Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Entity Registrant Name	QEP RESOURCES, INC.
Entity Central Index Key	0001108827
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		239,566,263
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Entity Public Float			$ 4,224,248,350

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES
Oil sales	$ 769.1	$ 834.2	$ 1,368.5
Gas sales	417.1	468.5	776.4
NGL sales	83.5	80.0	223.3
Other revenues	6.2	15.1	11.1
Purchased oil, gas and NGL sales	101.2	620.8	913.9
Total Revenues	1,377.1	2,018.6	3,293.2
OPERATING EXPENSES
Purchased oil, gas and NGL expense	105.5	626.8	910.1
Lease operating expense	224.7	238.8	240.1
Oil, gas and NGL transportation and other handling costs	289.2	291.3	277.6
Gathering and other expense	5.0	5.8	6.7
General and administrative	198.4	181.1	204.4
Production and property taxes	94.8	117.6	205.2
Depreciation, depletion and amortization	871.1	881.1	994.7
Exploration expenses	1.7	2.7	9.9
Impairment	1,194.3	55.6	1,143.2
Total Operating Expenses	2,984.7	2,400.8	3,991.9
Net gain (loss) from asset sales	5.0	4.6	(148.6)
OPERATING INCOME (LOSS)	(1,602.6)	(377.6)	(847.3)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(233.0)	277.2	363.3
Interest and other income	25.6	3.0	12.8
Income from unconsolidated affiliates	0.0	0.0	0.3
Loss from early extinguishment of debt	0.0	0.0	(2.0)
Interest expense	(143.2)	(145.6)	(169.1)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(1,953.2)	(243.0)	(642.0)
Income tax (provision) benefit	708.2	93.6	232.5
NET INCOME FROM CONTINUING OPERATIONS	(1,245.0)	(149.4)	(409.5)
Net income from discontinued operations, net of income tax	0.0	0.0	1,193.9
NET INCOME (LOSS)	$ (1,245.0)	$ (149.4)	$ 784.4
Earnings (Loss) Per Common Share
Basic total	$ (5.62)	$ (0.85)	$ 4.36
Diluted total	$ (5.62)	$ (0.85)	$ 4.36
Weighted-average common shares outstanding
Used in basic calculation	221.7	176.6	179.8
Used in diluted calculation	221.7	176.6	179.8
Dividends per common share	$ 0.00	$ 0.08	$ 0.08
Continuing Operations [Member]
Earnings (Loss) Per Common Share
Basic total	(5.62)	(0.85)	(2.28)
Diluted total	(5.62)	(0.85)	(2.28)
Discontinued Operations [Member]
Earnings (Loss) Per Common Share
Basic total	0.00	0.00	6.64
Diluted total	$ 0.00	$ 0.00	$ 6.64

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Statement of Comprehensive Income [Abstract]

Net income (loss)

$ (1,245.0)

$ (149.4)

$ 784.4

Pension and other postretirement plans adjustments:

Current year prior service cost

^[1]

0.0

(0.6)

0.0

Current year net actuarial gain (loss)

^[2]

(5.6)

(0.5)

(13.6)

Amortization of net prior service cost

^[3]

0.8

8.2

9.7

Amortization of net actuarial loss

^[4]

0.5

0.3

0.5

Net curtailment and settlements cost incurred

^[5]

0.0

4.5

5.6

Other comprehensive income

(4.3)

11.9

2.2

Comprehensive income (loss)

$ (1,249.3)

$ (137.5)

$ 786.6

[1]	Presented net of income tax benefit of $0.3 million for the year ended December 31, 2015.
[2]	Presented net of income tax benefit of $3.3 million, $0.3 million and $8.5 million for the years ended December 31, 2016, 2015 and 2014, respectively
[3]	Presented net of income tax expense of $0.5 million, $4.9 million, and $6.0 million during the years ended December 31, 2016, 2015, and 2014, respectively.
[4]	Presented net of income tax expense of $0.3 million, $0.2 million, and $0.3 million during the years ended December 31, 2016, 2015, and 2014, respectively.
[5]	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, 2016

Dec. 31, 2015

Dec. 31, 2014

Pension and other postretirement plans adjustments:

Net Prior Service Cost, Tax

$ 0.0

$ 0.3

$ 0.0

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

^[1]

3.3

0.3

8.5

Tax expense on prior service cost incurred

(0.5)

(4.9)

(6.0)

Amortization of Net Actuarial Gain (Loss), Tax

^[2]

(0.3)

(0.2)

(0.3)

Net Curtailment And Settlements, Tax

$ 0.0

$ (2.6)

$ (3.5)

[1]	Presented net of income tax benefit of $3.3 million, $0.3 million and $8.5 million for the years ended December 31, 2016, 2015 and 2014, respectively
[2]	Presented net of income tax expense of $0.5 million, $4.9 million, and $6.0 million during the years ended December 31, 2016, 2015, and 2014, respectively.

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 443.8	$ 376.1
Accounts receivable, net	155.7	278.2
Income tax receivable	18.6	87.3
Fair value of derivative contracts	0.0	146.8
Oil, gas and NGL inventories, at lower of average cost or market	10.4	13.3
Prepaid expenses and other	11.6	30.1
Total Current Assets	640.1	931.8
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	14,232.5	13,314.9
Unproved properties	871.5	691.0
Marketing and other	301.8	297.9
Materials and supplies	32.7	38.5
Total Property, Plant and Equipment	15,438.5	14,342.3
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	8,797.7	6,870.2
Marketing and other	101.8	87.5
Total Accumulated Depreciation, Depletion and Amortization	8,899.5	6,957.7
Net Property, Plant and Equipment	6,539.0	7,384.6
Fair value of derivative contracts	0.0	23.2
Other noncurrent assets	66.3	58.6
TOTAL ASSETS	7,245.4	8,398.2
Current Liabilities
Checks outstanding in excess of cash balances	12.3	29.8
Accounts payable and accrued expenses	269.7	351.7
Production and property taxes	30.1	46.1
Interest payable	32.9	36.4
Fair value of derivative contracts	169.8	0.8
Current portion of long-term debt	0.0	176.8
Total Current Liabilities	514.8	641.6
Long-term debt	2,020.9	2,014.7
Deferred income taxes	825.9	1,479.8
Asset retirement obligations	225.8	204.9
Fair value of derivative contracts	32.0	4.0
Other long-term liabilities	123.3	105.3
Commitments and Contingencies (Note 10)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 240.7 million and 177.3 million shares issued, respectively	2.4	1.8
Treasury stock – 1.1 million and 0.5 million shares, respectively	(22.9)	(14.6)
Additional paid-in capital	1,366.6	554.8
Retained earnings	2,173.3	3,418.3
Accumulated other comprehensive (loss) income	(16.7)	(12.4)
Total Common Shareholders' Equity	3,502.7	3,947.9
TOTAL LIABILITIES AND EQUITY	$ 7,245.4	$ 8,398.2

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares shares in Millions	Dec. 31, 2016	Dec. 31, 2015
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)	240.7	177.3
Treasury stock (in shares)	1.1	0.5

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Millions, $ in Millions	Total	Common Stock, Value [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]	Stockholders' Equity, Total [Member]
Balance at Dec. 31, 2013		$ 1.8	$ (14.9)	$ 498.4	$ 2,917.8	$ (26.5)	$ 500.2	$ 3,876.8
Shares at Dec. 31, 2013		179.7
Treasury shares at Dec. 31, 2013			(0.4)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ (784.4)	$ 0.0	$ 0.0	0.0	784.4	0.0	0.0	784.4
Stockholders' Equity, Other Shares		0.0	0.0
Dividends		0.0	0.0
Dividends		$ 0.0	$ 0.0	0.0	(14.6)	0.0	0.0	(14.6)
Share-based compensation		$ 0.0	$ (10.5)	36.9	0.0	0.0	0.2	26.6
Share-based compensation, shares		1.2	(0.4)
Distribution of noncontrolling interest		$ 0.0	$ 0.0	0.0	0.0	0.0	(31.9)	(31.9)
Distribution of noncontrolling interest, shares		0.0	0.0
Common stock repurchased and retired		$ 0.0	$ 0.0	0.0	(99.7)	0.0	0.0	(99.7)
Common stock repurchased and retired, shares		(4.7)	0.0
Noncontrolling interest decrease from sale of substantially all of QEP's midstream business		$ 0.0	$ 0.0	0.0	0.0	0.0	(468.5)	(468.5)
Noncontrolling interest decrease from sale of substantially all of QEP's midstream business, shares		0.0	0.0
Change in pension and postretirement liability, net of tax, shares		0.0	0.0
Change in pension and postretirement liability, net of tax		$ 0.0	$ 0.0	0.0	0.0	2.2	0.0	2.2
Shares at Dec. 31, 2014		176.2
Treasury shares at Dec. 31, 2014			(0.8)
Balance at Dec. 31, 2014		$ 1.8	$ (25.4)	535.3	3,587.9	(24.3)	0.0	4,075.3
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 149.4	$ 0.0	$ 0.0	0.0	(149.4)	0.0	0.0	(149.4)
Stockholders' Equity, Other Shares		0.0	0.0
Dividends			0.0
Dividends		$ 0.0	$ 0.0	0.0	(14.1)	0.0	0.0	(14.1)
Share-based compensation		$ 0.0	$ 10.8	19.5	(6.1)	0.0	0.0	24.2
Share-based compensation, shares		1.1	0.3
Change in pension and postretirement liability, net of tax, shares		0.0	0.0
Change in pension and postretirement liability, net of tax		$ 0.0	$ 0.0	0.0	0.0	11.9	0.0	11.9
Shares at Dec. 31, 2015		177.3
Treasury shares at Dec. 31, 2015	(0.5)		(0.5)
Balance at Dec. 31, 2015	$ 3,947.9	$ 1.8	$ (14.6)	554.8	3,418.3	(12.4)	0.0	3,947.9
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 1,245.0	$ 0.0	$ 0.0	0.0	(1,245.0)	0.0	0.0	(1,245.0)
Stockholders' Equity, Other Shares		0.0	0.0
Dividends		0.0
Stock Issued During Period, Shares, New Issues		61.0	0.0
Stock Issued During Period, Value, New Issues		$ 0.6	$ 0.0	780.8	0.0	0.0	0.0	781.4
Share-based compensation		$ 0.0	$ (8.3)	31.0	0.0	0.0	0.0	22.7
Share-based compensation, shares		2.4	0.6
Change in pension and postretirement liability, net of tax, shares		0.0	0.0
Change in pension and postretirement liability, net of tax		$ 0.0	$ 0.0	0.0	0.0	(4.3)	0.0	(4.3)
Shares at Dec. 31, 2016		240.7
Treasury shares at Dec. 31, 2016	(1.1)		(1.1)
Balance at Dec. 31, 2016		$ 2.4	$ (22.9)	$ 1,366.6	$ 2,173.3	$ (16.7)	$ 0.0	$ 3,502.7

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES
Net income (loss)	$ (1,245.0)	$ (149.4)	$ 784.4
Net income attributable to noncontrolling interest	0.0	0.0	21.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	871.1	881.1	1,040.6
Deferred income taxes	(651.3)	25.3	(84.1)
Impairment	1,194.3	55.6	1,143.2
Bargain purchase gain from acquisition	(22.6)	0.0	0.0
Share-based compensation	35.6	34.7	27.9
Pension curtailment loss	0.0	11.2	0.0
Amortization of debt issuance costs and discounts	6.4	6.2	6.7
Net gain from asset sales	(5.0)	(4.6)	(1,644.8)
Income from unconsolidated affiliates	0.0	0.0	(5.2)
Distributions from unconsolidated affiliates and other	0.0	0.0	9.4
Non-cash loss on early extinguishment of debt	0.0	0.0	4.4
Unrealized (gains) losses on marketable securities	(1.4)	0.2	0.0
Unrealized gains (losses) on derivative contracts	367.0	183.7	(374.4)
Accounts receivable	96.5	165.5	(160.5)
Inventories	8.7	15.5	(20.2)
Prepaid expenses	18.5	16.7	(7.3)
Accounts payable and accrued expenses	(51.5)	(71.3)	320.1
Federal income taxes	68.7	(619.4)	494.1
Other	(26.3)	(69.7)	(13.4)
Net Cash Provided by (Used in) Operating Activities	663.7	481.3	1,542.5
INVESTING ACTIVITIES
Property acquisitions	(639.0)	(98.3)	(960.5)
Property, plant and equipment, including dry exploratory well expense	(569.1)	(1,141.1)	(1,765.9)
Proceeds from disposition of assets	29.0	21.8	3,296.6
Acquisition deposit held in escrow	0.0	0.0	50.0
Other investing activities	0.0	0.0	(42.0)
Net Cash Provided by (Used in) Investing Activities	(1,179.1)	(1,217.6)	578.2
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(17.5)	(24.9)	(54.4)
Long-term debt issued	0.0	0.0	300.0
Long-term debt issuance costs paid	0.0	(2.6)	(9.3)
Long-term debt repaid	(176.8)	0.0	(600.0)
Proceeds from credit facility	0.0	0.0	5,455.0
Repayments of credit facility	0.0	0.0	(5,935.0)
Common stock repurchased and retired	0.0	0.0	(99.7)
Treasury stock repurchases	(4.1)	(2.7)	(6.2)
Other capital contributions	0.0	(0.2)	6.0
Dividends paid	0.0	(14.1)	(14.6)
Proceeds from issuance of common stock, net	781.4	0.0	0.0
Excess tax (provision) benefit on share-based compensation	0.1	(3.2)	(0.5)
Distribution to noncontrolling interest	0.0	0.0	(31.9)
Net Cash Provided by (Used in) Financing Activities	583.1	(47.7)	(990.6)
Change in cash and cash equivalents	67.7	(784.0)	1,130.1
Beginning cash and cash equivalents	376.1	1,160.1	30.0
Ending cash and cash equivalents	$ 443.8	$ 376.1	$ 1,160.1

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Nature of Business

QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company focused in two regions of the United States: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) 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.

Changes in Segment Reporting due to Discontinued Operations and Termination of Marketing Agreements

In December 2014 , the Company sold substantially all of its midstream business, including the Company's 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). As a result of the Midstream Sale, the results of operations for the QEP Field Services Company (QEP Field Services) reporting segment, excluding the retained ownership of the Haynesville gathering system (Haynesville Gathering), were classified as discontinued operations on the Consolidated Statement of Operations and the Notes accompanying the Consolidated Financial Statements.

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP Energy is directly marketing its own oil, gas and NGL production. While QEP will continue to act as an agent for the sale of oil, gas and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to 2016.

In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements for historical periods to reflect the impact of the Midstream Sale and the termination of marketing agreements to show its financial results without segments.

Equity Offerings

In June 2016, QEP issued 23.0 million shares of common stock through a public offering and received net proceeds of approximately $412.9 million. In October 2016, QEP used the net proceeds from this offering to partially fund the 2016 Permian Basin Acquisition (see Note 2 – Acquisitions and Divestitures).

In March 2016, QEP issued 37.95 million shares of common stock through a public offering and received net proceeds of approximately $368.5 million. QEP used the net proceeds from this offering for general corporate purposes.

Reclassifications

Certain prior period balances on the Consolidated Balance Sheets have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's operating income, net income, earnings per share, cash flows or retained earnings previously reported.

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 oil, gas 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 oil, gas and NGL, which are affected by many factors outside of QEP's control, including changes in market supply and demand. Changes in market supply and demand are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. Field-level prices received for QEP's oil and gas production have historically been volatile and may 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. QEP generally funds its operations and capital expenditures with cash flow from its operating activities, cash on hand and, if needed, borrowings under its revolving credit facility. The Company expects to be able to fund its operations, planned capital expenditures and working capital requirements 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 its 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

QEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with the sale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized as oil, gas and NGL are 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 has sold volumes in excess of its share of remaining reserves in an underlying property.

QEP also purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. QEP recognizes revenue from these resale activities when title transfers to the customer.

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, 2016, QEP had unrestricted cash of $443.8 million and restricted cash of $21.6 million. As of December 31, 2015, QEP had unrestricted cash of $376.1 million and restricted cash of $18.1 million. QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin and is included in "Other noncurrent assets" and "Prepaid expenses and other" on the Consolidated Balance Sheet.

Supplemental cash flow information is shown in the table below:



	Year Ended December 31,
	2016			2015			2014
Supplemental Disclosures	(in millions)
Cash paid for interest, net of capitalized interest	$	139.1		$	139.4		$	163.2
Cash paid (refund received) for income taxes, net	$	(123.5	)	$	487.8		$	0.3
Non-cash investing activities
Change in capital expenditure accrual balance	$	(32.8	)	$	(129.2	)	$	8.4

Accounts Receivable

Accounts receivable 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, 2016, 2015 and 2014, was $1.8 million, $0.5 million, and $2.1 million, respectively, and is included in "General and administrative" expense on the Consolidated Statement of Operations. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad debt expenses was $4.8 million at December 31, 2016, and $3.9 million at December 31, 2015.

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 project 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, a reduction of oil, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, and declines in oil, gas and NGL prices. If impairment is indicated, fair value is estimated 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, 2016, QEP recorded impairment charges of $1,194.3 million, of which $1,172.7 million was related to proved properties due to lower future oil and gas prices, $17.9 million was related to expiring leaseholds on unproved properties and $3.7 million was related to the impairment of goodwill. Of the $1,172.7 million impairment of proved properties, $1,164.0 million related to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to Other Northern properties and $0.6 million related to QEP's remaining Other Southern properties.

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 of proved properties, $20.2 million related to QEP's remaining Other Southern properties, $18.4 million related to Other Northern properties and $0.7 million related to 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 of 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 Haynesville/Cotton Valley properties, $467.7 million related to Permian Basin properties, $18.7 million related to QEP's remaining Other Southern properties, $13.5 million related Other Northern properties, $5.8 million related to Williston Basin properties and $3.6 million related to Uinta Basin properties.

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 ARO liability 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 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 include estimated quantities of oil, gas 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, 2016, QEP recorded $3.7 million of goodwill, which related to an acquisition in the first quarter of 2016. During the performance of a goodwill impairment test performed during the first quarter of 2016, QEP failed the first step of the goodwill impairment test as described above, primarily due to lower future oil and gas prices. QEP performed the second step test described above, which resulted in a full write down of goodwill of $3.7 million.

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 future oil and gas 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.

Litigation and Other Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of business. In each reporting period, the Company 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. The amount of ultimate loss may differ from these estimates. 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. See Note 10 – Commitments and Contingencies for additional information.

QEP accrues material 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 Contracts

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 oil or gas 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 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. 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 "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statement of Operations in the month of settlement and are also marked-to-market monthly. See Note 7 – Derivative Contracts for additional information.

Credit Risk

Management believes that its credit review procedures, loss reserves, cash deposits and investments, and collection procedures have adequately provided for usual and customary credit-related losses. 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 commercial and industrial enterprises and financial institutions that may react differently to changing conditions.

The Company utilizes various processes to monitor and evaluate its credit risk exposure, which include closely monitoring current market conditions and counterparty credit fundamentals, including public credit ratings, where available. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals, and is aggregated across all lines of business, including derivatives, physical exposure and short-term cash investments. To further manage the level of credit risk, the Company requests credit support and, in some cases, requests parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. The Company also has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

The Company enters into International Swap Dealers Association Master Agreements (ISDA Agreements) with each of its derivative counterparties prior to executing derivative contracts. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or counterparty to a derivative contract. The Company routinely monitors and manages its exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings.

The Company's five largest customers accounted for 48%, 30%, and 33% of QEP's revenues for the years ended December 31, 2016, 2015 and 2014, respectively. During the year ended December 31, 2016, Shell Trading Company, BP Energy Company and Valero Marketing & Supply Company accounted for 14%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2015, no customer accounted for 10% or more of QEP's total revenues. During the year ended December 31, 2014, Valero Marketing & Supply Company accounted for 10% of QEP'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, 2016, the Company had a valuation allowance of $20.6 million against the state net operating 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 2016 have been examined by the Internal Revenue Service and are closed. Income tax returns for 2016 have not yet been filed. Most state tax returns for 2013 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, 2016 and 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. During the year ended December 31, 2016, the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions. During the year ended December 31, 2015, the Company incurred $0.5 million of estimated interest expense and $2.2 million of estimated penalties related to uncertain tax positions. During the year ended December 31, 2014, no uncertain tax positions were recorded.

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 stock 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. 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. This program expired on December 31, 2015.

Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income 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 share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to 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 years ended December 31, 2016 and 2014, there were 0.1 million and 0.3 million shares, respectively, not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss from continuing operations. For the year ended December 31, 2015, there were no anti-dilutive shares. A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:



	December 31,
	2016	2015	2014
	(in millions)
Weighted-average basic common shares outstanding	221.7	176.6	179.8
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—
Average diluted common shares outstanding	221.7	176.6	179.8

Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses an accelerated method in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. 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. QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. Restricted share award 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. Non-vested restricted share awards have voting and dividend rights; however, sale or transfer is restricted. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfunded deferred compensation plan at the time of vesting. Share-based compensation cost for restricted share units is equal to its fair value as of the end of the period and is classified as a liability. The Company also awards performance share units under its Cash Incentive Plan (CIP), which are generally paid out in cash depending upon the Company's total shareholder return compared to a group of its peers over a three-year period. Share-based compensation cost for the performance share units is equal to its fair value as of the end of the period and is classified as a liability. For additional information, see Note 11 – Share-Based Compensation for additional information.

Pension and Other Postretirement Benefits

QEP maintains closed, defined-benefit pension and other postretirement benefit plans, including both a qualified and a supplemental plan. QEP also provides certain health care and life insurance benefits for certain retired QEP employees. Determination of the benefit obligations for QEP's defined-benefit pension and other postretirement benefit plans impacts the recorded amounts for such obligations on the Consolidated Balance Sheets and the amount of benefit expense recorded to the Consolidated Statement of Operations.

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 benefit 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, which 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.

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 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 addition, new and enhanced disclosures will be required. The amendment is effective prospectively for reporting periods beginning on or after December 31, 2017 and early adoption is permitted for periods beginning on or after December 31, 2016. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company has not yet selected a transition method and is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Topic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This guidance provides additional information to guide management's evaluation of whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. The amendment was effective for annual periods ending after December 15, 2016. The adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclosing key quantitative and qualitative information about leasing arrangements. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company does not expect that the adoption of this new standard will have a material impact on the Company's Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-08, Revenue from contracts with customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations. The amendment will be effective prospectively for reporting periods beginning on or after December 31, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment was effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption was permitted. The adoption of this new standard will not have a material impact on the Company's Consolidated Financial Statements.

In April 2016, the FASB issued ASU No. 2016-10, Revenue from contracts with customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In May 2016, the FASB issued ASU No. 2016-11, Revenue recognition (Topic 605) and Derivatives and hedging (Topic 815): Rescission of SEC guidance because of ASU 2014-09 and 2014-16, which rescinds certain SEC staff observer comments that are codified in Topic 605, Revenue Recognition. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from contracts with customers (Topic 606): Narrow-scope improvements and practical expedients, which intends to reduce the cost and complexity of applying the new revenue standard by narrowing the scope of improvements to the guidance on collectability, non-cash consideration, and completed contracts at transition. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of certain cash receipts and cash payments, which intends to reduce the diversity in practice in how certain transactions are classified in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company does not expect that the adoption of this new standard will have a material impact on the Company's Consolidated Financial Statements.

In October 2016, the FASB issued ASU No. 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory, which intends to reduce the complexity in accounting standards related to intra-entity asset transfers by requiring a reporting entity to recognize the tax effects from the sale of assets when a transfer occurs, even though the pre-tax effects of the transaction are eliminated in consolidation. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently assessing the impact of the ASU, but at this time, does not expect that the adoption of this new standard will have a material impact on the Company's Consolidated Financial Statements.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted cash, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company does not expect that the adoption of this new standard will have a material impact on the Company's Consolidated Financial Statements.

In December 2016, the FASB issued ASU No. 2016-19, Technical Corrections and Improvements, which intends to make corrections or improvements to the FASB Accounting Standards Codification which includes guidance and reference clarification, simplification and minor improvements. This amendment is effective immediately. The adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements.

In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which intends to make corrections or improvements to the FASB Accounting Standards Codification which includes guidance and reference clarification, simplification and minor improvements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Acquisitions and divestitures [Text Block]

2016 Permian Basin Acquisition

In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $590.6 million, subject to customary purchase price adjustments (the 2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with proceeds from the June 2016 equity offering and cash on hand.

The 2016 Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it includes significant proved properties. QEP allocated the cost of the 2016 Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $3.8 million and a net loss of $0.7 million were generated from the acquired properties from October 19, 2016 to December 31, 2016, and are included in QEP's Consolidated Statements of Operations. During the year ended December 31, 2016, QEP incurred acquisition-related costs of $2.3 million, which are included in "General and administrative" expense on the Consolidated Statement of Operations. In conjunction with the 2016 Permian Basin Acquisition, the Company recorded an $18.2 million bargain purchase gain. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)". The acquisition resulted in a bargain purchase gain primarily as a result of an increase in future oil prices from the execution of the purchase and sale agreement to the closing date of the acquisition.

The Consolidated Balance Sheet as of December 31, 2016, includes the 2016 Permian Basin Acquisition. The following table presents a summary of the Company's purchase accounting entries (in millions):



Consideration:
Total consideration	$	590.6

Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	406.2
Unproved properties	214.2
Asset retirement obligations	(11.6		)
Bargain purchase gain	(18.2		)
Total fair value	$	590.6

The following unaudited, pro forma results of operations are provided for the years ended December 31, 2016 and 2015. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the periods presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the years ended December 31, 2016 and 2015, the acquired properties' historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the preliminary purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the 2016 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,
	2016						2015
	Actual			Pro forma			Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	1,377.1		$	1,392.5		$	2,018.6		$	2,041.5
Net income (loss)	$	(1,245.0	)	$	(1,246.8	)	$	(149.4	)	$	(152.5	)
Earnings (loss) per common share
Basic	$	(5.62	)	$	(5.62	)	$	(0.85	)	$	(0.86	)
Diluted	$	(5.62	)	$	(5.62	)	$	(0.85	)	$	(0.86	)

2014 Permian Basin Acquisition

In February 2014, QEP acquired oil and gas properties in the Permian Basin 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.

The 2014 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 2014 Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $186.0 million and a net loss of $13.2 million were generated from the acquired properties during the year ended December 31, 2016. 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 year ended December 31, 2014. Pro forma results are not provided for the years ended December 31, 2015 and 2016, because the 2014 Permian Basin Acquisition occurred during the first quarter of 2014, and therefore the 2014 Permian Basin Acquisition results are included in QEP's results for these periods. 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 year ended December 31, 2014, 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 have resulted from the 2014 Permian Basin Acquisition or any estimated costs that have been incurred by the Company to integrate the acquired properties.



	Year ended December 31,
	2014
	Actual		Pro Forma
	(in millions, except per share amounts)
Revenues	$	3,293.2	$	3,319.3
Net income (loss)	$	784.4	$	791.4
Earnings (loss) per common share
Basic	$	4.36	$	4.40
Diluted	$	4.36	$	4.40

Other Acquisitions

In addition to the 2016 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2016, primarily in the Permian and Williston basins, for an aggregate purchase price of $54.6 million, subject to customary purchase price adjustments, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $3.7 million of goodwill, which was subsequently impaired, and a $4.4 million bargain purchase gain. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)".

During the year ended December 31, 2015, QEP acquired various oil and gas properties, primarily in the Permian and Williston basins, for a total purchase price of $98.3 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $14.3 million of goodwill, which was subsequently impaired.

In addition to the 2014 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2014, primarily in the Other Northern area and the Uinta Basin, for a total purchase price of $18.7 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage.

Divestitures

During the year ended December 31, 2016, QEP sold its interest in certain non-core properties, primarily in the Other Southern area, for aggregate proceeds of $29.0 million and recorded a pre-tax gain on sale of $8.4 million.

During the year ended December 31, 2015, QEP sold its interest in certain non-core properties in the Other Southern area for aggregate proceeds of $31.7 million and recorded a pre-tax gain on sale of $21.0 million. For the year ended December 31, 2016, QEP recorded a pre-tax loss on sale of $0.9 million, due to post-closing purchase price adjustments from the sale of such properties.

During the year ended December 31, 2014, QEP sold its interest in certain non-core properties in the Other Southern area and Williston Basin for aggregate proceeds of $783.8 million and recorded a pre-tax loss on sale of $147.0 million. During the years ended December 31, 2016 and 2015, QEP recorded a pre-tax gain of sale of $0.6 million and a pre-tax loss on sale of $9.3 million, respectively, due to post-closing purchase price adjustments from the sale of such properties.

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, 2016

Discontinued Operations and Disposal Groups [Abstract]

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

In December 2014, the Company sold 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 results of operations of QEP Field Services Company (QEP Field Services), excluding Haynesville Gathering (the Discontinued Operations of QEP Field Services), were classified as discontinued operations on the Consolidated Statements of Operations and Notes accompanying the Consolidated Financial Statements for the year ended December 31, 2014. 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, 2016, 2015 and 2014, cash outflows for these transactions included in continuing operations were $137.9 million, $131.8 million and $145.3 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 was 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 Operation

The Discontinued Operations of QEP Field Services is summarized below:



	Year Ended December 31,
	2014
REVENUES	(in millions)
NGL sales	$	109.3
Other revenues	140.9
Purchased oil and gas sales⁽¹⁾	(47.1		)
Total Revenues	203.1
OPERATING EXPENSES
Purchased oil and gas expense⁽¹⁾	(48.5		)
Lease operating expense⁽¹⁾	(5.5		)
Oil, gas and NGL transport & other handling costs⁽¹⁾	(55.4		)
Gathering, processing, and other	85.9
General and administrative	42.1
Production and property taxes	7.3
Depreciation, depletion and amortization	45.9
Total Operating Expenses	71.8
Net gain (loss) from asset sales	1,793.4
OPERATING INCOME	1,924.7
Interest and other income	0.3
Income from unconsolidated affiliates	4.9
Loss on early extinguishment of debt	(2.4		)
Interest expense	(3.8		)
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES⁽²⁾	1,923.7
Income tax (provision) benefit	(708.2		)
NET INCOME FROM DISCONTINUED OPERATIONS	1,215.5
Net income attributable to noncontrolling interest	(21.6		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	1,193.9

___________________________


⁽¹⁾	Includes discontinued intercompany eliminations.


⁽²⁾	Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owned 57.8%) of $28.9 million for the year ended December 31, 2014.

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 for the year ended December 31, 2014. 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 for the year ended December 31, 2014.

- Definition

The entire disclosure related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=65878427&loc=SL51721533-107759

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
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-Section 50
-Paragraph 4B
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Paragraph 5C
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
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-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=64862545&loc=SL51724579-110230

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Paragraph 3
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Paragraph 1
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Section 50
-Paragraph 5B
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721659-107760

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5A
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721671-107760

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5D
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721677-107760

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=64827811&loc=d3e1474-107760

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721683-107760

+ Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

QEP records ARO 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 $231.6 million and $206.8 million ARO liability for the years ended December 31, 2016 and 2015, respectively, $5.8 million and $1.9 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
	2016			2015
	(in millions)
ARO liability at January 1,	$	206.8		$	195.1
Accretion	8.9			8.7
Additions⁽¹⁾	17.0			3.8
Revisions	6.5			17.2
Liabilities related to assets sold	—			(16.0		)
Liabilities settled	(7.6		)	(2.0		)
ARO liability at December 31,	$	231.6		$	206.8

___________________________


⁽¹⁾	Additions for the year ended December 31, 2016, include $11.6 million related to the 2016 Permian Basin Acquisition (see Note 2 – Acquisitions and Divestitures).

Fair Value Measurements

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015, 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, 2016
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	—	$	—	$	—		$	—
Fair value of derivative contracts – long-term	—		—		—		—			—
Total financial assets	$	—	$	—	$	—	$	—		$	—

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	169.8	$	—	$	—		$	169.8
Fair value of derivative contracts – long-term	—		32.0		—		—			32.0
Total financial liabilities	$	—	$	201.8	$	—	$	—		$	201.8

	December 31, 2015
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	147.8	$	—	$	(1.0	)	$	146.8
Fair value of derivative contracts – long-term	—		23.2		—		—			23.2
Total financial assets	$	—	$	171.0	$	—	$	(1.0	)	$	170.0

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	1.8	$	—	$	(1.0	)	$	0.8
Fair value of derivative contracts – long-term	—		4.0		—		—			4.0
Total financial liabilities	$	—	$	5.8	$	—	$	(1.0	)	$	4.8

____________________________


⁽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, 2016				December 31, 2015
Financial Assets	(in millions)
Cash and cash equivalents	$	443.8	$	443.8	$	376.1	$	376.1
Financial Liabilities
Checks outstanding in excess of cash balances	$	12.3	$	12.3	$	29.8	$	29.8
Long-term debt	$	2,020.9	$	2,104.3	$	2,191.5	$	1,784.6

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 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, 2016 and 2015, the Company recorded impairments of certain proved oil and gas properties of $1,172.7 million and $39.3 million, respectively, resulting in a reduction 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 discounted at an appropriate weighted average cost of capital. Given the unobservable nature of the inputs, proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. See Note 1 – Summary of Significant Accounting Policies for additional information on impairment of oil and gas properties.

Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date which utilizes the following inputs to estimate future net cash flows: estimated quantities of oil, gas and NGL reserves; estimates of future commodity prices; and estimated production rates, future operating and development costs, which are 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 acquired 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.

- Definition

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

+ References + Details

Derivative Contracts

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, 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 transactions. QEP does not enter into commodity derivative contracts 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 oil or gas 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. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma or oil price swaps that use ICE Brent oil prices as the reference price. Gas price derivative instruments are typically structured as fixed-price swaps or collars at regional price indices. QEP also enters into oil and gas basis swaps to achieve a fixed-price swap for a portion of its oil and gas sales 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. QEP's commodity derivative contract counterparties are typically 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, actively monitoring counterparties public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

During 2014, 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.

Derivative Contracts – Production

The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of December 31, 2016:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2017	NYMEX WTI	13.5	$	51.39
2018	NYMEX WTI	7.3	$	53.40
Gas sales		(MMBtu)	($/MMBtu)
2017	NYMEX HH	94.9	$	2.86
2017	IFNPCR	32.9	$	2.51
2018	NYMEX HH	62.1	$	2.96

The following table presents QEP's volumes and average prices for its commodity derivative gas collars as of December 31, 2016:

Year

Index

Total Volumes

Average Price Floor

Average Price Ceiling

(in millions)

(MMBtu)

($/MMBtu)

2017

NYMEX HH

11.0

2.50

3.50

QEP uses oil and gas basis swaps, combined with NYMEX WTI and NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil and gas basis swaps as of December 31, 2016:



Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2017	NYMEX WTI	Argus WTI Midland	2.9	$	(0.64	)
2018	NYMEX WTI	Argus WTI Midland	2.2	$	(0.90	)
Gas sales			(MMBtu)	($/MMBtu)
2017	NYMEX HH	IFNPCR	51.1	$	(0.18	)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)

Derivative Contracts – Gas Storage

QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table presents QEP's volumes and average prices for its gas storage commodity derivative swap contracts as of December 31, 2016:



Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	4.0	$	2.88

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 on 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	2016		2015		2016		2015
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	—	$	147.8	$	169.8	$	1.8
Long-term:
Commodity	Fair value of derivative contracts	—		23.2		32.0		4.0
Total derivative instruments		$	—	$	171.0	$	201.8	$	5.8

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	2016			2015			2014
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	86.3		$	353.7		$	15.7
Gas derivative contracts	44.8			103.4			(16.7		)
Gas Storage
Gas derivative contracts	2.9			3.8			(2.5		)
Total realized gains (losses) on commodity derivative contracts	134.0			460.9			(3.5		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(217.2		)	(244.9		)	299.8
Gas derivative contracts	(145.4		)	62.0			68.4
Gas Storage
Gas derivative contracts	(4.4		)	(0.8		)	4.2
Total unrealized gains (losses) on commodity derivative contracts	(367.0		)	(183.7		)	372.4
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(233.0	)	$	277.2		$	368.9

Realized gains (losses) on interest rate swaps
Realized gains (losses) on interest rate swaps	$	—		$	—		$	(7.6	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	—			—			2.0
Total realized and unrealized gains (losses) on interest rate swaps	—			—			(5.6		)
Total net realized gains (losses) on derivative contracts	134.0			460.9			(11.1		)
Total net unrealized gains (losses) on derivative contracts	(367.0		)	(183.7		)	374.4
Grand Total	$	(233.0	)	$	277.2		$	363.3

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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+ Details

Restructuring Costs	12 Months Ended
Restructuring Costs	Dec. 31, 2016
Restructuring and Related Activities [Abstract]
Restructuring Costs	In April 2016, the Company streamlined its organizational structure, resulting in a reduction of approximately 6% of its total workforce. The total costs related to the 2016 restructuring were approximately $1.9 million and were related to one-time termination benefits. During the year ended December 31, 2016, restructuring costs of $1.9 million were incurred and paid related to the 2016 restructuring. The Company does not expect to incur additional costs related to the 2016 restructuring. During 2015, QEP had multiple restructuring events, including the closure of its Tulsa office, which occurred in the third quarter of 2015. The total costs related to the 2015 restructuring events were approximately $8.3 million, of which approximately $5.3 million was related to one-time termination benefits and approximately $3.0 million was related to relocation of certain employees. During the year ended December 31, 2016, restructuring costs of $0.6 million were incurred and paid related to the Tulsa office closure, all of which were related to the relocation of certain employees. The Company does not expect to incur additional costs related to the closure of its Tulsa office. All restructuring costs were recorded within "General and administrative" expense on the Consolidated Statement of Operations.

Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Debt

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



	December 31,
	2016			2015
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
6.05% Senior Notes due 2016⁽¹⁾	—			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 and unamortized debt issuance costs	(24.1		)	(30.3		)
Total principal amount of debt (including current portion)	2,020.9			2,191.5
Less: current portion of long-term debt	—			(176.8		)
Total long-term debt outstanding	$	2,020.9		$	2,014.7

_______________________


⁽¹⁾	During the year ended December 31, 2016, the Company paid $176.8 million for the repayment of the 6.05% Senior Notes, which were due on September 1, 2016.

Of the total debt outstanding on December 31, 2016, the 6.80% Senior Notes due April 1, 2018, the 6.80% Senior Notes due March 1, 2020 and the 6.875% Senior Notes due March 1, 2021, 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 (that are defined in the credit agreement) that limit the amount of debt the Company may incur and may limit the amount available to be drawn under the credit facility, including: (i) a net funded debt to capitalization ratio that 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, 2016 and 2015, QEP was in compliance with the covenants under the credit agreement.

During the years ended December 31, 2016 and 2015, QEP had no borrowings outstanding under the credit facility. At December 31, 2016 and 2015, QEP had $2.8 million and $3.4 million, respectively, in letters of credit outstanding under the credit facility.

Senior Notes

At December 31, 2016, the Company had $2,045.0 million principal amount of senior notes outstanding with maturities ranging from April 2018 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, 2016

Commitments and Contingencies Disclosure [Abstract]

Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company 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.

Legal proceedings are inherently unpredictable, and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter.

Litigation

Rocky Mountain Resources Lawsuit – Rocky Mountain Resources, LLC (Rocky Mountain) filed a complaint against the Company in March 2011, seeking determination of the existence of a 4% overriding royalty interest in an oil and gas lease. Rocky Mountain alleged that the defendants 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 the Company and awarded Rocky Mountain damages in the amount of $16.7 million, including interest. The Company appealed the verdict to the Wyoming Supreme Court and in February 2017, the Wyoming Supreme Court reversed and remanded the case back to the trial court with instructions to enter judgment in favor of the Company. The Company had been depositing monthly revenues attributable to the contested overriding royalty interest with the Court as such amounts became due and payable. These deposits are presented within "Prepaid expenses and other" on the Company’s Consolidated Balance Sheets. Based upon the favorable ruling from the Wyoming Supreme Court, the Company will file a motion with the trial court seeking the release of the escrowed funds.

Claims of Former Limited Partners – The Company received a demand from certain former limited partners of terminated drilling partnerships of the Company (acting as the general partner). The former limited partners allege that distributions to which they were entitled from the drilling partnerships were not made or were calculated incorrectly. Other former limited partners may assert claims. No litigation has been filed, and the Company is in the process of evaluating the allegations and its defenses.

Department of Interior Investigation regarding Indian Royalties – Pursuant to regulations published by the Office of Natural Resources Revenue (ONRR) of the Department of the Interior (DOI), certain of the Company’s Indian leases are subject to “dual accounting” and “major portion” requirements. The Company must initially report royalties on production from these leases based upon its actual sales arrangements and, once ONRR publishes the major portion price (approximately 18 months after a calendar year), the Company must recalculate its previously reported royalties for the applicable calendar year and pay additional royalties if the dual accounting or major portion pricing results in higher royalties. In July 2016, the Company was notified that the Office of Inspector General of the DOI is conducting an investigation into the timeliness of the Company’s compliance with ONRR dual accounting and major portion requirements to recalculate royalties for 2013 on production from certain Indian leases. There may be penalties and additional royalties due.

EPA Request for Information – In July 2015, QEP received an information request from the Environmental Protection Agency (EPA) pursuant to Section 114(a) of the Clean Air Act. The information request sought facts and data about certain tank batteries in QEP’s Williston Basin operations. QEP timely responded to the information requests. In August 2016, the EPA requested a conference to review this matter. In addition, since February 2016, the North Dakota Department of Health (NDDH) has engaged with the oil and gas production industry in North Dakota to address potential noncompliance associated with emissions from tank batteries. QEP has participated in these discussions. While no formal federal or state enforcement action has been commenced in connection with the tank batteries to date, other operators have been assessed penalties following similar information requests. QEP anticipates that resolution of these matters will likely result in penalties and require QEP to incur additional capital expenditures to correct noncompliance issues.

To the extent that the Company can reasonably estimate losses for contingencies where the risk of a material loss (in excess of accruals, if any) is reasonably possible, the Company estimates such losses could total between zero and approximately $25.0 million.

Commitments

QEP has contracted for gathering, processing, firm transportation and storage services with various third parties. 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
2017	$	130.7
2018	$	111.9
2019	$	104.5
2020	$	87.8
2021	$	51.0
After 2021	$	207.8

QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $9.1 million, $8.0 million, and $8.2 million during the years ended December 31, 2016, 2015 and 2014, respectively. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions):



Year	Amount
2017	$	8.7
2018	$	7.2
2019	$	7.1
2020	$	6.9
2021	$	7.0
After 2021	$	11.2

Share-Based Compensation

12 Months Ended

Dec. 31, 2016

Share-based Compensation [Abstract]

Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units 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 share awards, restricted share units and performance share units. There were 7.1 million shares available for future grants under the LTSIP at December 31, 2016.

Share-based compensation expense related to continuing operations is recognized within "General and administrative" expense on the Consolidated Statements of Operations and is summarized in the table below. In addition, during the year ended December 31, 2014, QEP recognized $5.8 million in total compensation expense related to discontinued operations (including compensation expense related to the QEP Midstream Long Term Incentive Plan) which is reflected within "Net income from discontinued operations, net of income tax" on the Consolidated Statement of Operations.



	Year Ended
	December 31,
	2016		2015		2014
	(in millions)
Stock options	$	2.3	$	2.9	$	3.3
Restricted share awards	23.7		25.6		18.1
Performance share units	9.4		6.2		0.7
Restricted share units	0.2		—		—
Total share-based compensation expense	$	35.6	$	34.7	$	22.1

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of 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 calculating the value of options not 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,
	2016			2015			2014
Weighted-average grant date fair value of awards granted during the period	$	3.77		$	6.82		$	10.11
Risk-free interest rate range	0.99% - 1.15%			1.38% - 1.38%			1.31% - 1.34%
Weighted-average risk-free interest rate	1.2		%	1.4		%	1.3		%
Expected price volatility range	43.42% - 43.66%			36.8% - 36.8%			36.1% - 37.3%
Weighted-average expected price volatility	43.4		%	36.8		%	37.1		%
Expected dividend yield	—		%	0.37		%	0.25		%
Expected term in years at the date of grant	4.5			4.5			4.5

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, 2015	2,200,776		$	27.94
Granted	438,180		10.14
Canceled	(486,999	)	23.77
Outstanding at December 31, 2016	2,151,957		$	25.26	3.66	$	3.6
Options Exercisable at December 31, 2016	1,385,753		$	30.18	2.61	$	0.1
Unvested Options at December 31, 2016	766,204		$	16.38	5.57	$	3.5

During the year ended December 31, 2016, there were no exercises of stock options. 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 and $0.6 million during the years ended December 31, 2015 and 2014, respectively. The Company realized an income tax benefit of $0.2 million for the year ended December 31, 2016, $6.4 million of income tax expense for the year ended December 31, 2015, and there was no income tax impact for the year ended December 31, 2014. Stock options increased the Company's Additional Paid-in-Capital (APIC) pool by $0.3 million as of December 31, 2016. As of December 31, 2016, $1.2 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 1.84 years.

Restricted Share Awards

Restricted share award 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 share awards that vested during the years ended December 31, 2016, 2015 and 2014, was $24.3 million, $22.7 million and $26.8 million, respectively. There was no income tax impact for the year ended December 31, 2016. The Company realized an income tax benefit of $3.2 million for the year ended December 31, 2015, and an income tax expense $0.5 million for the year ended December 31, 2014. Restricted share awards increased the Company's APIC pool by $3.5 million as of December 31, 2016. The weighted-average grant date fair value of restricted share awards granted was $10.50 per share, $20.92 per share and $31.40 per share for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016, $17.5 million of unrecognized compensation cost related to restricted share awards 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 1.98 years.

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



	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	2,008,210		$	24.18
Granted	2,467,954		10.50
Vested	(973,307	)	25.01
Forfeited	(294,354	)	14.26
Unvested balance at December 31, 2016	3,208,503		$	14.32

Performance Share Units

The payouts for performance share units' 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, 2016, the Company expects to settle all awards in cash. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Consolidated Balance Sheet. As these awards are dependent upon the Company's total shareholder return and stock price, they are measured at fair value at the end of each reporting period. The Company paid $2.8 million, $3.1 million and $1.7 million for vested performance share units related to continuing operations during the years ended December 31, 2016, 2015 and 2014, respectively. In addition, during the year ended December 31, 2014, the Company paid $0.5 million for vested performance share units related to discontinued operations. The weighted-average grant date fair value of the performance share units granted during the years ended December 31, 2016, 2015 and 2014, were $10.16, $21.69, and $31.57 per share, respectively. As of December 31, 2016, $12.3 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 1.85 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, 2015	630,786		$	27.50
Granted	597,185		10.16
Vested and paid out	(178,169	)	30.07
Forfeited	(22,522	)	15.16
Unvested balance at December 31, 2016	1,027,280		$	17.24

Restricted Share Units

Restricted share units vest over a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately delivered in cash. They are classified as liabilities in"Other long-term liabilities" on the Consolidated Balance Sheet and are measured at fair value at the end of each reporting period. The weighted-average grant date fair value of the restricted share units was $10.12 per share for the year ended December 31, 2016. As of December 31, 2016, $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.32 years.

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



	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	—		$	—
Granted	21,493		10.12
Vested	(193	)	10.12
Forfeited	(3,266	)	10.12
Unvested balance at December 31, 2016	18,034		$	10.12

- Definition

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

+ References + Details

Employee Benefits

12 Months Ended

Dec. 31, 2016

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 (the 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 pension benefits to certain QEP employees, which, as of December 31, 2016, covers 41 active and suspended participants, or 6%, of QEP's active employees, and 173 participants that are retired or were 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, 2016, 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 2017. 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 was 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, 2016, the Company made contributions of $3.2 million to its SERP and expects to contribute approximately $2.5 million in 2017. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and was 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 QEP employees. The Medical Plan is provided only to employees hired before January 1, 1997. Of the 41 active, pension eligible employees, 25 are also eligible for the Medical Plan when they retire. As of December 31, 2016, 50 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, 2016, the Company made contributions of $0.4 million and expects to contribute approximately $0.3 million of benefits in 2017. At December 31, 2016 and 2015, 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 Other Southern 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 property sales in the Other Southern area 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 $124.5 million and $117.4 million at December 31, 2016 and 2015, 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, 2016 and 2015, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2016 and 2015:



	Pension Plan and SERP benefits						Medical Plan benefits
	2016			2015			2016			2015
Change in benefit obligation	(in millions)
Benefit obligation at January 1,	$	120.3		$	132.6		$	5.2		$	6.6
Service cost	1.2			2.1			—			—
Interest cost	5.2			4.9			0.2			0.2
Curtailments	—			(7.1		)	—			—
Benefit payments	(7.8		)	(7.7		)	(0.4		)	(0.2		)
Plan amendments	—			0.9			—			—
Actuarial loss (gain)	10.3			(5.4		)	0.4			(1.4		)
Benefit obligation at December 31,	$	129.2		$	120.3		$	5.4		$	5.2
Change in plan assets
Fair value of plan assets at January 1,	$	79.3		$	81.4		$	—		$	—
Actual return on plan assets	7.4			(1.9		)	—			—
Company contributions to the plan	7.2			7.5			0.4			0.2
Benefit payments	(7.8		)	(7.7		)	(0.4		)	(0.2		)
Fair value of plan assets at December 31,	86.1			79.3			—			—
Underfunded status (current and long-term)	$	(43.1	)	$	(41.0	)	$	(5.4	)	$	(5.2	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(2.5	)	$	(2.9	)	$	(0.3	)	$	(0.3	)
Other long-term liabilities	(40.6		)	(38.1		)	(5.1		)	(4.9		)
Total amount recognized in balance sheet	$	(43.1	)	$	(41.0	)	$	(5.4	)	$	(5.2	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	23.5		$	15.8		$	(0.4	)	$	(0.8	)
Prior service cost	2.9			4.1			1.0			1.2
Total amount recognized in AOCI	$	26.4		$	19.9		$	0.6		$	0.4

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
	2016			2015			2014			2016			2015			2014
Components of net periodic benefit cost	(in millions)
Service cost	$	1.2		$	2.1		$	2.6		$	—		$	—		$	—
Interest cost	5.2			4.9			5.3			0.2			0.2			0.3
Expected return on plan assets	(5.6		)	(5.7		)	(5.1		)	—			—			—
Curtailment loss	—			11.2			9.3			—			—			1.4
Special termination benefits	—			—			1.9			—			—			—
Settlements	—			—			0.7			—			—			—
Amortization of prior service costs	1.1			1.7			4.7			0.2			0.2			0.3
Amortization of actuarial loss	0.8			0.5			0.8			—			—			—
Periodic expense	$	2.7		$	14.7		$	20.2		$	0.4		$	0.4		$	2.0
Components recognized in accumulated other comprehensive income
Current period prior service cost	$	—		$	0.9		$	—		$	—		$	—		$	—
Current period actuarial (gain) loss	8.5			2.2			21.5			0.4			(1.4		)	0.6
Amortization of prior service cost	(1.1		)	(12.9		)	(14.0		)	(0.2		)	(0.2		)	(1.7		)
Amortization of actuarial gain (loss)	(0.8		)	(0.5		)	(0.8		)	—			—			—
Loss on curtailment in current period	—			(7.1		)	(8.2		)	—			—			(0.2		)
Settlements	—			—			(0.7		)	—			—			—
Total amount recognized in accumulated other comprehensive income	$	6.6		$	(17.4	)	$	(2.2	)	$	0.2		$	(1.6	)	$	(1.3	)

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 2017 is $2.2 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 2017 is $0.2 million, which represents amortization of prior service cost recognition. 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" expense.

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, 2016 and 2015:



	Pension Plan and SERP benefits				Medical Plan benefits
	2016		2015		2016		2015
Discount rate	3.96	%	4.24	%	4.10	%	4.40	%
Rate of increase in compensation⁽¹⁾	3.50	%	4.00	%	3.50	%	4.00	%

_______________________


⁽¹⁾	The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the year ended December 31, 2016, the rate of increase in compensation only includes the SERP and Medical Plan.

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
	2016		2015		2014		2016		2015		2014
Discount rate	4.23	%	3.94	%	4.40	%	4.40	%	4.00	%	5.00	%
Expected long-term return on plan assets	6.50	%	6.75	%	7.00	%	n/a		n/a		n/a
Rate of increase in compensation⁽¹⁾	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%

_______________________


⁽¹⁾	The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the year ended December 31, 2016, the rate of increase in compensation only includes the SERP and Medical Plan.

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 2017. 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. International equity securities consisted of developed and emerging market foreign equity assets that were invested in funds that hold a 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 five to ten 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 five to seven years.

Although the actual allocation to cash and short-term investments is minimal (less than 5%), 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.

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. These investments are public investment vehicles valued using the net asset value (NAV) as a practical expedient. The NAV is based on the underlying assets owned by the fund excluding transaction costs and minus liabilities, which can be traced back to observable asset values. No assets held by the Pension Plan that were valued using the NAV methodology were subject to redemption restrictions on their valuation date. 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. In conjunction with the issuance of ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investment in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), QEP no longer presents its Pension Plan assets in the fair value hierarchy, as all investments are measured at NAV as a practical expedient, which are now required to be excluded from the fair value hierarchy.

The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2016 and 2015, respectively:



	December 31, 2016				December 31, 2015
	Total		Percentage of total		Total		Percentage of total
	(in millions, except percentages)
Cash and short-term investments	$	3.5	4	%	$	0.4	—	%
Equity securities:
Domestic	39.3		46	%	38.5		49	%
International	21.6		25	%	16.8		21	%
Fixed income	21.7		25	%	23.6		30	%
Total investments	$	86.1	100	%	$	79.3	100	%

Expected Benefit Payments

As of December 31, 2016, the following future benefit payments are expected to be paid:



	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2017	$	7.2	$	0.3
2018	$	6.6	$	0.3
2019	$	8.6	$	0.3
2020	$	8.0	$	0.3
2021	$	8.9	$	0.3
2022 through 2026	$	42.3	$	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 year ended December 31, 2016, all employees not covered by the SERP were eligible for matching contributions equal to 100% of the employees’ contributions up to a maximum of 8% of their qualifying earnings. For the year ended December 31, 2016, employees covered by the SERP were eligible for matching contributions equal to 100% of the employee's contributions up to a maximum of 6% of their qualifying earnings. For the years ended December 31, 2015 and 2014, the Company made matching contributions for employees not covered by the Pension Plan or the SERP equal to 100% of employees' contributions up to a maximum of 8% of their qualifying earnings. For the years ended December 31, 2015 and 2014, employees covered by the Pension Plan or the SERP 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 or SERP. The Company recognizes expense equal to its yearly contributions, which amounted to $5.6 million, $6.3 million and $7.6 million during the years ended December 31, 2016, 2015 and 2014, respectively.

Income Taxes

12 Months Ended

Dec. 31, 2016

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,
	2016			2015			2014
Federal income tax provision (benefit)	(in millions)
Current	$	(55.5	)	$	(112.3	)	$	(324.0	)
Deferred	(614.3		)	34.5			110.3
State income tax provision (benefit)
Current	(1.5		)	(6.6		)	(15.5		)
Deferred	(36.9		)	(9.2		)	(3.3		)
Total income tax provision (benefit)	$	(708.2	)	$	(93.6	)	$	(232.5	)

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,
	2016		2015		2014
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	2.4	%	4.2	%	(1.5	)%
State rate change	(1.1	)%	—	%	3.4	%
Penalties	—	%	(0.3	)%	—	%
Return to provision adjustment	—	%	(0.3	)%	(0.4	)%
Other	—	%	(0.1	)%	(0.3	)%
Effective income tax rate	36.3	%	38.5	%	36.2	%

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



	December 31,
	2016		2015
Deferred tax liabilities	(in millions)
Property, plant and equipment	$	1,135.0	$	1,531.0
Commodity price derivatives	—		60.4
Total deferred tax liabilities	1,135.0		1,591.4
Deferred tax assets
Net operating loss and tax credit carryforwards	$	161.6	$	51.9
Employee benefits and compensation costs	49.0		43.6
Bonus and vacation accrual	11.4		7.0
Commodity price derivatives	74.3		—
Other	12.8		9.1
Total deferred tax assets	309.1		111.6
Net deferred income tax liability	$	825.9	$	1,479.8
Balance sheet classification
Deferred income tax liability – noncurrent	825.9		1,479.8
Net deferred income tax liability	$	825.9	$	1,479.8

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2016, are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2017-2033	$	53.6
State net operating loss valuation allowance		(20.6		)
U.S. net operating loss	2036	109.1
U.S. alternative minimum tax credit	Indefinite	19.5
Total		$	161.6

The valuation allowance of $20.6 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 property sales in the Other Southern area 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, 2016 and 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. The uncertain tax positions the Company reported during the year ended December 31, 2016 and 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, 2016, the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions. During the year ended December 31, 2015, the Company incurred $0.5 million of estimated interest expense and $2.2 million of estimated penalties related to uncertain tax positions.

The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2016 and 2015:



	Unrecognized Tax Benefits
	2016		2015
	(in millions)
Balance as of January 1,	$	15.6	$	—
Additions for tax positions taken during the current period	—		15.6
Balance as of December 31,	$	15.6	$	15.6

As of December 31, 2016 and 2015, QEP had approximately $15.6 million of unrecognized tax benefit that would impact its effective tax rate if recognized.

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

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



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
2016	(in millions, except per share amounts or otherwise specified)
Revenues	$	261.3		$	333.7		$	382.4		$	399.7		$	1,377.1
Operating income (loss)	(1,379.2		)	(92.9		)	(93.6		)	(36.9		)	(1,602.6		)
Net income (loss)	(863.8		)	(197.0		)	(50.9		)	(133.3		)	(1,245.0		)
Net gain (loss) from asset sales and impairment	(1,181.9		)	(1.6		)	0.3			(6.1		)	(1,189.3		)
Nonrecurring items in operating income (loss)⁽¹⁾	7.7			—			25.0			—			32.7
Per share information
Basic EPS	$	(4.55	)	$	(0.90	)	$	(0.21	)	$	(0.56	)	$	(5.62	)
Diluted EPS	(4.55		)	(0.90		)	(0.21		)	(0.56		)	(5.62		)
Production information
Total equivalent production (Mboe)	13,766.4			13,882.4			14,445.7			13,675.7			55,780.2
Total equivalent production (Bcfe)	82.7			83.3			86.6			82.1			334.7



2015
Revenues	$	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		)
Net gain (loss) from asset sales and impairment	(50.5		)	24.0			(2.1		)	(22.4		)	(51.0		)
Nonrecurring items in operating income (loss)⁽¹⁾	—			11.2			—			—			11.2
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		)
Production information
Total equivalent production (Mboe)	12,528.8			13,484.3			14,462.4			13,986.6			54,462.1
Total equivalent production (Bcfe)	75.2			80.9			86.7			84.0			326.8

____________________________


⁽¹⁾	Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2016, and a non-cash pension curtailment incurred during the year ended December 31, 2015.

Supplemental Gas and Oil Information (Unaudited)

12 Months Ended

Dec. 31, 2016

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,
	2016			2015
	(in millions)
Proved properties	$	14,232.5		$	13,314.9
Unproved properties, net	871.5			691.0
Total proved and unproved properties	15,104.0			14,005.9
Accumulated depreciation, depletion and amortization	(8,797.7		)	(6,870.2		)
Net capitalized costs	$	6,306.3		$	7,135.7

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 $34.6 million and ARO additions and revisions of $23.5 million during the year ended December 31, 2016. The costs incurred to advance the development of reserves that were classified as proved undeveloped were approximately $258.1 million in 2016, $490.4 million in 2015, and $792.9 million in 2014. The costs incurred in 2016 related to the drilling and completion of PUD locations in QEP's operating areas were reduced from historical levels in conjunction with our efforts to reduce drilling and completion activities in 2016 due to lower commodity prices.



	Year Ended December 31,
	2016		2015		2014
	(in millions)
Proved property acquisitions	$	431.6	$	49.6	$	465.4
Unproved property acquisitions	208.7		39.8		496.3
Exploration (capitalized and expensed)	13.4		8.7		23.6
Development	509.2		1,010.3		1,695.1
Total costs incurred	$	1,162.9	$	1,108.4	$	2,680.4

Results of Operations

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



	Year Ended December 31,
	2016			2015			2014
	(in millions)
Revenues	$	1,271.0		$	1,390.4		$	2,374.6
Production costs	616.7			654.1			735.6
Exploration expenses	1.7			2.7			9.9
Depreciation, depletion and amortization	852.3			870.8			984.4
Impairment	1,194.3			55.6			1,143.2
Total expenses	2,665.0			1,583.2			2,873.1
Income (loss) before income taxes	(1,394.0		)	(192.8		)	(498.5		)
Income tax benefit (expense)	517.2			70.6			182.5
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(876.8	)	$	(122.2	)	$	(316.0	)

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 oversight of a multi-functional reserves review committee reporting to the Company's Audit Committee of the Board of Directors. The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of all of its proved reserves as of December 31, 2016, and retained RSC and DeGolyer and MacNaughton to prepare the estimates of all of its proved reserves as of December 31, 2015 and 2014. The estimated proved reserves have been prepared 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's proved undeveloped reserves at December 31, 2016, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. 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, 2016, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil, gas and NGL reserves for the years ended December 31, 2014, 2015 and 2016 are as follows:



	Oil		Gas		NGL		Total⁽¹³⁾
	(MMbbl)		(Bcf)		(MMbbl)		(MMboe)
Balance at December 31, 2013	148.6		2,554.9		102.6		677.0
Revisions of previous estimates⁽¹⁾	(4.0	)	27.1		1.4		1.9
Extensions and discoveries⁽²⁾	16.8		141.4		8.6		49.0
Purchase of reserves in place⁽³⁾	35.7		72.5		12.3		60.1
Sale of reserves in place⁽⁴⁾	(7.5	)	(299.4	)	(21.5	)	(78.9	)
Production	(17.1	)	(179.3	)	(6.8	)	(53.8	)
Balance at December 31, 2014	172.5		2,317.2		96.6		655.3
Revisions of previous estimates⁽⁵⁾	(47.0	)	(463.8	)	(55.3	)	(179.6	)
Extensions and discoveries⁽⁶⁾	85.6		467.7		21.8		185.4
Purchase of reserves in place⁽⁷⁾	2.0		3.2		0.6		3.1
Sale of reserves in place⁽⁸⁾	(0.4	)	(34.3	)	(0.2	)	(6.3	)
Production	(19.6	)	(181.1	)	(4.7	)	(54.5	)
Balance at December 31, 2015	193.1		2,108.9		58.8		603.4
Revisions of previous estimates⁽⁹⁾	(9.7	)	412.8		(0.3	)	58.8
Extensions and discoveries⁽¹⁰⁾	13.0		158.1		3.3		42.6
Purchase of reserves in place⁽¹¹⁾	62.7		54.6		11.5		83.3
Sale of reserves in place⁽¹²⁾	(0.2	)	(3.6	)	(0.1	)	(0.9	)
Production	(20.3	)	(177.0	)	(6.0	)	(55.8	)
Balance at December 31, 2016	238.6		2,553.8		67.2		731.4
Proved developed reserves
Balance at December 31, 2013	71.8		1,406.3		52.8		359.0
Balance at December 31, 2014	99.3		1,288.4		52.2		366.2
Balance at December 31, 2015	109.7		1,245.3		34.4		351.6
Balance at December 31, 2016	103.2		1,309.8		35.7		357.2
Proved undeveloped reserves
Balance at December 31, 2013	76.8		1,148.6		49.8		318.0
Balance at December 31, 2014	73.2		1,028.8		44.4		289.1
Balance at December 31, 2015	83.4		863.6		24.4		251.8
Balance at December 31, 2016	135.4		1,244.0		31.5		374.2

___________________________

⁽¹⁾

Revisions of previous estimates in 2014 include 41.4 MMboe negative performance revisions partially offset by positive other revisions of 33.0 MMboe, operating cost revisions of 6.5 MMboe and pricing revisions of 3.8 MMboe. Negative performance revisions were driven by a 32.3 MMboe 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. Pricing revisions were primarily due to increased gas prices, which increased reserves by 3.7 MMboe.


⁽²⁾	Extensions and discoveries in 2014 increased proved reserves by 49.0 MMboe, primarily related to extensions and discoveries in Pinedale of 22.3 MMboe and the Williston Basin of 20.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations as well as new compression well projections in Pinedale.


⁽³⁾	Purchase of reserves in place in 2014 relate to the Company's 2014 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.


⁽⁴⁾	Sale of reserves in place primarily related to property sales in the Other Southern area in the second and fourth quarters of 2014 as discussed in Note 2 – Acquisitions and Divestitures.


⁽⁵⁾	Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin.


⁽⁶⁾	Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations.


⁽⁷⁾	Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston Basin as discussed in Note 2 – Acquisitions and Divestitures.


⁽⁸⁾	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.

⁽⁹⁾

Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.


⁽¹⁰⁾	Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.


⁽¹¹⁾	Purchase of reserves in place in 2016 relate primarily to the Company's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.


⁽¹²⁾	Sale of reserves in place in 2016 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.


⁽¹³⁾	Proved reserves include gas reserves that QEP expects to produce and use as field fuel.

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

Future net cash flows were calculated at December 31, 2016, 2015 and 2014, 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 2016, 2015 and 2014, 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,
	2016		2015		2014
Average benchmark price per unit:
Oil price (per bbl)	$	42.75	$	50.28	$	94.99
Gas price (per MMBtu)	$	2.48	$	2.59	$	4.35

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 proved undeveloped reserves are approximately $503.0 million in 2017, $717.3 million in 2018 and $781.3 million in 2019. 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 its operating activities, cash on hand and, if needed, availability under its revolving 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,
	2016			2015			2014
	(in millions)
Future cash inflows	$	16,239.8		$	15,325.3		$	28,167.3
Future production costs	(7,789.0		)	(7,389.9		)	(9,842.1		)
Future development costs	(3,432.9		)	(2,202.5		)	(3,521.3		)
Future income tax expenses	(913.4		)	(1,169.3		)	(4,304.0		)
Future net cash flows	4,104.5			4,563.6			10,499.9
10% annual discount for estimated timing of net cash flows	(2,176.5		)	(2,087.3		)	(5,159.9		)
Standardized measure of discounted future net cash flows	$	1,928.0		$	2,476.3		$	5,340.0

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,
	2016			2015			2014
	(in millions)
Balance at January 1,	$	2,476.3		$	5,340.0		$	4,383.9
Sales of oil, gas and NGL produced, net of production costs	(654.3		)	(736.3		)	(1,639.0		)
Net change in sales prices and in production (lifting) costs related to future production	(739.4		)	(6,307.8		)	726.6
Net change due to extensions and discoveries	81.8			1,765.7			979.9
Net change due to revisions of quantity estimates	122.7			(1,350.2		)	35.9
Net change due to purchases of reserves in place	256.5			29.7			695.3
Net change due to sales of reserves in place	(4.3		)	(48.8		)	(1,153.7		)
Previously estimated development costs incurred during the period	374.6			865.0			867.5
Changes in estimated future development costs	(476.5		)	560.7			409.6
Accretion of discount	311.1			752.9			597.3
Net change in income taxes	205.4			1,554.4			(600.3		)
Other	(25.9		)	51.0			37.0
Net change	(548.3		)	(2,863.7		)	956.1
Balance at December 31,	$	1,928.0		$	2,476.3		$	5,340.0

Subsequent Event (Notes)	12 Months Ended
Subsequent Event (Notes)	Dec. 31, 2016
Subsequent Event [Abstract]
Subsequent Events [Text Block]	Note 16 – Subsequent Event In 2017 through the date this Annual Report on Form 10-K was filed with the SEC, QEP closed on multiple acquisitions of surface acreage and mineral leases near its existing operations in the Permian Basin for an aggregate purchase price of $37.9 million, which were funded with cash on hand. Final purchase price accounting, if applicable, for these various transactions was not complete at the time this Form 10-K was filed with the SEC, and as such, any applicable disclosures required by ASC Topic 805, Business Combinations, have not been made herein. The Company will include any applicable information in future filings with the SEC.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Summary of Significant Accounting Policies [Abstract]

Nature of Business [Text Block]

Nature of Business

Principles of Consolidation [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.

Changes in Segment Reporting due to Discontinued Operations [Policy Text Block]

Changes in Segment Reporting due to Discontinued Operations and Termination of Marketing Agreements

Equity Offerings [Policy Text Block]

Equity Offerings

Reclassifications [Policy Text Block]

Reclassifications

Use of Estimates [Policy Text Block]

Use of Estimates

Risks And Uncertainties [Policy Text Block]

Risks and Uncertainties

Revenue Recognition [Policy Text Block]

Revenue Recognition

Cash and Cash Equivalents and Restricted Cash [Policy Text Block]

Cash and Cash Equivalents and Restricted Cash

Supplemental cash flow information is shown in the table below:



	Year Ended December 31,
	2016			2015			2014
Supplemental Disclosures	(in millions)
Cash paid for interest, net of capitalized interest	$	139.1		$	139.4		$	163.2
Cash paid (refund received) for income taxes, net	$	(123.5	)	$	487.8		$	0.3
Non-cash investing activities
Change in capital expenditure accrual balance	$	(32.8	)	$	(129.2	)	$	8.4

Accounts Receivable [Policy Text Block]

Accounts Receivable

Property, Plant and Equipment [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 [Policy Text Block]

Goodwill

Litigation and Other Contingencies [Policy Text Block]

Litigation and Other Contingencies

Derivative Contracts [Policy Text Block]

Derivative Contracts

Credit Risk [Policy Text Block]

Credit Risk

Income Taxes [Policy Text Block]

Income Taxes

Treasury Stock [Policy Text Block]

Treasury Stock

Share Repurchases And Retirements [Policy Text Block]

Share Repurchases and Retirements

Earnings Per Share [Policy Text Block]

Earnings Per Share



	December 31,
	2016	2015	2014
	(in millions)
Weighted-average basic common shares outstanding	221.7	176.6	179.8
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—
Average diluted common shares outstanding	221.7	176.6	179.8

Share-based Compensation [Policy Text Block]

Share-Based Compensation

Pension and Other Postretirement Benefits [Policy Text Block]

Pension and Other Postretirement Benefits

Comprehensive Income [Policy Text Block]

Comprehensive Income

Recent Accounting Developments [Policy Text Block]

Recent Accounting Developments

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Information [Line Items]

Supplemental Cash Flow Information [Table Text Block]

Supplemental cash flow information is shown in the table below:



	Year Ended December 31,
	2016			2015			2014
Supplemental Disclosures	(in millions)
Cash paid for interest, net of capitalized interest	$	139.1		$	139.4		$	163.2
Cash paid (refund received) for income taxes, net	$	(123.5	)	$	487.8		$	0.3
Non-cash investing activities
Change in capital expenditure accrual balance	$	(32.8	)	$	(129.2	)	$	8.4

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,
	2016	2015	2014
	(in millions)
Weighted-average basic common shares outstanding	221.7	176.6	179.8
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—
Average diluted common shares outstanding	221.7	176.6	179.8

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2016

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



Consideration:
Total consideration	$	590.6

Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	406.2
Unproved properties	214.2
Asset retirement obligations	(11.6		)
Bargain purchase gain	(18.2		)
Total fair value	$	590.6

Business Acquisition, Pro Forma Information [Table Text Block]



	Year ended December 31,
	2016						2015
	Actual			Pro forma			Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	1,377.1		$	1,392.5		$	2,018.6		$	2,041.5
Net income (loss)	$	(1,245.0	)	$	(1,246.8	)	$	(149.4	)	$	(152.5	)
Earnings (loss) per common share
Basic	$	(5.62	)	$	(5.62	)	$	(0.85	)	$	(0.86	)
Diluted	$	(5.62	)	$	(5.62	)	$	(0.85	)	$	(0.86	)



	Year ended December 31,
	2014
	Actual		Pro Forma
	(in millions, except per share amounts)
Revenues	$	3,293.2	$	3,319.3
Net income (loss)	$	784.4	$	791.4
Earnings (loss) per common share
Basic	$	4.36	$	4.40
Diluted	$	4.36	$	4.40

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2016

Discontinued Operations and Disposal Groups [Abstract]

Income Statement Impact Of Discontinued Operations [Table Text Block]



	Year Ended December 31,
	2014
REVENUES	(in millions)
NGL sales	$	109.3
Other revenues	140.9
Purchased oil and gas sales⁽¹⁾	(47.1		)
Total Revenues	203.1
OPERATING EXPENSES
Purchased oil and gas expense⁽¹⁾	(48.5		)
Lease operating expense⁽¹⁾	(5.5		)
Oil, gas and NGL transport & other handling costs⁽¹⁾	(55.4		)
Gathering, processing, and other	85.9
General and administrative	42.1
Production and property taxes	7.3
Depreciation, depletion and amortization	45.9
Total Operating Expenses	71.8
Net gain (loss) from asset sales	1,793.4
OPERATING INCOME	1,924.7
Interest and other income	0.3
Income from unconsolidated affiliates	4.9
Loss on early extinguishment of debt	(2.4		)
Interest expense	(3.8		)
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES⁽²⁾	1,923.7
Income tax (provision) benefit	(708.2		)
NET INCOME FROM DISCONTINUED OPERATIONS	1,215.5
Net income attributable to noncontrolling interest	(21.6		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	1,193.9

___________________________


⁽¹⁾	Includes discontinued intercompany eliminations.


⁽²⁾	Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owned 57.8%) of $28.9 million for the year ended December 31, 2014.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair value and related carrying amount of certain financial instruments

The fair value of financial assets and liabilities at December 31, 2016 and 2015, 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, 2016
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	—	$	—	$	—		$	—
Fair value of derivative contracts – long-term	—		—		—		—			—
Total financial assets	$	—	$	—	$	—	$	—		$	—

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	169.8	$	—	$	—		$	169.8
Fair value of derivative contracts – long-term	—		32.0		—		—			32.0
Total financial liabilities	$	—	$	201.8	$	—	$	—		$	201.8

	December 31, 2015
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	147.8	$	—	$	(1.0	)	$	146.8
Fair value of derivative contracts – long-term	—		23.2		—		—			23.2
Total financial assets	$	—	$	171.0	$	—	$	(1.0	)	$	170.0

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	1.8	$	—	$	(1.0	)	$	0.8
Fair value of derivative contracts – long-term	—		4.0		—		—			4.0
Total financial liabilities	$	—	$	5.8	$	—	$	(1.0	)	$	4.8



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2016				December 31, 2015
Financial Assets	(in millions)
Cash and cash equivalents	$	443.8	$	443.8	$	376.1	$	376.1
Financial Liabilities
Checks outstanding in excess of cash balances	$	12.3	$	12.3	$	29.8	$	29.8
Long-term debt	$	2,020.9	$	2,104.3	$	2,191.5	$	1,784.6

Derivative Contracts (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Volumes and Average Prices

Derivative Contracts – Production

The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of December 31, 2016:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2017	NYMEX WTI	13.5	$	51.39
2018	NYMEX WTI	7.3	$	53.40
Gas sales		(MMBtu)	($/MMBtu)
2017	NYMEX HH	94.9	$	2.86
2017	IFNPCR	32.9	$	2.51
2018	NYMEX HH	62.1	$	2.96

The following table presents QEP's volumes and average prices for its commodity derivative gas collars as of December 31, 2016:

Year

Index

Total Volumes

Average Price Floor

Average Price Ceiling

(in millions)

(MMBtu)

($/MMBtu)

2017

NYMEX HH

11.0

2.50

3.50



Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2017	NYMEX WTI	Argus WTI Midland	2.9	$	(0.64	)
2018	NYMEX WTI	Argus WTI Midland	2.2	$	(0.90	)
Gas sales			(MMBtu)	($/MMBtu)
2017	NYMEX HH	IFNPCR	51.1	$	(0.18	)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)

Derivative Contracts – Gas Storage



Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	4.0	$	2.88

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	2016		2015		2016		2015
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	—	$	147.8	$	169.8	$	1.8
Long-term:
Commodity	Fair value of derivative contracts	—		23.2		32.0		4.0
Total derivative instruments		$	—	$	171.0	$	201.8	$	5.8

Effects of Derivative Transactions



Derivative instruments not designated as cash flow hedges	Year Ended December 31,
Derivative instruments not designated as cash flow hedges	2016			2015			2014
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	86.3		$	353.7		$	15.7
Gas derivative contracts	44.8			103.4			(16.7		)
Gas Storage
Gas derivative contracts	2.9			3.8			(2.5		)
Total realized gains (losses) on commodity derivative contracts	134.0			460.9			(3.5		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(217.2		)	(244.9		)	299.8
Gas derivative contracts	(145.4		)	62.0			68.4
Gas Storage
Gas derivative contracts	(4.4		)	(0.8		)	4.2
Total unrealized gains (losses) on commodity derivative contracts	(367.0		)	(183.7		)	372.4
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(233.0	)	$	277.2		$	368.9

Realized gains (losses) on interest rate swaps
Realized gains (losses) on interest rate swaps	$	—		$	—		$	(7.6	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	—			—			2.0
Total realized and unrealized gains (losses) on interest rate swaps	—			—			(5.6		)
Total net realized gains (losses) on derivative contracts	134.0			460.9			(11.1		)
Total net unrealized gains (losses) on derivative contracts	(367.0		)	(183.7		)	374.4
Grand Total	$	(233.0	)	$	277.2		$	363.3

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

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
2017	$	130.7
2018	$	111.9
2019	$	104.5
2020	$	87.8
2021	$	51.0
After 2021	$	207.8

Operating Leases of Lessee Disclosure [Table Text Block]

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



Year	Amount
2017	$	8.7
2018	$	7.2
2019	$	7.1
2020	$	6.9
2021	$	7.0
After 2021	$	11.2

- Definition

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

+ References + Details

Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

Share-based Compensation [Abstract]

Share-based Compensation Expense [Table Text Block]



	Year Ended
	December 31,
	2016		2015		2014
	(in millions)
Stock options	$	2.3	$	2.9	$	3.3
Restricted share awards	23.7		25.6		18.1
Performance share units	9.4		6.2		0.7
Restricted share units	0.2		—		—
Total share-based compensation expense	$	35.6	$	34.7	$	22.1

Schedule of calculated fair value of options granted and major assumptions used [Table Text Block]

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,
	2016			2015			2014
Weighted-average grant date fair value of awards granted during the period	$	3.77		$	6.82		$	10.11
Risk-free interest rate range	0.99% - 1.15%			1.38% - 1.38%			1.31% - 1.34%
Weighted-average risk-free interest rate	1.2		%	1.4		%	1.3		%
Expected price volatility range	43.42% - 43.66%			36.8% - 36.8%			36.1% - 37.3%
Weighted-average expected price volatility	43.4		%	36.8		%	37.1		%
Expected dividend yield	—		%	0.37		%	0.25		%
Expected term in years at the date of grant	4.5			4.5			4.5

Stock Options Activity [Table Text Block]

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, 2015	2,200,776		$	27.94
Granted	438,180		10.14
Canceled	(486,999	)	23.77
Outstanding at December 31, 2016	2,151,957		$	25.26	3.66	$	3.6
Options Exercisable at December 31, 2016	1,385,753		$	30.18	2.61	$	0.1
Unvested Options at December 31, 2016	766,204		$	16.38	5.57	$	3.5

Restricted Share Awards Activity [Table Text Block]

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



	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	2,008,210		$	24.18
Granted	2,467,954		10.50
Vested	(973,307	)	25.01
Forfeited	(294,354	)	14.26
Unvested balance at December 31, 2016	3,208,503		$	14.32

Performance Share Units Activity [Table Text Block]



	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	630,786		$	27.50
Granted	597,185		10.16
Vested and paid out	(178,169	)	30.07
Forfeited	(22,522	)	15.16
Unvested balance at December 31, 2016	1,027,280		$	17.24

Restricted Share Units Activity [Table Text Block]

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



	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	—		$	—
Granted	21,493		10.12
Vested	(193	)	10.12
Forfeited	(3,266	)	10.12
Unvested balance at December 31, 2016	18,034		$	10.12

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2016

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
	2016			2015			2016			2015
Change in benefit obligation	(in millions)
Benefit obligation at January 1,	$	120.3		$	132.6		$	5.2		$	6.6
Service cost	1.2			2.1			—			—
Interest cost	5.2			4.9			0.2			0.2
Curtailments	—			(7.1		)	—			—
Benefit payments	(7.8		)	(7.7		)	(0.4		)	(0.2		)
Plan amendments	—			0.9			—			—
Actuarial loss (gain)	10.3			(5.4		)	0.4			(1.4		)
Benefit obligation at December 31,	$	129.2		$	120.3		$	5.4		$	5.2
Change in plan assets
Fair value of plan assets at January 1,	$	79.3		$	81.4		$	—		$	—
Actual return on plan assets	7.4			(1.9		)	—			—
Company contributions to the plan	7.2			7.5			0.4			0.2
Benefit payments	(7.8		)	(7.7		)	(0.4		)	(0.2		)
Fair value of plan assets at December 31,	86.1			79.3			—			—
Underfunded status (current and long-term)	$	(43.1	)	$	(41.0	)	$	(5.4	)	$	(5.2	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(2.5	)	$	(2.9	)	$	(0.3	)	$	(0.3	)
Other long-term liabilities	(40.6		)	(38.1		)	(5.1		)	(4.9		)
Total amount recognized in balance sheet	$	(43.1	)	$	(41.0	)	$	(5.4	)	$	(5.2	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	23.5		$	15.8		$	(0.4	)	$	(0.8	)
Prior service cost	2.9			4.1			1.0			1.2
Total amount recognized in AOCI	$	26.4		$	19.9		$	0.6		$	0.4

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
	2016			2015			2014			2016			2015			2014
Components of net periodic benefit cost	(in millions)
Service cost	$	1.2		$	2.1		$	2.6		$	—		$	—		$	—
Interest cost	5.2			4.9			5.3			0.2			0.2			0.3
Expected return on plan assets	(5.6		)	(5.7		)	(5.1		)	—			—			—
Curtailment loss	—			11.2			9.3			—			—			1.4
Special termination benefits	—			—			1.9			—			—			—
Settlements	—			—			0.7			—			—			—
Amortization of prior service costs	1.1			1.7			4.7			0.2			0.2			0.3
Amortization of actuarial loss	0.8			0.5			0.8			—			—			—
Periodic expense	$	2.7		$	14.7		$	20.2		$	0.4		$	0.4		$	2.0
Components recognized in accumulated other comprehensive income
Current period prior service cost	$	—		$	0.9		$	—		$	—		$	—		$	—
Current period actuarial (gain) loss	8.5			2.2			21.5			0.4			(1.4		)	0.6
Amortization of prior service cost	(1.1		)	(12.9		)	(14.0		)	(0.2		)	(0.2		)	(1.7		)
Amortization of actuarial gain (loss)	(0.8		)	(0.5		)	(0.8		)	—			—			—
Loss on curtailment in current period	—			(7.1		)	(8.2		)	—			—			(0.2		)
Settlements	—			—			(0.7		)	—			—			—
Total amount recognized in accumulated other comprehensive income	$	6.6		$	(17.4	)	$	(2.2	)	$	0.2		$	(1.6	)	$	(1.3	)

Schedule of Assumptions Used [Table Text Block]



	Pension Plan and SERP benefits				Medical Plan benefits
	2016		2015		2016		2015
Discount rate	3.96	%	4.24	%	4.10	%	4.40	%
Rate of increase in compensation⁽¹⁾	3.50	%	4.00	%	3.50	%	4.00	%

_______________________


⁽¹⁾	The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the year ended December 31, 2016, the rate of increase in compensation only includes the SERP and Medical Plan.



	Pension Plan and SERP benefits						Medical Plan benefits
	2016		2015		2014		2016		2015		2014
Discount rate	4.23	%	3.94	%	4.40	%	4.40	%	4.00	%	5.00	%
Expected long-term return on plan assets	6.50	%	6.75	%	7.00	%	n/a		n/a		n/a
Rate of increase in compensation⁽¹⁾	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%

_______________________


⁽¹⁾	The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the year ended December 31, 2016, the rate of increase in compensation only includes the SERP and Medical Plan.

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

The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2016 and 2015, respectively:



	December 31, 2016				December 31, 2015
	Total		Percentage of total		Total		Percentage of total
	(in millions, except percentages)
Cash and short-term investments	$	3.5	4	%	$	0.4	—	%
Equity securities:
Domestic	39.3		46	%	38.5		49	%
International	21.6		25	%	16.8		21	%
Fixed income	21.7		25	%	23.6		30	%
Total investments	$	86.1	100	%	$	79.3	100	%

Schedule of Expected Benefit Payments [Table Text Block]

Expected Benefit Payments

As of December 31, 2016, the following future benefit payments are expected to be paid:



	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2017	$	7.2	$	0.3
2018	$	6.6	$	0.3
2019	$	8.6	$	0.3
2020	$	8.0	$	0.3
2021	$	8.9	$	0.3
2022 through 2026	$	42.3	$	1.4

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

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,
	2016			2015			2014
Federal income tax provision (benefit)	(in millions)
Current	$	(55.5	)	$	(112.3	)	$	(324.0	)
Deferred	(614.3		)	34.5			110.3
State income tax provision (benefit)
Current	(1.5		)	(6.6		)	(15.5		)
Deferred	(36.9		)	(9.2		)	(3.3		)
Total income tax provision (benefit)	$	(708.2	)	$	(93.6	)	$	(232.5	)

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,
	2016		2015		2014
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	2.4	%	4.2	%	(1.5	)%
State rate change	(1.1	)%	—	%	3.4	%
Penalties	—	%	(0.3	)%	—	%
Return to provision adjustment	—	%	(0.3	)%	(0.4	)%
Other	—	%	(0.1	)%	(0.3	)%
Effective income tax rate	36.3	%	38.5	%	36.2	%

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



	December 31,
	2016		2015
Deferred tax liabilities	(in millions)
Property, plant and equipment	$	1,135.0	$	1,531.0
Commodity price derivatives	—		60.4
Total deferred tax liabilities	1,135.0		1,591.4
Deferred tax assets
Net operating loss and tax credit carryforwards	$	161.6	$	51.9
Employee benefits and compensation costs	49.0		43.6
Bonus and vacation accrual	11.4		7.0
Commodity price derivatives	74.3		—
Other	12.8		9.1
Total deferred tax assets	309.1		111.6
Net deferred income tax liability	$	825.9	$	1,479.8
Balance sheet classification
Deferred income tax liability – noncurrent	825.9		1,479.8
Net deferred income tax liability	$	825.9	$	1,479.8

Summary of Operating Loss Carryforwards [Table Text Block]

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2016, are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2017-2033	$	53.6
State net operating loss valuation allowance		(20.6		)
U.S. net operating loss	2036	109.1
U.S. alternative minimum tax credit	Indefinite	19.5
Total		$	161.6

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 years ended December 31, 2016 and 2015:



	Unrecognized Tax Benefits
	2016		2015
	(in millions)
Balance as of January 1,	$	15.6	$	—
Additions for tax positions taken during the current period	—		15.6
Balance as of December 31,	$	15.6	$	15.6

As of December 31, 2016 and 2015, QEP had approximately $15.6 million of unrecognized tax benefit that would impact its effective tax rate if recognized.

Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

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
2016	(in millions, except per share amounts or otherwise specified)
Revenues	$	261.3		$	333.7		$	382.4		$	399.7		$	1,377.1
Operating income (loss)	(1,379.2		)	(92.9		)	(93.6		)	(36.9		)	(1,602.6		)
Net income (loss)	(863.8		)	(197.0		)	(50.9		)	(133.3		)	(1,245.0		)
Net gain (loss) from asset sales and impairment	(1,181.9		)	(1.6		)	0.3			(6.1		)	(1,189.3		)
Nonrecurring items in operating income (loss)⁽¹⁾	7.7			—			25.0			—			32.7
Per share information
Basic EPS	$	(4.55	)	$	(0.90	)	$	(0.21	)	$	(0.56	)	$	(5.62	)
Diluted EPS	(4.55		)	(0.90		)	(0.21		)	(0.56		)	(5.62		)
Production information
Total equivalent production (Mboe)	13,766.4			13,882.4			14,445.7			13,675.7			55,780.2
Total equivalent production (Bcfe)	82.7			83.3			86.6			82.1			334.7



2015
Revenues	$	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		)
Net gain (loss) from asset sales and impairment	(50.5		)	24.0			(2.1		)	(22.4		)	(51.0		)
Nonrecurring items in operating income (loss)⁽¹⁾	—			11.2			—			—			11.2
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		)
Production information
Total equivalent production (Mboe)	12,528.8			13,484.3			14,462.4			13,986.6			54,462.1
Total equivalent production (Bcfe)	75.2			80.9			86.7			84.0			326.8

____________________________


⁽¹⁾	Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2016, and a non-cash pension curtailment incurred during the year ended December 31, 2015.

Supplemental Gas and Oil Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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



	December 31,
	2016			2015
	(in millions)
Proved properties	$	14,232.5		$	13,314.9
Unproved properties, net	871.5			691.0
Total proved and unproved properties	15,104.0			14,005.9
Accumulated depreciation, depletion and amortization	(8,797.7		)	(6,870.2		)
Net capitalized costs	$	6,306.3		$	7,135.7

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



	Year Ended December 31,
	2016		2015		2014
	(in millions)
Proved property acquisitions	$	431.6	$	49.6	$	465.4
Unproved property acquisitions	208.7		39.8		496.3
Exploration (capitalized and expensed)	13.4		8.7		23.6
Development	509.2		1,010.3		1,695.1
Total costs incurred	$	1,162.9	$	1,108.4	$	2,680.4

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

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



	Year Ended December 31,
	2016			2015			2014
	(in millions)
Revenues	$	1,271.0		$	1,390.4		$	2,374.6
Production costs	616.7			654.1			735.6
Exploration expenses	1.7			2.7			9.9
Depreciation, depletion and amortization	852.3			870.8			984.4
Impairment	1,194.3			55.6			1,143.2
Total expenses	2,665.0			1,583.2			2,873.1
Income (loss) before income taxes	(1,394.0		)	(192.8		)	(498.5		)
Income tax benefit (expense)	517.2			70.6			182.5
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(876.8	)	$	(122.2	)	$	(316.0	)

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



	Oil		Gas		NGL		Total⁽¹³⁾
	(MMbbl)		(Bcf)		(MMbbl)		(MMboe)
Balance at December 31, 2013	148.6		2,554.9		102.6		677.0
Revisions of previous estimates⁽¹⁾	(4.0	)	27.1		1.4		1.9
Extensions and discoveries⁽²⁾	16.8		141.4		8.6		49.0
Purchase of reserves in place⁽³⁾	35.7		72.5		12.3		60.1
Sale of reserves in place⁽⁴⁾	(7.5	)	(299.4	)	(21.5	)	(78.9	)
Production	(17.1	)	(179.3	)	(6.8	)	(53.8	)
Balance at December 31, 2014	172.5		2,317.2		96.6		655.3
Revisions of previous estimates⁽⁵⁾	(47.0	)	(463.8	)	(55.3	)	(179.6	)
Extensions and discoveries⁽⁶⁾	85.6		467.7		21.8		185.4
Purchase of reserves in place⁽⁷⁾	2.0		3.2		0.6		3.1
Sale of reserves in place⁽⁸⁾	(0.4	)	(34.3	)	(0.2	)	(6.3	)
Production	(19.6	)	(181.1	)	(4.7	)	(54.5	)
Balance at December 31, 2015	193.1		2,108.9		58.8		603.4
Revisions of previous estimates⁽⁹⁾	(9.7	)	412.8		(0.3	)	58.8
Extensions and discoveries⁽¹⁰⁾	13.0		158.1		3.3		42.6
Purchase of reserves in place⁽¹¹⁾	62.7		54.6		11.5		83.3
Sale of reserves in place⁽¹²⁾	(0.2	)	(3.6	)	(0.1	)	(0.9	)
Production	(20.3	)	(177.0	)	(6.0	)	(55.8	)
Balance at December 31, 2016	238.6		2,553.8		67.2		731.4
Proved developed reserves
Balance at December 31, 2013	71.8		1,406.3		52.8		359.0
Balance at December 31, 2014	99.3		1,288.4		52.2		366.2
Balance at December 31, 2015	109.7		1,245.3		34.4		351.6
Balance at December 31, 2016	103.2		1,309.8		35.7		357.2
Proved undeveloped reserves
Balance at December 31, 2013	76.8		1,148.6		49.8		318.0
Balance at December 31, 2014	73.2		1,028.8		44.4		289.1
Balance at December 31, 2015	83.4		863.6		24.4		251.8
Balance at December 31, 2016	135.4		1,244.0		31.5		374.2

___________________________

⁽¹⁾


⁽²⁾	Extensions and discoveries in 2014 increased proved reserves by 49.0 MMboe, primarily related to extensions and discoveries in Pinedale of 22.3 MMboe and the Williston Basin of 20.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations as well as new compression well projections in Pinedale.


⁽³⁾	Purchase of reserves in place in 2014 relate to the Company's 2014 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.


⁽⁴⁾	Sale of reserves in place primarily related to property sales in the Other Southern area in the second and fourth quarters of 2014 as discussed in Note 2 – Acquisitions and Divestitures.


⁽⁵⁾	Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin.


⁽⁶⁾	Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations.


⁽⁷⁾	Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston Basin as discussed in Note 2 – Acquisitions and Divestitures.


⁽⁸⁾	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.

⁽⁹⁾


⁽¹⁰⁾	Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.


⁽¹¹⁾	Purchase of reserves in place in 2016 relate primarily to the Company's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.


⁽¹²⁾	Sale of reserves in place in 2016 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,
	2016		2015		2014
Average benchmark price per unit:
Oil price (per bbl)	$	42.75	$	50.28	$	94.99
Gas price (per MMBtu)	$	2.48	$	2.59	$	4.35

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,
	2016			2015			2014
	(in millions)
Future cash inflows	$	16,239.8		$	15,325.3		$	28,167.3
Future production costs	(7,789.0		)	(7,389.9		)	(9,842.1		)
Future development costs	(3,432.9		)	(2,202.5		)	(3,521.3		)
Future income tax expenses	(913.4		)	(1,169.3		)	(4,304.0		)
Future net cash flows	4,104.5			4,563.6			10,499.9
10% annual discount for estimated timing of net cash flows	(2,176.5		)	(2,087.3		)	(5,159.9		)
Standardized measure of discounted future net cash flows	$	1,928.0		$	2,476.3		$	5,340.0

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,
	2016			2015			2014
	(in millions)
Balance at January 1,	$	2,476.3		$	5,340.0		$	4,383.9
Sales of oil, gas and NGL produced, net of production costs	(654.3		)	(736.3		)	(1,639.0		)
Net change in sales prices and in production (lifting) costs related to future production	(739.4		)	(6,307.8		)	726.6
Net change due to extensions and discoveries	81.8			1,765.7			979.9
Net change due to revisions of quantity estimates	122.7			(1,350.2		)	35.9
Net change due to purchases of reserves in place	256.5			29.7			695.3
Net change due to sales of reserves in place	(4.3		)	(48.8		)	(1,153.7		)
Previously estimated development costs incurred during the period	374.6			865.0			867.5
Changes in estimated future development costs	(476.5		)	560.7			409.6
Accretion of discount	311.1			752.9			597.3
Net change in income taxes	205.4			1,554.4			(600.3		)
Other	(25.9		)	51.0			37.0
Net change	(548.3		)	(2,863.7		)	956.1
Balance at December 31,	$	1,928.0		$	2,476.3		$	5,340.0

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62352-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62246-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62136-109447

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=50486907&loc=d3e511914-122862

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62259-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62395-109447

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=34713648&loc=d3e63071-109448

+ Details

- Definition

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

+ References + Details

- Definition

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

+ References + Details

Summary of Significant Accounting Policies Changes in Segment Reporting due to Discontinued Operations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($)
Discontinued Operations and Disposal Groups [Abstract]
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

Summary of Significant Accounting Policies Equity Offerings (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Offering [Line Items]
Proceeds from issuance of common stock, net	$ 781.4	$ 0.0	$ 0.0
Share Issuance - March 2016 [Member]
Equity Offering [Line Items]
Shares Issued	37,950
Proceeds from issuance of common stock, net	$ 368.5
Share Issuance - June 2016 [Member]
Equity Offering [Line Items]
Shares Issued	23,000
Proceeds from issuance of common stock, net	$ 412.9

Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Line Items]
Unrestricted Cash	$ 443.8	$ 376.1
Restricted cash	21.6	18.1
Supplemental Disclosures
Cash paid for interest, net of capitalized interest	139.1	139.4	$ 163.2
Cash paid (refund received) for income taxes, net	(123.5)	487.8	0.3
Non-cash investing activities
Change in capital expenditure accrual balance	$ (32.8)	$ (129.2)	$ 8.4

Summary of Significant Accounting Policies Accounts Receivable (Details) - Allowance for Doubtful Accounts [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Bad Debt Expense	$ 1.8	$ 0.5	$ 2.1
Allowance for Doubtful Accounts Receivable	$ 4.8	$ 3.9

Summary of Significant Accounting Policies Property, plant and equipment (Details)	12 Months Ended
	Dec. 31, 2016
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 1,194.3	$ 55.6	$ 1,143.2
Williston Basin [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			5.8
Pinedale [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	1,164.0
Uinta Basin [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	4.7		3.6
Other Northern [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	3.4	18.4	13.5
Permian Basin [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		0.7
Haynesville/Cotton Valley [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			532.1
Other Southern [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	0.6	20.2	18.7
Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	1,172.7	39.3	1,041.4
Unproved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	17.9	2.0	$ 101.8
Goodwill [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 3.7	$ 14.3

Summary of Significant Accounting Policies Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Goodwill	$ 3.7	$ 14.3
Goodwill [Member]
Goodwill [Line Items]
Impairment of Oil and Gas Properties	$ 3.7	$ 14.3

Summary of Significant Accounting Policies Credit Risk (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Concentration Risk [Line Items]
Concentration Risk, Percentage	48.00%	30.00%	33.00%
Shell Trading Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	14.00%
BP Energy Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
Valero Marketing And Supply Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%		10.00%
No Customer [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%

Summary of Significant Accounting Policies Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Changes and Error Corrections [Abstract]
Unrecognized Tax Benefits	$ 15.6	$ 15.6	$ 0.0
Interest Related to Uncertain Tax Positions	0.7	0.5
Penalties Related to Uncertain Tax Positions	$ 0.6	$ 2.2

Summary of Significant Accounting Policies Share Repurchases And Retirements (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive shares excluded from computation of EPS	0.1		0.3
Used in basic calculation	221.7	176.6	179.8
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan	0.0	0.0	0.0
Average diluted common shares outstanding (in shares)	221.7	176.6	179.8

Acquisitions and Divestitures (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) a	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) a
Significant Acquisitions and Disposals [Line Items]
Bargain purchase gain from acquisition	$ (22.6)	$ 0.0	$ 0.0
Goodwill	3.7	14.3
Payments to Acquire Oil and Gas Property	639.0	98.3	960.5
Proceeds from Sale of Oil and Gas Property and Equipment	29.0	21.8	3,296.6
2015 Divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Gain (Loss) on Sale of Properties, before Applicable Income Taxes	(0.9)
2014 Divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Gain (Loss) on Sale of Properties, before Applicable Income Taxes	0.6	(9.3)
Non-core properties divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	29.0	31.7	783.8
Gain (Loss) on Sale of Properties, before Applicable Income Taxes	8.4	21.0	(147.0)
Goodwill [Member]
Significant Acquisitions and Disposals [Line Items]
Impairment of Oil and Gas Properties	3.7	14.3
2016 Permian Basin Acquisition [Member]
Significant Acquisitions and Disposals [Line Items]
Aggregate purchase price	$ 590.6
Net acres of producing and undeveloped oil and gas properties \| a	9,600
Revenue of acquired properties since acquisition date	$ 3.8
Net income (loss) of acquired properties since acquisition date	(0.7)
Acquisition Related Costs	2.3
Bargain purchase gain from acquisition	18.2
Recognized identifiable assets acquired and liabilities assumed, net	(590.6)
2016 Permian Basin Acquisition [Member] \| Bargain Purchase Gain [Member]
Significant Acquisitions and Disposals [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	18.2
2014 Permian Basin Acquisition [Member]
Significant Acquisitions and Disposals [Line Items]
Aggregate purchase price			$ 941.8
Vertical producing oil and gas wells			270
Net acres of producing and undeveloped oil and gas properties \| a			26,500
Revenue of acquired properties since acquisition date	186.0	149.9	$ 159.5
Net income (loss) of acquired properties since acquisition date	(13.2)	(2.8)	(438.3)
Recognized identifiable assets acquired and liabilities assumed, net			(941.8)
Impairment of Oil and Gas Properties			467.7
Williston & Permian Basins [Member]
Significant Acquisitions and Disposals [Line Items]
Aggregate purchase price	54.6	98.3
Bargain purchase gain from acquisition	4.4
Goodwill	$ 3.7	$ 14.3
Other Northern & Uinta Basin [Member]
Significant Acquisitions and Disposals [Line Items]
Aggregate purchase price			$ 18.7

Acquisitions and Divestitures 2016 Permian Basin Purchase Accounting Entries (Details) - 2016 Permian Basin Acquisition [Member] $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Business Acquisition [Line Items]
Aggregate purchase price	$ 590.6
Recognized identifiable assets acquired and liabilities assumed, net	590.6
Proved Property [Member]
Business Acquisition [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	406.2
Unproved Property [Member]
Business Acquisition [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	214.2
Asset Retirement Obligation Costs [Member]
Business Acquisition [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	(11.6)
Bargain Purchase Gain [Member]
Business Acquisition [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	$ (18.2)

Acquisitions and Divestitures 2016 Permian Basin Acquisition Pro Forma Results (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Oil and Gas Revenue	$ 399.7	$ 382.4	$ 333.7	$ 261.3	$ 468.3	$ 507.6	$ 574.6	$ 468.1	$ 1,377.1	$ 2,018.6	$ 3,293.2
Net income (loss)	$ (133.3)	$ (50.9)	$ (197.0)	$ (863.8)	$ (38.6)	$ 21.1	$ (76.3)	$ (55.6)	$ (1,245.0)	$ (149.4)	$ 784.4
Earnings Per Share, Basic	$ (0.56)	$ (0.21)	$ (0.90)	$ (4.55)	$ (0.22)	$ 0.12	$ (0.43)	$ (0.32)	$ (5.62)	$ (0.85)	$ 4.36
Earnings Per Share, Diluted	$ (0.56)	$ (0.21)	$ (0.90)	$ (4.55)	$ (0.22)	$ 0.12	$ (0.43)	$ (0.32)	$ (5.62)	$ (0.85)	$ 4.36
2016 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Oil and Gas Revenue									$ 1,377.1	$ 2,018.6
Net income (loss)									$ (1,245.0)	$ (149.4)
Earnings Per Share, Basic									$ (5.62)	$ (0.85)
Earnings Per Share, Diluted									$ (5.62)	$ (0.85)
Business Acquisition, Pro Forma Revenue									$ 1,392.5	$ 2,041.5
Business Acquisition, Pro Forma Net Income (Loss)									$ (1,246.8)	$ (152.5)
Business Acquisition, Pro Forma Earnings Per Share, Basic									$ (5.62)	$ (0.86)
Business Acquisition, Pro Forma Earnings Per Share, Diluted									$ (5.62)	$ (0.86)

Acquisitions and Divestitures Schedule Of Purchase Accounting Entries (Details) - 2014 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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Revenues	$ 399.7	$ 382.4	$ 333.7	$ 261.3	$ 468.3	$ 507.6	$ 574.6	$ 468.1	$ 1,377.1	$ 2,018.6	$ 3,293.2
Net income (loss)	$ (133.3)	$ (50.9)	$ (197.0)	$ (863.8)	$ (38.6)	$ 21.1	$ (76.3)	$ (55.6)	$ (1,245.0)	$ (149.4)	$ 784.4
Earnings Per Share, Basic	$ (0.56)	$ (0.21)	$ (0.90)	$ (4.55)	$ (0.22)	$ 0.12	$ (0.43)	$ (0.32)	$ (5.62)	$ (0.85)	$ 4.36
Earnings Per Share, Diluted	$ (0.56)	$ (0.21)	$ (0.90)	$ (4.55)	$ (0.22)	$ 0.12	$ (0.43)	$ (0.32)	$ (5.62)	$ (0.85)	$ 4.36
2014 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Revenues											$ 3,293.2
Net income (loss)											$ 784.4
Earnings Per Share, Basic											$ 4.36
Earnings Per Share, Diluted											$ 4.36
Business Acquisition, Pro Forma Revenue											$ 3,319.3
Business Acquisition, Pro Forma Net Income (Loss)											$ 791.4
Business Acquisition, Pro Forma Earnings Per Share, Basic											$ 4.40
Business Acquisition, Pro Forma Earnings Per Share, Diluted											$ 4.40

Discontinued Operations (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 137.9	$ 131.8	145.3
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
Payments to Acquire Oil and Gas Property and Equipment			$ 55.2

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

3 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

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

NGL sales

$ 83.5

$ 80.0

$ 223.3

Other revenues

6.2

15.1

11.1

Purchased oil, gas and NGL sales

101.2

620.8

913.9

Total Revenues

$ 399.7

$ 382.4

$ 333.7

$ 261.3

$ 468.3

$ 507.6

$ 574.6

$ 468.1

1,377.1

2,018.6

3,293.2

Purchased oil, gas and NGL expense

(105.5)

(626.8)

(910.1)

Lease operating expense

(224.7)

(238.8)

(240.1)

Oil, gas and NGL transportation and other handling costs

(289.2)

(291.3)

(277.6)

Gathering and other expense

5.0

5.8

6.7

General and administrative

198.4

181.1

204.4

Production and property taxes

94.8

117.6

205.2

Total Operating Expenses

2,984.7

2,400.8

3,991.9

Net gain (loss) from asset sales

5.0

4.6

(148.6)

OPERATING INCOME (LOSS)

$ (36.9)

$ (93.6)

$ (92.9)

$ (1,379.2)

$ (144.6)

$ (87.7)

$ (16.7)

$ (128.6)

(1,602.6)

(377.6)

(847.3)

Realized and unrealized gains (losses) on derivative contracts

(233.0)

277.2

363.3

Interest and other income

25.6

3.0

12.8

Income from unconsolidated affiliates

0.0

0.3

Loss from early extinguishment of debt

0.0

(2.0)

Interest expense

143.2

145.6

169.1

Net income attributable to noncontrolling interest

0.0

21.6

NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX

$ 0.0

1,193.9

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

^[1]

$ 28.9

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

NGL sales

109.3

Other revenues

140.9

Purchased oil, gas and NGL sales

^[2]

(47.1)

Total Revenues

203.1

Purchased oil, gas and NGL expense

^[2]

(48.5)

Lease operating expense

^[2]

(5.5)

Oil, gas and NGL transportation and other handling costs

^[2]

(55.4)

Gathering and other expense

85.9

General and administrative

42.1

Production and property taxes

7.3

Depreciation, depletion and amortization

45.9

Total Operating Expenses

71.8

Net gain (loss) from asset sales

1,793.4

OPERATING INCOME (LOSS)

1,924.7

Interest and other income

0.3

Income from unconsolidated affiliates

4.9

Loss from early extinguishment of debt

(2.4)

Interest Income (Expense), Net

(3.8)

INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES

^[1]

1,923.7

Income taxes

(708.2)

NET INCOME FROM DISCONTINUED OPERATIONS

1,215.5

Net income attributable to noncontrolling interest

(21.6)

NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX

$ 1,193.9

[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 for the year ended December 31, 2014.
[2]	Includes discontinued intercompany eliminations.

Capitalized Exploratory Well Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Capitalized Exploratory Well Costs [Abstract]
Beginning Balance	$ 2.6	$ 12.6	$ 2.6
Additions to capitalized exploratory well costs pending the determination of proved reserves	11.7	6.0	13.7
Reclassifications to proved properties after the determination of proved reserves	0.0	(16.0)	0.0
Capitalized exploratory well costs charged to expense	(0.1)	0.0	3.7
Ending Balance	$ 14.2	$ 2.6	$ 12.6

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset retirement obligation, current	$ 5.8	$ 1.9
Asset retirement obligations, noncurrent	225.8	204.9
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	206.8	195.1
Accretion	8.9	8.7
Liabilities incurred	17.0	3.8
Revisions of Estimates	6.5	17.2
Liabilities related to assets sold	0.0	(16.0)
Liabilities settled	(7.6)	(2.0)
ARO liability, Ending Balance	231.6	$ 206.8
Permian Basin Acquisition [Member]
ARO Liability [Roll Forward]
Liabilities incurred	$ 11.6

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Proved properties [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Impairment of Oil and Gas Properties	$ 1,172.7	$ 39.3	$ 1,041.4

Fair Value of Financial Assets and Liabilities (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Financial Assets
Derivative instruments	$ 0.0	$ 170.0
Financial liabilities
Derivative instruments	201.8	4.8
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	0.0	171.0
Financial liabilities
Derivative instruments	201.8	5.8
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	0.0	(1.0)
Financial liabilities
Derivative instruments	0.0	(1.0)
Long term [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments	0.0	23.2
Financial liabilities
Derivative instruments	32.0	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	0.0	23.2
Financial liabilities
Derivative instruments	32.0	4.0
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	0.0
Short term [Member] \| Commodity Contract [Member]
Financial Assets
Derivative instruments	0.0	146.8
Financial liabilities
Derivative instruments	169.8	0.8
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	0.0	147.8
Financial liabilities
Derivative instruments	169.8	1.8
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	0.0	(1.0)
Financial liabilities
Derivative instruments	$ 0.0	$ (1.0)

Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 443.8	$ 376.1
Checks outstanding in excess of cash balances	12.3	29.8
Long-term Debt, Gross	2,020.9	2,191.5
Long-term Debt	2,020.9	2,014.7
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	443.8	376.1
Checks outstanding in excess of cash balances	12.3	29.8
Long-term debt	$ 2,104.3	$ 1,784.6

Derivative Contracts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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) bbl in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) MMBTU bbl $ / MMBTU $ / bbl
Oil Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount \| bbl	13.5
Underlying, Derivative Asset \| $ / bbl	51.39
Oil Swaps [Member] \| Production [Member] \| Year 2018 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount \| bbl	7.3
Underlying, Derivative Asset \| $ / bbl	53.40
Gas Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	94.9
Underlying, Derivative Asset \| $ / MMBTU	2.86
Gas Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	32.9
Underlying, Derivative Asset \| $ / MMBTU	2.51
Gas Swaps [Member] \| Production [Member] \| Year 2018 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	62.1
Underlying, Derivative Asset \| $ / MMBTU	2.96
Gas Swaps [Member] \| Storage [Member] \| Year 2017 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4.0
Underlying, Derivative Asset \| $ / MMBTU	2.88
Gas Collars [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	11.0
Derivative Average Price Floor \| $	$ 2.50
Derivative Average Price Ceiling \| $	$ 3.50
Oil Basis Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2.9
Derivatives, Weighted Average Differential \| $	$ (0.64)
Oil Basis Swaps [Member] \| Production [Member] \| Year 2018 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2.2
Derivatives, Weighted Average Differential \| $	$ (0.90)
Gas Basis Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX HH less IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	51.1
Derivatives, Weighted Average Differential \| $	$ (0.18)
Gas Basis Swaps [Member] \| Production [Member] \| Year 2018 [Member] \| NYMEX HH less IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7.3
Derivatives, Weighted Average Differential \| $	$ (0.16)

Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative instruments - assets	$ 0.0	$ 170.0
Derivative instruments - liabilities	201.8	4.8
Commodity Contract [Member] \| Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	0.0	146.8
Derivative instruments - liabilities	169.8	0.8
Commodity Contract [Member] \| Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	0.0	23.2
Derivative instruments - liabilities	32.0	4.0
Fair Value, Inputs, Level 2 [Member]
Derivative [Line Items]
Derivative instruments - assets	0.0	171.0
Derivative instruments - liabilities	201.8	5.8
Fair Value, Inputs, Level 2 [Member] \| Commodity Contract [Member] \| Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	0.0	147.8
Derivative instruments - liabilities	169.8	1.8
Fair Value, Inputs, Level 2 [Member] \| Commodity Contract [Member] \| Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	0.0	23.2
Derivative instruments - liabilities	$ 32.0	$ 4.0

Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) derivative contracts not designated as hedging instruments	$ 134.0	$ 460.9	$ (11.1)
Unrealized gain (loss) derivative contracts not designated as hedging instruments	(367.0)	(183.7)	374.4
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(233.0)	277.2	363.3
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	134.0	460.9	(3.5)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(367.0)	(183.7)	372.4
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	(233.0)	277.2	368.9
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	0.0	(7.6)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.0	2.0
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	0.0	0.0	(5.6)
Oil derivative contracts [Member] \| Production [Member] \| 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	86.3	353.7	15.7
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(217.2)	(244.9)	299.8
Gas derivative contracts [Member] \| Production [Member] \| 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	44.8	103.4	(16.7)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(145.4)	62.0	68.4
Gas derivative contracts [Member] \| Storage [Member] \| 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	2.9	3.8	(2.5)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	$ (4.4)	$ (0.8)	$ 4.2

Restructuring Costs (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Denver Restructuring [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, percentage of reduction	6.00%
Restructuring costs, costs incurred	$ 1.9
Denver Restructuring [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, costs incurred	1.9
Tulsa Office Closure [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, costs incurred		$ 8.3
Tulsa Office Closure [Member] \| Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, costs incurred	$ 0.6	3.0
Tulsa Office Closure [Member] \| Special Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, costs incurred		$ 5.3

Debt (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
Debt (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
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 Line of Credit	$ 1,800.0
Letters of Credit Outstanding, Amount	$ 2.8	$ 3.4
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%
Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Mar. 01, 2020
Debt Instrument, Interest Rate, Stated Percentage	6.80%
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Mar. 01, 2021
Debt Instrument, Interest Rate, Stated Percentage	6.875%

Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total principal amount of debt	$ 2,020.9	$ 2,191.5
Less unamortized discount	(24.1)	(30.3)
Long-term Debt, Excluding Current Maturities	2,020.9	2,014.7
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	0.0	176.8
6.80% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	134.0	134.0
Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	136.0	136.0
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	$ 0.0	$ (176.8)

Commitments and Contingencies Litigation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Overriding Royalty Interest	4.00%
Litigation Settlement, Amount	$ 16.7
Loss Contingency, Range of Possible Loss, Minimum	0.0
Loss Contingency, Estimate of Possible Loss, Maximum	$ 25.0

Commitments and Contingencies Other Commitments (Details) $ in Millions	Dec. 31, 2016 USD ($)
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 130.7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	111.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	104.5
Unrecorded Unconditional Purchase Obligation, Due within Four Years	87.8
Unrecorded Unconditional Purchase Obligation, Due within Five Years	51.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 207.8

Commitments and Contingencies Long-term Operating lease commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating lease commitments [Abstract]
Operating Leases, Rent Expense	$ 9.1	$ 8.0	$ 8.2
Operating Leases, Future Minimum Payments Due, Next Twelve Months	8.7
Operating Leases, Future Minimum Payments, Due in Two Years	7.2
Operating Leases, Future Minimum Payments, Due in Three Years	7.1
Operating Leases, Future Minimum Payments, Due in Four Years	6.9
Operating Leases, Future Minimum Payments, Due in Five Years	7.0
Operating Leases, Future Minimum Payments, Due Thereafter	$ 11.2

Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 35.6	$ 34.7	$ 22.1
Shares available for future grants	7.1
Share-based compensation	$ 35.6	34.7	27.9
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	2.3	2.9	3.3
Intrinsic value of options exercised		0.1	$ 0.6
Tax benefit from equity-based compensation expense	0.2	$ (6.4)
Adjustment to additional paid In capital resulting from income tax effect of share-based compensation	0.3
Unrecognized compensation costs	$ 1.2
Weighted average period for recognition of equity-based compensation expense		1 year 10 months 1 day
Weighted average grant date fair value	$ 3.77	$ 6.82	$ 10.11
Restricted Share Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 10.50
Share-based compensation expense	$ 23.7	$ 25.6	$ 18.1
Adjustment to additional paid In capital resulting from income tax effect of share-based compensation	3.5
Unrecognized compensation costs	$ 17.5
Weighted average period for recognition of equity-based compensation expense	1 year 11 months 22 days
Award vesting period	3 years
Total fair value of stock that vested during the period	$ 24.3	22.7	26.8
Income tax expense (benefit) related to restricted stock compensation		$ (3.2)	$ 0.5
Weighted average grant date fair value	$ 10.50	$ 20.92	$ 31.40
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 10.16
Share-based compensation expense	$ 9.4	$ 6.2	$ 0.7
Unrecognized compensation costs	$ 12.3
Weighted average period for recognition of equity-based compensation expense	1 year 10 months 6 days
Weighted average grant date fair value	$ 10.16	$ 21.69	$ 31.57
Restricted Share Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 10.12
Share-based compensation expense	$ 0.2	$ 0.0	$ 0.0
Unrecognized compensation costs	$ 0.1
Weighted average period for recognition of equity-based compensation expense	1 year 3 months 27 days
Continuing Operations [Member] \| Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 2.8	$ 3.1	1.7
Discontinued Operations [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense			5.8
Discontinued Operations [Member] \| Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid			$ 0.5

Share-Based Compensation Schedule of Share-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Expense [Line Items]
Share-based compensation expense	$ 35.6	$ 34.7	$ 22.1
Stock Options [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	2.3	2.9	3.3
Restricted Share Awards [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	23.7	25.6	18.1
Performance Share Units [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	9.4	6.2	0.7
Restricted Share Units (RSUs) [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	$ 0.2	$ 0.0	0.0
Discontinued Operations [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense			$ 5.8

Share-Based Compensation Fair Value of Options Granted and Major Assumptions Used (Details) - Stock Options [Member] - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value	$ 3.77	$ 6.82	$ 10.11
Risk free interest rate, minimum	0.99%	1.38%	1.31%
Risk free interest rate, maximum	1.15%	1.38%	1.34%
Weighted average risk-free interest rate	1.20%	1.40%	1.30%
Expected price volatility range, minimum	43.42%	36.80%	36.10%
Expected price volatility range, maximum	43.66%	36.80%	37.30%
Weighted average expected price volatility	43.40%	36.80%	37.10%
Expected dividend yield	0.00%	0.37%	0.25%
Expected term in years at the date of grant	4 years 6 months	4 years 6 months	4 years 6 months

Share-Based Compensation Schedule of Stock Option Transactions (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Stock options outstanding, beginning of year \| shares	2,200,776
Options granted \| shares	438,180
Options Cancelled \| shares	(486,999)
Stock options outstanding, end of year \| shares	2,151,957
Options exercisable, shares \| shares	1,385,753
Unvested options, shares \| shares	766,204
Share-based Compensation Arrangement by Share-based Payment Award, Additional General Disclosures [Abstract]
Weighted average exercise price, beginning of year \| $ / shares	$ 27.94
Weighted average exercise price, granted in period \| $ / shares	10.14
Weighted average exercise price, cancelled in period \| $ / shares	23.77
Weighted average exercise price, end of year \| $ / shares	25.26
Options exercisable, weighted average exercise price \| $ / shares	30.18
Unvested options, weighted average exercise price \| $ / shares	$ 16.38
Weighted average remaining contractual term, options outstanding	3 years 7 months 28 days
Weighted average remaining contractual term, options exercisable	2 years 7 months 10 days
Weighted average remaining contractual term, options unvested	5 years 6 months 24 days
Aggregate intrinsic value, options outstanding \| $	$ 3.6
Aggregate intrinsic value, options exercisable \| $	0.1
Aggregate intrinsic value, options unvested \| $	$ 3.5

Share-Based Compensation Schedule of Restricted Stock Transactions (Details) - Restricted Share Awards [Member]	12 Months Ended
	Dec. 31, 2016 $ / 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	2,008,210
Shares granted \| shares	2,467,954
Shares vested \| shares	(973,307)
Shares forfeited \| shares	(294,354)
Unvested balance at end of period \| shares	3,208,503
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	$ 24.18
Weighted average grant date fair value, grants \| $ / shares	10.50
Weighted average grant date fair value, vested \| $ / shares	25.01
Weighted average grant date fair value, forfeited \| $ / shares	14.26
Weighted average grant date fair value, end of period \| $ / shares	$ 14.32

Share-Based Compensation Schedule of Performance Share Unit Transactions (Details) - Performance Share Units [Member]	12 Months Ended
	Dec. 31, 2016 $ / 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	630,786
Shares granted \| shares	597,185
Shares vested and paid out \| shares	(178,169)
Shares forfeited \| shares	(22,522)
Unvested balance at end of period \| shares	1,027,280
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	$ 27.50
Weighted average grant date fair value, grants \| $ / shares	10.16
Weighted average grant date fair value, vested and paid out \| $ / shares	30.07
Weighted average grant date fair value, forfeited \| $ / shares	15.16
Weighted average grant date fair value, end of period \| $ / shares	$ 17.24

Share-Based Compensation Schedule of Restricted Share Unit Transactions (Details) - Restricted Share Units (RSUs) [Member]	12 Months Ended
	Dec. 31, 2016 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested balance at beginning of period \| shares	0
Shares granted \| shares	21,493
Shares vested \| shares	(193)
Shares forfeited \| shares	(3,266)
Unvested balance at end of period \| shares	18,034
Weighted average grant date fair value, beginning of period \| $ / shares	$ 0.00
Weighted average grant date fair value, grants \| $ / shares	10.12
Weighted average grant date fair value, vested \| $ / shares	10.12
Weighted average grant date fair value, forfeited \| $ / shares	10.12
Weighted average grant date fair value, end of period \| $ / shares	$ 10.12

Employee Benefits (Narrative) (Details) $ in Millions	12 Months Ended
Employee Benefits (Narrative) (Details) $ in Millions	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 124.5	$ 117.4
Pension Plan and SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match		100.00%	100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent		6.00%	6.00%
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	6.00%
Employee Investment Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%	100.00%	100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	8.00%	8.00%	8.00%
Defined Contribution Plan, Cost Recognized	$ 5.6	$ 6.3	$ 7.6
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Contributions by Employer	4.0
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	$ 4.0
Defined Benefit Plan, Curtailment loss		11.2	10.7
Defined Benefit Plan, Special termination benefits			1.9
Pension Plan [Member] \| Active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Employees Covered	41
Defined Benefit Plan, Percentage Of Employees Covered	6.00%
Pension Plan [Member] \| Non-active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Employees Covered	173
Pension Plan and SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Contributions by Employer	$ 7.2	7.5
Defined Benefit Plan, Curtailment loss	0.0	11.2	9.3
Defined Benefit Plan, Special termination benefits	0.0	0.0	1.9
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year	$ 2.2
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Eligible	25
Defined Benefit Plan, Number of Employees Covered	50
Defined Benefit Plan, Contributions by Employer	$ 0.4	0.2
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	0.3
Defined Benefit Plan, Curtailment loss	0.0	0.0	1.4
Defined Benefit Plan, Special termination benefits	0.0	$ 0.0	$ 0.0
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year	0.2
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Contributions by Employer	3.2
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	$ 2.5

Employee Benefits Schedule of Changes in Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	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	$ 79.3
Fair value of plan assets, end of period	86.1	$ 79.3
Pension Plan and SERP [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	120.3	132.6
Service cost	1.2	2.1	$ 2.6
Interest cost	5.2	4.9	5.3
Loss on curtailment in current period	0.0	(7.1)
Benefit payments	(7.8)	(7.7)
Defined Benefit Plan, Plan Amendments	0.0	0.9
Actuarial loss (gain)	10.3	(5.4)
Benefit obligation, end of period	129.2	120.3	132.6
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of period	79.3	81.4
Actual gain on plan assets	7.4	(1.9)
Company contributions to the plan	7.2	7.5
Benefit payments	(7.8)	(7.7)
Fair value of plan assets, end of period	86.1	79.3	81.4
Underfunded status (current and long-term)	(43.1)	(41.0)
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Amounts included in accounts payable and accrued expenses	(2.5)	(2.9)
Amounts included in other long-term liabilities	(40.6)	(38.1)
Total amount recognized in balance sheets	(43.1)	(41.0)
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net actuarial loss (gain)	23.5	15.8
Prior service cost	2.9	4.1
Total amount recognized in AOCI	26.4	19.9
Medical Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	5.2	6.6
Service cost	0.0	0.0	0.0
Interest cost	0.2	0.2	0.3
Loss on curtailment in current period	0.0	0.0
Benefit payments	(0.4)	(0.2)
Defined Benefit Plan, Plan Amendments	0.0	0.0
Actuarial loss (gain)	0.4	(1.4)
Benefit obligation, end of period	5.4	5.2	6.6
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of period	0.0	0.0
Actual gain on plan assets	0.0	0.0
Company contributions to the plan	0.4	0.2
Benefit payments	(0.4)	(0.2)
Fair value of plan assets, end of period	0.0	0.0	$ 0.0
Underfunded status (current and long-term)	(5.4)	(5.2)
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Amounts included in accounts payable and accrued expenses	(0.3)	(0.3)
Amounts included in other long-term liabilities	(5.1)	(4.9)
Total amount recognized in balance sheets	(5.4)	(5.2)
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net actuarial loss (gain)	(0.4)	(0.8)
Prior service cost	1.0	1.2
Total amount recognized in AOCI	$ 0.6	$ 0.4

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, 2016

Dec. 31, 2015

Dec. 31, 2014

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

Current period prior service cost

^[1]

$ 0.0

$ 0.6

$ 0.0

Pension Plan and SERP [Member]

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

Service cost

1.2

2.1

2.6

Interest cost

5.2

4.9

5.3

Expected return on plan assets

(5.6)

(5.7)

(5.1)

Curtailment loss

0.0

11.2

9.3

Special termination benefits

0.0

1.9

Settlements

0.0

0.7

Amortization of prior service costs

1.1

1.7

4.7

Amortization of actuarial loss

0.8

0.5

0.8

Periodic expense

2.7

14.7

20.2

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

Current period prior service cost

0.0

0.9

0.0

Current period actuarial (gain) loss

8.5

2.2

21.5

Amortization of prior service cost

(1.1)

(12.9)

(14.0)

Amortization of actuarial gain (loss)

(0.8)

(0.5)

(0.8)

Loss on curtailment in current period

0.0

(7.1)

Loss on curtailment in current period

0.0

(7.1)

(8.2)

Settlements

0.0

0.7

Total amount recognized in accumulated other comprehensive income

0.0

(0.7)

Other Comprehensive Income (Loss), before Tax

6.6

(17.4)

(2.2)

Medical Plan [Member]

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

Service cost

0.0

Interest cost

0.2

0.3

Expected return on plan assets

0.0

Curtailment loss

0.0

1.4

Special termination benefits

0.0

Settlements

0.0

Amortization of prior service costs

0.2

0.3

Amortization of actuarial loss

0.0

Periodic expense

0.4

2.0

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

Current period prior service cost

0.0

Current period actuarial (gain) loss

0.4

(1.4)

0.6

Amortization of prior service cost

(0.2)

(1.7)

Amortization of actuarial gain (loss)

0.0

Loss on curtailment in current period

0.0

Loss on curtailment in current period

0.0

(0.2)

Settlements

0.0

Total amount recognized in accumulated other comprehensive income

0.0

Other Comprehensive Income (Loss), before Tax

$ 0.2

$ (1.6)

$ (1.3)

[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan and SERP [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate used in calculating benefit obligation	3.96%	4.24%
Rate of increase in compensation used for calculating benefit obligation	3.50%	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	4.23%	3.94%	4.40%
Expected long-term return on plan assets used in calculating net periodic benefit cost	6.50%	6.75%	7.00%
Rate of increase in compensation used in calculating net periodic benefit cost	4.00%	4.00%	4.00%
Medical Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate used in calculating benefit obligation	4.10%	4.40%
Rate of increase in compensation used for calculating benefit obligation	3.50%	4.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate used in calculating net periodic benefit cost	4.40%	4.00%	5.00%
Rate of increase in compensation used in calculating net periodic benefit cost	4.00%	4.00%	4.00%

Employee Benefits Schedule of Fair Values of Pension and Postretirement Benefit Assets by Asset Class (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 86.1	$ 79.3
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Cash and short-term investments [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 3.5	$ 0.4
Defined Benefit Plan, Actual Plan Asset Allocations	4.00%	0.00%
Domestic equity securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 39.3	$ 38.5
Defined Benefit Plan, Actual Plan Asset Allocations	46.00%	49.00%
International equity securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 21.6	$ 16.8
Defined Benefit Plan, Actual Plan Asset Allocations	25.00%	21.00%
Fixed income securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 21.7	$ 23.6
Defined Benefit Plan, Actual Plan Asset Allocations	25.00%	30.00%

Employee Benefits Schedule of Expected Benefit Payments for Pension and Other Postretirement Benefits (Details) $ in Millions	Dec. 31, 2016 USD ($)
Pension Plan and SERP [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2017	$ 7.2
2018	6.6
2019	8.6
2020	8.0
2021	8.9
2022 through 2026	42.3
Medical Plan [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2017	0.3
2018	0.3
2019	0.3
2020	0.3
2021	0.3
2022 through 2026	$ 1.4

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Operating Loss Carryforwards, Valuation Allowance	$ 20.6
Unrecognized tax benefits, ending balance	15.6	$ 15.6
Interest Related to Uncertain Tax Positions	0.7	0.5
Penalties Related to Uncertain Tax Positions	$ 0.6	$ 2.2

Income Taxes Schedule of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Federal Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current federal income tax provision (benefit)	$ (55.5)	$ (112.3)	$ (324.0)
Deferred federal income tax provision (benefit)	(614.3)	34.5	110.3
State and Local Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current state income tax provision (benefit)	(1.5)	(6.6)	(15.5)
Deferred state income tax provision (benefit)	(36.9)	(9.2)	(3.3)
Total income tax provision (benefit)	$ (708.2)	$ (93.6)	$ (232.5)

Income Taxes Reconciliation of Statutory Federal Income Tax Rate and Effective Tax Rate (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	2.40%	4.20%	(1.50%)
State rate change	(1.10%)	0.00%	3.40%
Penalties	0.00%	(0.30%)	0.00%
Return to provision adjustment	0.00%	(0.30%)	(0.40%)
Other	0.00%	(0.10%)	(0.30%)
Effective income tax rate	36.30%	38.50%	36.20%

Income Taxes Schedule of Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Components of Deferred Tax Assets and Liabilities [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	$ 1,135.0	$ 1,531.0
Deferred Tax Liabilities, Derivatives	0.0	60.4
Deferred Tax Liabilities, Net	1,135.0	1,591.4
Deferred Tax Assets Net Operating Loss And Tax Credit Carryforwards	161.6	51.9
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits	49.0	43.6
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Bonuses	11.4	7.0
Deferred Tax Assets, Derivative Instruments	74.3	0.0
Deferred Tax Assets, Other	12.8	9.1
Deferred Tax Assets, Gross	309.1	111.6
Deferred Tax Assets, Net of Valuation Allowance, Classification [Abstract]
Deferred Tax Liabilities, Net, Noncurrent	825.9	1,479.8
Deferred Tax Liabilities, Net	$ 825.9	$ 1,479.8

Income Taxes Amounts and Expiration Dates of Net Operating Loss and Tax Credit Carryforwards (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Operating Loss Carryforwards [Line Items]
State net operating loss and tax credit carryforwards	$ 53.6
State net operating loss valuation allowance	(20.6)
U.S. net operating loss	109.1
U.S. alternative minimum tax credit	19.5
Total tax credit carryforwards	$ 161.6
State [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards Minimum Expiration Date	2017
Operating Loss Carryforwards Maximum Expiration Date	2033
U.S. (Federal) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards Maximum Expiration Date	2036

Income Taxes Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Unrecognized tax benefits, beginning balance	$ 15.6	$ 0.0
Additions for tax positions taken during the current period	0.0	15.6
Unrecognized tax benefits, ending balance	$ 15.6	$ 15.6

Quarterly Financial Information (Unaudited) (Details)
$ / shares in Units, MBoe in Millions, Bcfe in Millions, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2016

USD ($)

Bcfe

MBoe

$ / shares

Sep. 30, 2016

USD ($)

Bcfe

MBoe

$ / shares

Jun. 30, 2016

USD ($)

Bcfe

MBoe

$ / shares

Mar. 31, 2016

USD ($)

Bcfe

MBoe

$ / shares

Dec. 31, 2015

USD ($)

Bcfe

MBoe

$ / shares

Sep. 30, 2015

USD ($)

Bcfe

MBoe

$ / shares

Jun. 30, 2015

USD ($)

Bcfe

MBoe

$ / shares

Mar. 31, 2015

USD ($)

Bcfe

MBoe

$ / shares

Dec. 31, 2016

USD ($)

Bcfe

MBoe

$ / shares

Dec. 31, 2015

USD ($)

Bcfe

MBoe

$ / shares

Dec. 31, 2014

USD ($)

$ / shares

Quarterly Financial Information Disclosure [Line Items]

Revenues

$ 399.7

$ 382.4

$ 333.7

$ 261.3

$ 468.3

$ 507.6

$ 574.6

$ 468.1

$ 1,377.1

$ 2,018.6

$ 3,293.2

Operating income (loss)

(36.9)

(93.6)

(92.9)

(1,379.2)

(144.6)

(87.7)

(16.7)

(128.6)

(1,602.6)

(377.6)

(847.3)

Income (loss) from continuing operations

(1,245.0)

(149.4)

(409.5)

Net income from discontinued operations, net of income tax

0.0

1,193.9

Net income (loss)

(133.3)

(50.9)

(197.0)

(863.8)

(38.6)

21.1

(76.3)

(55.6)

(1,245.0)

(149.4)

$ 784.4

Net gain (loss) from asset sales and impairment

(6.1)

0.3

(1.6)

(1,181.9)

(22.4)

(2.1)

24.0

(50.5)

(1,189.3)

(51.0)

Nonrecurring items in operating income (loss)

^[1]

$ 0.0

$ 25.0

$ 0.0

$ 7.7

$ 0.0

$ 11.2

$ 0.0

$ 32.7

$ 11.2

Basic total | $ / shares

$ (0.56)

$ (0.21)

$ (0.90)

$ (4.55)

$ (0.22)

$ 0.12

$ (0.43)

$ (0.32)

$ (5.62)

$ (0.85)

$ 4.36

Diluted total | $ / shares

$ (0.56)

$ (0.21)

$ (0.90)

$ (4.55)

$ (0.22)

$ 0.12

$ (0.43)

$ (0.32)

$ (5.62)

$ (0.85)

4.36

Total equivalent production (Mboe) | MBoe

13,675.7

14,445.7

13,882.4

13,766.4

13,986.6

14,462.4

13,484.3

12,528.8

55,780.2

54,462.1

Total equivalent production (Bcfe) | Bcfe

82.1

86.6

83.3

82.7

84.0

86.7

80.9

75.2

334.7

326.8

Continuing Operations [Member]

Quarterly Financial Information Disclosure [Line Items]

Basic total | $ / shares

$ (5.62)

$ (0.85)

(2.28)

Diluted total | $ / shares

(5.62)

(0.85)

(2.28)

Discontinued Operations [Member]

Quarterly Financial Information Disclosure [Line Items]

Basic total | $ / shares

0.00

6.64

Diluted total | $ / shares

$ 0.00

$ 6.64

[1]	Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2016, and a non-cash pension curtailment incurred during the year ended December 31, 2015.

Supplemental Gas and Oil Information (Unaudited) Capitalized costs (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
Proved properties	$ 14,232.5	$ 13,314.9
Unproved properties, net	871.5	691.0
Total proved and unproved properties	15,104.0	14,005.9
Accumulated depreciation, depletion and amortization	(8,797.7)	(6,870.2)
Net capitalized costs	$ 6,306.3	$ 7,135.7

Supplemental Gas and Oil Information (Unaudited) Costs incurred (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract]
Accrued capital costs included in development costs	$ 34.6
ARO additions and revisions	23.5
Costs incurred related to the development of proved undeveloped reserves	258.1	$ 490.4	$ 792.9
Proved property acquisitions	431.6	49.6	465.4
Unproved property acquisitions	208.7	39.8	496.3
Exploration (capitalized and expensed)	13.4	8.7	23.6
Development	509.2	1,010.3	1,695.1
Total costs incurred	$ 1,162.9	$ 1,108.4	$ 2,680.4

Supplemental Gas and Oil Information (Unaudited) Results of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Results of Operations, Income before Income Taxes [Abstract]
Revenues	$ 1,271.0	$ 1,390.4	$ 2,374.6
Production costs	616.7	654.1	735.6
Exploration expenses	1.7	2.7	9.9
Depreciation, depletion and amortization	852.3	870.8	984.4
Impairment	1,194.3	55.6	1,143.2
Total expenses	2,665.0	1,583.2	2,873.1
Income (loss) before income taxes	(1,394.0)	(192.8)	(498.5)
Income tax benefit (expense)	517.2	70.6	182.5
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$ (876.8)	$ (122.2)	$ (316.0)

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

12 Months Ended

Dec. 31, 2016

MMBoe

Bcf

MMBbls

Dec. 31, 2015

MMBoe

Bcf

MMBbls

Dec. 31, 2014

MMBoe

Bcf

MMBbls

Oil [Member]

Reserve Quantities [Line Items]

Proved reserves balance, beginning balance | MMBbls

193.1

172.5

148.6

Revisions of previous estimates | MMBbls

(9.7)

^[1]

(47.0)

^[2]

(4.0)

^[3]

Extensions and discoveries | MMBbls

13.0

^[4]

85.6

^[5]

16.8

^[6]

Purchase of reserves in place | MMBbls

62.7

^[7]

2.0

^[8]

35.7

^[9]

Sale of reserves in place | MMBbls

(0.2)

^[10]

(0.4)

^[11]

(7.5)

^[12]

Production | MMBbls

(20.3)

(19.6)

(17.1)

Proved reserves balance, ending balance | MMBbls

238.6

193.1

172.5

Proved undeveloped reserves, beginning balance | MMBbls

83.4

73.2

76.8

Proved undeveloped reserve, ending balance | MMBbls

135.4

83.4

73.2

Proved developed reserves, beginning balance | MMBbls

109.7

99.3

71.8

Proved developed reserves, ending balance | MMBbls

103.2

109.7

99.3

Gas [Member]

Reserve Quantities [Line Items]

Proved reserves balance, beginning balance | Bcf

2,108.9

2,317.2

2,554.9

Revisions of previous estimates | Bcf

412.8

^[1]

(463.8)

^[2]

27.1

^[3]

Extensions and discoveries | Bcf

158.1

^[4]

467.7

^[5]

141.4

^[6]

Purchase of reserves in place | Bcf

54.6

^[7]

3.2

^[8]

72.5

^[9]

Sale of reserves in place | Bcf

(3.6)

^[10]

(34.3)

^[11]

(299.4)

^[12]

Production | Bcf

(177.0)

(181.1)

(179.3)

Proved reserves balance, ending balance | Bcf

2,553.8

2,108.9

2,317.2

Proved undeveloped reserves, beginning balance | Bcf

863.6

1,028.8

1,148.6

Proved undeveloped reserve, ending balance | Bcf

1,244.0

863.6

1,028.8

Proved developed reserves, beginning balance | Bcf

1,245.3

1,288.4

1,406.3

Proved developed reserves, ending balance | Bcf

1,309.8

1,245.3

1,288.4

Natural Gas Liquids [Member]

Reserve Quantities [Line Items]

Proved reserves balance, beginning balance | MMBbls

58.8

96.6

102.6

Revisions of previous estimates | MMBbls

(0.3)

^[1]

(55.3)

^[2]

1.4

^[3]

Extensions and discoveries | MMBbls

3.3

^[4]

21.8

^[5]

8.6

^[6]

Purchase of reserves in place | MMBbls

11.5

^[7]

0.6

^[8]

12.3

^[9]

Sale of reserves in place | MMBbls

(0.1)

^[10]

(0.2)

^[11]

(21.5)

^[12]

Production | MMBbls

(6.0)

(4.7)

(6.8)

Proved reserves balance, ending balance | MMBbls

67.2

58.8

96.6

Proved undeveloped reserves, beginning balance | MMBbls

24.4

44.4

49.8

Proved undeveloped reserve, ending balance | MMBbls

31.5

24.4

44.4

Proved developed reserves, beginning balance | MMBbls

34.4

52.2

52.8

Proved developed reserves, ending balance | MMBbls

35.7

34.4

52.2

Barrels of oil equivalent production [Member]

Reserve Quantities [Line Items]

Proved developed and undeveloped reserves, beginning balance | MMBoe

^[13]

603.4

655.3

677.0

Revisions of previous estimates | MMBoe

^[13]

58.8

^[1]

(179.6)

^[2]

1.9

^[3]

Extensions and discoveries | MMBoe

^[13]

42.6

^[4]

185.4

^[5]

49.0

^[6]

Purchase of reserves in place | MMBoe

^[13]

83.3

^[7]

3.1

^[8]

60.1

^[9]

Sale of reserves in place | MMBoe

^[13]

(0.9)

^[10]

(6.3)

^[11]

(78.9)

^[12]

Production | MMBoe

^[13]

(55.8)

(54.5)

(53.8)

Proved developed and undeveloped reserves, ending balance | MMBoe

^[13]

731.4

603.4

655.3

Proved undeveloped reserves, beginning balance | MMBoe

251.8

289.1

318.0

Proved undeveloped reserves, ending balance | MMBoe

374.2

251.8

289.1

Proved developed reserves, beginning balance | MMBoe

351.6

366.2

359.0

Proved developed reserves, ending balance | MMBoe

357.2

351.6

366.2

Pricing Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

18.5

126.2

3.8

Pricing Revisions [Member] | Gas [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

3.7

Performance Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

5.5

13.7

41.4

Positive revisions [Member] | Barrels of oil equivalent production [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

77.3

Operating Cost Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

6.5

Other Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

67.2

33.0

Williston Basin [Member] | Barrels of oil equivalent production [Member]

Reserve Quantities [Line Items]

Extensions and discoveries | MMBoe

68.2

20.6

Pinedale [Member] | Barrels of oil equivalent production [Member]

Reserve Quantities [Line Items]

Extensions and discoveries | MMBoe

22.3

Pinedale [Member] | Performance Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

32.3

Uinta Basin [Member] | Barrels of oil equivalent production [Member]

Reserve Quantities [Line Items]

Extensions and discoveries | MMBoe

53.2

Permian Basin [Member] | Barrels of oil equivalent production [Member]

Reserve Quantities [Line Items]

Extensions and discoveries | MMBoe

49.6

[1]	Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.
[2]	Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin.
[3]	Revisions of previous estimates in 2014 include 41.4 MMboe negative performance revisions partially offset by positive other revisions of 33.0 MMboe, operating cost revisions of 6.5 MMboe and pricing revisions of 3.8 MMboe. Negative performance revisions were driven by a 32.3 MMboe 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. Pricing revisions were primarily due to increased gas prices, which increased reserves by 3.7 MMboe.
[4]	Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.
[5]	Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations
[6]	Extensions and discoveries in 2014 increased proved reserves by 49.0 MMboe, primarily related to extensions and discoveries in Pinedale of 22.3 MMboe and the Williston Basin of 20.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations as well as new compression well projections in Pinedale.
[7]	Purchase of reserves in place in 2016 relate primarily to the Company's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.
[8]	Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston Basin as discussed in Note 2 – Acquisitions and Divestitures
[9]	Purchase of reserves in place in 2014 relate to the Company's 2014 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.
[10]	Sale of reserves in place in 2016 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.
[11]	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.
[12]	Sale of reserves in place primarily related to property sales in the Other Southern area in the second and fourth quarters of 2014 as discussed in Note 2 – Acquisitions and Divestitures
[13]	Proved reserves include gas reserves that QEP expects to produce and use as field fuel.

Supplemental Gas and Oil Information (Unaudited) Average price per unit (Details)	12 Months Ended
	Dec. 31, 2016 $ / bbl $ / Mcf	Dec. 31, 2015 $ / bbl $ / Mcf	Dec. 31, 2014 $ / bbl $ / Mcf
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
12 month average first-of the month commodity price \| $ / bbl	42.75	50.28	94.99
Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
12 month average first-of the month commodity price \| $ / Mcf	2.48	2.59	4.35

Supplemental Gas and Oil Information (Unaudited) Future Development Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Future Development Costs [Abstract]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Next Twelve Months	$ 503.0
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Two	717.3
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Three	$ 781.3

Supplemental Gas and Oil Information (Unaudited) Standardized Measure Of Future Net Cash Flows (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract]
Future cash inflows	$ 16,239.8	$ 15,325.3	$ 28,167.3
Future production costs	(7,789.0)	(7,389.9)	(9,842.1)
Future development costs	(3,432.9)	(2,202.5)	(3,521.3)
Future income tax expenses	(913.4)	(1,169.3)	(4,304.0)
Future net cash flows	4,104.5	4,563.6	10,499.9
10% annual discount for estimated timing of net cash flows	(2,176.5)	(2,087.3)	(5,159.9)
Standardized measure of discounted future net cash flows	$ 1,928.0	$ 2,476.3	$ 5,340.0	$ 4,383.9

Supplemental Gas and Oil Information (Unaudited) Change in Standardized Measure of Future Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Change in Standardized Measure of Future Cash Flows [Abstract]
Beginning Balance	$ 2,476.3	$ 5,340.0	$ 4,383.9
Sales of gas, oil and NGL produced during the period, net of production costs	(654.3)	(736.3)	(1,639.0)
Net change in sales prices and in production (lifting) costs related to future production	(739.4)	(6,307.8)	726.6
Net change due to extensions and discoveries	81.8	1,765.7	979.9
Net change due to revisions of quantity estimates	122.7	(1,350.2)	35.9
Changes due to purchases of reserves in place	256.5	29.7	695.3
Changes due to sales of reserves in place	(4.3)	(48.8)	(1,153.7)
Previously estimated development costs incurred during the period	374.6	865.0	867.5
Changes in estimated future development costs	(476.5)	560.7	409.6
Accretion of discount	311.1	752.9	597.3
Net change in income taxes	205.4	1,554.4	(600.3)
Other	(25.9)	51.0	37.0
Net change	(548.3)	(2,863.7)	956.1
Ending Balance	$ 1,928.0	$ 2,476.3	$ 5,340.0

Subsequent Event (Details) $ in Millions	12 Months Ended
Subsequent Event (Details) $ in Millions	Dec. 31, 2016 USD ($)
Additional acquisitions in the Permian Basin [Member]
Subsequent Event [Line Items]
Aggregate purchase price	$ 37.9