 million to the Pension Plan in 2016. Contributions to the Pension Plan increase plan assets.

As a result of the Company's 2014 divestitures and retirements in 2015, the number of active participants in the Pension Plan fell to 50 participants during the year ended December 31, 2015, which is the minimum number of active participants for a plan to be qualified under the Internal Revenue Services' participant rules. In order to prevent disqualification, the Pension Plan was amended in June 2015 and will be frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services. This change resulted in a non-cash curtailment loss of $11.2 million recognized on the Consolidated Statement of Operations within "General and administrative" expense during the year ended December 31, 2015. A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services.

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. SERP 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. During the year ended December 31, 2015, the Company made contributions of $3.5 million to its SERP and expects to contribute approximately $2.9 million of benefits in 2016. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and will be closed to new participants effective January 1, 2016.

The Medical Plan is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired employees. The Medical Plan is provided only to employees hired before January 1, 1997. Of the 50 active, pension eligible employees, 29 are also eligible for the Medical Plan when they retire. As of December 31, 2015, 51 retirees are enrolled in the Medical 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. During the year ended December 31, 2015, the Company made contributions of $0.2 million and expects to contribute approximately $0.3 million of benefits in 2016. At December 31, 2015 and 2014, QEP's accumulated benefit obligation exceeded the fair value of its qualified retirement plan assets.

During the year ended December 31, 2014, the Company recognized a $10.7 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.

The accumulated benefit obligation for all defined-benefit pension plans was $117.4 million and $121.8 million at December 31, 2015 and 2014, respectively.

The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's Pension Plan, SERP and Medical Plan for the years ended December 31, 2015 and 2014, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2015 and 2014:



	Pension Plan and SERP benefits						Medical Plan benefits
	2015			2014			2015			2014
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$	132.6		$	118.0		$	6.6		$	5.9
Service cost	2.1			2.6			—			—
Interest cost	4.9			5.3			0.2			0.3
Special termination benefits	—			1.9			—			—
Curtailments	(7.1		)	(8.2		)	—			(0.2		)
Plan settlements	—			(2.3		)	—			—
Benefit payments	(7.7		)	(5.5		)	(0.2		)	—
Plan amendments	0.9			—			—			—
Actuarial loss (gain)	(5.4		)	20.8			(1.4		)	0.6
Benefit obligation at December 31,	$	120.3		$	132.6		$	5.2		$	6.6
Change in plan assets
Fair value of plan assets at January 1,	$	81.4		$	71.7		$	—		$	—
Actual gain (loss) on plan assets	(1.9		)	4.5			—			—
Company contributions to the plan	7.5			13.0			0.2			—
Benefit payments	(7.7		)	(5.5		)	(0.2		)	—
Plan settlements	—			(2.3		)	—			—
Fair value of plan assets at December 31,	79.3			81.4			—			—
Underfunded status (current and long-term)	$	(41.0	)	$	(51.2	)	$	(5.2	)	$	(6.6	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(2.9	)	$	(4.3	)	$	(0.3	)	$	(0.3	)
Other long-term liabilities	(38.1		)	(46.9		)	(4.9		)	(6.3		)
Total amount recognized in balance sheet	$	(41.0	)	$	(51.2	)	$	(5.2	)	$	(6.6	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	15.8		$	21.2		$	(0.8	)	$	0.6
Prior service cost	4.1			16.1			1.2			1.4
Total amount recognized in AOCI	$	19.9		$	37.3		$	0.4		$	2.0

The following table sets forth the Company's Pension Plan, SERP and Medical Plan cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31:



	Pension Plan and SERP benefits									Medical Plan benefits
	2015			2014			2013			2015			2014			2013
	(in millions)
Components of net periodic benefit cost
Service cost	$	2.1		$	2.6		$	3.3		$	—		$	—		$	0.1
Interest cost	4.9			5.3			4.8			0.2			0.3			0.3
Expected return on plan assets	(5.7		)	(5.1		)	(3.9		)	—			—			—
Curtailment loss	11.2			9.3			—			—			1.4			—
Special termination benefits	—			1.9			—			—			—			—
Settlements	—			0.7			—			—			—			—
Amortization of prior service costs	1.7			4.7			5.0			0.2			0.3			0.3
Amortization of actuarial loss	0.5			0.8			2.3			—			—			0.1
Periodic expense	$	14.7		$	20.2		$	11.5		$	0.4		$	2.0		$	0.8
Components recognized in accumulated other comprehensive income
Current period actuarial loss (gain)	$	2.2		$	21.5		$	(20.8	)	$	(1.4	)	$	0.6		$	(1.0	)
Amortization of actuarial gain (loss)	(0.5		)	(0.8		)	(2.3		)	—			—			(0.1		)
Amortization of prior service cost	(12.9		)	(14.0		)	(5.0		)	(0.2		)	(1.7		)	(0.4		)
Current year prior service cost	0.9			—			—			—			—			—
Loss on curtailment in current period	(7.1		)	(8.2		)	—			—			(0.2		)	—
Settlements	—			(0.7		)	—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	(17.4	)	$	(2.2	)	$	(28.1	)	$	(1.6	)	$	(1.3	)	$	(1.5	)

The estimated portion of net actuarial loss and net prior service cost for the Pension Plan and SERP that will be amortized from AOCI into net periodic benefit cost in 2016 is $1.4 million, which represents amortization of prior service cost recognition and actuarial losses. The estimated portion to be recognized in net periodic cost for the Medical Plan from AOCI in 2016 is $0.2 million, which represents amortization of prior service cost recognition and actuarial gains. Amortization of prior service costs and actuarial gains or losses 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 the Pension Plan, SERP and Medical Plan obligations at December 31, 2015 and 2014:



	Pension Plan and SERP benefits				Medical Plan benefits
	2015		2014		2015		2014
Discount rate	4.24	%	3.94	%	4.40	%	4.00	%
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 Plan, SERP and Medical Plan 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 Plan, SERP and Medical Plan cost for the years ended December 31:



	Pension Plan and SERP benefits						Medical Plan benefits
	2015		2014		2013		2015		2014		2013
Discount rate	3.94	%	4.40	%	3.69	%	4.00	%	5.00	%	4.10	%
Expected long-term return on plan assets	6.75	%	7.00	%	6.75	%	n/a		n/a		n/a
Rate of increase in compensation	4.00	%	4.00	%	3.60	%	4.00	%	4.00	%	3.60	%

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 2016. 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 EBC'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 the Employee Retirement Income Security Act of 1974 (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.

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. 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 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 the Pension Plan assets:



	December 31, 2015								Percentage of total
	Level 1		Level 2		Level 3		Total		Percentage of total
	(in millions except percentages)
Cash and short-term investments	$	—	$	—	$	0.4	$	0.4	—	%
Equity securities:
Domestic	—		—		38.5		38.5		49	%
International	—		—		16.8		16.8		21	%
Fixed income	—		—		23.6		23.6		30	%
Total investments	$	—	$	—	$	79.3	$	79.3	100	%
	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	%

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



	Year ended December 31,
	2015			2014
	(in millions)
Balance at January 1,	$	81.4		$	71.7
Employer contributions	4.0			8.1
Unrealized gains (losses)	(3.0		)	(1.0		)
Realized gains	1.6			5.9
Administrative fees	(0.6		)	(0.4		)
Benefits paid	(4.1		)	(2.9		)
Balance at December 31,	$	79.3		$	81.4

Expected Benefit Payments

As of December 31, 2015, the following future benefit payments are expected to be paid:



	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2016	$	7.3	$	0.3
2017	$	6.6	$	0.3
2018	$	5.9	$	0.3
2019	$	7.4	$	0.3
2020	$	7.2	$	0.3
2021 through 2025	$	40.7	$	1.4

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, 2015, 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. For the years ended December 31, 2015, 2014 and 2013, employees covered by the Pension Plan were eligible for matching contributions equal to 100% of the employees' contributions up to a maximum of 6% match of their qualifying earnings. The Company may contribute a discretionary portion beyond the Company's matching contribution to employees not in the Pension Plan. The Company recognizes expense equal to its yearly contributions, which amounted to $6.3 million, $7.6 million and $6.9 million during the years ended December 31, 2015, 2014 and 2013, respectively.

Income Taxes

12 Months Ended

Dec. 31, 2015

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,
	2015			2014			2013
	(in millions)
Federal income tax provision (benefit)
Current	$	(112.3	)	$	(324.0	)	$	(92.2	)
Deferred	34.5			110.3			152.3
State income tax provision (benefit)
Current	(6.6		)	(15.5		)	(1.4		)
Deferred	(9.2		)	(3.3		)	1.4
Total income tax provision (benefit)	$	(93.6	)	$	(232.5	)	$	60.1

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,
	2015		2014		2013
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	4.2	%	(1.5	)%	(5.0	)%
State rate change	—	%	3.4	%	—	%
Penalties	(0.3	)%	—	%	0.4	%
Return to provision adjustment	(0.3	)%	(0.4	)%	5.0	%
Book impairment of goodwill	—	%	—	%	18.6	%
Other	(0.1	)%	(0.3	)%	(0.4	)%
Effective income tax rate	38.5	%	36.2	%	53.6	%

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



	December 31,
	2015		2014
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$	1,531.0	$	1,402.9
Commodity price and interest rate derivatives	60.4		127.7
Total deferred tax liabilities	1,591.4		1,530.6
Deferred tax assets
Net operating loss and tax credit carryforwards	51.9		11.7
Employee benefits and compensation costs	43.6		43.0
Bonus and vacation accrual	7.0		16.3
Other	9.1		12.4
Total deferred tax assets	111.6		83.4
Net deferred income tax liability	$	1,479.8	$	1,447.2
Balance sheet classification
Deferred income tax asset - current	$	—	$	—
Deferred income tax liability - current	—		84.5
Deferred income tax liability - non-current	1,479.8		1,362.7
Net deferred income tax liability	$	1,479.8	$	1,447.2

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2015 are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2015-2033	$	40.5
State net operating loss valuation allowance		(20.3		)
U.S. alternative minimum tax credit	Indefinite	—
Total		$	20.2

The valuation allowance of $20.3 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.

Unrecognized Tax Benefit

As of December 31, 2015, QEP had $15.6 million of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which were recorded within "Other long-term liabilities" on the Consolidated Balance Sheet. At December 31, 2014, no uncertain tax positions had been recorded. The uncertain tax positions the Company reported during the year ended December 31, 2015, were expensed during the year ended December 31, 2014. The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statement of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. During the year ended December 31, 2015, the Company incurred $0.5 million of interest expense and $2.2 million of penalties related to uncertain tax positions.

The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the year ended December 31, 2015:



	2015
	(in millions)
Balance as of January 1,	$	—
Additions for tax positions taken during the current period	15.6
Balance as of December 31,	$	15.6

As of December 31, 2015, QEP had approximately $15.6 million of unrecognized tax benefit that would impact our effective tax rate if recognized.

Operations by Line of Business

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Operations by Line of Business

QEP’s two lines of business include oil and gas exploration and production (QEP Energy) and oil and gas marketing, operation of a gas gathering system and an underground gas storage facility 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 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, 2015, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	1,477.2		$	654.5		$	(113.1	)	$	2,018.6
From affiliated customers	—			946.8			(946.8		)	—
Total Revenues	1,477.2			1,601.3			(1,059.9		)	2,018.6
OPERATING EXPENSES
Purchased gas and oil expense	87.3			1,588.1			(1,048.6		)	626.8
Lease operating expense	238.8			—			—			238.8
Gas, oil and NGL transportation and other handling costs	300.2			—			(8.9		)	291.3
Gathering and other expense	—			5.8			—			5.8
General and administrative	176.8			6.7			(2.4		)	181.1
Production and property taxes	115.1			2.5			—			117.6
Depreciation, depletion and amortization	870.8			10.3			—			881.1
Impairment and exploration expenses	58.3			—			—			58.3
Total Operating Expenses	1,847.3			1,613.4			(1,059.9		)	2,400.8
Net gain (loss) from asset sales	9.7			(5.1		)	—			4.6
OPERATING INCOME (LOSS)	(360.4		)	(17.2		)	—			(377.6		)
Realized and unrealized gains (losses) on derivative contracts	274.2			3.0			—			277.2
Interest and other income	1.9			205.7			(204.6		)	3.0
Interest expense	(204.5		)	(145.7		)	204.6			(145.6		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(288.8		)	45.8			—			(243.0		)
Income tax (provision) benefit	105.9			(12.3		)	—			93.6
NET INCOME (LOSS)	$	(182.9	)	$	33.5		$	—		$	(149.4	)
Identifiable total assets	$	7,799.5		$	626.0		$	—		$	8,425.5
Cash capital expenditures	$	1,233.3		$	6.1		$	—		$	1,239.4
Accrued capital expenditures	$	1,105.7		$	4.5		$	—		$	1,110.2

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⁽¹⁾	$	2,524.6		$	889.7		$	(121.1	)	$	—	$	3,293.2
From affiliated customers	—			1,492.6			(1,492.6		)	—		—
Total Revenues	2,524.6			2,382.3			(1,613.7		)	—		3,293.2
OPERATING EXPENSES
Purchased gas and oil expense⁽¹⁾	150.0			2,356.6			(1,596.5		)	—		910.1
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			(1,613.7		)	—		3,991.9
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)	$	(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

____________________________

⁽¹⁾

In the fourth quarter of 2015, the Company determined that certain purchased oil transactions that had been included in "Revenues" and "Purchased gas and oil expense" on a gross basis should have been reported net, as the transactions were with the same counterparty and were entered into in contemplation of one another. The revisions had no effect on the Company’s operating income or net income. The following table details the impact to Eliminations of the revisions to the Consolidated Statement of Operations. See Note 1 – Summary of Significant Accounting Policies for additional information.



	Eliminations as Reported			Eliminations as Revised			Change
	(in millions)
From unaffiliated customers	$	—		$	(121.1	)	$	(121.1	)
Purchased gas and oil expense	(1,475.4		)	(1,596.5		)	(121.1		)

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 and oil 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 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) benefit	(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)	$	25.6		$	26.5		$	—		$	107.3	$	159.4
Identifiable 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 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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2015

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 amounts)
2015
Revenues⁽¹⁾	$	468.1		$	574.6		$	507.6		$	468.3		$	2,018.6
Operating income (loss)	(128.6		)	(16.7		)	(87.7		)	(144.6		)	(377.6		)
Net income (loss)	(55.6		)	(76.3		)	21.1			(38.6		)	(149.4		)
Non-recurring items in operating income (loss) ⁽³⁾	(50.5		)	24.0			(2.1		)	(22.4		)	(51.0		)
Per share information
Basic EPS	$	(0.32	)	$	(0.43	)	$	0.12		$	(0.22	)	$	(0.85	)
Diluted EPS	(0.32		)	(0.43		)	0.12			(0.22		)	(0.85		)



2014
Revenues⁽¹⁾	$	827.6	$	850.0		$	858.5		$	757.1		$	3,293.2
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 ⁽²⁾	27.0		13.8			17.4			1,135.7			1,193.9
Net income (loss)	39.7		(92.3		)	171.1			665.9			784.4
Non-recurring items in operating income (loss) ⁽³⁾	0.4		(202.5		)	(11.9		)	$	(1,077.8	)	(1,291.8		)
Per share information
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

____________________________

⁽¹⁾In the fourth quarter of 2015, the Company determined that certain purchased oil transactions that had been included in "Revenues" on a gross basis should have been reported net, as the transactions were with the same counterparty and were entered into in contemplation of one another. The revisions had no effect on the Company’s operating income, net income or earnings per share. See Note 1 – Summary of Significant Accounting Policies for additional information. The following tables detail the impact to Revenues of the revisions to the Consolidated Statement of Operations for the quarters presented.



	2015
	First Quarter							Second Quarter							Third Quarter
	As Reported		As Adjusted		Change			As Reported		As Adjusted		Change			As Reported		As Adjusted		Change
	(in millions)
Revenues	$	491.6	$	468.1	$	(23.5	)	$	608.6	$	574.6	$	(34.0	)	$	536.7	$	507.6	$	(29.1	)



	2014
	First Quarter						Second Quarter
	As Reported		As Adjusted		Change		As Reported		As Adjusted		Change
	(in millions)
Revenues	$	817.5	$	827.6	$	10.1	$	887.2	$	850.0	$	(37.2	)



	2014
	Third Quarter							Fourth Quarter
	As Reported		As Adjusted		Change			As Reported		As Adjusted		Change
	(in millions)
Revenues	$	910.0	$	858.5	$	(51.5	)	$	799.6	$	757.1	$	(42.5	)


⁽²⁾	In December 2014, QEP completed the Midstream Sale. QEP Field Services' financial results (excluding results of Haynesville Gathering) have been reflected as discontinued operations and all prior periods have been reclassified.


⁽³⁾	Includes net gains and losses from asset sales and losses due to asset impairments.

Supplemental Gas and Oil Information (Unaudited)

12 Months Ended

Dec. 31, 2015

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 of QEP's 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,
	2015			2014
	(in millions)
Proved properties	$	13,314.9		$	12,278.7
Unproved properties, net	691.0			825.2
Total proved and unproved properties	14,005.9			13,103.9
Accumulated depreciation, depletion and amortization	(6,870.2		)	(6,153.0		)
Net capitalized costs	$	7,135.7		$	6,950.9

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 $127.6 million and ARO additions and revisions of $21.0 million during the year ended December 31, 2015. The costs incurred to advance the development of reserves that were classified as proved undeveloped were approximately $811.3 million in 2015, $796.7 million in 2014, and $645.9 million in 2013.



	Year Ended December 31,
	2015		2014		2013
	(in millions)
Proved property acquisitions	$	49.6	$	465.4	$	31.6
Unproved property acquisitions	39.8		496.3		9.3
Exploration (capitalized and expensed)	8.7		23.6		14.6
Development	1,010.3		1,695.1		1,440.8
Total costs incurred	$	1,108.4	$	2,680.4	$	1,496.3

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,
	2015			2014			2013
	(in millions)
Revenues	$	1,390.4		$	2,374.6		$	1,901.2
Production costs	654.1			735.6			583.3
Exploration expenses	2.7			9.9			11.9
Depreciation, depletion and amortization	870.8			984.4			954.2
Impairment	55.6			1,143.2			93.0
Total expenses	1,583.2			2,873.1			1,642.4
Income (loss) before income taxes	(192.8		)	(498.5		)	258.8
Income tax benefit (provision)	70.6			182.5			(96.3		)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(122.2	)	$	(316.0	)	$	162.5

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, 2015, 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 plans to continue development of its leasehold and anticipates that it will have the financial capability to continue development in the manner estimated. While the majority of QEP's PUD reserves are located on leaseholds that are held by production, any PUD locations on expiring leaseholds are scheduled for development during the primary term of the lease.

As of December 31, 2015, 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 gas, oil and NGL reserves for the years ended December 31, 2013, 2014 and 2015 are as follows:



	Gas		Oil		NGL		Total
	(Bcf)		(MMbbl)		(MMbbl)		(Bcfe)
Balance at December 31, 2012	2,622.4		119.0		99.9		3,936.1
Revisions of previous estimates⁽¹⁾	(288.3	)	1.3		(8.0	)	(328.5	)
Extensions and discoveries⁽²⁾	455.6		38.3		16.4		783.8
Purchase of reserves in place	1.0		1.9		0.2		13.4
Sale of reserves in place	(16.9	)	(1.7	)	(1.1	)	(33.9	)
Production	(218.9	)	(10.2	)	(4.8	)	(309.0	)
Balance at December 31, 2013	2,554.9		148.6		102.6		4,061.9
Revisions of previous estimates⁽³⁾	27.1		(4.0	)	1.4		11.3
Extensions and discoveries⁽⁴⁾	141.4		16.8		8.6		294.1
Purchase of reserves in place⁽⁵⁾	72.5		35.7		12.3		360.7
Sale of reserves in place⁽⁶⁾	(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
Revisions of previous estimates⁽⁷⁾	(463.8	)	(47.0	)	(55.3	)	(1,077.9	)
Extensions and discoveries⁽⁸⁾	467.7		85.6		21.8		1,111.9
Purchase of reserves in place⁽⁹⁾	3.2		2.0		0.6		18.7
Sale of reserves in place⁽¹⁰⁾	(34.3	)	(0.4	)	(0.2	)	(37.6	)
Production	(181.1	)	(19.6	)	(4.7	)	(326.8	)
Balance at December 31, 2015	2,108.9		193.1		58.8		3,620.2
Proved developed reserves
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
Balance at December 31, 2015	1,245.3		109.7		34.4		2,109.4
Proved undeveloped reserves
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
Balance at December 31, 2014	1,028.8		73.2		44.4		1,734.4
Balance at December 31, 2015	863.6		83.4		24.4		1,510.8

___________________________

⁽¹⁾

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

⁽²⁾

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

⁽³⁾

Revisions of previous estimates in 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.


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


⁽⁶⁾	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.


⁽⁷⁾	Revisions of previous estimates in 2015 include: 756.9 Bcfe of negative revisions due to lower pricing and 403.2 Bcfe of negative revisions unrelated to pricing, partially offset by 82.2 Bcfe of positive performance revisions. Negative pricing revisions were driven by lower gas, oil, and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and Uinta Basin.

⁽⁸⁾

Extensions and discoveries in 2015 increased proved reserves by 1,111.9 Bcfe, primarily related to extensions and discoveries in Williston Basin of 409.3 Bcfe, Uinta Basin of 318.9 Bcfe, and Permian Basin of 297.8 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.


⁽⁹⁾	Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP's operated wells in the Williston Basin as discussed in Note 2 – Acquisitions and Divestitures.


⁽¹⁰⁾	Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties 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, 2015, 2014 and 2013, 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 2015, 2014 and 2013, 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,
	2015		2014		2013
Average benchmark price per unit:
Gas price (per MMBtu)	$	2.59	$	4.35	$	3.67
Oil price (per bbl)	50.28		94.99		96.94

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 $438.9 million in 2016, $472.8 million in 2017 and $306.8 million in 2018. The scheduled PUD development costs are reduced from historical levels in conjunction with our efforts to reduce drilling and completion activities, gain operational efficiencies, slow production growth and preserve liquidity in the current commodity price environment. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. QEP believes cash flow from operations, cash on hand and availability under its credit facility will be sufficient to cover these estimated future development costs.

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,
	2015			2014			2013
	(in millions)
Future cash inflows	$	15,325.3		$	28,167.3		$	24,805.7
Future production costs	(7,389.9		)	(9,842.1		)	(8,400.3		)
Future development costs	(2,202.5		)	(3,521.3		)	(4,056.7		)
Future income tax expenses	(1,169.3		)	(4,304.0		)	(3,284.6		)
Future net cash flows	4,563.6			10,499.9			9,064.1
10% annual discount for estimated timing of net cash flows	(2,087.3		)	(5,159.9		)	(4,680.2		)
Standardized measure of discounted future net cash flows	$	2,476.3		$	5,340.0		$	4,383.9

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,
	2015			2014			2013
	(in millions)
Balance at January 1,	$	5,340.0		$	4,383.9		$	3,034.7
Sales of gas, oil and NGL produced during the period, net of production costs	(736.3		)	(1,639.0		)	(1,317.9		)
Net change in sales prices and in production (lifting) costs related to future production	(6,307.8		)	726.6			1,236.3
Net change due to extensions, discoveries and improved recovery	1,765.7			979.9			2,230.7
Net change due to revisions of quantity estimates	(1,350.2		)	35.9			(709.6		)
Net change due to purchases of reserves in place	29.7			695.3			36.8
Net change due to sales of reserves in place	(48.8		)	(1,153.7		)	(73.2		)
Previously estimated development costs incurred during the period	865.0			867.5			722.7
Changes in estimated future development costs	560.7			409.6			(596.5		)
Accretion of discount	752.9			597.3			402.2
Net change in income taxes	1,554.4			(600.3		)	(601.7		)
Other	51.0			37.0			19.4
Net change	(2,863.7		)	956.1			1,349.2
Balance at December 31,	$	2,476.3		$	5,340.0		$	4,383.9

Schedule of Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2015

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, 2015
Allowance for bad debts	$	4.6	$	0.5	$	(1.2	)	$	3.9
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

Subsequent Event (Notes)	12 Months Ended
Subsequent Event (Notes)	Dec. 31, 2015
Subsequent Event [Abstract]
Subsequent Events [Text Block]	Note 17 – Subsequent Event Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing and QEP Energy. As a result, QEP Energy will market its own gas, oil and NGL production. In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts have been assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. The change in affiliate transactions will simplify our business processes and financial statements by eliminating the majority of intercompany transactions. QEP also conducted a segment analysis in accordance with ASC Topic 280, Segment Reporting, and based on the changes discussed above, determined that QEP has one reportable segment after January 1, 2016. The elimination of the affiliate transactions has no impact to historical net income. However, since revenues and expenses were historically reported gross for working interest owner products in accordance with principal-agent considerations, QEP will report lower resale revenue and expenses in future periods. The remaining third party resale activity will be reported in “Other revenues” and "Gathering and other expense" on the Consolidated Statement of Operations.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

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.

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

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents and Restricted Cash

Supplemental cash flow information is shown in the table below:



	Year Ended December 31,
	2015			2014		2013
Supplemental Disclosures	(in millions)
Cash paid for interest, net of capitalized interest	$	139.4		$	163.2	$	156.7
Cash paid for income taxes	487.8			0.3		77.9
Non-cash investing activities
Change in capital expenditure accrual balance	$	(129.2	)	$	8.4	$	(25.2	)

Receivables, Policy [Policy Text Block]

Accounts Receivable Trade

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

Property, Plant and Equipment

Successful Efforts Accounting for Oil and Gas Operations

Capitalized exploratory well costs

Depreciation, depletion and amortization (DD&A)



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

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

Goodwill

Commitments and Contingencies, Policy [Policy Text Block]

Litigation and Other Contingencies

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,
	2015	2014	2013
	(in millions)
Weighted-average basic common shares outstanding	176.6	179.8	179.2
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	0.3
Average diluted common shares outstanding	176.6	179.8	179.5

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

Share-Based Compensation

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

Pension and Other Postretirement Benefits

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

Supplemental Cash Flow Information [Table Text Block]

Revision of Financial Statements

The following table details the impact of these revisions for the year ended December 31, 2014, on the Consolidated Statement of Operations.



	Year Ended December 31, 2014
	As reported		As revised		Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	1,035.0	$	913.9	$	(121.1	)
Total Revenues	3,414.3		3,293.2		(121.1		)
OPERATING EXPENSES
Purchased gas and oil expense	$	1,031.2	$	910.1	$	(121.1	)
Total Operating Expenses	4,113.0		3,991.9		(121.1		)

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

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies [Abstract]

Schedule of Error Corrections and Prior Period Adjustments [Table Text Block]



	Year Ended December 31, 2014
	As reported		As revised		Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	1,035.0	$	913.9	$	(121.1	)
Total Revenues	3,414.3		3,293.2		(121.1		)
OPERATING EXPENSES
Purchased gas and oil expense	$	1,031.2	$	910.1	$	(121.1	)
Total Operating Expenses	4,113.0		3,991.9		(121.1		)



	Eliminations as Reported			Eliminations as Revised			Change
	(in millions)
From unaffiliated customers	$	—		$	(121.1	)	$	(121.1	)
Purchased gas and oil expense	(1,475.4		)	(1,596.5		)	(121.1		)

Supplemental Cash Flow Information [Table Text Block]

Revision of Financial Statements

The following table details the impact of these revisions for the year ended December 31, 2014, on the Consolidated Statement of Operations.



	Year Ended December 31, 2014
	As reported		As revised		Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	1,035.0	$	913.9	$	(121.1	)
Total Revenues	3,414.3		3,293.2		(121.1		)
OPERATING EXPENSES
Purchased gas and oil expense	$	1,031.2	$	910.1	$	(121.1	)
Total Operating Expenses	4,113.0		3,991.9		(121.1		)

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

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]



	December 31,
	2015	2014	2013
	(in millions)
Weighted-average basic common shares outstanding	176.6	179.8	179.2
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	0.3
Average diluted common shares outstanding	176.6	179.8	179.5

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Schedule of Purchase Price Allocation [Table Text Block]



Consideration:
Total consideration	$	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 [Table Text Block]



	Year ended December 31,
	2014				2013
	Actual		Pro Forma		Actual		Pro Forma
	(in millions, except per share amounts)
Revenues	$	3,293.2	$	3,319.3	$	2,685.1	$	2,858.8
Net income	784.4		791.4		159.4		195.3
Earnings per common share
Basic	$	4.36	$	4.40	$	0.89	$	1.09
Diluted	4.36		4.40		0.89		1.09

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2015

Discontinued Operations and Disposal Groups [Abstract]

Income Statement Impact Of Discontinued Operations [Table Text Block]



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

___________________________


⁽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 and $33.5 million for the years ended December 31, 2014 and 2013, respectively.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair value and related carrying amount of certain financial instruments



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2015				December 31, 2014
	(in millions)
Financial Assets
Cash and cash equivalents	$	376.1	$	376.1	$	1,160.1	$	1,160.1
Financial Liabilities
Checks outstanding in excess of cash balances	$	29.8	$	29.8	$	54.7	$	54.7
Long-term debt	2,218.8		1,784.6		2,218.1		2,171.6

The fair value of financial assets and liabilities at December 31, 2015 and 2014, is shown in the table below:



	Fair Value Measurements
	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)
	December 31, 2015
Financial Assets
Commodity derivative instruments - short-term	$	—	$	147.8	$	—	$	(1.0	)	$	146.8
Commodity derivative instruments - long-term	—		23.2		—		—			23.2
Total financial assets	$	—	$	171.0	$	—	$	(1.0	)	$	170.0

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	1.8	$	—	$	(1.0	)	$	0.8
Commodity derivative instruments - long-term	—		4.0		—		—			4.0
Total financial liabilities	$	—	$	5.8	$	—	$	(1.0	)	$	4.8

	December 31, 2014
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	)	$	—

Derivative Contracts (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Volumes and Average Prices

QEP Energy Derivative Contracts

The following table sets forth QEP Energy's quantities and average prices for its commodity derivative swap contracts as of December 31, 2015:



Year	Index	Total Volumes	Average Swap Price per unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2016	NYMEX HH	51.2	$	2.83
2016	IFNPCR	65.9	$	2.57
2017	NYMEX HH	40.2	$	2.83
2017	IFNPCR	21.9	$	2.52
Oil sales		(bbls)	($/bbl)
2016	NYMEX WTI	6.6	$	58.00
2017	NYMEX WTI	2.6	$	54.39

The following table sets forth QEP Energy's gas collars as of December 31, 2015:

Year

Index

Total Volume

Average Price Floor

Average Price Ceiling

(in millions)

(MMBtu)

($/MMBtu)

2016

NYMEX HH

7.3

2.75

3.89

QEP uses gas basis swaps, combined with NYMEX HH fixed price swaps, to achieve fixed price swaps at the location at which it sells its physical production.

The following table sets forth QEP Energy's gas basis swaps as of December 31, 2015:



Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2016	NYMEX HH	IFNPCR	29.3	$	(0.15	)
2017	NYMEX HH	IFNPCR	7.3	$	(0.20	)

QEP Marketing Derivative Contracts



Year	Type of Contract	Index	Total Volumes	Average Swap Price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2016	SWAP	IFNPCR	2.3	$	2.87
Gas purchases			(MMBtu)
2016	SWAP	IFNPCR	0.2	$	2.11

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	2015		2014		2015		2014
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	147.8	$	339.3	$	1.8	$	0.3
Long-term:
Commodity	Fair value of derivative contracts	23.2		9.9		4.0		—
Total derivative instruments		$	171.0	$	349.2	$	5.8	$	0.3

Effects of Derivative Transactions



Derivative instruments not designated as cash flow hedges	Year Ended December 31,
Derivative instruments not designated as cash flow hedges	2015			2014			2013
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	103.4		$	(16.7	)	$	152.0
Oil derivative contracts	353.7			15.7			(2.2		)
QEP Marketing
Gas derivative contracts	3.8			(2.5		)	0.5
Total realized gains (losses) on commodity derivative contracts	460.9			(3.5		)	150.3
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	62.0			68.4			(42.6		)
Oil derivative contracts	(244.9		)	299.8			(48.1		)
QEP Marketing
Gas derivative contracts	(0.8		)	4.2			(2.1		)
Total unrealized gains (losses) on commodity derivative contracts	(183.7		)	372.4			(92.8		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	277.2		$	368.9		$	57.5

Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	—		$	(7.6	)	$	(2.7	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	—			2.0			4.1
Total realized and unrealized gains (losses) on interest rate swaps	—			(5.6		)	1.4
Total net realized gains (losses) on derivative contracts	460.9			(11.1		)	147.6
Total net unrealized gains (losses) on derivative contracts	(183.7		)	374.4			(88.7		)
Grand Total	$	277.2		$	363.3		$	58.9

Restructuring Costs (Tables)

12 Months Ended

Dec. 31, 2015

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Costs [Table Text Block]



	Restructuring Liability
	(in millions)
Balance at December 31, 2014	$	—
Costs incurred and charged to expense	7.7
Costs paid or otherwise settled	(7.7		)
Balance at December 31, 2015	$	—

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

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
2016	$	126.4
2017	$	129.4
2018	$	111.8
2019	$	105.0
2020	$	87.8
After 2020	$	259.0

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 and utilities are as follows (in millions):



Year	Amount
2016	$	9.7
2017	$	9.8
2018	$	8.5
2019	$	7.6
2020	$	7.4
After 2020	$	18.6

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.

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

Equity-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2015

Share-based Compensation [Abstract]

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



	Stock Option Assumptions
	Year Ended December 31,
	2015			2014			2013
Weighted-average grant date fair value of awards granted during the period	$	6.82		$	10.11		$	15.16
Risk-free interest rate range	1.38% - 1.38%			1.31% - 1.34%			0.97% - 1.84%
Weighted-average risk-free interest rate	1.4		%	1.3		%	1.0		%
Expected price volatility range	36.8% - 36.8%			36.1% - 37.3%			51.5% - 58.5%
Weighted-average expected price volatility	36.8		%	37.1		%	58.3		%
Expected dividend yield	0.37		%	0.25		%	0.27		%
Expected term in years at the date of grant	4.5			4.5			5.5

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, 2014	1,996,215		$	28.60
Granted	425,877		21.69
Exercised	(15,000	)	19.37
Forfeited	(2,817	)	31.31
Canceled	(203,499	)	21.87
Outstanding at December 31, 2015	2,200,776		$	27.94	3.19	$	—
Options Exercisable at December 31, 2015	1,522,326		$	29.17	2.10	$	—
Unvested Options at December 31, 2015	678,450		$	25.20	5.63	$	—

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, 2014	1,426,453		$	31.02
Granted	1,509,384		20.92
Vested	(748,157	)	30.33
Forfeited	(179,470	)	25.45
Unvested balance at December 31, 2015	2,008,210		$	24.18

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
			(per share)
Unvested balance at December 31, 2014	552,209		$	30.85
Granted	234,085		21.69
Vested and paid out	(131,665	)	30.77
Canceled ⁽¹⁾	(14,612	)	30.77
Forfeited	(9,231	)	29.19
Unvested balance at December 31, 2015	630,786		$	27.50

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2015

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

Schedule of Defined Benefit Plans Disclosures [Table Text Block]



	Pension Plan and SERP benefits						Medical Plan benefits
	2015			2014			2015			2014
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$	132.6		$	118.0		$	6.6		$	5.9
Service cost	2.1			2.6			—			—
Interest cost	4.9			5.3			0.2			0.3
Special termination benefits	—			1.9			—			—
Curtailments	(7.1		)	(8.2		)	—			(0.2		)
Plan settlements	—			(2.3		)	—			—
Benefit payments	(7.7		)	(5.5		)	(0.2		)	—
Plan amendments	0.9			—			—			—
Actuarial loss (gain)	(5.4		)	20.8			(1.4		)	0.6
Benefit obligation at December 31,	$	120.3		$	132.6		$	5.2		$	6.6
Change in plan assets
Fair value of plan assets at January 1,	$	81.4		$	71.7		$	—		$	—
Actual gain (loss) on plan assets	(1.9		)	4.5			—			—
Company contributions to the plan	7.5			13.0			0.2			—
Benefit payments	(7.7		)	(5.5		)	(0.2		)	—
Plan settlements	—			(2.3		)	—			—
Fair value of plan assets at December 31,	79.3			81.4			—			—
Underfunded status (current and long-term)	$	(41.0	)	$	(51.2	)	$	(5.2	)	$	(6.6	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(2.9	)	$	(4.3	)	$	(0.3	)	$	(0.3	)
Other long-term liabilities	(38.1		)	(46.9		)	(4.9		)	(6.3		)
Total amount recognized in balance sheet	$	(41.0	)	$	(51.2	)	$	(5.2	)	$	(6.6	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	15.8		$	21.2		$	(0.8	)	$	0.6
Prior service cost	4.1			16.1			1.2			1.4
Total amount recognized in AOCI	$	19.9		$	37.3		$	0.4		$	2.0

Pension and Other Postretirement Benefit Costs

The following table sets forth the Company's Pension Plan, SERP and Medical Plan cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31:



	Pension Plan and SERP benefits									Medical Plan benefits
	2015			2014			2013			2015			2014			2013
	(in millions)
Components of net periodic benefit cost
Service cost	$	2.1		$	2.6		$	3.3		$	—		$	—		$	0.1
Interest cost	4.9			5.3			4.8			0.2			0.3			0.3
Expected return on plan assets	(5.7		)	(5.1		)	(3.9		)	—			—			—
Curtailment loss	11.2			9.3			—			—			1.4			—
Special termination benefits	—			1.9			—			—			—			—
Settlements	—			0.7			—			—			—			—
Amortization of prior service costs	1.7			4.7			5.0			0.2			0.3			0.3
Amortization of actuarial loss	0.5			0.8			2.3			—			—			0.1
Periodic expense	$	14.7		$	20.2		$	11.5		$	0.4		$	2.0		$	0.8
Components recognized in accumulated other comprehensive income
Current period actuarial loss (gain)	$	2.2		$	21.5		$	(20.8	)	$	(1.4	)	$	0.6		$	(1.0	)
Amortization of actuarial gain (loss)	(0.5		)	(0.8		)	(2.3		)	—			—			(0.1		)
Amortization of prior service cost	(12.9		)	(14.0		)	(5.0		)	(0.2		)	(1.7		)	(0.4		)
Current year prior service cost	0.9			—			—			—			—			—
Loss on curtailment in current period	(7.1		)	(8.2		)	—			—			(0.2		)	—
Settlements	—			(0.7		)	—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	(17.4	)	$	(2.2	)	$	(28.1	)	$	(1.6	)	$	(1.3	)	$	(1.5	)

Schedule of Assumptions Used [Table Text Block]



	Pension Plan and SERP benefits				Medical Plan benefits
	2015		2014		2015		2014
Discount rate	4.24	%	3.94	%	4.40	%	4.00	%
Rate of increase in compensation	4.00	%	4.00	%	4.00	%	4.00	%



	Pension Plan and SERP benefits						Medical Plan benefits
	2015		2014		2013		2015		2014		2013
Discount rate	3.94	%	4.40	%	3.69	%	4.00	%	5.00	%	4.10	%
Expected long-term return on plan assets	6.75	%	7.00	%	6.75	%	n/a		n/a		n/a
Rate of increase in compensation	4.00	%	4.00	%	3.60	%	4.00	%	4.00	%	3.60	%

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 the Pension Plan assets:



	December 31, 2015								Percentage of total
	Level 1		Level 2		Level 3		Total		Percentage of total
	(in millions except percentages)
Cash and short-term investments	$	—	$	—	$	0.4	$	0.4	—	%
Equity securities:
Domestic	—		—		38.5		38.5		49	%
International	—		—		16.8		16.8		21	%
Fixed income	—		—		23.6		23.6		30	%
Total investments	$	—	$	—	$	79.3	$	79.3	100	%
	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	%

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,
	2015			2014
	(in millions)
Balance at January 1,	$	81.4		$	71.7
Employer contributions	4.0			8.1
Unrealized gains (losses)	(3.0		)	(1.0		)
Realized gains	1.6			5.9
Administrative fees	(0.6		)	(0.4		)
Benefits paid	(4.1		)	(2.9		)
Balance at December 31,	$	79.3		$	81.4

Schedule of Expected Benefit Payments [Table Text Block]

Expected Benefit Payments

As of December 31, 2015, the following future benefit payments are expected to be paid:



	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2016	$	7.3	$	0.3
2017	$	6.6	$	0.3
2018	$	5.9	$	0.3
2019	$	7.4	$	0.3
2020	$	7.2	$	0.3
2021 through 2025	$	40.7	$	1.4

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

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,
	2015			2014			2013
	(in millions)
Federal income tax provision (benefit)
Current	$	(112.3	)	$	(324.0	)	$	(92.2	)
Deferred	34.5			110.3			152.3
State income tax provision (benefit)
Current	(6.6		)	(15.5		)	(1.4		)
Deferred	(9.2		)	(3.3		)	1.4
Total income tax provision (benefit)	$	(93.6	)	$	(232.5	)	$	60.1

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,
	2015		2014		2013
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	4.2	%	(1.5	)%	(5.0	)%
State rate change	—	%	3.4	%	—	%
Penalties	(0.3	)%	—	%	0.4	%
Return to provision adjustment	(0.3	)%	(0.4	)%	5.0	%
Book impairment of goodwill	—	%	—	%	18.6	%
Other	(0.1	)%	(0.3	)%	(0.4	)%
Effective income tax rate	38.5	%	36.2	%	53.6	%

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



	December 31,
	2015		2014
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$	1,531.0	$	1,402.9
Commodity price and interest rate derivatives	60.4		127.7
Total deferred tax liabilities	1,591.4		1,530.6
Deferred tax assets
Net operating loss and tax credit carryforwards	51.9		11.7
Employee benefits and compensation costs	43.6		43.0
Bonus and vacation accrual	7.0		16.3
Other	9.1		12.4
Total deferred tax assets	111.6		83.4
Net deferred income tax liability	$	1,479.8	$	1,447.2
Balance sheet classification
Deferred income tax asset - current	$	—	$	—
Deferred income tax liability - current	—		84.5
Deferred income tax liability - non-current	1,479.8		1,362.7
Net deferred income tax liability	$	1,479.8	$	1,447.2

Summary of Operating Loss Carryforwards [Table Text Block]

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2015 are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2015-2033	$	40.5
State net operating loss valuation allowance		(20.3		)
U.S. alternative minimum tax credit	Indefinite	—
Total		$	20.2

Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Table Text Block]

The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the year ended December 31, 2015:



	2015
	(in millions)
Balance as of January 1,	$	—
Additions for tax positions taken during the current period	15.6
Balance as of December 31,	$	15.6

As of December 31, 2015, QEP had approximately $15.6 million of unrecognized tax benefit that would impact our effective tax rate if recognized.

Operations by Line of Business (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Summary of operating results by line of business [Table Text Block]

The following table is a summary of operating results for the year ended December 31, 2015, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	1,477.2		$	654.5		$	(113.1	)	$	2,018.6
From affiliated customers	—			946.8			(946.8		)	—
Total Revenues	1,477.2			1,601.3			(1,059.9		)	2,018.6
OPERATING EXPENSES
Purchased gas and oil expense	87.3			1,588.1			(1,048.6		)	626.8
Lease operating expense	238.8			—			—			238.8
Gas, oil and NGL transportation and other handling costs	300.2			—			(8.9		)	291.3
Gathering and other expense	—			5.8			—			5.8
General and administrative	176.8			6.7			(2.4		)	181.1
Production and property taxes	115.1			2.5			—			117.6
Depreciation, depletion and amortization	870.8			10.3			—			881.1
Impairment and exploration expenses	58.3			—			—			58.3
Total Operating Expenses	1,847.3			1,613.4			(1,059.9		)	2,400.8
Net gain (loss) from asset sales	9.7			(5.1		)	—			4.6
OPERATING INCOME (LOSS)	(360.4		)	(17.2		)	—			(377.6		)
Realized and unrealized gains (losses) on derivative contracts	274.2			3.0			—			277.2
Interest and other income	1.9			205.7			(204.6		)	3.0
Interest expense	(204.5		)	(145.7		)	204.6			(145.6		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(288.8		)	45.8			—			(243.0		)
Income tax (provision) benefit	105.9			(12.3		)	—			93.6
NET INCOME (LOSS)	$	(182.9	)	$	33.5		$	—		$	(149.4	)
Identifiable total assets	$	7,799.5		$	626.0		$	—		$	8,425.5
Cash capital expenditures	$	1,233.3		$	6.1		$	—		$	1,239.4
Accrued capital expenditures	$	1,105.7		$	4.5		$	—		$	1,110.2

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⁽¹⁾	$	2,524.6		$	889.7		$	(121.1	)	$	—	$	3,293.2
From affiliated customers	—			1,492.6			(1,492.6		)	—		—
Total Revenues	2,524.6			2,382.3			(1,613.7		)	—		3,293.2
OPERATING EXPENSES
Purchased gas and oil expense⁽¹⁾	150.0			2,356.6			(1,596.5		)	—		910.1
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			(1,613.7		)	—		3,991.9
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)	$	(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

____________________________

⁽¹⁾



	Eliminations as Reported			Eliminations as Revised			Change
	(in millions)
From unaffiliated customers	$	—		$	(121.1	)	$	(121.1	)
Purchased gas and oil expense	(1,475.4		)	(1,596.5		)	(121.1		)

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 and oil 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 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) benefit	(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)	$	25.6		$	26.5		$	—		$	107.3	$	159.4
Identifiable 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

Schedule of Error Corrections and Prior Period Adjustments [Table Text Block]



	Year Ended December 31, 2014
	As reported		As revised		Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	1,035.0	$	913.9	$	(121.1	)
Total Revenues	3,414.3		3,293.2		(121.1		)
OPERATING EXPENSES
Purchased gas and oil expense	$	1,031.2	$	910.1	$	(121.1	)
Total Operating Expenses	4,113.0		3,991.9		(121.1		)



	Eliminations as Reported			Eliminations as Revised			Change
	(in millions)
From unaffiliated customers	$	—		$	(121.1	)	$	(121.1	)
Purchased gas and oil expense	(1,475.4		)	(1,596.5		)	(121.1		)

Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

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 amounts)
2015
Revenues⁽¹⁾	$	468.1		$	574.6		$	507.6		$	468.3		$	2,018.6
Operating income (loss)	(128.6		)	(16.7		)	(87.7		)	(144.6		)	(377.6		)
Net income (loss)	(55.6		)	(76.3		)	21.1			(38.6		)	(149.4		)
Non-recurring items in operating income (loss) ⁽³⁾	(50.5		)	24.0			(2.1		)	(22.4		)	(51.0		)
Per share information
Basic EPS	$	(0.32	)	$	(0.43	)	$	0.12		$	(0.22	)	$	(0.85	)
Diluted EPS	(0.32		)	(0.43		)	0.12			(0.22		)	(0.85		)



2014
Revenues⁽¹⁾	$	827.6	$	850.0		$	858.5		$	757.1		$	3,293.2
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 ⁽²⁾	27.0		13.8			17.4			1,135.7			1,193.9
Net income (loss)	39.7		(92.3		)	171.1			665.9			784.4
Non-recurring items in operating income (loss) ⁽³⁾	0.4		(202.5		)	(11.9		)	$	(1,077.8	)	(1,291.8		)
Per share information
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

____________________________



	2015
	First Quarter							Second Quarter							Third Quarter
	As Reported		As Adjusted		Change			As Reported		As Adjusted		Change			As Reported		As Adjusted		Change
	(in millions)
Revenues	$	491.6	$	468.1	$	(23.5	)	$	608.6	$	574.6	$	(34.0	)	$	536.7	$	507.6	$	(29.1	)



	2014
	First Quarter						Second Quarter
	As Reported		As Adjusted		Change		As Reported		As Adjusted		Change
	(in millions)
Revenues	$	817.5	$	827.6	$	10.1	$	887.2	$	850.0	$	(37.2	)



	2014
	Third Quarter							Fourth Quarter
	As Reported		As Adjusted		Change			As Reported		As Adjusted		Change
	(in millions)
Revenues	$	910.0	$	858.5	$	(51.5	)	$	799.6	$	757.1	$	(42.5	)


⁽²⁾	In December 2014, QEP completed the Midstream Sale. QEP Field Services' financial results (excluding results of Haynesville Gathering) have been reflected as discontinued operations and all prior periods have been reclassified.


⁽³⁾	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, 2015

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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



	December 31,
	2015			2014
	(in millions)
Proved properties	$	13,314.9		$	12,278.7
Unproved properties, net	691.0			825.2
Total proved and unproved properties	14,005.9			13,103.9
Accumulated depreciation, depletion and amortization	(6,870.2		)	(6,153.0		)
Net capitalized costs	$	7,135.7		$	6,950.9

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



	Year Ended December 31,
	2015		2014		2013
	(in millions)
Proved property acquisitions	$	49.6	$	465.4	$	31.6
Unproved property acquisitions	39.8		496.3		9.3
Exploration (capitalized and expensed)	8.7		23.6		14.6
Development	1,010.3		1,695.1		1,440.8
Total costs incurred	$	1,108.4	$	2,680.4	$	1,496.3

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,
	2015			2014			2013
	(in millions)
Revenues	$	1,390.4		$	2,374.6		$	1,901.2
Production costs	654.1			735.6			583.3
Exploration expenses	2.7			9.9			11.9
Depreciation, depletion and amortization	870.8			984.4			954.2
Impairment	55.6			1,143.2			93.0
Total expenses	1,583.2			2,873.1			1,642.4
Income (loss) before income taxes	(192.8		)	(498.5		)	258.8
Income tax benefit (provision)	70.6			182.5			(96.3		)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(122.2	)	$	(316.0	)	$	162.5

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, 2012	2,622.4		119.0		99.9		3,936.1
Revisions of previous estimates⁽¹⁾	(288.3	)	1.3		(8.0	)	(328.5	)
Extensions and discoveries⁽²⁾	455.6		38.3		16.4		783.8
Purchase of reserves in place	1.0		1.9		0.2		13.4
Sale of reserves in place	(16.9	)	(1.7	)	(1.1	)	(33.9	)
Production	(218.9	)	(10.2	)	(4.8	)	(309.0	)
Balance at December 31, 2013	2,554.9		148.6		102.6		4,061.9
Revisions of previous estimates⁽³⁾	27.1		(4.0	)	1.4		11.3
Extensions and discoveries⁽⁴⁾	141.4		16.8		8.6		294.1
Purchase of reserves in place⁽⁵⁾	72.5		35.7		12.3		360.7
Sale of reserves in place⁽⁶⁾	(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
Revisions of previous estimates⁽⁷⁾	(463.8	)	(47.0	)	(55.3	)	(1,077.9	)
Extensions and discoveries⁽⁸⁾	467.7		85.6		21.8		1,111.9
Purchase of reserves in place⁽⁹⁾	3.2		2.0		0.6		18.7
Sale of reserves in place⁽¹⁰⁾	(34.3	)	(0.4	)	(0.2	)	(37.6	)
Production	(181.1	)	(19.6	)	(4.7	)	(326.8	)
Balance at December 31, 2015	2,108.9		193.1		58.8		3,620.2
Proved developed reserves
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
Balance at December 31, 2015	1,245.3		109.7		34.4		2,109.4
Proved undeveloped reserves
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
Balance at December 31, 2014	1,028.8		73.2		44.4		1,734.4
Balance at December 31, 2015	863.6		83.4		24.4		1,510.8

___________________________

⁽¹⁾

⁽²⁾

⁽³⁾


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


⁽⁶⁾	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.


⁽⁷⁾	Revisions of previous estimates in 2015 include: 756.9 Bcfe of negative revisions due to lower pricing and 403.2 Bcfe of negative revisions unrelated to pricing, partially offset by 82.2 Bcfe of positive performance revisions. Negative pricing revisions were driven by lower gas, oil, and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and Uinta Basin.

⁽⁸⁾


⁽⁹⁾	Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP's operated wells in the Williston Basin as discussed in Note 2 – Acquisitions and Divestitures.


⁽¹⁰⁾	Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties 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,
	2015		2014		2013
Average benchmark price per unit:
Gas price (per MMBtu)	$	2.59	$	4.35	$	3.67
Oil price (per bbl)	50.28		94.99		96.94

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,
	2015			2014			2013
	(in millions)
Future cash inflows	$	15,325.3		$	28,167.3		$	24,805.7
Future production costs	(7,389.9		)	(9,842.1		)	(8,400.3		)
Future development costs	(2,202.5		)	(3,521.3		)	(4,056.7		)
Future income tax expenses	(1,169.3		)	(4,304.0		)	(3,284.6		)
Future net cash flows	4,563.6			10,499.9			9,064.1
10% annual discount for estimated timing of net cash flows	(2,087.3		)	(5,159.9		)	(4,680.2		)
Standardized measure of discounted future net cash flows	$	2,476.3		$	5,340.0		$	4,383.9

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,
	2015			2014			2013
	(in millions)
Balance at January 1,	$	5,340.0		$	4,383.9		$	3,034.7
Sales of gas, oil and NGL produced during the period, net of production costs	(736.3		)	(1,639.0		)	(1,317.9		)
Net change in sales prices and in production (lifting) costs related to future production	(6,307.8		)	726.6			1,236.3
Net change due to extensions, discoveries and improved recovery	1,765.7			979.9			2,230.7
Net change due to revisions of quantity estimates	(1,350.2		)	35.9			(709.6		)
Net change due to purchases of reserves in place	29.7			695.3			36.8
Net change due to sales of reserves in place	(48.8		)	(1,153.7		)	(73.2		)
Previously estimated development costs incurred during the period	865.0			867.5			722.7
Changes in estimated future development costs	560.7			409.6			(596.5		)
Accretion of discount	752.9			597.3			402.2
Net change in income taxes	1,554.4			(600.3		)	(601.7		)
Other	51.0			37.0			19.4
Net change	(2,863.7		)	956.1			1,349.2
Balance at December 31,	$	2,476.3		$	5,340.0		$	4,383.9

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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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.

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.

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

Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Disclosures
Restricted cash	$ 18.1
Cash paid for interest, net of capitalized interest	139.4	$ 163.2	$ 156.7
Cash paid for income taxes	487.8	0.3	77.9
Non-cash investing activities
Change in capital expenditure accrual balance	$ (129.2)	$ (8.4)	$ (25.2)

Summary of Significant Accounting Policies Accounts Receivable Trade (Details) - Allowance for Doubtful Accounts [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable [Line Items]
Bad Debt Expense	$ 0.5	$ 2.1	$ 0.1
Allowance for Doubtful Accounts Receivable	$ 3.9	$ 4.6

Summary of Significant Accounting Policies Property, plant and equipment (Details)	12 Months Ended
	Dec. 31, 2015
Building [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years
Building [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	30 years
Leasehold Improvements [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Leasehold Improvements [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years
Equipment [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Equipment [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	7 years
Furniture and Fixtures [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Furniture and Fixtures [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	7 years

Summary of Significant Accounting Policies Impairment of long-lived assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 55.6	$ 1,143.2	$ 93.0
Cash and cash equivalents	376.1	1,160.1
Midcontinent [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	20.2	18.7
Other Northern [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	18.4	13.5
Permian Basin [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	0.7	467.7
Williston Basin [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		5.8
Uinta Basin [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		3.6
Unproved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	2.0	101.8	32.3
Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	39.3	1,041.4	1.2
Haynesville [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		$ 532.1
Goodwill [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 14.3		$ 59.5

Summary of Significant Accounting Policies Credit Risk (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Concentration Risk [Line Items]
Concentration Risk, Customer	0.3	0.33	0.38
Concentration Risk, Percentage	10.00%
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%

Summary of Significant Accounting Policies Income Taxes (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Accounting Changes and Error Corrections [Abstract]
Operating Loss Carryforwards, Valuation Allowance	$ 20.3
Unrecognized Tax Benefits	15.6
Interest Related to Uncertain Tax Positions	0.5
Penalties Related to Uncertain Tax Positions	$ 2.2

Summary of Significant Accounting Policies Share Repurchases And Retirements (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($) $ / shares shares
Share Repurchases And Retirements [Abstract]
Stock Repurchase Program, Authorized Amount \| $	$ 500.0
Number of shares of common stock repurchased and retired \| shares	4,731,438
Weighted average price of common stock repurchased and retired \| $ / shares	$ 21.08
Commission paid per share of common stock repurchased and retired \| $ / shares	$ 0.02
Value of stock repurchased and retired \| $	$ 99.7

Summary of Significant Accounting Policies Earnings Per Share (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	176.6	179.8	179.2
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan	0.0	0.0	0.3
Average diluted common shares outstanding (in shares)	176.6	179.8	179.5

Summary of Significant Accounting Policies Revision of Financial Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Purchased gas, oil and NGL sales	$ (620.8)	$ (913.9)	$ (774.9)
Purchased gas, oil and NGL expense	(626.8)	(910.1)	(783.5)
Operating Expenses	$ (2,400.8)	(3,991.9)	$ (2,585.6)
Purchased gas and oil sales as reported [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Purchased gas, oil and NGL sales		(1,035.0)
Revenues		(3,414.3)
Purchased gas, oil and NGL expense		(1,031.2)
Operating Expenses		(4,113.0)
Purchased gas and oil sales as revised [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Purchased gas, oil and NGL sales		(913.9)
Revenues		(3,293.2)
Purchased gas, oil and NGL expense		(910.1)
Operating Expenses		(3,991.9)
Change [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Purchased gas, oil and NGL sales		(121.1)
Revenues		(121.1)
Purchased gas, oil and NGL expense		(121.1)
Operating Expenses		$ (121.1)

Acquisitions and Divestitures (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) a	Dec. 31, 2013 USD ($)
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 21.8	$ 3,296.6	$ 211.1
Payments to Acquire Oil and Gas Property	98.3	960.5	40.9
Permian Basin Acquisition [Member]
Significant Acquisitions and Disposals [Line Items]
Aggregate purchase price		$ 941.8
Net acres of producing and undeveloped oil and gas properties \| a		26,500
Vertical producing oil and gas wells		270
Revenue of acquired properties since acquisition date	149.9	$ 159.5
Net income of acquired properties since acquisition date	(2.8)	(438.3)
Permian Basin [Member]
Significant Acquisitions and Disposals [Line Items]
Impairment of Oil and Gas Properties	0.7	467.7
Goodwill [Member]
Significant Acquisitions and Disposals [Line Items]
Impairment of Oil and Gas Properties	14.3		59.5
Nonrecurring Adjustment [Domain]
Significant Acquisitions and Disposals [Line Items]
Gain (Loss) on Sale of Properties, before Applicable Income Taxes	(9.3)
Non-core properties Divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	31.7	783.8	205.8
Gain (Loss) on Sale of Properties, before Applicable Income Taxes	$ 21.0	$ (147.0)	$ 105.7

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

Acquisitions and Divestitures Schedule of Pro Forma Results Of Operations (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues	$ 468.3	$ 507.6	$ 574.6	$ 468.1	$ 757.1	$ 858.5	$ 850.0	$ 827.6	$ 2,018.6	$ 3,293.2	$ 2,685.1
Net income (loss)	$ (38.6)	$ 21.1	$ (76.3)	$ (55.6)	$ 665.9	$ 171.1	$ (92.3)	$ 39.7	$ (149.4)	$ 784.4	$ 159.4
Earnings Per Share, Basic									$ (0.85)	$ 4.36	$ 0.89
Diluted total									$ (0.85)	$ 4.36	$ 0.89
Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Revenues										$ 3,293.2	$ 2,685.1
Net income (loss)										$ 784.4	$ 159.4
Earnings Per Share, Basic										$ 4.36	$ 0.89
Diluted total										$ 4.36	$ 0.89
Business Acquisition, Pro Forma Revenue										$ 3,319.3	$ 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

Discontinued Operations (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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		1,800.0
Continuing Cash Flows To Business Held For Sale	$ 131.8	145.3	$ 124.6
Depreciation, depletion and amortization	$ 881.1	994.7	963.8
Retention Bonuses Related To Discontinued Operations		10.4
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
Payments to Acquire Oil and Gas Property and Equipment		$ 55.2	$ 88.9

Discontinued Operations Income Statement Impact Of Discontinued Operations (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

NGL sales

$ 80.0

$ 223.3

$ 192.2

Other revenues

15.1

11.1

22.4

Purchased gas, oil and NGL sales

620.8

913.9

774.9

Total Revenues

$ 468.3

$ 507.6

$ 574.6

$ 468.1

$ 757.1

$ 858.5

$ 850.0

$ 827.6

2,018.6

3,293.2

2,685.1

Purchased gas, oil and NGL expense

(626.8)

(910.1)

(783.5)

Lease operating expense

(238.8)

(240.1)

(181.3)

Natural gas, oil and NGL transportation and other handling costs

(291.3)

(277.6)

(222.0)

Gathering and other expense

5.8

6.7

8.4

General and administrative

181.1

204.4

160.4

Production and property taxes

117.6

205.2

161.3

Depreciation, depletion and amortization

881.1

994.7

963.8

Total Operating Expenses

2,400.8

3,991.9

2,585.6

Net gain (loss) from asset sales

4.6

(148.6)

103.5

OPERATING INCOME (LOSS)

$ (144.6)

$ (87.7)

$ (16.7)

$ (128.6)

(1,067.3)

115.1

(35.9)

140.8

(377.6)

(847.3)

203.0

Realized and unrealized gains (losses) on derivative contracts

277.2

363.3

58.9

Interest and other income

3.0

12.8

15.2

Income from unconsolidated affiliates

0.0

0.3

0.2

Loss from early extinguishment of debt

0.0

(2.0)

0.0

Interest expense

145.6

169.1

165.1

Net income attributable to noncontrolling interest

0.0

21.6

12.0

NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX

$ 1,135.7

$ 17.4

$ 13.8

$ 27.0

$ 0.0

1,193.9

107.3

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

^[1]

$ 28.9

33.5

Ownership Percentage

^[1]

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

NGL sales

109.3

101.9

Other revenues

140.9

166.6

Purchased gas, oil and NGL sales

^[2]

(47.1)

(17.8)

Total Revenues

203.1

250.7

Purchased gas, oil and NGL expense

^[2]

(48.5)

(17.6)

Lease operating expense

^[2]

(5.5)

(3.5)

Natural gas, oil and NGL transportation and other handling costs

^[2]

(55.4)

(80.6)

Gathering and other expense

85.9

82.2

General and administrative

42.1

30.7

Production and property taxes

7.3

5.2

Depreciation, depletion and amortization

45.9

52.2

Total Operating Expenses

71.8

68.6

Net gain (loss) from asset sales

1,793.4

(0.5)

OPERATING INCOME (LOSS)

1,924.7

181.6

Interest and other income

0.3

(10.0)

Income from unconsolidated affiliates

4.9

5.6

Loss from early extinguishment of debt

(2.4)

0.0

Interest Income (Expense), Net

(3.8)

1.8

INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES

^[1]

1,923.7

179.0

Income taxes

(708.2)

(59.7)

NET INCOME FROM DISCONTINUED OPERATIONS

1,215.5

119.3

Net income attributable to noncontrolling interest

(21.6)

(12.0)

NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX

$ 1,193.9

$ 107.3

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

Capitalized Exploratory Well Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized Exploratory Well Costs [Abstract]
Beginning Balance	$ 12.6	$ 2.6	$ 2.1
Additions to capitalized exploratory well costs pending the determination of proved reserves	6.0	13.7	2.7
Reclassifications to proved properties after the determination of proved reserves	(16.0)	0.0	(2.2)
Capitalized exploratory well costs charged to expense	0.0	(3.7)	0.0
Ending Balance	$ 2.6	$ 12.6	$ 2.6

Asset Retirement Obligations (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

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

Asset retirement obligation, current

$ 1.9

$ 1.3

Asset retirement obligations, noncurrent

204.9

193.8

ARO Liability [Roll Forward]

ARO liability, Beginning Balance

^[1]

195.1

165.1

Accretion

8.7

6.7

Liabilities incurred

^[2]

3.8

17.1

Revisions of Estimates

17.2

33.6

ARO Liabilities Transferred

(16.0)

(24.7)

Liabilities settled

(2.0)

(2.7)

ARO liability, Ending Balance

$ 206.8

195.1

^[1]

Midstream Business Held For Sale [Member] | Asset Retirement Obligation Costs [Member]

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

Asset retirement obligations, noncurrent

28.5

Permian Basin Acquisition [Member]

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

Recognized identifiable assets acquired and liabilities assumed, net

941.8

Permian Basin Acquisition [Member] | Asset Retirement Obligation Costs [Member]

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

Recognized identifiable assets acquired and liabilities assumed, net

$ 9.7

[1]	Excludes $28.5 million of ARO as of January 1, 2014, classified as "Noncurrent liabilities of discontinued operations" on the Consolidated Balance Sheet.
[2]	Additions for the year ended December 31, 2014, include $9.7 million related to the Permian Basin Acquisition (see Note 2 – Acquisitions and Divestitures).

Fair Value of Financial Assets and Liabilities (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Financial Assets
Derivative instruments	$ 170.0	$ 348.9
Financial liabilities
Derivative instruments	4.8	0.0
Level 1 [Member]
Financial Assets
Derivative instruments	0.0	0.0
Financial liabilities
Derivative instruments	0.0	0.0
Level 2 [Member]
Financial Assets
Derivative instruments	171.0	349.2
Financial liabilities
Derivative instruments	5.8	0.3
Level 3 [Member]
Financial Assets
Derivative instruments	0.0	0.0
Financial liabilities
Derivative instruments	0.0	0.0
Netting Adjustments [Member]
Financial Assets
Derivative instruments	(1.0)	(0.3)
Financial liabilities
Derivative instruments	(1.0)	(0.3)
Long term [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments	23.2	9.9
Financial liabilities
Derivative instruments	4.0
Long term [Member] \| Commodity Contract [Member] \| Level 1 [Member]
Financial Assets
Derivative instruments	0.0	0.0
Long term [Member] \| Commodity Contract [Member] \| Level 2 [Member]
Financial Assets
Derivative instruments	23.2	9.9
Financial liabilities
Derivative instruments	4.0	0.0
Long term [Member] \| Commodity Contract [Member] \| Level 3 [Member]
Financial Assets
Derivative instruments	0.0	0.0
Long term [Member] \| Commodity Contract [Member] \| Netting Adjustments [Member]
Financial Assets
Derivative instruments	0.0	0.0
Financial liabilities
Derivative instruments	0.0
Short term [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments	146.8	339.0
Financial liabilities
Derivative instruments	0.8	0.0
Short term [Member] \| Commodity Contract [Member] \| Level 1 [Member]
Financial Assets
Derivative instruments	0.0	0.0
Financial liabilities
Derivative instruments	0.0	0.0
Short term [Member] \| Commodity Contract [Member] \| Level 2 [Member]
Financial Assets
Derivative instruments	147.8	339.3
Financial liabilities
Derivative instruments	1.8	0.3
Short term [Member] \| Commodity Contract [Member] \| Level 3 [Member]
Financial Assets
Derivative instruments	0.0	0.0
Financial liabilities
Derivative instruments	0.0	0.0
Short term [Member] \| Commodity Contract [Member] \| Netting Adjustments [Member]
Financial Assets
Derivative instruments	(1.0)	(0.3)
Financial liabilities
Derivative instruments	$ (1.0)	$ (0.3)

Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 376.1	$ 1,160.1
Checks outstanding in excess of cash balances	29.8	54.7
Long-term Debt, Gross	2,218.8	2,218.1
Long-term Debt	2,042.0	2,218.1
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	376.1	1,160.1
Checks outstanding in excess of cash balances	29.8	54.7
Long-term debt	$ 1,784.6	$ 2,171.6

Derivative Contracts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Forecasted production from proved reserves (in hundredths)	100.00%
Expected Annual Production Covered By Derivatives	50.00%
Expected Annual Production Covered By Derivatives, High	75.00%
Term Loan due 2017 [Member]
Derivatives, Fair Value [Line Items]
Total principal amount of debt		$ 600.0

Derivative Contracts Schedule of Commodity Derivative Contracts (Details) MMBTU in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) MMBTU $ / MMBTU
Gas Basis Swaps [Member] \| QEP Energy [Member] \| Year 2016 [Member] \| NYMEX WTI less LLS Differential [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	29.3
Derivatives, Weighted Average Differential \| $	$ (0.15)
Gas Basis Swaps [Member] \| QEP Energy [Member] \| Year 2017 [Member] \| NYMEX WTI less LLS Differential [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7.3
Derivatives, Weighted Average Differential \| $	$ (0.20)
Natural Gas Sales Costless Collars [Member] \| QEP Energy [Member] \| Year 2016 [Member] \| NYMEX [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7.3
Derivative Average Price Floor \| $	$ 2.75
Derivative Average Price Ceiling \| $	$ 3.89
Natural Gas Sales [Member] \| QEP Energy [Member] \| Year 2016 [Member] \| NYMEX [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	51.2
Underlying, Derivative Asset \| $ / MMBTU	2.83
Natural Gas Sales [Member] \| QEP Energy [Member] \| Year 2016 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	65.9
Underlying, Derivative Asset \| $ / MMBTU	2.57
Natural Gas Sales [Member] \| QEP Energy [Member] \| Year 2017 [Member] \| NYMEX [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	40.2
Underlying, Derivative Asset \| $ / MMBTU	2.83
Natural Gas Sales [Member] \| QEP Energy [Member] \| Year 2017 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	21.9
Underlying, Derivative Asset \| $ / MMBTU	2.52
Natural Gas Sales [Member] \| QEP Marketing [Member] \| Year 2016 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2.3
Underlying, Derivative Asset \| $ / MMBTU	2.87
Purchased Gas and Oil Expense [Member] \| QEP Marketing [Member] \| Year 2016 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.2
Underlying, Derivative Asset \| $ / MMBTU	2.11
Oil Sales [Member] \| QEP Energy [Member] \| Year 2016 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6.6
Underlying, Derivative Asset \| $ / MMBTU	58.00
Oil Sales [Member] \| QEP Energy [Member] \| Year 2017 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2.6
Underlying, Derivative Asset \| $ / MMBTU	54.39

Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative instruments - assets	$ 170.0	$ 348.9
Derivative instruments - liabilities	4.8	0.0
Commodity Contract [Member] \| Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	146.8	339.0
Derivative instruments - liabilities	0.8	0.0
Commodity Contract [Member] \| Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	23.2	9.9
Derivative instruments - liabilities	4.0
Fair Value, Inputs, Level 2 [Member]
Derivative [Line Items]
Derivative instruments - assets	171.0	349.2
Derivative instruments - liabilities	5.8	0.3
Fair Value, Inputs, Level 2 [Member] \| Commodity Contract [Member] \| Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	147.8	339.3
Derivative instruments - liabilities	1.8	0.3
Fair Value, Inputs, Level 2 [Member] \| Commodity Contract [Member] \| Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	23.2	9.9
Derivative instruments - liabilities	$ 4.0	$ 0.0

Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) derivative contracts not designated as hedging instruments	$ 460.9	$ (11.1)	$ 147.6
Unrealized gain (loss) derivative contracts not designated as hedging instruments	(183.7)	374.4	(88.7)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	277.2	363.3	58.9
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	460.9	(3.5)	150.3
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(183.7)	372.4	(92.8)
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	277.2	368.9	57.5
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	103.4	(16.7)	152.0
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	62.0	68.4	(42.6)
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	3.8	(2.5)	0.5
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(0.8)	4.2	(2.1)
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	353.7	15.7	(2.2)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(244.9)	299.8	(48.1)
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	0.0	(7.6)	(2.7)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	2.0	4.1
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	$ 0.0	$ (5.6)	$ 1.4

Restructuring Costs (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2015
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost Remaining		$ 0.4
Restructuring and Related Cost, Cost Incurred to Date		5.0
Special Termination Benefits	$ 2.7
Estimated restructuring costs		5.4
Special Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Cost Incurred to Date		2.6
Relocation of Employees		2.4
Estimated restructuring costs		2.6
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Estimated restructuring costs		$ 2.8

Restructuring Costs Schedule of Restructuring Costs by Line of Business (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Restructuring Costs [Abstract]
Restructuring and Related Costs, Liability - beginning balance	$ 0.0
Restructuring and Related Cost, Cost Incurred to Date	7.7
Restructuring and Related Costs, Costs paid & settled	(7.7)
Restructuring and Related Costs, Liability - ending balance	$ 0.0

Debt (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
Debt (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
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%
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt, Weighted Average Interest Rate		2.23%
Long-term Line of Credit	$ 1,800.0
Letters of Credit Outstanding, Amount	$ 3.4	$ 3.7
6.05% Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Sep. 01, 2016
Debt Instrument, Interest Rate, Stated Percentage	6.05%
6.80% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Apr. 01, 2018
Debt Instrument, Interest Rate, Stated Percentage	6.80%
6.80% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Mar. 01, 2020
Debt Instrument, Interest Rate, Stated Percentage	6.80%

Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total principal amount of debt	$ 2,218.8	$ 2,218.1
Less unamortized discount	(3.0)	(3.7)
Long-term Debt, Excluding Current Maturities	2,042.0	2,218.1
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	0.0	0.0
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
Current Portion of Long-Term Debt [Member]
Debt Instrument [Line Items]
Total principal amount of debt	$ 176.8	$ 0.0

Commitments and Contingencies Litigation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Litigation Settlement, Amount	$ 16.7
Loss Contingency Bond Posted	20.0
Loss Contingency, Range of Possible Loss, Minimum	0.0
Loss Contingency, Range of Possible Loss, Maximum	$ 20.0
Litigation Settlement Statutory Interest Rate	10.00%

Commitments and Contingencies Other Commitments (Details) $ in Millions	Dec. 31, 2015 USD ($)
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 126.4
Unrecorded Unconditional Purchase Obligation, Due within Two Years	129.4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	111.8
Unrecorded Unconditional Purchase Obligation, Due within Four Years	105.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	87.8
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 259.0

Commitments and Contingencies Long-term Operating lease commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating lease commitments [Abstract]
Operating Leases, Rent Expense	$ 8.0	$ 8.2	$ 7.8
Operating Leases, Future Minimum Payments Due, Next Twelve Months	9.7
Operating Leases, Future Minimum Payments, Due in Two Years	9.8
Operating Leases, Future Minimum Payments, Due in Three Years	8.5
Operating Leases, Future Minimum Payments, Due in Four Years	7.6
Operating Leases, Future Minimum Payments, Due in Five Years	7.4
Operating Leases, Future Minimum Payments, Due Thereafter	$ 18.6

Equity-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for future grants	9.3
Equity-based compensation	$ 34.7	$ 27.2	$ 27.1
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of options exercised	0.1	$ 0.6	4.3
Tax benefit from equity-based compensation expense	6.4		$ 1.4
Adjustment to Additional Paid In Capital resulting from income tax effect of equity-based compensation	0.1
Unrecognized compensation costs	1.9
Weighted average period for recognition of equity-based compensation expense		1 year 11 months 16 days
Cash received in relation to stock options	$ 0.3
Weighted average grant date fair value	$ 6.82	$ 10.11	$ 15.16
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	$ 3.5
Unrecognized compensation costs	$ 20.3
Weighted average period for recognition of equity-based compensation expense	2 years 15 days
Award vesting period	3 years
Total fair value of stock that vested during the period	$ 22.7	$ 26.8	$ 19.8
Income tax expense (benefit) related to restricted stock compensation	$ 3.2	$ 0.5	$ 0.1
Weighted average grant date fair value	$ 20.92	$ 31.40	$ 30.06
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$ 4.5
Weighted average period for recognition of equity-based compensation expense	1 year 9 months 1 day
Weighted average grant date fair value	$ 21.69	$ 31.57	$ 30.12
Continuing Operations [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 34.7	$ 21.4	$ 25.7
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) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value	$ 6.82	$ 10.11	$ 15.16
Risk free interest rate, minimum	1.31%	0.97%	0.63%
Risk free interest rate, maximum	1.34%	1.84%	1.04%
Weighted average risk-free interest rate	1.38%	1.31%	1.00%
Expected price volatility range, minimum	36.10%	51.50%	55.90%
Expected price volatility range, maximum	37.30%	58.50%	56.50%
Weighted average expected price volatility	36.77%	37.10%	58.30%
Expected dividend yield	0.37%	0.25%	0.27%
Expected term in years at the date of grant	4 years 6 months	4 years 6 months	5 years 6 months
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value	$ 20.92	$ 31.40	$ 30.06
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value	$ 21.69	$ 31.57	$ 30.12

Equity-Based Compensation Schedule of Stock Option Transactions (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Stock options outstanding, beginning of year \| shares	1,996,215
Options granted \| shares	425,877
Options exercised \| shares	(15,000)
Options forfeited \| shares	(2,817)
Options Cancelled \| shares	(203,499)
Stock options outstanding, end of year \| shares	2,200,776
Share-based Compensation Arrangement by Share-based Payment Award, Additional General Disclosures [Abstract]
Weighted average exercise price, beginning of year \| $ / shares	$ 28.60
Weighted average exercise price, granted in period \| $ / shares	21.69
Weighted average exercise price, exercised in period \| $ / shares	19.37
Weighted average exercise price, forfeited in period \| $ / shares	31.31
Weighted average exercise price, cancelled in period \| $ / shares	21.87
Weighted average exercise price, end of year \| $ / shares	$ 27.94
Options exercisable, shares \| shares	1,522,326
Options exercisable, weighted average exercise price \| $ / shares	$ 29.17
Unvested options, shares \| shares	678,450
Unvested options, weighted average exercise price \| $ / shares	$ 25.20
Weighted average remaining contractual term, options outstanding	3 years 2 months 10 days
Weighted average remaining contractual term, options exercisable	2 years 1 month 5 days
Weighted average remaining contractual term, options unvested	5 years 7 months 18 days
Aggregate intrinsic value, options outstanding \| $	$ 0.0
Aggregate intrinsic value, options exercisable \| $	0.0
Aggregate intrinsic value, options unvested \| $	$ 0.0

Equity-Based Compensation Schedule of Restricted Stock Transactions (Details) - Restricted Stock [Member]	12 Months Ended
	Dec. 31, 2015 $ / shares shares
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 \| shares	1,426,453
Shares granted \| shares	1,509,384
Shares vested \| shares	(748,157)
Shares forfeited \| shares	(179,470)
Unvested balance at end of period \| shares	2,008,210
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 \| $ / shares	$ 31.02
Weighted average grant date fair value, grants \| $ / shares	20.92
Weighted average grant date fair value, vested \| $ / shares	30.33
Weighted average grant date fair value, forfeited \| $ / shares	25.45
Weighted average grant date fair value, end of period \| $ / shares	$ 24.18

Equity-Based Compensation Schedule of Performance Share Unit Transactions (Details) - Performance Share Units [Member]	12 Months Ended
	Dec. 31, 2015 $ / shares shares
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 \| shares	552,209
Shares granted \| shares	234,085
Shares vested and paid out \| shares	(131,665)
Shares vested and canceled \| shares	(14,612)
Shares forfeited \| shares	(9,231)
Unvested balance at end of period \| shares	630,786
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 \| $ / shares	$ 30.85
Weighted average grant date fair value, grants \| $ / shares	21.69
Weighted average grant date fair value, vested and paid out \| $ / shares	30.77
Weighted average grant date fair value, vested and canceled \| $ / shares	30.77
Weighted average grant date fair value, forfeited \| $ / shares	29.19
Weighted average grant date fair value, end of period \| $ / shares	$ 27.50

Employee Benefits (Narrative) (Details) $ in Millions	12 Months Ended
Employee Benefits (Narrative) (Details) $ in Millions	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 117.4	$ 121.8
Defined Contribution Plan, Cost Recognized	$ 6.3	7.6	$ 6.9
Active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Employees Covered	50
Non-active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Employees Covered	164
Employee Investment Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	8.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%
Closed Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	6.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%
Funded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension Contributions	$ 4.0
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	7.00%
Unfunded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension Contributions	$ 3.5
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	$ 2.9
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	29
Postretirement Health Care Benefits, Number of Employees Covered	51
Defined Benefit Plan, Curtailments	$ 0.0	0.2	0.0
Special termination benefits	0.0	0.0	0.0
Pension Contributions	0.2
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	(0.2)	(1.7)	(0.4)
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Curtailments	7.1	8.2	0.0
Special termination benefits	0.0	1.9	0.0
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year	1.4
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	$ (12.9)	(14.0)	$ (5.0)
Midstream Business Held For Sale [Member] \| Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Curtailments		$ 10.7

Employee Benefits Schedule of Changes in Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

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

Net actuarial loss recognized in AOCI

^[1]

$ (0.5)

$ (13.6)

$ 13.5

Pension Plan [Member]

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

Benefit obligation, beginning of period

132.6

118.0

2.1

2.6

3.3

4.9

5.3

4.8

0.0

1.9

0.0

(7.1)

(8.2)

0.0

0.0

(2.3)

Defined Benefit Plan, Plan Amendments

(7.7)

(5.5)

0.9

0.0

Actuarial loss (gain)

(5.4)

20.8

Benefit obligation, end of period

120.3

132.6

118.0

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

Fair value of plan assets, beginning of period

81.4

71.7

Actual gain on plan assets

(1.9)

4.5

Company contributions to the plan

7.5

13.0

(7.7)

(5.5)

Fair value of plan assets, end of period

0.0

(2.3)

79.3

81.4

71.7

Underfunded status (current and long-term)

(41.0)

(51.2)

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

Amounts included in accounts payable and accrued expenses

(2.9)

(4.3)

Amounts included in other long-term liabilities

(38.1)

(46.9)

Total amount recognized in balance sheets

(41.0)

(51.2)

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

Net actuarial loss recognized in AOCI

15.8

21.2

Prior service cost recognized in AOCI

4.1

16.1

Total amount recognized in AOCI

19.9

37.3

Other Postretirement Benefit Plan [Member]

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

Benefit obligation, beginning of period

6.6

5.9

0.0

0.1

0.2

0.3

0.0

0.0

(0.2)

0.0

0.0

Defined Benefit Plan, Plan Amendments

(0.2)

0.0

0.0

Actuarial loss (gain)

(1.4)

0.6

Benefit obligation, end of period

5.2

6.6

5.9

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

Fair value of plan assets, beginning of period

0.0

Actual gain on plan assets

0.0

Company contributions to the plan

0.2

0.0

(0.2)

0.0

Fair value of plan assets, end of period

0.0

0.0

$ 0.0

Underfunded status (current and long-term)

(5.2)

(6.6)

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

Amounts included in accounts payable and accrued expenses

(0.3)

Amounts included in other long-term liabilities

(4.9)

(6.3)

Total amount recognized in balance sheets

(5.2)

(6.6)

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

Net actuarial loss recognized in AOCI

(0.8)

0.6

Prior service cost recognized in AOCI

1.2

1.4

Total amount recognized in AOCI

$ 0.4

$ 2.0

[1]	Presented net of income tax benefit of $0.3 million for the year ended December 31, 2015, net of income tax benefit of $8.5 million for the year ended December 31, 2014, and net of income tax expense of $8.3 million for the year ended December 31, 2013

Employee Benefits Schedule of Net Periodic Benefit Cost and Other Comprehensive Income for Pension and Other Postretirement Benefit Plans (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

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

$ 0.7

^[1]

$ 0.6

0.0

$ 0.0

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

0.7

Pension Plan [Member]

2.1

2.6

3.3

Expected return on plan assets

4.9

5.3

4.8

(5.7)

(5.1)

(3.9)

Curtailment loss

11.2

9.3

0.0

0.0

1.9

0.0

Amortization of prior service costs

0.0

0.7

0.0

1.7

4.7

5.0

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

0.5

0.8

2.3

Periodic expense

14.7

20.2

11.5

Current period actuarial loss (gain)

2.2

21.5

(20.8)

Amortization of prior service cost

(0.5)

(0.8)

(2.3)

(12.9)

(14.0)

(5.0)

0.9

0.0

(7.1)

(8.2)

0.0

Total amount recognized in accumulated other comprehensive income

0.0

0.7

0.0

(17.4)

(2.2)

(28.1)

Other Postretirement Benefit Plan [Member]

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

0.0

0.1

Expected return on plan assets

0.2

0.3

0.0

Curtailment loss

0.0

1.4

0.0

0.0

Amortization of prior service costs

0.0

0.2

0.3

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

0.0

0.1

Periodic expense

0.4

2.0

0.8

Current period actuarial loss (gain)

(1.4)

0.6

(1.0)

Amortization of prior service cost

0.0

(0.1)

(0.2)

(1.7)

(0.4)

0.0

0.0

(0.2)

0.0

Total amount recognized in accumulated other comprehensive income

0.0

$ (1.6)

$ (1.3)

$ (1.5)

[1]	Presented net of income tax benefit of $0.3 million for the year ended December 31, 2015.

Employee Benefits Schedule of Weighted Average Actuarial Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Costs (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate used in calculating benefit obligation	4.24%	3.94%
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	3.94%	4.40%	3.69%
Expected long-term return on plan assets used in calculating net periodic benefit cost	6.75%	7.00%	6.75%
Rate of increase in compensation used in calculating net periodic benefit cost	4.00%	4.00%	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	4.40%	4.00%
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	4.00%	5.00%	4.10%
Rate of increase in compensation used in calculating net periodic benefit cost	4.00%	4.00%	3.60%

Employee Benefits Schedule of Changes in Level 3 Assets (Details) - Fair Value, Inputs, Level 3 [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of period	$ 81.4	$ 71.7
Employer contributions	4.0	8.1
Unrealized gains (losses)	(3.0)	(1.0)
Realized gains (losses)	1.6	5.9
Administration fees	(0.6)	(0.4)
Benefits paid	(4.1)	(2.9)
Fair value of plan assets, end of period	$ 79.3	$ 81.4

Employee Benefits Schedule of Expected Benefit Payments for Pension and Other Postretirement Benefits (Details) $ in Millions	Dec. 31, 2015 USD ($)
Pension Plan [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2016	$ 7.3
2017	6.6
2018	5.9
2019	7.4
2020	7.2
2021 through 2025	40.7
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2016	0.3
2017	0.3
2018	0.3
2019	0.3
2020	0.3
2021 through 2025	$ 1.4

Income Taxes Schedule of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Federal Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	$ (112.3)	$ (324.0)	$ (92.2)
Deferred Federal Income Tax Expense (Benefit)	34.5	110.3	152.3
State and Local Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current State and Local Tax Expense (Benefit)	(6.6)	(15.5)	(1.4)
Deferred State and Local Income Tax Expense (Benefit)	(9.2)	(3.3)	1.4
Income tax (provision) benefit	$ (93.6)	$ (232.5)	$ 60.1

Income Taxes Reconciliation of Statutory Federal Income Tax Rate and Effective Tax Rate (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	4.20%	(1.50%)	(5.00%)
State rate change	0.00%	3.40%	0.00%
Penalties	(0.30%)	0.00%	0.40%
Return to provision adjustment	(0.30%)	(0.40%)	5.00%
Book impairment of goodwill	0.00%	0.00%	18.60%
Other	(0.10%)	(0.30%)	(0.40%)
Effective income tax rate	38.50%	36.20%	53.60%

Income Taxes Schedule of Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Components of Deferred Tax Assets and Liabilities [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	$ 1,531.0	$ 1,402.9
Deferred Tax Liabilities, Derivatives	60.4	127.7
Deferred Tax Liabilities, Net	1,591.4	1,530.6
Deferred Tax Assets Net Operating Loss And Tax Credit Carryforwards	51.9	11.7
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits	43.6	43.0
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Bonuses	7.0	16.3
Deferred Tax Assets, Other	9.1	12.4
Deferred Tax Assets, Gross	111.6	83.4
Deferred Tax Assets, Net of Valuation Allowance, Classification [Abstract]
Deferred Tax Assets, Net of Valuation Allowance, Current	0.0	0.0
Deferred income taxes	0.0	84.5
Deferred Tax Liabilities, Net, Noncurrent	1,479.8	1,362.7
Deferred Tax Liabilities, Net	$ 1,479.8	$ 1,447.2

Income Taxes Amounts and Expiration Dates of Net Operating Loss and Tax Credit Carryforwards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015
Deferred Tax Assets, Tax Credit Carryforwards [Abstract]
State net operating loss and tax credit carryforwards		$ 40.5
U.S. alternative minimum tax credit		0.0
Total tax credit carryforwards		20.2
State net operating loss valuation allowance		$ (20.3)
Operating Loss Carryforwards Minimum Expiration Date	2015
Operating Loss Carryforwards Maximum Expiration Date	2033

Income Taxes Narrative (Details) $ in Millions	12 Months Ended
Income Taxes Narrative (Details) $ in Millions	Dec. 31, 2015 USD ($)
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	$ 15.6
Interest Related to Uncertain Tax Positions	0.5
Penalties Related to Uncertain Tax Positions	$ 2.2

Operations by Line of Business (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total Revenues	$ 468.3	$ 507.6	$ 574.6	$ 468.1	$ 757.1	$ 858.5	$ 850.0	$ 827.6	$ 2,018.6	$ 3,293.2	$ 2,685.1
OPERATING EXPENSES
Purchased gas, oil and NGL expense									(626.8)	(910.1)	(783.5)
Lease operating expense									238.8	240.1	181.3
Natural gas, oil and NGL transportation and other handling costs									291.3	277.6	222.0
Gathering and other expense									5.8	6.7	8.4
General and administrative									181.1	204.4	160.4
Production and property taxes									117.6	205.2	161.3
Depreciation, depletion and amortization									881.1	994.7	963.8
Other Expenses									58.3	1,153.1	104.9
Operating Expenses									2,400.8	3,991.9	2,585.6
Net gain (loss) from asset sales									4.6	(148.6)	103.5
OPERATING INCOME (LOSS)	(144.6)	(87.7)	(16.7)	(128.6)	(1,067.3)	115.1	(35.9)	140.8	(377.6)	(847.3)	203.0
Realized and unrealized gains (losses) on derivative contracts									277.2	363.3	58.9
Gain (Loss) on Derivative Instruments, Net, Pretax									277.2	363.3	58.9
Interest and other income									3.0	12.8	15.2
Income from unconsolidated affiliates									0.0	0.3	0.2
Loss from early extinguishment of debt									0.0	(2.0)	0.0
Interest expense									(145.6)	(169.1)	(165.1)
Income (loss) from continuing operations before income taxes									(243.0)	(642.0)	112.2
Income tax (provision) benefit									93.6	232.5	(60.1)
NET INCOME FROM CONTINUING OPERATIONS					(469.8)	153.7	(106.1)	12.7	(149.4)	(409.5)	52.1
Net income from discontinued operations, net of income tax					1,135.7	17.4	13.8	27.0	0.0	1,193.9	107.3
NET INCOME (LOSS)	(38.6)	21.1	(76.3)	(55.6)	665.9	171.1	(92.3)	39.7	(149.4)	784.4	159.4
Assets	8,425.5				9,286.8				8,425.5	9,286.8	9,408.9
Cash capital expenditures									1,239.4	2,726.4	1,602.6
Accrued capital expenditures									1,110.2	2,734.8	1,577.4
Unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues									2,018.6	3,293.2	2,685.1
Affiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues									0.0	0.0	0.0
QEP Energy [Member]
Segment Reporting Information [Line Items]
Total Revenues									1,477.2	2,524.6	2,092.8
OPERATING EXPENSES
Purchased gas, oil and NGL expense									(87.3)	(150.0)	(197.1)
Lease operating expense									238.8	240.1	181.3
Natural gas, oil and NGL transportation and other handling costs									300.2	291.5	242.2
Gathering and other expense									0.0	0.0	0.0
General and administrative									176.8	201.3	160.6
Production and property taxes									115.1	204.0	159.8
Depreciation, depletion and amortization									870.8	984.4	954.2
Other Expenses									58.3	1,153.1	104.9
Operating Expenses									1,847.3	3,224.4	2,000.1
Net gain (loss) from asset sales									9.7	(148.6)	104.1
OPERATING INCOME (LOSS)									(360.4)	(848.4)	196.8
Gain (Loss) on Derivative Instruments, Net, Pretax									274.2	367.2	59.1
Interest and other income									1.9	11.8	3.6
Income from unconsolidated affiliates										0.3	0.2
Loss from early extinguishment of debt										0.0
Interest expense									(204.5)	(210.3)	(192.6)
Income (loss) from continuing operations before income taxes									(288.8)	(679.4)	67.1
Income tax (provision) benefit									105.9	246.9	(41.5)
NET INCOME FROM CONTINUING OPERATIONS									(182.9)	(432.5)	25.6
Net income from discontinued operations, net of income tax										0.0	0.0
NET INCOME (LOSS)										(432.5)	25.6
Assets	7,799.5				8,001.1				7,799.5	8,001.1	7,937.0
Cash capital expenditures									1,233.3	2,660.3	1,488.6
Accrued capital expenditures									1,105.7	2,670.5	1,467.2
QEP Energy [Member] \| Unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues									1,477.2	2,524.6	2,092.8
QEP Energy [Member] \| Affiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues									0.0	0.0	0.0
QEP Marketing and Other [Member]
Segment Reporting Information [Line Items]
Total Revenues									1,601.3	2,382.3	1,601.2
OPERATING EXPENSES
Purchased gas, oil and NGL expense									(1,588.1)	(2,356.6)	(1,570.5)
Lease operating expense									0.0	0.0	0.0
Natural gas, oil and NGL transportation and other handling costs									0.0	0.0	0.0
Gathering and other expense									5.8	6.8	8.4
General and administrative									6.7	6.3	4.4
Production and property taxes									2.5	1.2	1.5
Depreciation, depletion and amortization									10.3	10.3	9.6
Other Expenses									0.0	0.0	0.0
Operating Expenses									1,613.4	2,381.2	1,594.4
Net gain (loss) from asset sales									(5.1)	0.0	(0.6)
OPERATING INCOME (LOSS)									(17.2)	1.1	6.2
Gain (Loss) on Derivative Instruments, Net, Pretax									3.0	(3.9)	0.2
Interest and other income									205.7	209.7	206.9
Income from unconsolidated affiliates										0.0	0.0
Loss from early extinguishment of debt										(2.0)
Interest expense									(145.7)	(167.5)	(167.8)
Income (loss) from continuing operations before income taxes									45.8	37.4	45.1
Income tax (provision) benefit									(12.3)	(14.4)	(18.6)
NET INCOME FROM CONTINUING OPERATIONS									33.5	23.0	26.5
Net income from discontinued operations, net of income tax										0.0	0.0
NET INCOME (LOSS)										23.0	26.5
Assets	626.0				1,285.7				626.0	1,285.7	182.2
Cash capital expenditures									6.1	10.9	25.1
Accrued capital expenditures									4.5	13.6	24.6
QEP Marketing and Other [Member] \| Unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues									654.5	889.7	592.3
QEP Marketing and Other [Member] \| Affiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues									946.8	1,492.6	1,008.9
Elimination [Member]
Segment Reporting Information [Line Items]
Total Revenues									(1,059.9)	(1,613.7)	(1,008.9)
OPERATING EXPENSES
Purchased gas, oil and NGL expense									1,048.6	1,596.5	984.1
Lease operating expense									0.0	0.0	0.0
Natural gas, oil and NGL transportation and other handling costs									(8.9)	(13.9)	(20.2)
Gathering and other expense									0.0	(0.1)	0.0
General and administrative									(2.4)	(3.2)	(4.6)
Production and property taxes									0.0	0.0	0.0
Depreciation, depletion and amortization									0.0	0.0	0.0
Other Expenses									0.0	0.0	0.0
Operating Expenses									(1,059.9)	(1,613.7)	(1,008.9)
Net gain (loss) from asset sales									0.0	0.0	0.0
OPERATING INCOME (LOSS)									0.0	0.0	0.0
Gain (Loss) on Derivative Instruments, Net, Pretax									0.0	0.0	0.0
Interest and other income									(204.6)	(208.7)	(195.3)
Income from unconsolidated affiliates										0.0	0.0
Loss from early extinguishment of debt										0.0
Interest expense									204.6	208.7	195.3
Income (loss) from continuing operations before income taxes									0.0	0.0	0.0
Income tax (provision) benefit									0.0	0.0	0.0
NET INCOME FROM CONTINUING OPERATIONS									0.0	0.0	0.0
Net income from discontinued operations, net of income tax										0.0	0.0
NET INCOME (LOSS)										0.0	0.0
Assets	$ 0.0				0.0				0.0	0.0	0.0
Cash capital expenditures									0.0	0.0	0.0
Accrued capital expenditures									0.0	0.0	0.0
Elimination [Member] \| Unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues									(113.1)	(121.1)	0.0
Elimination [Member] \| Affiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues									$ (946.8)	(1,492.6)	(1,008.9)
Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Total Revenues										0.0	0.0
OPERATING EXPENSES
Purchased gas, oil and NGL expense										0.0	0.0
Lease operating expense										0.0	0.0
Natural gas, oil and NGL transportation and other handling costs										0.0	0.0
Gathering and other expense										0.0	0.0
General and administrative										0.0	0.0
Production and property taxes										0.0	0.0
Depreciation, depletion and amortization										0.0	0.0
Other Expenses										0.0	0.0
Operating Expenses										0.0	0.0
Net gain (loss) from asset sales										0.0	0.0
OPERATING INCOME (LOSS)										0.0	0.0
Gain (Loss) on Derivative Instruments, Net, Pretax										0.0	0.0
Interest and other income										0.0	0.0
Income from unconsolidated affiliates										0.0	0.0
Loss from early extinguishment of debt										0.0
Interest expense										0.0	0.0
Income (loss) from continuing operations before income taxes										$ 0.0	0.0
Income tax (provision) benefit											0.0
NET INCOME FROM CONTINUING OPERATIONS										$ 0.0	0.0
Net income from discontinued operations, net of income tax										1,193.9	107.3
NET INCOME (LOSS)										1,193.9	107.3
Assets					0.0					0.0	1,289.7
Cash capital expenditures										55.2	88.9
Accrued capital expenditures										50.7	$ 85.6
Eliminations as Reported [Member]
OPERATING EXPENSES
Purchased gas, oil and NGL expense										(1,475.4)
Eliminations as Reported [Member] \| Affiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues										0.0
Eliminations as Revised [Member]
OPERATING EXPENSES
Purchased gas, oil and NGL expense										(1,596.5)
Eliminations as Revised [Member] \| Unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Total Revenues										(121.1)
Eliminations as Revised [Member] \| Change [Member]
Segment Reporting Information [Line Items]
Total Revenues										(121.1)
Change [Member]
Segment Reporting Information [Line Items]
Total Revenues		$ 29.1	$ 34.0	$ 23.5	$ 42.5	$ 51.5	$ 37.2	$ (10.1)
OPERATING EXPENSES
Purchased gas, oil and NGL expense										(121.1)
Operating Expenses										$ 121.1

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Effect of Fourth Quarter Events [Line Items]
Revenues	$ (468.3)	$ (507.6)	$ (574.6)	$ (468.1)	$ (757.1)	$ (858.5)	$ (850.0)	$ (827.6)	$ (2,018.6)	$ (3,293.2)	$ (2,685.1)
OPERATING INCOME (LOSS)	(144.6)	(87.7)	(16.7)	(128.6)	(1,067.3)	115.1	(35.9)	140.8	(377.6)	(847.3)	203.0
Income (loss) from continuing operations					(469.8)	153.7	(106.1)	12.7	(149.4)	(409.5)	52.1
Net income from discontinued operations, net of income tax					1,135.7	17.4	13.8	27.0	0.0	1,193.9	107.3
Net income (loss)	(38.6)	21.1	(76.3)	(55.6)	665.9	171.1	(92.3)	39.7	(149.4)	784.4	$ 159.4
Non-recurring income(loss)	$ (22.4)	$ (2.1)	$ 24.0	$ (50.5)	$ (1,077.8)	$ (11.9)	$ (202.5)	$ 0.4	$ (51.0)	$ (1,291.8)
Basic total									$ (0.85)	$ 4.36	$ 0.89
Diluted total									(0.85)	4.36	0.89
Continuing Operations [Member]
Effect of Fourth Quarter Events [Line Items]
Basic total	$ (0.22)	$ 0.12	$ (0.43)	$ (0.32)	$ (2.62)	$ 0.85	$ (0.59)	$ 0.07	(0.85)	(2.28)	0.29
Diluted total	$ (0.22)	$ 0.12	$ (0.43)	$ (0.32)	(2.62)	0.84	(0.59)	0.07	(0.85)	(2.28)	0.29
Discontinued Operations [Member]
Effect of Fourth Quarter Events [Line Items]
Basic total					6.34	0.10	0.08	0.15	0.00	6.64	0.60
Diluted total					$ 6.34	$ 0.10	$ 0.08	$ 0.15	$ 0.00	$ 6.64	$ 0.60
Revenues as reported [Member]
Effect of Fourth Quarter Events [Line Items]
Revenues		$ (536.7)	$ (608.6)	$ (491.6)	$ (799.6)	$ (910.0)	$ (887.2)	$ (817.5)
Revenues as Adjusted [Member]
Effect of Fourth Quarter Events [Line Items]
Revenues		(507.6)	(574.6)	(468.1)	(757.1)	(858.5)	(850.0)	(827.6)
Change [Member]
Effect of Fourth Quarter Events [Line Items]
Revenues		$ (29.1)	$ (34.0)	$ (23.5)	$ (42.5)	$ (51.5)	$ (37.2)	$ 10.1

Supplemental Gas and Oil Information (Unaudited) Capitalized costs (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
Proved properties	$ 13,314.9	$ 12,278.7
Unproved properties, net	691.0	825.2
Total proved and unproved properties	14,005.9	13,103.9
Accumulated depreciation, depletion and amortization	(6,870.2)	(6,153.0)
Net capitalized costs	$ 7,135.7	$ 6,950.9

Supplemental Gas and Oil Information (Unaudited) Costs incurred (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract]
Accrued capital costs included in development costs	$ 127.6
Costs Incurred, Asset Retirement Obligation Incurred	21.0
Costs Incurred To Advance The Development Of Proved Undeveloped Reserves	811.3	$ 796.7	$ 645.9
Unproved	39.8	496.3	9.3
Proved	49.6	465.4	31.6
Exploration	8.7	23.6	14.6
Development	1,010.3	1,695.1	1,440.8
Total costs incurred	$ 1,108.4	$ 2,680.4	$ 1,496.3

Supplemental Gas and Oil Information (Unaudited) Results of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Results of Operations, Income before Income Taxes [Abstract]
Revenues	$ 1,390.4	$ 2,374.6	$ 1,901.2
Production costs	654.1	735.6	583.3
Exploration expenses	2.7	9.9	11.9
Depreciation, depletion and amortization	870.8	984.4	954.2
Abandonment and impairment	55.6	1,143.2	93.0
Total expenses	1,583.2	2,873.1	1,642.4
Income before income taxes	(192.8)	(498.5)	258.8
Income taxes	70.6	182.5	(96.3)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$ (122.2)	$ (316.0)	$ 162.5

Supplemental Gas and Oil Information (Unaudited) Estimated Quantities of Proved Gas and Oil Reserves (Details)
MMcf in Millions, MMBbls in Millions

12 Months Ended

Dec. 31, 2015

MMcf

MMBbls

Dec. 31, 2014

MMcf

MMBbls

Dec. 31, 2013

MMcf

MMBbls

Dec. 31, 2012

MMcf

MMBbls

Proved reserves balance, beginning balance | MMBbls

Proved reserves balance, ending balance | MMBbls

Natural Gas [Member]

Proved reserves balance, beginning balance

(Bcf)

2,317.2

2,554.9

2,622.4

(463.8)

^[1]

27.1

^[2]

(288.3)

^[3]

Purchase of reserves in place

467.7

^[4]

141.4

^[5]

455.6

^[6]

3.2

^[7]

72.5

^[8]

1.0

Sale of reserves in place

(34.3)

^[9]

(299.4)

^[10]

(16.9)

Production

(181.1)

(179.3)

(218.9)

Proved reserves balance, ending balance

2,108.9

2,317.2

2,554.9

2,622.4

Proved developed reserves, beginning balance

1,288.4

1,406.3

1,531.7

Proved developed reserves, ending balance

1,245.3

1,288.4

1,406.3

1,531.7

Proved undeveloped reserves, beginning balance

1,028.8

1,148.6

1,090.7

Proved undeveloped reserve, ending balance

863.6

1,028.8

1,148.6

1,090.7

Oil [Member]

Proved reserves balance, beginning balance | MMBbls

(MMbbl)

172.5

148.6

119.0

(47.0)

^[1]

(4.0)

^[2]

1.3

^[3]

Purchase of reserves in place | MMBbls

85.6

^[4]

16.8

^[5]

38.3

^[6]

2.0

^[7]

35.7

^[8]

1.9

Sale of reserves in place | MMBbls

(0.4)

^[9]

(7.5)

^[10]

(1.7)

Production | MMBbls

(19.6)

(17.1)

(10.2)

Proved reserves balance, ending balance | MMBbls

193.1

172.5

148.6

119.0

Proved developed reserves, beginning balance | MMBbls

99.3

71.8

47.4

Proved developed reserves, ending balance | MMBbls

109.7

99.3

71.8

47.4

Proved undeveloped reserves, beginning balance | MMBbls

73.2

76.8

71.6

Proved undeveloped reserve, ending balance | MMBbls

83.4

73.2

76.8

71.6

Natural Gas Liquids [Member]

Proved reserves balance, beginning balance | MMBbls

(MMbbl)

96.6

102.6

99.9

(55.3)

^[1]

1.4

^[2]

(8.0)

^[3]

Purchase of reserves in place | MMBbls

21.8

^[4]

8.6

^[5]

16.4

^[6]

0.6

^[7]

12.3

^[8]

0.2

Sale of reserves in place | MMBbls

(0.2)

^[9]

(21.5)

^[10]

(1.1)

Production | MMBbls

(4.7)

(6.8)

(4.8)

Proved reserves balance, ending balance | MMBbls

58.8

96.6

102.6

99.9

Proved developed reserves, beginning balance | MMBbls

52.2

52.8

49.3

Proved developed reserves, ending balance | MMBbls

34.4

52.2

52.8

49.3

Proved undeveloped reserves, beginning balance | MMBbls

44.4

49.8

50.6

Proved undeveloped reserve, ending balance | MMBbls

24.4

44.4

49.8

50.6

Total Reserves Natural Gas Equivalent [Member]

Proved reserves balance, beginning balance

(Bcfe)

3,931.9

4,061.9

3,936.1

(1,077.9)

^[1]

11.3

^[2]

(328.5)

^[3]

Purchase of reserves in place

1,111.9

^[4],[6]

294.1

^[5]

783.8

^[6]

18.7

^[7]

360.7

^[8]

13.4

Sale of reserves in place

(37.6)

^[9]

(473.4)

^[10]

(33.9)

Production

(326.8)

(322.7)

(309.0)

Proved reserves balance, ending balance

3,620.2

3,931.9

4,061.9

3,936.1

Proved developed reserves, beginning balance

2,197.5

2,154.0

2,111.9

Proved developed reserves, ending balance

2,109.4

2,197.5

2,154.0

2,111.9

Proved undeveloped reserves, beginning balance

1,734.4

1,824.2

Proved undeveloped reserve, ending balance

1,510.8

1,734.4

1,824.2

Proved Undeveloped Reserves [Member]

Pricing Revisions [Member]

^[6]

0.0

Pricing Revisions [Member] | Natural Gas [Member]

^[3]

756.9

22.9

80.0

Performance Revisions [Member]

21.9

68.4

Operating Cost Revisions [Member]

^[3]

82.2

248.5

265.5

^[3]

39.2

42.0

Other Revisions [Member]

^[3]

403.2

197.7

101.0

Williston Basin [Member]

Williston Basin [Member] | Total Reserves Natural Gas Equivalent [Member]

^[6]

217.6

409.3

^[6]

123.3

^[8]

Pinedale [Member]

Pinedale [Member] | Total Reserves Natural Gas Equivalent [Member]

^[6]

265.3

Pinedale [Member] | Performance Revisions [Member]

^[8]

133.6

^[3]

194.0

129.5

Haynesville [Member]

Haynesville [Member] | Performance Revisions [Member]

^[6]

175.9

Uinta Basin [Member] | Total Reserves Natural Gas Equivalent [Member]

^[3]

112.7

Permian Basin [Member] | Total Reserves Natural Gas Equivalent [Member]

^[6]

318.9