Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2018	Jan. 31, 2019	Jun. 30, 2018
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		236,366,458
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Entity Public Float			$ 2,905,325,233

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
REVENUES
Oil and condensate, gas and NGL sales									$ 1,871.3	$ 1,545.3	$ 1,269.7
Other revenues									12.5	15.0	6.2
Purchased oil and gas sales									48.8	62.6	101.2
Total Revenues	$ 410.5	$ 560.8	$ 532.4	$ 428.9	$ 429.0	$ 390.1	$ 383.7	$ 420.1	1,932.6	1,622.9	1,377.1
OPERATING EXPENSES
Purchased oil and gas expense									51.0	64.3	105.5
Lease operating expense									263.1	294.8	224.7
Transportation and processing costs									117.6	245.3	289.2
Gathering and other expense									15.5	7.3	5.0
General and administrative									221.7	153.5	196.5
Production and property taxes									130.8	114.3	94.8
Depreciation, depletion and amortization									857.1	754.5	871.1
Exploration expenses									0.3	22.0	1.7
Impairment									1,560.9	78.9	1,194.3
Total Operating Expenses									3,218.0	1,734.9	2,982.8
Net gain (loss) from asset sales, inclusive of restructuring costs									25.0	213.5	5.0
OPERATING INCOME (LOSS)	(1,116.8)	156.8	(321.8)	21.4	(24.5)	132.1	(0.9)	(5.2)	(1,260.4)	101.5	(1,600.7)
Realized and unrealized gains (losses) on derivative contracts (Note 7)									90.4	24.5	(233.0)
Interest and other income (expense)									(9.6)	1.6	23.7
Loss from early extinguishment of debt									0.0	(32.7)	0.0
Interest expense									(149.4)	(137.8)	(143.2)
INCOME (LOSS) BEFORE INCOME TAXES									(1,329.0)	(42.9)	(1,953.2)
Income tax (provision) benefit									317.4	312.2	708.2
NET INCOME (LOSS)	$ (629.3)	$ 7.3	$ (336.0)	$ (53.6)	$ 150.3	$ (3.3)	$ 45.4	$ 76.9	$ (1,011.6)	$ 269.3	$ (1,245.0)
Earnings (loss) per common share
Basic	$ (2.66)	$ 0.03	$ (1.42)	$ (0.22)	$ 0.62	$ (0.01)	$ 0.19	$ 0.32	$ (4.25)	$ 1.12	$ (5.62)
Diluted	$ (2.66)	$ 0.03	$ (1.42)	$ (0.22)	$ 0.62	$ (0.01)	$ 0.19	$ 0.32	$ (4.25)	$ 1.12	$ (5.62)
Weighted-average common shares outstanding
Used in basic calculation									237.9	240.6	221.7
Used in diluted calculation									237.9	240.6	221.7

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Statement of Comprehensive Income [Abstract]

Net income (loss)

$ (1,011.6)

$ 269.3

$ (1,245.0)

Other comprehensive income, net of tax:

Future tax effective rate change(1)

^[1]

0.0

(3.8)

0.0

Pension and other postretirement plans adjustments:

Current period prior service cost(2)

^[2]

(0.1)

2.4

0.0

Current period net actuarial (gain) loss(3)

^[3]

(4.2)

5.8

(5.6)

Amortization of prior service cost(4)

^[4]

0.4

0.5

0.8

Amortization of net actuarial (gain) loss(5)

^[5]

0.6

0.3

0.5

Net curtailment and settlement cost incurred(6)

^[6]

0.1

0.4

0.0

Other comprehensive income (loss)

(3.2)

5.6

(4.3)

Comprehensive income (loss)

$ (1,014.8)

$ 274.9

$ (1,249.3)

[1]	Refer to New Accounting Pronouncements in Note 1 – Summary of Significant Accounting Policies.
[2]	Presented net of income tax benefit of $0.1 million for the year ended December 31, 2018 and net of income tax expense of $0.8 million for the year ended December 31, 2017.
[3]	Presented net of income tax benefit of $1.3 million for the year ended December 31, 2018, net of income tax expense of $1.8 million for the year ended December 31, 2017 and net of income tax benefit of $3.3 million for the year ended December 31, 2016.
[4]	Presented net of income tax expense of $0.1 million, $0.2 million and $0.5 million for the years ended December 31, 2018, 2017 and 2016, respectively.
[5]	Presented net of income tax expense of $0.2 million, $0.1 million and $0.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.
[6]	Presented net of income tax expense $0.1 million for the year ended December 31, 2017.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Pension and other postretirement plans adjustments:

Current period prior service cost, tax

^[1]

$ (0.1)

$ 0.8

$ 0.0

Current period net actuarial (gain) loss, tax

^[2]

1.3

(1.8)

3.3

Amortization of prior service cost, tax

^[3]

(0.1)

(0.2)

(0.5)

Amortization of net actuarial (gain) loss, tax

^[4]

(0.2)

(0.1)

(0.3)

Net curtailment and settlement cost incurred, tax

^[5]

$ 0.0

$ 0.1

$ 0.0

[1]	Presented net of income tax benefit of $0.1 million for the year ended December 31, 2018 and net of income tax expense of $0.8 million for the year ended December 31, 2017.
[2]	Presented net of income tax benefit of $1.3 million for the year ended December 31, 2018, net of income tax expense of $1.8 million for the year ended December 31, 2017 and net of income tax benefit of $3.3 million for the year ended December 31, 2016.
[3]	Presented net of income tax expense of $0.1 million, $0.2 million and $0.5 million for the years ended December 31, 2018, 2017 and 2016, respectively.
[4]	Presented net of income tax expense of $0.2 million, $0.1 million and $0.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.
[5]	Presented net of income tax expense $0.1 million for the year ended December 31, 2017.

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 0.0	$ 0.0
Accounts receivable, net	104.3	140.0
Income tax receivable	75.9	4.9
Fair value of derivative contracts	87.5	3.4
Prepaid expenses	12.7	10.1
Other current assets	0.2	3.6
Total Current Assets	280.6	162.0
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,096.9	8,081.0
Unproved properties	705.5	1,028.5
Gathering and other	167.7	111.0
Materials and supplies	29.9	24.8
Total Property, Plant and Equipment	10,000.0	9,245.3
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	4,882.4	3,315.2
Gathering and other	58.1	63.4
Total Accumulated Depreciation, Depletion and Amortization	4,940.5	3,378.6
Net Property, Plant and Equipment	5,059.5	5,866.7
Fair value of derivative contracts	35.4	0.1
Other noncurrent assets	49.6	45.1
Noncurrent assets held for sale	692.7	1,320.9
TOTAL ASSETS	6,117.8	7,394.8
Current Liabilities
Checks outstanding in excess of cash balances	14.6	44.0
Accounts payable and accrued expenses	258.1	360.1
Production and property taxes	24.1	31.6
Interest payable	32.4	26.0
Fair value of derivative contracts	0.0	103.6
Asset Retirement Obligation, Current	5.1	2.8
Total Current Liabilities	334.3	568.1
Long-term debt	2,507.1	2,160.8
Deferred income taxes	269.2	518.0
Asset retirement obligations	96.9	104.1
Fair value of derivative contracts	0.7	34.8
Other long-term liabilities	97.4	101.9
Other long-term liabilities held for sale	61.3	109.2
Commitments and Contingencies (Note 10)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 239.8 million and 243.0 million shares issued, respectively	2.4	2.4
Treasury stock - 3.1 million and 2.0 million shares, respectively	(45.6)	(34.2)
Additional paid-in capital	1,431.9	1,398.2
Retained earnings	1,376.5	2,442.6
Accumulated other comprehensive income (loss)	(14.3)	(11.1)
Total Common Shareholders' Equity	2,750.9	3,797.9
TOTAL LIABILITIES AND EQUITY	$ 6,117.8	$ 7,394.8

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares shares in Millions	Dec. 31, 2018	Dec. 31, 2017
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)	239.8	243.0
Treasury stock (in shares)	3.1	2.0

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]	Stockholders' Equity, Total [Member]
Balance at Dec. 31, 2015		$ 1.8	$ (14.6)	$ 554.8	$ 3,418.3	$ (12.4)	$ 3,947.9
Shares at Dec. 31, 2015		177.3
Treasury shares at Dec. 31, 2015			(0.5)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss), shares		0.0	0.0
Net income (loss)	$ 1,245.0	$ 0.0	$ 0.0	0.0	(1,245.0)	0.0	(1,245.0)
Equity issuance, net of offering costs, Shares		61.0	0.0
Equity issuance, net of offering costs, Value		$ 0.6	$ 0.0	780.8	0.0	0.0	781.4
Common stock repurchased and retired, Value	0.0
Share-based compensation, shares		2.4	(0.6)
Share-based compensation		$ 0.0	$ (8.3)	31.0	0.0	0.0	22.7
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)	(4.3)
Shares at Dec. 31, 2016		240.7
Treasury shares at Dec. 31, 2016			(1.1)
Balance at Dec. 31, 2016		$ 2.4	$ (22.9)	1,366.6	2,173.3	(16.7)	3,502.7
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss), shares		0.0	0.0
Net income (loss)	(269.3)	$ 0.0	$ 0.0	0.0	269.3	0.0	269.3
Common stock repurchased and retired, Value	$ 0.0
Share-based compensation, shares		2.3	(0.9)
Share-based compensation		$ 0.0	$ (11.3)	31.6	0.0	0.0	20.3
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	5.6	5.6
Shares at Dec. 31, 2017		243.0
Treasury shares at Dec. 31, 2017	(2.0)		(2.0)
Balance at Dec. 31, 2017	$ 3,797.9	$ 2.4	$ (34.2)	1,398.2	2,442.6	(11.1)	3,797.9
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss), shares		0.0	0.0
Net income (loss)	1,011.6	$ 0.0	$ 0.0	0.0	(1,011.6)	0.0	(1,011.6)
Reclassification related to ASU 2018-02 adoption		0.0	0.0
Reclassification related to ASU 2018-02		$ 0.0	$ 0.0	0.0	3.8	(3.8)	0.0
Common stock repurchased and retired, Shares		(6.2)	0.0
Common stock repurchased and retired, Value	$ 58.4	$ (0.1)	$ 0.0	0.0	(58.3)	0.0	(58.4)
Share-based compensation, shares		3.0	(1.1)
Share-based compensation		$ 0.1	$ (11.4)	33.7	0.0	0.0	22.4
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	0.6	0.6
Shares at Dec. 31, 2018		239.8
Treasury shares at Dec. 31, 2018	(3.1)		(3.1)
Balance at Dec. 31, 2018		$ 2.4	$ (45.6)	$ 1,431.9	$ 1,376.5	$ (14.3)	$ 2,750.9

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
OPERATING ACTIVITIES
Net income (loss)	$ (1,011.6)	$ 269.3	$ (1,245.0)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	857.1	754.5	871.1
Deferred income taxes	(247.6)	(314.8)	(651.3)
Impairment	1,560.9	78.9	1,194.3
Dry hole exploratory well expense	0.0	21.3	0.0
Share-based compensation	39.1	22.4	35.6
Amortization of debt issuance costs and discounts	5.4	6.2	6.4
Bargain purchase gain from acquisitions	0.0	0.4	(22.6)
Net (gain) loss from asset sales, inclusive of restructuring costs	(25.0)	(213.5)	(5.0)
Loss from early extinguishment of debt	0.0	32.7	0.0
Unrealized (gains) losses on marketable securities	1.2	(2.9)	(1.4)
Unrealized (gains) losses on derivative contracts	(248.5)	(40.0)	367.0
Other non-cash activity	0.0	(9.4)	0.0
Accounts receivable	33.7	(2.0)	95.3
Prepaid expenses	(2.0)	(1.3)	18.7
Accounts payable and accrued expenses	(74.2)	3.5	(50.3)
Income taxes receivable	(71.0)	13.7	68.7
Other	(1.3)	(18.8)	(14.3)
Net Cash Provided by (Used in) Operating Activities	816.2	600.2	667.2
INVESTING ACTIVITIES
Property acquisitions	(65.6)	(815.2)	(639.0)
Property, plant and equipment, including exploratory well expense	(1,234.1)	(1,159.6)	(569.1)
Proceeds from disposition of assets	243.6	806.8	29.0
Net Cash Provided by (Used in) Investing Activities	(1,056.1)	(1,168.0)	(1,179.1)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(29.5)	31.7	(17.5)
Long-term debt issued	0.0	500.0	0.0
Long-term debt issuance costs paid	(0.1)	(14.4)	0.0
Long-term debt extinguishment costs paid	0.0	(28.1)	0.0
Long-term debt repaid	0.0	(445.6)	(176.8)
Proceeds from credit facility	3,608.0	492.0	0.0
Repayments of credit facility	(3,267.0)	(403.0)	0.0
Common stock repurchased and retired	(58.4)	0.0	0.0
Treasury stock repurchases	(8.7)	(6.8)	(4.1)
Other capital contributions	0.3	0.0	0.0
Proceeds from issuance of common stock, net	0.0	0.0	781.4
Excess tax (provision) benefit on share-based compensation	0.0	0.0	0.1
Net Cash Provided by (Used in) Financing Activities	244.6	125.8	583.1
Change in cash, cash equivalents and restricted cash(1)	4.7	(442.0)	71.2
Beginning cash, cash equivalents and restricted cash(1)	23.4	465.4	394.2
Ending cash, cash equivalents and restricted cash(1)	$ 28.1	$ 23.4	$ 465.4

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Nature of Business

QEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Southern Region (primarily in Texas) and the Northern Region (primarily in North Dakota). During 2018, the Company sold its Uinta Basin assets and entered into purchase and sale agreements to divest substantially all of its Haynesville/Cotton Valley assets in Louisiana and its Williston Basin assets in North Dakota. In January, the Company closed the sale of its Haynesville/Cotton Valley assets. In February 2019, the Company agreed with the buyer to terminate the purchase and sale agreement related to its Williston Basin assets. 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 Regulation S-X. 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.

Business Segments

QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP has one reportable segment.

Reclassifications

Certain prior period balances on the Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified due to noncurrent held for sale classification related to the divestiture of the Uinta Basin assets and Haynesville/Cotton Valley assets and to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share 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 and condensate, 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, contingencies, 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 condensate 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 condensate and gas production. Refer to Note 7 – Derivative Contracts for the Company's open oil and gas commodity derivative contracts.

Revenue Recognition

QEP recognizes revenue from the sales of oil and condensate, gas and NGL in the period that the performance obligations are satisfied. QEP's performance obligations are satisfied when the customer obtains control of product, when we have no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sales of oil and condensate, gas and NGL are made under contracts with customers, which typically include consideration that is based on pricing tied to local indices and volumes delivered in the current month. Reported revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. Performance obligations under our contracts with customers are typically satisfied at a point in time through monthly delivery of oil and condensate, gas and/or NGL. Our contracts with customers typically require payment for oil and condensate, gas and NGL sales within 30 days following the calendar month of delivery.

QEP's oil is typically sold at specific delivery points under contract terms that are common in our industry. QEP's gas and NGL are also sold under contract types that are common in our industry; however, under these contracts, the gas and its components, including NGL, may be sold to a single purchaser or the residue gas and NGL may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate the Company for the value of the residue gas and NGL constituent components at market prices for each product. 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 in the period that the performance obligations are satisfied.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist principally of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day. Restricted cash are funds that are legally or contractually reserved for a specific purpose and therefore not available for immediate or general business use.

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the amounts shown in the Consolidated Statements of Cash Flows:



	December 31,
	2018		2017
	(in millions)
Cash and cash equivalents	$	—	$	—
Restricted cash⁽¹⁾	28.1		23.4
Total cash, cash equivalents and restricted cash shown in the Consolidated Statements of Cash Flows	$	28.1	$	23.4

_______________________


⁽¹⁾	As of December 31, 2018 and 2017, the restricted cash balance related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Consolidated Balance Sheets.

Supplemental cash flow information is shown in the table below:



	Year Ended December 31,
	2018			2017			2016
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	136.9		$	134.9		$	139.1
Cash paid (refund received) for income taxes, net	$	0.8		$	(0.3	)	$	(123.5	)
Non-cash Investing Activities:
Change in capital expenditure accrual balance	$	(57.4	)	$	60.2		$	(32.8	)

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, 2018 and 2016 was $0.6 million and $1.8 million, respectively. Recovery of bad debt associated with accounts receivable for the year ended December 31, 2017 was $1.0 million. Bad debt expense or recovery is included in "General and administrative" expense on the Consolidated Statements 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 $1.3 million at December 31, 2018, and $1.6 million at December 31, 2017.

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 net realizable value. 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.

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 total 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 and condensate, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, potential disposition of assets 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. The signing of a purchase and sale agreement could also cause the Company to recognize an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. If a range is estimated for the amount of possible future cash flows, the fair value of property is measured utilizing a probability-weighted approach whereas the likelihood of possible outcomes is taken into consideration. Specific to the Planned Williston Basin Divestiture, the Company obtained a Black-Scholes-Merton estimate of the value of the contractual rights to receive up to 5.8 million shares of the buyer's common stock at December 31, 2018. 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, 2018, QEP recorded impairment charges of $1,560.9 million, of which $1,559.3 million related to proved and unproved properties impairment as a result of signing purchase and sale agreements for the divestitures of the Williston Basin and Uinta Basin assets. The Williston Basin assets were impaired in the fourth quarter utilizing a probability-weighted assets held and use model, and the Uinta Basin assets were impaired in the second quarter utilizing an assets held for sale model.

During the year ended December 31, 2017, QEP recorded impairment charges of $78.9 million, of which $38.1 million, primarily in the Other Northern area, was related to proved properties due to lower future gas prices, $29.0 million was primarily related to unproved leasehold acreage in the Central Basin Platform (refer to Note 4 – Capitalized Exploratory Well Costs for more information), $6.5 million was related to the impairment of an underground gas storage facility and $5.3 million was related to the impairment of goodwill.

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 was related to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to the Other Northern area and $0.6 million related to QEP's remaining Other Southern properties.

Asset Retirement Obligations (ARO)

QEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other 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. Refer to Note 5 – Asset Retirement Obligations for more 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. QEP performs an annual goodwill impairment test by comparing the fair value of a reporting unit with its carry amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. QEP determines the 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 and condensate, 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.

During the years ended December 31, 2017 and 2016, QEP recorded $5.3 million and $3.7 million, respectively, of goodwill. During the years ended December 31, 2017 and 2016, QEP tested goodwill for impairment, which resulted in a full write down of $5.3 million and $3.7 million, respectively.

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 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. 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. Refer to Note 10 – Commitments and Contingencies for more 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 more 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, typically fixed-price swaps and costless 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 Statements of Operations in the month of settlement and are also marked-to-market monthly. Refer to Note 7 – Derivative Contracts for more 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. Credit exposure 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, if needed, are 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 49%, 59%, and 48% of QEP's revenues for the years ended December 31, 2018, 2017 and 2016, respectively. The following table presents the percentages by customer that accounted for 10% or more of QEP's total revenues.



Year Ended December 31, 2018
Occidental Energy Marketing	16	%
Plains Marketing LP	12	%

Year Ended December 31, 2017
Shell Trading Company	14	%
Occidental Energy Marketing	13	%
Andeavor Logistics LP	13	%
BP Energy Company	10	%
Plains Marketing LP	10	%

Year Ended December 31, 2016
Shell Trading Company	14	%
BP Energy Company	10	%
Valero Marketing & Supply Company	10	%

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, except as noted below. As of December 31, 2018, the Company had a valuation allowance of $82.3 million against the state net operating loss deferred tax asset mainly because management does not forecast future income in Oklahoma, Utah and Louisiana to offset net operating losses before they expire. All federal income tax returns prior to 2018 have been examined by the Internal Revenue Service and are closed. Income tax returns for 2018 have not yet been filed. Most state tax returns for 2015 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 (expense)" on the Consolidated Statements of Operations, any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements 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, 2018 and 2017, QEP had $19.0 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 Sheets. During the years ended December 31, 2018, 2017 and 2016, the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016, the Company incurred $0.6 million of estimated penalties related to uncertain tax positions.

In December 2017, the Tax Cuts and Jobs Act (H.R.1) (Tax Legislation) was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation. Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. As additional guidance to the Tax Legislation is published in the form of Treasury Regulations and other IRS communications, the Company will monitor, assess, and determine the impact of these communications on the Company's consolidated financial statements and operations. In addition to the Tax Legislation, QEP is continuing to monitor proposed regulations regarding the 163(j) Limitation on Deduction for Business Interest Expense, which when finalized, could require QEP to re-characterize the Company's deferred tax assets, resulting in changes in QEP's income tax disclosures. QEP expects the impact to the Company's results of operations to be immaterial.

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 more information.

Earnings (Loss) Per Share

Basic earnings (loss) per share (EPS) are computed by dividing net income (loss) 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 (loss) per share pursuant to the two-class method. The Company's unvested restricted share 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 share awards do 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 (loss) 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 (loss) per common share. For the years ended December 31, 2018 and 2017, there were no anti-dilutive shares. For the year ended December 31, 2016, there were 0.1 million shares not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss from continuing operations.

The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:



	December 31,
	2018	2017	2016
	(in millions)
Weighted-average basic common shares outstanding	237.9	240.6	221.7
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	237.9	240.6	221.7

Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its 2018 Long-Term Incentive Plan (LTIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The grant date fair value for restricted share awards is determined based on the closing bid price of the Company's common stock on the grant date. 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. QEP uses an accelerated method in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards have voting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as 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. The Company also awards performance share units under its Cash Incentive Plan (CIP) that 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. Refer to Note 11 – Share-Based Compensation for more 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 Statements 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. Refer to Note 12 – Employee Benefits for more information.

Comprehensive Income (Loss)

Comprehensive income (loss) is the sum of net income (loss) as reported in the Consolidated Statements of Operations and changes in the components of other comprehensive income (loss). Other comprehensive income (loss) includes certain items that are recorded directly to equity and classified as accumulated other comprehensive income (AOCI), which includes changes in the underfunded portion of the Company's defined-benefit pension 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 Accounting Standards Update (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 FASB subsequently issued various ASUs which deferred the effective date of ASU No. 2014-09 and provided additional implementation guidance, including industry specific guidance. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when revenue 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 are required. The amendment was effective for public companies prospectively for reporting periods beginning on or after December 15, 2017, and early adoption was permitted for periods beginning on or after December 15, 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 selected the modified retrospective method and adopted this standard in the first quarter of 2018. Refer to Note 2 – Revenue for more information.

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 disclose key quantitative and qualitative information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance. ASU 2016-02 and its amendments will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company will adopt ASU 2016-02 on January 1, 2019, using the modified retrospective transition approach with a cumulative effect adjustment as of the date of adoption. This standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources. This new guidance will increase other assets and other liabilities recorded on the Company's Consolidated Balance Sheets due to an increase in right of use assets and corresponding lease liabilities primarily related to leases for office buildings, compressors and generators. Also, any deferred rent balances as of December 31, 2018 will be reclassified to the right of use asset. The new guidance will not have a significant impact on the income statement.

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 was effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption was permitted. The Company adopted this standard in the first quarter of 2018 and the adoption did not 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 was effective retrospectively for reporting periods after December 15, 2017, and early adoption was permitted. The Company adopted this standard in the first quarter of 2018 and the adoption did not have a material impact on the Company's Consolidated Statements of Cash Flows.

In February 2018, the FASB issued ASU No. 2018-02, Income statement – Reporting comprehensive income (Topic 220) – Reclassification of certain tax effects from accumulated other comprehensive income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Legislation. This amendment is effective for reporting periods beginning after December 15, 2018, and early adoption was permitted. The Company early adopted this standard in the fourth quarter of 2018 and the adoption did not have a material impact on the Company's Consolidated Financial Statements.

In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740) – Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118, which amends guidance on certain investments and income taxes as a result of the Tax Legislation. The amendment was effective upon issuance. The adoption did not have a material impact on the Company's Consolidated Financial Statements.

In August 2018, the FASB issued ASU No. 2018-13, Fair value measurement (Topic 820) – Disclosure framework – Changes to the disclosure requirements for fair value measurement, which modifies the disclosure requirements on fair value measurements in Topic 820. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In August 2018, the FASB issued ASU No. 2018-14, Compensation – retirement benefits – Defined benefit plans – General (Subtopic 715-20) – Disclosure Framework – Changes to the disclosure requirements for defined benefit plans, which modifies disclosure requirements on defined benefit plans in Topic 715. The amendment will be effective for reporting periods beginning after December 15, 2020, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

Revenue

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue Recognition [Text Block]

Adoption of ASC Topic 606, Revenue from Contracts with Customers

On January 1, 2018, QEP adopted ASC Topic 606, Revenue from Contracts with Customers, using the modified retrospective approach, which was applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018, are presented in accordance with ASC Topic 606, while prior period amounts are reported in accordance with ASC Topic 605, Revenue Recognition.

In accordance with ASC Topic 606, QEP now records transportation and processing costs that are incurred after control of its product has transferred to the customer as a reduction of "Oil and condensate, gas and NGL sales" on the Consolidated Statements of Operations. Prior to the adoption of ASC Topic 606, these transportation and processing costs were recorded as an expense within "Transportation and processing costs" on the Consolidated Statements of Operations. There was no impact to net income (loss) or opening retained earnings as a result of adopting ASC Topic 606.

The following table presents the impact to the Consolidated Statements of Operations as a result of adopting ASC Topic 606.



	Year Ended December 31, 2018
	As Reported			ASC Topic 606 Adjustments		As Adjusted⁽¹⁾
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	1,871.3		$	55.0	$	1,926.3
Other revenues	12.5			—		12.5
Purchased oil and gas sales	48.8			—		48.8
Total Revenues	1,932.6			55.0		1,987.6
OPERATING EXPENSES
Purchased oil and gas expense	51.0			—		51.0
Lease operating expense	263.1			—		263.1
Transportation and processing costs	117.6			55.0		172.6
Gathering and other expense	15.5			—		15.5
General and administrative	221.7			—		221.7
Production and property taxes	130.8			—		130.8
Depreciation, depletion and amortization	857.1			—		857.1
Exploration expenses	0.3			—		0.3
Impairment	1,560.9			—		1,560.9
Total Operating Expenses	3,218.0			55.0		3,273.0
Net gain (loss) from asset sales, inclusive of restructuring costs	25.0			—		25.0
OPERATING INCOME (LOSS)	(1,260.4		)	—		(1,260.4		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	90.4			—		90.4
Interest and other income (expense)	(9.6		)	—		(9.6		)
Interest expense	(149.4		)	—		(149.4		)
INCOME (LOSS) BEFORE INCOME TAXES	(1,329.0		)	—		(1,329.0		)
Income tax (provision) benefit	317.4			—		317.4
NET INCOME (LOSS)	$	(1,011.6	)	$	—	$	(1,011.6	)

Earnings (loss) per common share
Basic	$	(4.25	)	$	—	$	(4.25	)
Diluted	$	(4.25	)	$	—	$	(4.25	)

Weighted-average common shares outstanding
Used in basic calculation	237.9			—		237.9
Used in diluted calculation	237.9			—		237.9

____________________________


⁽¹⁾	This column excludes the impact of adopting ASC Topic 606 and is consistent with the presentation prior to January 1, 2018.

The following tables present our revenues that are disaggregated by revenue source and by geographic area. Transportation and processing costs in the following tables are not all of the transportation and processing costs that the Company incurs, only the expenses that are netted against revenues pursuant to ASC Topic 606.



	Oil and condensate sales			Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Year Ended December 31, 2018
Northern Region
Williston Basin	$	707.0		$	45.3	$	56.5	$	(43.1	)	$	765.7
Uinta Basin	25.3			25.0		4.8		—			55.1
Other Northern⁽¹⁾	4.9			2.0		—		—			6.9
Southern Region
Permian Basin	684.4			17.3		49.5		(11.9		)	739.3
Haynesville/Cotton Valley	1.0			303.1		—		—			304.1
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,422.4		$	393.1	$	110.8	$	(55.0	)	$	1,871.3

	Year Ended December 31, 2017⁽²⁾
Northern Region
Williston Basin	$	586.5		$	42.3	$	51.5	$	—		$	680.3
Pinedale	18.0			154.8		31.8		—			204.6
Uinta Basin	29.6			50.0		5.9		—			85.5
Other Northern	4.9			16.6		0.3		—			21.8
Southern Region
Permian Basin	298.8			15.5		22.0		—			336.3
Haynesville/Cotton Valley	1.2			214.4		0.4		—			216.0
Other Southern	0.4			0.4		—		—			0.8
Total oil and condensate, gas and NGL sales	$	939.4		$	494.0	$	111.9	$	—		$	1,545.3

	Year Ended December 31, 2016⁽²⁾
Northern Region
Williston Basin	$	541.6		$	33.1	$	22.7	$	—		$	597.4
Pinedale	25.8			194.1		40.6		—			260.5
Uinta Basin	28.0			52.5		6.4		—			86.9
Other Northern	5.0			18.7		0.3		—			24.0
Southern Region
Permian Basin	166.1			11.6		12.9		—			190.6
Haynesville/Cotton Valley	1.1			106.6		0.4		—			108.1
Other Southern	1.5			0.5		0.2		—			2.2
Total oil and condensate, gas and NGL sales	$	769.1		$	417.1	$	83.5	$	—		$	1,269.7

_______________________


⁽¹⁾	For the year ended December 31, 2018, immaterial amounts of revenue associated with adjustments in Pinedale have been included in Other Northern.


⁽²⁾	Prior period amounts have not been adjusted under the modified retrospective method.

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Acquisitions and divestitures [Text Block]

Acquisitions

2017 Permian Basin Acquisition

In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin for an aggregate purchase price of $721.0 million (2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consists of approximately 15,100 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the Pinedale Divestiture (defined below). The 2017 Permian Basin Acquisition meets the definition of an asset acquisition because substantially all of the total fair value acquired relates to undeveloped leaseholds which do not have outputs. During the year ended December 31, 2018, QEP closed $49.1 million of acquisitions from various entities that owned additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the 2017 Permian Basin Acquisition.

2016 Permian Basin Acquisition

In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million (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 cash on hand, which included proceeds from an equity offering in June 2016.

The 2016 Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included significant proved properties. QEP allocated the cost of the 2016 Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $498.4 million and $80.2 million and net income of $282.4 million and $221.4 million were generated from the acquired properties for the years ended December 31, 2018 and 2017. 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. The revenue and net income (loss) 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 Statements of Operations. In conjunction with the 2016 Permian Basin Acquisition, the Company recorded a $17.8 million bargain purchase gain. 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 bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)".

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



Consideration:
Total consideration	$	591.0

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	(17.8		)
Total fair value	$	591.0

The following unaudited, pro forma results of operations are provided for the year ended December 31, 2016. Pro forma results are not provided for the years ended December 31, 2018 and 2017, because the 2016 Permian Basin Acquisition occurred during the fourth quarter of 2016; and therefore, the results are included in QEP's results of operations for the years ended December 31, 2018 and 2017. The supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the periods presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the year ended December 31, 2016, 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, and quantifying, the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the 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
	Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	1,377.1		$	1,392.5
Net income (loss)	$	(1,245.0	)	$	(1,246.8	)
Earnings (loss) per common share
Basic	$	(5.62	)	$	(5.62	)
Diluted	$	(5.62	)	$	(5.62	)

Other Acquisitions

In addition to the acquisitions related to the 2017 Permian Basin Acquisition, during the year ended December 31, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $16.5 million, subject to post-closing purchase price adjustments.

In addition to the 2017 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2017, which primarily included undeveloped leasehold acreage, producing wells and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million, subject to post-closing purchase price adjustments. In conjunction with the acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired.

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, 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)".

Divestitures

In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives (2018 Strategic Initiatives) including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. As of December 31, 2018, the Company closed the sale of its Uinta Basin assets and entered into purchase and sale agreements for its Williston Basin and Haynesville/Cotton Valley assets. Assets are considered held for sale once it is deemed unlikely that there will be any significant changes to QEP's divestiture plan. Refer to Note 16 – Subsequent Events for more information.

Haynesville/Cotton Valley Divestiture

In November 2018, the Company's wholly owned subsidiaries, QEP Energy Company, QEP Marketing Company, and QEP Oil & Gas Company, entered into a definitive agreement to sell its assets in Haynesville/Cotton Valley for a purchase price of $735.0 million, subject to purchase price adjustments, including adjustments for certain title and environmental defects asserted prior to the closing (Haynesville Divestiture). In January 2019, QEP closed the Haynesville Divestiture for net cash proceeds of $605.1 million, subject to post-closing purchase price adjustments. In addition, $32.2 million was placed in escrow due to title defects asserted prior to closing, to be resolved pursuant to the purchase and sale agreement's title dispute resolution procedures. Since the transaction was substantially finalized as of December 31, 2018, the assets and liabilities associated with the Haynesville Divestiture have been classified as noncurrent assets and liabilities held for sale on the Consolidated Balance Sheets and the notes accompanying the Consolidated Financial Statements. In addition, QEP recorded $3.0 million of estimated restructuring costs related to this divestiture during the year ended December 31, 2018, included in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations. Refer to Note 8 – Restructuring Costs for more information.

The following table presents the carrying amounts of the major classes of assets and liabilities classified as noncurrent assets and liabilities held for sale on the Consolidated Balance Sheets:



	December 31, 2018		December 31, 2017⁽¹⁾
	(in millions)
Assets
Current assets, total	$	1.2	$	3.4
Property, Plant and Equipment	683.7		1,290.3
Other noncurrent assets	7.8		27.2
Noncurrent assets held for sale	$	692.7	$	1,320.9
Liabilities
Current liabilities, total	$	3.4	$	4.5
Asset retirement obligations, current	0.7		4.7
Asset retirement obligations, long-term	56.9		102.5
Fair value of derivative contracts, long-term	—		(3.0		)
Other long-term liabilities	0.3		0.5
Other long-term liabilities held for sale	$	61.3	$	109.2

____________________________


⁽¹⁾	For the year ended December 31, 2017, the asset and liabilities held for sale also includes the Uinta Basin Divestiture.

Planned Williston Basin Divestiture

In November 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a purchase and sale agreement for its assets in the Williston Basin for a purchase price of $1,725.0 million, subject to purchase price adjustments which may be material (Planned Williston Basin Divestiture). The purchase price is comprised of $1,650.0 million in cash and contractual rights to receive $75.0 million of the buyer's common stock if certain conditions are met. The transaction is subject to certain conditions, including, but not limited to, approval of buyer's shareholders and regulatory approvals. As of December 31, 2018, the Williston Basin assets were classified as held and used in the Company's Consolidated Financial Statements as the assets did not meet the held for sale criteria. As a part of the 2018 Strategic Initiatives, QEP has incurred or expects to incur costs associated with contractual termination benefits, including severance, accelerated vesting of share-based compensation and other expenses. Refer to Note 8 – Restructuring Costs and Note 16 – Subsequent Events for more information.

Uinta Basin Divestiture

In September 2018, QEP sold substantially all of its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of $153.0 million, subject to post-closing purchase price adjustments (Uinta Basin Divestiture). During the year ended December 31, 2018, QEP recorded a pre-tax loss of $12.6 million related to the Uinta Basin Divestiture, which included $5.4 million related to estimated restructuring costs recorded on the Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs". In conjunction with the Uinta Basin Divestiture, QEP recorded $402.8 million of proved and unproved properties impairment during the year ended December 31, 2018. Refer to Note 1 – Summary of Significant Accounting Policies and Note 8 – Restructuring Costs for more information.

Pinedale Divestiture

In September 2017, QEP sold its Pinedale assets (Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million. During the year ended December 31, 2017 QEP recorded a pre-tax gain on sale of $180.4 million, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations. For the year ended December 31, 2018, QEP recorded a pre-tax gain on sale of $1.2 million, due to additional post-closing purchase price adjustments.

QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. As of December 31, 2018, the liability associated with estimated future payments for this commitment was $9.3 million and is reported on the Consolidated Balance Sheets within "Accounts payable and accrued expenses".

For the year ended December 31, 2017, QEP recorded net income before income taxes related to Pinedale, prior to the divestiture of $251.0 million, which includes the pre-tax gain on sale of $180.4 million. For the year ended December 31, 2016, QEP recorded a net loss before income taxes of $1,152.7 million. The net loss before income taxes was primarily due to an impairment on proved properties of $1,164.0 million recognized in 2016 as a result of a decrease in expected future gas prices.

Other Divestitures

In addition to the Uinta Basin Divestiture, during the year ended December 31, 2018, QEP received net cash proceeds of $90.6 million and recorded a net pre-tax gain on sale of $38.5 million related to the divestiture of properties outside our main operating areas.

In addition to the Pinedale Divestiture, during the year ended December 31, 2017, QEP also sold its Central Basin Platform assets (Central Basin Platform Divestiture) and received net cash proceeds of $3.5 million. Refer to Note 4 – Capitalized Exploratory Well Costs for more information. In addition, QEP received net cash proceeds of $85.1 million and recorded a pre-tax gain on sale of $33.1 million, primarily related to the sale of properties in the Other Northern area.

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 $8.6 million.

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

Capitalized Exploratory Well Costs

12 Months Ended

Dec. 31, 2018

Capitalized Exploratory Well Costs [Abstract]

Suspended Well Costs Disclosure [Text Block]

Net changes in capitalized exploratory well costs are presented in the table below.



	Capitalized Exploratory Well Costs
	2018		2017			2016
	(in millions)
Balance at January 1,	$	—	$	14.2		$	2.6
Additions to capitalized exploratory well costs	—		10.7			11.7
Reclassifications to proved properties	—		(3.6		)	—
Capitalized exploratory well costs charged to expense	—		(21.3		)	(0.1		)
Balance at December 31,	$	—	$	—		$	14.2

The balance at December 31, 2016 represents the amount of capitalized exploratory well costs that were pending the determination of proved reserves.

During the years ended December 31, 2017 and 2016, QEP's exploratory well activity was related to the Central Basin Platform exploration project in the Permian Basin targeting the Woodford Formation. QEP completed a second exploratory well related to this project in the first half of 2017. During the year ended December 31, 2017, based on the performance of the two exploratory wells that were drilled and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project and would seek to monetize the assets. QEP charged $21.3 million of exploratory well costs to exploration expense. In conjunction with the expensing of the exploratory well costs, QEP charged $28.3 million of the associated unproved leasehold acreage in the Central Basin Platform to impairment expense during the year ended December 31, 2017. QEP wrote down the Central Basin Platform assets to their fair market value of $3.6 million and reclassified the assets to proved properties. During the fourth quarter of 2017, QEP closed the Central Basin Platform Divestiture for net cash proceeds of $3.5 million.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

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.

The Consolidated Balance Sheet line items of QEP's ARO liability are presented in the table below:



	Asset Retirement Obligations
	December 31,
	2018		2017
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	5.1	$	2.8
Long-term:
Asset retirement obligations	96.9		104.1
Other long-term liabilities held for sale	57.6		107.2
Total ARO Liability	$	159.6	$	214.1

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



	Asset Retirement Obligations
	2018			2017
	(in millions)
ARO liability at January 1,	$	214.1		$	231.6
Accretion	6.4			7.7
Additions⁽¹⁾	4.1			23.5
Revisions	(4.9		)	8.5
Liabilities related to assets sold⁽²⁾	(56.8		)	(34.9		)
Liabilities settled	(3.3		)	(22.3		)
ARO liability at December 31,	$	159.6		$	214.1

___________________________


⁽¹⁾	Additions for the year ended December 31, 2017, include $14.2 million related to the 2017 Permian Basin Acquisition. Refer to Note 3 – Acquisitions and Divestitures for more information.


⁽²⁾	Liabilities related to assets sold for the year ended December 31, 2018, includes $51.0 million related to the Uinta Basin Divestiture. Liabilities related to assets sold for the year ended December 31, 2017 includes $34.9 million related to the Pinedale Divestiture. Refer to Note 3 – Acquisitions and Divestitures for more information.

Fair Value Measurements

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 7 – Derivative Contracts for more information) 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, 2018 and 2017, 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 Sheets
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheets
	(in millions)
	December 31, 2018
Financial Assets
Fair value of derivative contracts – short-term⁽²⁾	$	—	$	88.2	$	—	$	(0.4	)	$	87.8
Fair value of derivative contracts – long-term	—		35.4		—		—			35.4
Total financial assets	$	—	$	123.6	$	—	$	(0.4	)	$	123.2

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	0.4	$	—	$	(0.4	)	$	—
Fair value of derivative contracts – long-term	—		0.7		—		—			0.7
Total financial liabilities	$	—	$	1.1	$	—	$	(0.4	)	$	0.7

	December 31, 2017
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	20.6	$	—	$	(17.2	)	$	3.4
Fair value of derivative contracts – long-term	—		2.3		—		(2.2		)	0.1
Total financial assets	$	—	$	22.9	$	—	$	(19.4	)	$	3.5

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	120.8	$	—	$	(17.2	)	$	103.6
Fair value of derivative contracts – long-term⁽²⁾	—		34.0		—		(2.2		)	31.8
Total financial liabilities	$	—	$	154.8	$	—	$	(19.4	)	$	135.4

____________________________


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


⁽²⁾	Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 and "Other long-term liabilities held for sale" of $3.0 million as of December 31, 2017 on the Consolidated Balance Sheets related to the Haynesville Divestiture.

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, 2018				December 31, 2017
Financial Assets	(in millions)
Cash and cash equivalents	$	—	$	—	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	14.6	$	14.6	$	44.0	$	44.0
Long-term debt	$	2,507.1	$	2,350.5	$	2,160.8	$	2,256.2

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 fair value of the deficiency charge obligation associated with the Pinedale Divestiture was measured utilizing an internally developed cash flow model discounted at QEP's weighted average cost of debt. Given the unobservable nature of the inputs, the fair value calculation associated with the deficiency charges is considered Level 3 within the fair value hierarchy. Refer to Note 3 – Acquisitions and Divestitures for more information.

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 periodic basis, at least annually, to review its proved oil and gas properties for potential impairment when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. The fair value of property is measured utilizing the income approach, and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. If a range is estimated for the amount of possible future cash flows, the fair value of property is measured utilizing a probability-weighted approach whereas the likelihood of possible outcomes is taken into consideration. Specific to the Planned Williston Basin Divestiture, the Company obtained a Black-Scholes-Merton estimate of the value of the contractual rights to receive up to 5.8 million shares of the buyer's common stock at December 31, 2018. The estimated fair value of these contractual rights at December 31, 2018 was determined using a five-year contractual period, a 5% risk-free interest rate and a 49.3% weighted-average expected price volatility. Given the unobservable nature of the inputs, fair value calculations associated with proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. During the years ended December 31, 2018, 2017 and 2016, the Company recorded impairments on certain proved oil and gas properties of $1,524.6 million, $38.1 million and $1,172.7 million, respectively, resulting in a reduction of the associated carrying value to fair value. Refer to Note 1 – Summary of Significant Accounting Policies for more 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: (i) estimated quantities of oil and condensate, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) 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. Refer to Note 3 – Acquisitions and Divestitures for more 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, 2018

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 has historically entered 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 costless 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. Gas price derivative instruments are typically structured as fixed-price swaps or costless collars at NYMEX Henry Hub or 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.

Derivative Contracts – Production

The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of December 31, 2018:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	11.0	$	54.49
2020	NYMEX WTI	2.9	$	62.37
Gas sales		(MMBtu)	($/MMBtu)
2019	NYMEX HH	43.8	$	2.86

QEP uses oil basis swaps, combined with NYMEX WTI 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 basis swaps as of December 31, 2018:



Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2019	NYMEX WTI	Argus WTI Midland	6.6	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.4	$	4.35
2020	NYMEX WTI	Argus WTI Midland	1.5	$	(1.01	)

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	2018		2017		2018		2017
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	88.2	$	20.6	$	0.4	$	120.8
Long-term:
Commodity	Fair value of derivative contracts	35.4		2.3		0.7		34.0
Total derivative instruments⁽¹⁾		$	123.6	$	22.9	$	1.1	$	154.8

_______________________


⁽¹⁾	Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 and "Other long-term liabilities held for sale" of $3.0 million as of December 31, 2017 on the Consolidated Balance Sheets related to the Haynesville Divestiture.



Derivative contracts	Year Ended December 31,
Derivative contracts	2018			2017			2016
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(153.4	)	$	6.8		$	86.3
Gas derivative contracts	(5.0		)	(22.3		)	44.8
Gas Storage
Gas derivative contracts	0.3			—			2.9
Realized gains (losses) on commodity derivative contracts	(158.1		)	(15.5		)	134.0
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	277.0			(66.2		)	(217.2		)
Gas derivative contracts	(22.3		)	133.6			(145.4		)
Gas Storage
Gas derivative contracts	(0.3		)	2.5			(4.4		)
Unrealized gains (losses) on commodity derivative contracts	254.4			69.9			(367.0		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	96.3		$	54.4		$	(233.0	)

Derivatives associated with Uinta and Pinedale divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(2.7	)	$	(1.3	)	$	—
Gas derivative contracts	—			(23.5		)	—
NGL derivative contracts	(3.2		)	(5.1		)	—
Unrealized gains (losses) on commodity derivative contracts related to divestitures⁽¹⁾⁽²⁾	$	(5.9	)	$	(29.9	)	$	—

Total realized and unrealized gains (losses) on commodity derivative contracts	$	90.4		$	24.5		$	(233.0	)

_______________________

⁽¹⁾

During the year ended December 31, 2018, the unrealized gains (losses) on commodity derivative contracts related to the Uinta Basin Divestiture are comprised of derivatives entered into in conjunction with the execution of the Uinta Basin purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2018. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Uinta Basin Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.

⁽²⁾

During the year ended December 31, 2017, the unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.

Restructuring Costs

12 Months Ended

Dec. 31, 2018

Restructuring Cost and Reserve [Line Items]

Restructuring Costs

In connection with our 2018 Strategic Initiatives, QEP has incurred or expects to incur restructuring costs associated with contractual termination benefits including severance, accelerated vesting of share-based compensation and other expenses. The termination benefits will be accounted for under ASC 712, Compensation – Nonretirement Postemployment Benefits and ASC 718, Compensation – Stock Compensation.

Restructuring costs recognized associated with the 2018 restructuring (2018 Restructuring) are summarized below:



	Year Ended December 31, 2018
	Total recognized		Recognized in "General and administrative"		Recognized in "Net gain (loss) from asset sales, inclusive of restructuring costs"			Recognized in "Interest and other income (expense)"
	(in millions)
Termination benefits	$	32.3	$	25.7	$	6.6		—
Office lease termination costs	1.0		1.0		—			—
Accelerated share-based compensation⁽¹⁾	11.0		8.8		2.2			—
Retention expense (including share-based compensation)	18.8		18.8		—			—
Pension and Medical Plan curtailment	0.1		—		(0.2		)	0.3
Total restructuring costs	$	63.2	$	54.3	$	8.6		$	0.3

____________________________


⁽¹⁾	Accelerated share based compensation represents the additional expense or loss recognized in the Consolidated Statement of Operations for the year ended December 31, 2018. Total accelerated share based compensation was $11.2 million and was determined based on the contractual vesting date, with $11.0 million recognized in 2018 as shown above, and the remaining amount recognized in prior periods.



	Costs recognized period from inception to December 31, 2018		Total remaining costs expected to be incurred⁽⁴⁾
	(in millions)
Termination benefits	$	32.3	$	—	⁽¹⁾
Office lease termination costs	1.0		—		⁽¹⁾
Accelerated share-based compensation	11.2		15.5		⁽¹⁾⁽²⁾
Retention expense (including share-based compensation)	18.8		21.4		⁽³⁾
Pension and Medical Plan curtailment	0.1		—		⁽¹⁾
Total restructuring costs	$	63.4	$	36.9

____________________________


⁽¹⁾	Due to the nature of the strategic initiatives and uncertain factors such as the timing and terms of the potential divestitures, the Company is not able to reasonably estimate the total cost to be incurred as a part of these restructurings.


⁽²⁾	In January 2019, QEP had $15.5 million of accelerated share-based compensation due to the departure of two officers. The accelerated share-based compensation of $15.5 million was determined based on the contractual vesting date with $6.0 million expected to be recognized in the first quarter of 2019 and the remaining amount previously recognized in 2018 and prior periods.


⁽³⁾	QEP expects to incur an additional $3.9 million in 2019 related to the 2018 retention program and $17.5 million related to the 2019 retention program, which includes $16.0 million of cash and $1.5 million of share-based compensation.


⁽⁴⁾	Refer to the Note 16 – Subsequent Events for more information regarding expected restructuring costs.

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



	Restructuring liability
	Termination benefits			Office lease termination costs			Accelerated share-based compensation			Retention expense			Pension curtailment			Total
	(in millions)
Balance at December 31, 2017	$	—		$	—		$	0.2		$	—		$	—		$	0.2
Costs incurred and charged to expense	32.3			1.0			11.0			18.8			0.1			63.2
Costs paid or otherwise settled	(12.8		)	(1.0		)	(11.2		)	(8.0		)	(0.1		)	(33.1		)
Balance at December 31, 2018	$	19.5		$	—		$	—		$	10.8		$	—		$	30.3

Debt

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt

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



	December 31,
	2018			2017
	(in millions)
Revolving Credit Facility due 2022	$	430.0		$	89.0
6.80% Senior Notes due 2020	51.7			51.7
6.875% Senior Notes due 2021	397.6			397.6
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
5.625% Senior Notes due 2026	500.0			500.0
Less: unamortized discount and unamortized debt issuance costs	(22.2		)	(27.5		)
Total long-term debt outstanding	$	2,507.1		$	2,160.8

Of the total debt outstanding on December 31, 2018, the 6.80% Senior Notes due March 1, 2020, the 6.875% Senior Notes due March 1, 2021, the 5.375% Senior Notes due October 1, 2022 and the 5.25% Senior Notes due May 1, 2023, will mature within the next five years. In addition, the revolving credit facility matures on September 1, 2022.

Credit Facility

QEP's revolving credit facility, which matures, subject to satisfaction of certain conditions, in September 2022, provides for loan commitments of $1.25 billion. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit agreement contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can 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 4.00 times consolidated EBITDA (as defined in the credit agreement), through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings trigger period (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.40 times commencing on January 1, 2019 through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. As of December 31, 2018, the Company is not subject to the present value coverage ratio. As of December 31, 2018 and 2017, QEP was in compliance with the covenants under the credit agreement.

During the years ended December 31, 2018 and 2017, QEP's weighted-average interest rates on borrowings from its credit facility were 4.43% and 3.52%, respectively. As of December 31, 2018, QEP had $430.0 million of borrowings outstanding and $0.3 million in letters of credit outstanding under the credit facility. As of December 31, 2017, QEP had $89.0 million of borrowings outstanding and $1.0 million in letters of credit outstanding under the credit facility.

Senior Notes

At December 31, 2018, the Company had $2,099.3 million principal amount of senior notes outstanding with maturities ranging from March 2020 to March 2026 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, 2018

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.

Landowner Litigation – In October, 2017, the owners of certain surface and mineral interests in Martin and Andrews County, Texas, filed suit against QEP, alleging QEP improperly used the surface of the properties and failed to correctly pay royalties, and seeking money damages and a declaratory judgment that portions of the oil and gas leases covering the properties are no longer in effect.

Mandan, Hidatsa and Arikara Nation ("MHA Nation") Title Dispute – In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri Riverbeds on the Fort Berthold Reservation in North Dakota. The MHA Nation also passed a resolution purporting to rescind those portions of QEP's IMDA lease covering the disputed minerals underlying the Missouri River.

The Company is unable to make an estimate of the range of reasonably possible loss related to its contingencies.

Commitments

QEP has contracted for gathering, processing and firm transportation 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, drilling and fractionation contracts are as follows:



Year	Amount
	(in millions)
2019	$	72.2
2020	$	55.4
2021	$	31.3
2022	$	27.1
2023	$	15.3
After 2023	$	66.0

QEP rents office space, compressors, generators and equipment throughout its scope of operations from third-party lessors. Expense from operating leases amounted to $30.3 million, $24.9 million, and $21.7 million during the years ended December 31, 2018, 2017 and 2016, respectively. Minimum future payments under the terms of long-term operating leases are as follows:



Year	Amount
	(in millions)
2019	$	17.4
2020	$	13.8
2021	$	9.1
2022	$	7.4
2023	$	4.5
After 2023	$	—

Share-Based Compensation

12 Months Ended

Dec. 31, 2018

Share-based Compensation [Abstract]

Share-Based Compensation

In 2018, QEP's Board of Directors and QEP's shareholders approved the QEP Resources, Inc. 2018 Long-Term Incentive Plan (LTIP), which replaces the 2010 Long-Term Stock Incentive Plan (LTSIP) and provides for the issuance of up to 10.0 million shares such that the Board of Directors may grant long-term incentive compensation. QEP issues stock options, restricted share awards and restricted share units under its LTSIP or LTIP and awards performance share units under its CIP to certain officers, employees, and non-employee directors. Grants issued prior to May 15, 2018 are under the LTSIP and the grants issued on or after May 15, 2018 are under the LTIP. QEP recognizes the expense over the vesting periods for the stock options, restricted share awards, restricted share units and performance share units. There were 10.1 million shares available for future grants under the LTIP at December 31, 2018.

Share-based compensation expense is recognized within "General and administrative" expense on the Consolidated Statements of Operations and is summarized in the table below. During the year ended December 31, 2018, the Company recorded an additional $11.0 million of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program, of which $2.2 million for the year ended December 31, 2018 was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations and the remaining $8.8 million is included in share-based compensation expense below (refer to Note 8 – Restructuring Costs for more information):



	Year Ended December 31,
	2018		2017			2016
	(in millions)
Stock options	$	1.2	$	2.3		$	2.3
Restricted share awards	27.5		24.6			23.7
Performance share units	8.1		(4.5		)	9.4
Restricted share units	0.1		—			0.2
Total share-based compensation expense	$	36.9	$	22.4		$	35.6

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 Company recognizes forfeitures of stock options as they occur. In 2018, QEP did not issue stock options.

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,
	2017			2016
Weighted-average grant date fair value of awards granted during the period	$	6.44		$	3.77
Risk-free interest rate range	1.66% - 1.81%			0.99% - 1.15%
Weighted-average risk-free interest rate	1.8		%	1.2		%
Expected price volatility range	43.82% - 46.70%			43.42% - 43.66%
Weighted-average expected price volatility	43.9		%	43.4		%
Expected dividend yield	—		%	—		%
Expected term in years at the date of grant	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, 2017	2,354,277		$	23.62
Exercised	(23,337	)	10.12
Cancelled	(232,007	)	37.16
Outstanding at December 31, 2018	2,098,933		$	22.27	2.87	$	—
Options Exercisable at December 31, 2018	1,732,827		$	23.90	2.46	$	—
Unvested Options at December 31, 2018	366,106		$	14.57	4.81	$	—

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of stock options exercised was $0.1 million during the year ended December 31, 2018. During the years ended December 31, 2017 and 2016, there were no exercises of stock options. There was no income tax impact for the years ended December 31, 2018 and 2017. The Company realized an income tax benefit of $0.2 million for the year ended December 31, 2016. As of December 31, 2018, $0.4 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 1.19 years. The weighted-average vesting period may be reduced due to accelerated vesting under the restructuring program. Refer to Note 8 – Restructuring Costs for more information.

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 Company recognizes restricted share forfeitures as they occur. The total fair value of restricted share awards that vested during the years ended December 31, 2018, 2017 and 2016, was $21.5 million, $18.4 million and $24.3 million, respectively. There was no income tax impact for the years ended December 31, 2018 and 2017. The weighted-average grant date fair value of restricted share awards granted was $9.56 per share, $13.90 per share and $10.50 per share for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, $15.2 million of unrecognized compensation cost related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.98 years. The weighted-average vesting period may be reduced due to accelerated vesting of awards under the restructuring program. Refer to Note 8 – Restructuring Costs for more information.

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



	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2017	3,721,334		$	13.23
Granted	2,997,743		9.56
Vested	(2,630,959	)	12.87
Forfeited	(265,985	)	10.96
Unvested balance at December 31, 2018	3,822,133		$	10.76

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 paid 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 LTIP; however, as of December 31, 2018, the Company expects to settle all awards in cash under the CIP. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Consolidated Balance Sheets. 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, $5.3 million and $2.8 million for vested performance share units during the years ended December 31, 2018, 2017 and 2016, respectively. The weighted-average grant date fair value of the performance share units granted during the years ended December 31, 2018, 2017 and 2016, was $9.55, $16.90, and $10.16 per share, respectively. As of December 31, 2018, $7.3 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 1.84 years. The weighted-average vesting period may be reduced due to accelerated vesting under the restructuring program. Refer to Note 8 – Restructuring Costs for more information.

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, 2017	1,199,336		$	14.59
Granted	724,095		9.55
Vested	(364,119	)	17.26
Unvested balance at December 31, 2018	1,559,312		$	11.47

Restricted Share Units

Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as 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 paid in cash. They are classified as liabilities in "Other long-term liabilities" on the Consolidated Balance Sheets 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 $9.55, $16.98 and $10.12 per share for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, $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 0.88 years. The weighted-average vesting period may be reduced due to accelerated vesting of awards under the restructuring program. Refer to Note 8 – Restructuring Costs for more information.

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, 2017	21,946		$	13.22
Granted	31,835		9.55
Vested	(11,106	)	13.27
Unvested balance at December 31, 2018	42,675		$	10.47

Employee Benefits

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Employee Benefits

Pension and Other Postretirement Benefits

The Company provides pension and other postretirement benefits to certain employees through three benefit plans: the QEP Resources, Inc. Retirement Plan (Pension Plan), the Supplemental Executive Retirement Plan (SERP), and a postretirement medical plan (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, 2018, covers 20 active and suspended participants, or 4%, of QEP's active employees, and 194 participants that are retired or were terminated and vested. Pension Plan benefits are based on the employee's age at retirement, years of service as of the earlier of the participant's termination of employment or December 31, 2015, and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding termination of employment or, if earlier, December 31, 2015. During the year ended December 31, 2018, the Company made contributions of $5.0 million to the Pension Plan and expects to contribute approximately $5.0 million to the Pension Plan in 2019. Contributions to the Pension Plan increase plan assets.

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 the participant's termination of employment. During the year ended December 31, 2018, the Company made contributions of $0.7 million to its SERP and expects to contribute approximately $0.5 million in 2019. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and is closed to new participants effective January 1, 2016.

During the year ended December 31, 2017, the Company recognized a $0.7 million loss on curtailment related to the SERP in connection with the Pinedale Divestiture, which was recorded on the Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs".

The Medical Plan is a self-insured plan. It is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired QEP employees. The Medical Plan was originally provided only to employees hired by Questar Corporation before January 1, 1997. Of the 20 active, pension eligible employees, 12 are also eligible for the Medical Plan when they retire. As of December 31, 2018, 35 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, 2018, the Company made contributions of $0.4 million and expects to contribute approximately $0.2 million of benefits in 2019. At December 31, 2018 and 2017, QEP's accumulated benefit obligation exceeded the fair value of its qualified retirement plan assets.

In February 2017, the Company changed the eligibility requirements for active employees eligible for the Medical Plan, as well as retirees currently enrolled. Effective July 1, 2017, the Company no longer offers the Medical Plan to a retiree and spouse that are both Medicare eligible. In addition, the Company no longer offers life insurance to individuals retiring on or after July 1, 2017.

The Company's execution of its strategic initiatives may trigger curtailments related to the Pension Plan, SERP and/or Medical Plan at the closing of the various transactions. Refer to Note 8 – Restructuring Costs for more information. The Company recognized a $0.3 million curtailment loss related to the Pension Plan as part of the Uinta Basin Divestiture, which is included in "Interest and other income (expense)" on the Consolidated Statements of Operations. The Company recognized a $0.2 million curtailment gain related to the Medical Plan as part of the continued divestiture activity included in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.

In accordance with the early adoption of ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, the Company recast years ended December 31, 2017 and 2016 by recognizing service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations.

The accumulated benefit obligation for all defined-benefit pension plans was $121.6 million and $128.7 million at December 31, 2018 and 2017, 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, 2018 and 2017, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2018 and 2017:



	Pension Plan and SERP benefits						Medical Plan benefits
	2018			2017			2018			2017
Change in benefit obligation	(in millions)
Benefit obligation at January 1,	$	130.0		$	129.2		$	2.9		$	5.4
Service cost	0.8			0.8			—			—
Interest cost	4.6			4.7			0.1			0.1
Curtailments	0.1			(0.3		)	—			—
Benefit payments	(5.8		)	(6.9		)	(0.4		)	(0.1		)
Plan amendments	—			—			—			(2.4		)
Actuarial loss (gain)	(7.6		)	2.5			(0.1		)	(0.1		)
Benefit obligation at December 31,	$	122.1		$	130.0		$	2.5		$	2.9
Change in plan assets
Fair value of plan assets at January 1,	$	100.5		$	86.1		$	—		$	—
Actual return on plan assets	(7.1		)	15.3			—			—
Company contributions to the plan	5.7			6.0			0.4			0.1
Benefit payments	(5.8		)	(6.9		)	(0.4		)	(0.1		)
Fair value of plan assets at December 31,	93.3			100.5			—			—
Underfunded status (current and long-term)	$	(28.8	)	$	(29.5	)	$	(2.5	)	$	(2.9	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(1.1	)	$	(1.5	)	$	(0.2	)	$	(0.2	)
Other long-term liabilities	(27.7		)	(27.9		)	(2.3		)	(2.6		)
Total amount recognized in balance sheet	$	(28.8	)	$	(29.4	)	$	(2.5	)	$	(2.8	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	19.4		$	15.0		$	(0.5	)	$	(0.5	)
Prior service cost	0.4			1.2			(0.8		)	(1.2		)
Total amount recognized in AOCI	$	19.8		$	16.2		$	(1.3	)	$	(1.7	)

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
	2018			2017			2016			2018			2017			2016
Components of net periodic benefit cost	(in millions)
Service cost	$	0.8		$	0.8		$	1.2		$	—		$	—		$	—
Interest cost	4.6			4.7			5.2			0.1			0.1			0.2
Expected return on plan assets	(5.8		)	(5.4		)	(5.6		)	—			—			—
Curtailment loss	0.3			0.7			—			(0.2		)	—			—
Settlements	—			0.2			—			—			—			—
Amortization of prior service costs	0.8			1.0			1.1			(0.3		)	(0.3		)	0.2
Amortization of actuarial loss	0.8			0.5			0.8			—			(0.1		)	—
Periodic expense	$	1.5		$	2.5		$	2.7		$	(0.4	)	$	(0.3	)	$	0.4
Components recognized in accumulated other comprehensive income
Current period prior service cost	$	—		$	(0.7	)	$	—		$	0.2		$	(2.5	)	$	—
Current period actuarial (gain) loss	5.6			(7.5		)	8.5			(0.1		)	(0.1		)	0.4
Amortization of prior service cost	(0.8		)	(1.0		)	(1.1		)	0.3			0.3			(0.2		)
Amortization of actuarial gain (loss)	(0.8		)	(0.5		)	(0.8		)	—			0.1			—
Loss on curtailment in current period	(0.1		)	(0.3		)	—			—			—			—
Settlements	—			(0.2		)	—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	3.9		$	(10.2	)	$	6.6		$	0.4		$	(2.2	)	$	0.2

The Company recognizes service costs related to SERP and Medical Plan benefits on the Consolidated Statements of Operations within "General and administrative" expense. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized on the Consolidated Statements of Operations within "Interest and other income (expense)".

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 2019 is $1.8 million, which represents amortization of prior service cost recognized and actuarial losses. The estimated portion of net actuarial loss and net prior service cost for the Medical Plan that will be amortized from AOCI into net periodic benefit cost in 2019 is $0.3 million, which represents amortization of prior service cost recognized and actuarial gains. Amortization of prior service costs and actuarial gains or losses out of AOCI are recognized in the Consolidated Statements of Operations in "Interest and other income (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, 2018 and 2017:



	Pension Plan and SERP benefits				Medical Plan benefits
	2018		2017		2018		2017
Discount rate	4.19	%	3.52	%	4.30	%	3.60	%
Rate of increase in compensation⁽¹⁾	3.00	%	3.50	%	n/a		n/a

_______________________


⁽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 years ended December 31, 2018 and 2017, the rate of increase in compensation is only used for the SERP.

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
	2018		2017		2016		2018		2017		2016
Discount rate	3.50	%	4.00	%	4.23	%	3.60	%	4.10	%	4.40	%
Expected long-term return on plan assets	6.00	%	6.00	%	6.50	%	n/a		n/a		n/a
Rate of increase in compensation⁽¹⁾	3.50	%	3.50	%	4.00	%	n/a		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, 2018, the rate of increase in compensation is only used for the SERP. For the year ended December 31, 2017, the rate of increase in compensation is only used for 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 2019. 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.

The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2018 and 2017, respectively:



	December 31, 2018				December 31, 2017
	Total		Percentage of total		Total		Percentage of total
	(in millions, except percentages)
Cash and short-term investments	$	0.7	1	%	$	0.5	—	%
Equity securities:
Domestic	20.7		22	%	35.0		35	%
International	10.0		11	%	15.3		15	%
Fixed income	61.9		66	%	49.7		50	%
Total investments	$	93.3	100	%	$	100.5	100	%

Expected Benefit Payments

As of December 31, 2018, the following future benefit payments are expected to be paid:



	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2019	$	6.6	$	0.2
2020	$	16.7	$	0.2
2021	$	6.4	$	0.2
2022	$	6.4	$	0.2
2023	$	8.1	$	0.2
2024 through 2026	$	32.7	$	0.5

Employee Investment Plan

QEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (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. Both employees and QEP make contributions to the 401(k) Plan. The Company may contribute a discretionary portion beyond the Company's matching contribution to employees not in the Pension Plan or SERP. During the years ended December 31, 2018, 2017 and 2016, the Company made contributions of $5.8 million, $6.0 million and $5.6 million to the 401(k) Plan, respectively. The Company recognizes expense equal to its yearly contributions. Due to the Company's strategic initiatives, the amount expected to be contributed to the 401(k) Plan is subject to change. Participants receive 100% employer matching contributions on participant 401(k) plan contributions up to a percentage of qualifying earnings as described below.



	Year Ended December 31,
	2018		2017		2016
Employees who do not accrue a benefit in the SERP
Maximum employer matching of qualifying earnings	8	%	8	%	8	%

Employees who accrue a benefit in the SERP
Maximum employer matching of qualifying earnings	6	%	6	%	6	%

As a result of freezing benefits under the Pension Plan, the 401(k) Plan and a nonqualified, unfunded deferred compensation plan (the Wrap Plan), were amended to allow the Company to make discretionary contributions in the form of Company Transition Credits to eligible participants. Eligible participants are certain highly and non-highly compensated employees who were active participants in the Pension Plan on December 31, 2015. During the years ended December 31, 2018, 2017 and 2016, the Company made a discretionary contribution of $0.3 million, $0.4 million and $0.5 million, respectively, to active participants of the Pension Plan.

Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

On December 22, 2017 the Tax Legislation was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation. Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. As additional guidance to the Tax Legislation is published in the form of Treasury Regulations and other IRS communications, the Company will monitor, assess, and determine the impact of these communications on the Company's consolidated financial statements and operations. In addition to the Tax Legislation, QEP is continuing to monitor proposed regulations regarding the 163(j) Limitation on Deduction for Business Interest Expense, which when finalized, could require QEP to re-characterize the Company's deferred tax assets, resulting in changes in QEP's income tax disclosures. QEP expects the impact to the Company's results of operations to be immaterial.

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,
	2018			2017			2016
Federal income tax provision (benefit)	(in millions)
Current	$	(71.3	)	$	2.1		$	(55.5	)
Deferred	(257.8		)	(339.8		)	(614.3		)
State income tax provision (benefit)
Current	1.5			0.5			(1.5		)
Deferred	10.2			25.0			(36.9		)
Total income tax provision (benefit)	$	(317.4	)	$	(312.2	)	$	(708.2	)

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,
	2018		2017		2016
Federal income taxes statutory rate	21.0	%	35.0	%	35.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit⁽¹⁾	(0.7	)%	(40.1	)%	2.4	%
Federal rate change⁽²⁾	—	%	741.3	%	—	%
State rate change	—	%	2.1	%	(1.1	)%
Permanent adjustments	(0.1	)%	(0.4	)%	—	%
Return to provision adjustment	(0.1	)%	(0.7	)%	—	%
Uncertain tax provision (federal rate change)	—	%	(7.7	)%	—	%
AMT Credit Reclass due to NOL Carryback⁽³⁾	3.8	%	(1.8	)%	—	%
Effective income tax rate	23.9	%	727.7	%	36.3	%

____________________________


⁽¹⁾	State income taxes changed significantly from prior years mainly due to the change in valuation allowance recorded during 2017 of $36.2 million.


⁽²⁾	The Tax Legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets as of December 31, 2017 from a 35% to 21% federal corporate income tax rate which caused the majority of the change in rate.


⁽³⁾	In 2018, QEP agreed to an IRS proposed change to the initial treatment of the 2016 carryback of net operating losses. This change resulted in a reduction of available net operating loss carryforwards valued at $75.7 million and an increase in alternative minimum tax (AMT) credit carryforwards of $126.0 million. The net change in value of $50.3 million was recorded in deferred income taxes.

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



	December 31,
	2018		2017
Deferred tax liabilities	(in millions)
Property, plant and equipment	$	665.1	$	898.7
Commodity price derivatives	30.1		—
Deferred tax assets
Net operating loss and tax credit carryforwards	$	385.6	$	308.8
Employee benefits and compensation costs	26.1		26.4
Bonus and vacation accrual	7.1		6.2
Commodity price derivatives	—		29.9
Other	7.2		9.4
Total deferred tax assets	426.0		380.7
Net deferred income tax liability	$	269.2	$	518.0
Balance sheet classification
Deferred income tax liability – noncurrent	269.2		518.0
Net deferred income tax liability	$	269.2	$	518.0

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2018, are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2019-2038	$	121.4
State net operating loss valuation allowance		$	(82.3	)
U.S. net operating loss⁽¹⁾	2036-2037	$	272.3
U.S. alternative minimum tax credit	Indefinite	$	74.2

____________________________


⁽¹⁾	Net operating losses created in tax years beginning after December 31, 2017 can be carried forward indefinitely under the Tax Legislation (limited to 80% of taxable income computed without the net operating loss deduction).

The valuation allowance of $82.3 million was established in 2014, 2017 and 2018 against the available state net operating loss and is related primarily to losses incurred in Oklahoma, Utah and Louisiana. 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. As of December 31, 2018, $26.4 million of the allowance is related to Oklahoma net operating loss. In 2018, a valuation allowance of $49.0 million was established against Louisiana's net operating loss as the Company does not forecast sufficient taxable income to utilize the entire net operating loss in Louisiana. In 2018, a valuation allowance of $6.7 million was established against available Utah net operating losses, mainly due to the Uinta Basin Divestiture in 2018.

The Tax Legislation eliminated AMT and QEP has the ability to offset its regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior years. The Company currently anticipates it will realize approximately $148.4 million in AMT credit refunds over the next four years with $74.2 million to be realized in 2019 for tax year 2018, which is shown in "Income tax receivable" with the remaining $74.2 million included in "Deferred income taxes" on the Consolidated Balance Sheet as of December 31, 2018.

Unrecognized Tax Benefit

As of December 31, 2018 and 2017, QEP had $19.0 million of unrecognized tax benefit related to uncertain tax positions for asset sales that occurred in 2014, which were recorded within "Other long-term liabilities" on the Consolidated Balance Sheets. The $15.6 million uncertain tax position the Company reported during the year ended December 31, 2016, was expensed during the year ended December 31, 2014, with an additional $3.4 million expensed during the year ended December 31, 2017 with the Tax Legislation. 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 Statements 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 years ended December 31, 2018, 2017 and 2016, the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016, the Company incurred $0.6 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, 2018 and 2017:



	Unrecognized Tax Benefits
	2018		2017
	(in millions)
Balance as of January 1,	$	19.0	$	15.6
Federal benefit of state (change from 35% to 21%)	—		3.4
Balance as of December 31,	$	19.0	$	19.0

As of December 31, 2018 and 2017, QEP had $19.0 million of unrecognized tax benefit that would impact its effective tax rate if recognized.

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2018

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
2018	(in millions, except per share amounts or otherwise specified)
Revenues	$	428.9		$	532.4		$	560.8	$	410.5		$	1,932.6
Operating income (loss)	$	21.4		$	(321.8	)	$	156.8	$	(1,116.8	)	$	(1,260.4	)
Net income (loss)	$	(53.6	)	$	(336.0	)	$	7.3	$	(629.3	)	$	(1,011.6	)
Net gain (loss) from asset sales, inclusive of restructuring costs and impairment	$	2.8		$	(407.6	)	$	27.1	$	(1,158.2	)	$	(1,535.9	)
Per share information
Basic EPS	$	(0.22	)	$	(1.42	)	$	0.03	$	(2.66	)	$	(4.25	)
Diluted EPS	$	(0.22	)	$	(1.42	)	$	0.03	$	(2.66	)	$	(4.25	)
Production information
Total equivalent production (Mboe)	11,724.6			14,106.1			14,400.0		11,627.2			51,857.9



2017
Revenues	$	420.1		$	383.7		$	390.1		$	429.0		$	1,622.9
Operating income (loss)	$	(5.2	)	$	(0.9	)	$	132.1		$	(24.5	)	$	101.5
Net income (loss)	$	76.9		$	45.4		$	(3.3	)	$	150.3		$	269.3
Net gain (loss) from asset sales and impairment	$	(0.1	)	$	19.8		$	157.1		$	(42.2	)	$	134.6
Nonrecurring items in operating income (loss)⁽¹⁾	$	—		$	—		$	8.2		$	—		$	8.2
Per share information
Basic EPS	$	0.32		$	0.19		$	(0.01	)	$	0.62		$	1.12
Diluted EPS	$	0.32		$	0.19		$	(0.01	)	$	0.62		$	1.12
Production information
Total equivalent production (Mboe)	13,090.3			13,860.6			14,124.1			12,069.9			53,144.9

____________________________


⁽¹⁾	Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017.

Supplemental Gas and Oil Information (Unaudited)

12 Months Ended

Dec. 31, 2018

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.

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 and includes capitalized costs classified as “Noncurrent assets held for sale” on the Consolidated Balance Sheets:



	December 31,
	2018			2017
	(in millions)
Proved properties	$	12,140.7		$	12,470.9
Unproved properties, net	759.1			1,095.8
Total proved and unproved properties	12,899.8			13,566.7
Accumulated depreciation, depletion and amortization	(7,450.5		)	(6,642.9		)
Net capitalized costs	$	5,449.3		$	6,923.8

Costs Incurred

The costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Costs associated with the Company's midstream and corporate activities are not included. Development costs are net of the change in accrued capital costs of $59.2 million and ARO additions and revisions of $0.8 million during the year ended December 31, 2018. The costs incurred for the development of reserves that were classified as proved undeveloped were approximately $606.5 million in 2018, $389.3 million in 2017 and $258.1 million in 2016.



	Year Ended December 31,
	2018		2017		2016
	(in millions)
Proved property acquisitions	$	39.1	$	269.6	$	431.6
Unproved property acquisitions	25.8		532.4		208.7
Other acquisitions	0.8		13.2		—
Exploration costs (capitalized and expensed)	0.3		32.7		13.4
Development costs	1,133.1		1,189.3		509.2
Total costs incurred	$	1,199.1	$	2,037.2	$	1,162.9

Results of Operations

Following are the results of operations of QEP's oil and gas producing activities, before allocated corporate overhead and interest expenses. Revenues and expenses relating to the Company's midstream and corporate activities are not included.



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Revenues	$	1,920.3		$	1,548.1		$	1,271.0
Production costs	507.3			675.4			616.7
Exploration expenses	0.3			22.0			1.7
Depreciation, depletion and amortization	836.4			735.1			852.3
Impairment	1,560.9			72.3			1,194.3
Total expenses	2,904.9			1,504.8			2,665.0
Income (loss) before income taxes	(984.6		)	43.3			(1,394.0		)
Income tax benefit (expense)	243.2			(16.0		)	517.2
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(741.4	)	$	27.3		$	(876.8	)

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 include 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, 2018, 2017 and 2016. 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, 2018, 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 leaseholds 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, 2018, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's changes in quantities of proved oil and condensate, gas and NGL reserves for the years ended December 31, 2016, 2017 and 2018 are as follows:



	Oil and condensate		Gas		NGL		Total⁽¹³⁾
	(MMbbl)		(Bcf)		(MMbbl)		(MMboe)
Balance at December 31, 2015	193.1		2,108.9		58.8		603.4
Revisions of previous estimates⁽¹⁾	(9.7	)	412.8		(0.3	)	58.8
Extensions and discoveries⁽²⁾	13.0		158.1		3.3		42.6
Purchase of reserves in place⁽³⁾	62.7		54.6		11.5		83.3
Sale of reserves in place⁽⁴⁾	(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
Revisions of previous estimates⁽⁵⁾	3.7		12.5		(3.1	)	2.7
Extensions and discoveries⁽⁶⁾	59.1		101.9		10.4		86.4
Purchase of reserves in place⁽⁷⁾	46.6		125.5		8.7		76.3
Sale of reserves in place⁽⁸⁾	(7.9	)	(831.2	)	(12.6	)	(159.0	)
Production	(19.6	)	(168.9	)	(5.4	)	(53.1	)
Balance at December 31, 2017	320.5		1,793.6		65.2		684.7
Revisions of previous estimates⁽⁹⁾	2.1		314.0		6.7		61.0
Extensions and discoveries⁽¹⁰⁾	57.1		56.5		9.8		76.3
Purchase of reserves in place⁽¹¹⁾	8.2		7.9		1.3		10.9
Sale of reserves in place⁽¹²⁾	(24.9	)	(544.8	)	(7.1	)	(122.8	)
Production	(23.9	)	(139.6	)	(4.7	)	(51.9	)
Balance at December 31, 2018	339.1		1,487.6		71.2		658.2
Proved developed reserves
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
Balance at December 31, 2017	116.0		655.5		27.9		253.1
Balance at December 31, 2018	133.6		382.3		31.5		228.9
Proved undeveloped reserves
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
Balance at December 31, 2017	204.5		1,138.1		37.3		431.6
Balance at December 31, 2018	205.5		1,105.3		39.7		429.3

___________________________

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


⁽³⁾	Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 3 – Acquisitions and Divestitures.


⁽⁴⁾	Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 3 – Acquisitions and Divestitures.

⁽⁵⁾

Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related to pricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by 11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontal development plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. These negative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the Williston Basin.


⁽⁶⁾	Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin.


⁽⁷⁾	Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 3 – Acquisitions and Divestitures.


⁽⁸⁾	Sale of reserves in place in 2018 was primarily related to QEP's Pinedale Divestiture as discussed in Note 3 – Acquisitions and Divestitures.

⁽⁹⁾

Revisions of previous estimates in 2018 totaling 61.0 MMboe of positive revisions include 23.4 MMboe of other revisions, primarily related to changing our development plans in the Haynesville/Cotton Valley; 17.3 MMboe of positive revisions related to pricing, primarily driven by higher oil prices; 11.7 MMboe of positive revisions related to lower operating costs; and 8.7 MMboe of positive performance revisions.


⁽¹⁰⁾	Extensions and discoveries in 2018 primarily related to new well completions and associated new PUD locations in the Permian Basin.


⁽¹¹⁾	Purchase of reserves in place in 2018 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.


⁽¹²⁾	Sale of reserves in place in 2018 was primarily related to QEP's Uinta Basin Divestiture as discussed in Note 3 – Acquisitions and Divestitures.


⁽¹³⁾	Generally, gas consumed in operations was excluded from reserves, however, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.

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

Future net cash flows were calculated at December 31, 2018, 2017 and 2016, 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 2018, 2017 and 2016, 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,
	2018		2017		2016
Average benchmark price per unit:
Oil price (per bbl)	$	65.56	$	51.34	$	42.75
Gas price (per MMBtu)	$	3.10	$	2.98	$	2.48

Year ended 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 $620.1 million in 2019, $882.0 million in 2020 and $1,025.1 million in 2021. 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 borrowings 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 and do not reflect cost savings of Company owned midstream operations on future operating expenses.


•	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,
	2018			2017			2016
	(in millions)
Future cash inflows	$	26,482.6		$	22,028.9		$	16,239.8
Future production costs	(9,539.9		)	(9,074.2		)	(7,789.0		)
Future development costs⁽¹⁾	(4,441.5		)	(4,726.0		)	(3,432.9		)
Future income tax expenses⁽²⁾	(2,553.6		)	(1,439.1		)	(913.4		)
Future net cash flows	9,947.6			6,789.6			4,104.5
10% annual discount for estimated timing of net cash flows	(4,991.9		)	(3,692.3		)	(2,176.5		)
Standardized measure of discounted future net cash flows	$	4,955.7		$	3,097.3		$	1,928.0

___________________________


⁽¹⁾	Future development costs include future abandonment and salvage costs.


⁽²⁾	The standardized measure of discounted future net cash flows for the year ended December 31, 2018 and 2017, were estimated assuming a 21% federal tax rate from the Tax Legislation enacted in December 2017.

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,
	2018			2017			2016
	(in millions)
Balance at January 1,	$	3,097.3		$	1,928.0		$	2,476.3
Sales of oil and condensate, gas and NGL produced, net of production costs	(1,413.0		)	(872.7		)	(654.3		)
Net change in sales prices and in production (lifting) costs related to future production	1,632.5			1,457.2			(739.4		)
Net change due to extensions and discoveries	692.6			556.8			81.8
Net change due to revisions of quantity estimates	732.0			9.9			122.7
Net change due to purchases of reserves in place	117.0			342.7			256.5
Net change due to sales of reserves in place	(369.6		)	(504.7		)	(4.3		)
Previously estimated development costs incurred during the period	735.6			475.4			374.6
Changes in estimated future development costs	(28.3		)	(283.4		)	(476.5		)
Accretion of discount	375.4			235.7			311.1
Net change in income taxes	(615.7		)	(227.4		)	205.4
Other	(0.1		)	(20.2		)	(25.9		)
Net change	1,858.4			1,169.3			(548.3		)
Balance at December 31,	$	4,955.7		$	3,097.3		$	1,928.0

Subsequent Event (Notes)	12 Months Ended
Subsequent Event (Notes)	Dec. 31, 2018
subsequentevent [Abstract]
Subsequent Events [Text Block]	Note 16 – Subsequent Events On January 10, 2019, QEP closed its previously announced divestiture of its oil and gas assets and the gathering system in the Haynesville/Cotton Valley for net cash proceeds of $605.1 million, subject to post-closing purchase price adjustments. In addition, $32.2 million was placed in escrow due to title defects asserted prior to closing, to be resolved pursuant to the purchase and sale agreement's title dispute resolution procedures. The resolution of the asserted title defects could result in a gain or loss on sale. On February 20, 2019, the Company agreed with the buyer to terminate the purchase and sale agreement for its assets in the Williston Basin. Following the termination of the Planned Williston Basin Divestiture, QEP will continue operating its assets in the Williston Basin, including the Company's South Antelope and Fort Berthold leaseholds. Additionally, in light of the reduction of the Company's operational footprint over the last 12 months, QEP has reassessed its organizational needs and intends to significantly reduce its general and administrative expense to ensure its cost structure is competitive with industry peers. The Company expects the majority of the organizational changes will be implemented during the first half of 2019. QEP expects to incur restructuring costs associated with contractual termination benefits including severance, accelerated vesting of share-based compensation and other expenses.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

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.

Segment Reporting, Policy [Policy Text Block]

Business Segments

QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP has one reportable segment.

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, Cash Equivalents and Restricted Cash



	December 31,
	2018		2017
	(in millions)
Cash and cash equivalents	$	—	$	—
Restricted cash⁽¹⁾	28.1		23.4
Total cash, cash equivalents and restricted cash shown in the Consolidated Statements of Cash Flows	$	28.1	$	23.4

_______________________


⁽¹⁾	As of December 31, 2018 and 2017, the restricted cash balance related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Consolidated Balance Sheets.

Supplemental cash flow information is shown in the table below:



	Year Ended December 31,
	2018			2017			2016
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	136.9		$	134.9		$	139.1
Cash paid (refund received) for income taxes, net	$	0.8		$	(0.3	)	$	(123.5	)
Non-cash Investing Activities:
Change in capital expenditure accrual balance	$	(57.4	)	$	60.2		$	(32.8	)

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

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 (ARO)

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]

The following table presents the percentages by customer that accounted for 10% or more of QEP's total revenues.



Year Ended December 31, 2018
Occidental Energy Marketing	16	%
Plains Marketing LP	12	%

Year Ended December 31, 2017
Shell Trading Company	14	%
Occidental Energy Marketing	13	%
Andeavor Logistics LP	13	%
BP Energy Company	10	%
Plains Marketing LP	10	%

Year Ended December 31, 2016
Shell Trading Company	14	%
BP Energy Company	10	%
Valero Marketing & Supply Company	10	%

Income Taxes [Policy Text Block]

Income Taxes

Treasury Stock [Policy Text Block]

Treasury Stock

Earnings Per Share [Policy Text Block]

Earnings (Loss) Per Share

The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:



	December 31,
	2018	2017	2016
	(in millions)
Weighted-average basic common shares outstanding	237.9	240.6	221.7
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	237.9	240.6	221.7

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 (Loss)

Recent Accounting Developments [Policy Text Block]

Recent Accounting Developments

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Restricted Cash and Cash Equivalents Items [Line Items]

Restrictions on Cash and Cash Equivalents [Table Text Block]



	December 31,
	2018		2017
	(in millions)
Cash and cash equivalents	$	—	$	—
Restricted cash⁽¹⁾	28.1		23.4
Total cash, cash equivalents and restricted cash shown in the Consolidated Statements of Cash Flows	$	28.1	$	23.4

_______________________


⁽¹⁾	As of December 31, 2018 and 2017, the restricted cash balance related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Consolidated Balance Sheets.

Supplemental Cash Flow Information [Table Text Block]

Supplemental cash flow information is shown in the table below:



	Year Ended December 31,
	2018			2017			2016
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	136.9		$	134.9		$	139.1
Cash paid (refund received) for income taxes, net	$	0.8		$	(0.3	)	$	(123.5	)
Non-cash Investing Activities:
Change in capital expenditure accrual balance	$	(57.4	)	$	60.2		$	(32.8	)

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

Credit Risk [Policy Text Block]

The following table presents the percentages by customer that accounted for 10% or more of QEP's total revenues.



Year Ended December 31, 2018
Occidental Energy Marketing	16	%
Plains Marketing LP	12	%

Year Ended December 31, 2017
Shell Trading Company	14	%
Occidental Energy Marketing	13	%
Andeavor Logistics LP	13	%
BP Energy Company	10	%
Plains Marketing LP	10	%

Year Ended December 31, 2016
Shell Trading Company	14	%
BP Energy Company	10	%
Valero Marketing & Supply Company	10	%

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

The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:



	December 31,
	2018	2017	2016
	(in millions)
Weighted-average basic common shares outstanding	237.9	240.6	221.7
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	237.9	240.6	221.7

Revenue (Tables)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue Recognition [Table Text Block]

The following table presents the impact to the Consolidated Statements of Operations as a result of adopting ASC Topic 606.



	Year Ended December 31, 2018
	As Reported			ASC Topic 606 Adjustments		As Adjusted⁽¹⁾
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	1,871.3		$	55.0	$	1,926.3
Other revenues	12.5			—		12.5
Purchased oil and gas sales	48.8			—		48.8
Total Revenues	1,932.6			55.0		1,987.6
OPERATING EXPENSES
Purchased oil and gas expense	51.0			—		51.0
Lease operating expense	263.1			—		263.1
Transportation and processing costs	117.6			55.0		172.6
Gathering and other expense	15.5			—		15.5
General and administrative	221.7			—		221.7
Production and property taxes	130.8			—		130.8
Depreciation, depletion and amortization	857.1			—		857.1
Exploration expenses	0.3			—		0.3
Impairment	1,560.9			—		1,560.9
Total Operating Expenses	3,218.0			55.0		3,273.0
Net gain (loss) from asset sales, inclusive of restructuring costs	25.0			—		25.0
OPERATING INCOME (LOSS)	(1,260.4		)	—		(1,260.4		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	90.4			—		90.4
Interest and other income (expense)	(9.6		)	—		(9.6		)
Interest expense	(149.4		)	—		(149.4		)
INCOME (LOSS) BEFORE INCOME TAXES	(1,329.0		)	—		(1,329.0		)
Income tax (provision) benefit	317.4			—		317.4
NET INCOME (LOSS)	$	(1,011.6	)	$	—	$	(1,011.6	)

Earnings (loss) per common share
Basic	$	(4.25	)	$	—	$	(4.25	)
Diluted	$	(4.25	)	$	—	$	(4.25	)

Weighted-average common shares outstanding
Used in basic calculation	237.9			—		237.9
Used in diluted calculation	237.9			—		237.9

Revenue Recognition 606 [Table Text Block]

The following table presents the impact to the Consolidated Statements of Operations as a result of adopting ASC Topic 606.



	Year Ended December 31, 2018
	As Reported			ASC Topic 606 Adjustments		As Adjusted⁽¹⁾
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	1,871.3		$	55.0	$	1,926.3
Other revenues	12.5			—		12.5
Purchased oil and gas sales	48.8			—		48.8
Total Revenues	1,932.6			55.0		1,987.6
OPERATING EXPENSES
Purchased oil and gas expense	51.0			—		51.0
Lease operating expense	263.1			—		263.1
Transportation and processing costs	117.6			55.0		172.6
Gathering and other expense	15.5			—		15.5
General and administrative	221.7			—		221.7
Production and property taxes	130.8			—		130.8
Depreciation, depletion and amortization	857.1			—		857.1
Exploration expenses	0.3			—		0.3
Impairment	1,560.9			—		1,560.9
Total Operating Expenses	3,218.0			55.0		3,273.0
Net gain (loss) from asset sales, inclusive of restructuring costs	25.0			—		25.0
OPERATING INCOME (LOSS)	(1,260.4		)	—		(1,260.4		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	90.4			—		90.4
Interest and other income (expense)	(9.6		)	—		(9.6		)
Interest expense	(149.4		)	—		(149.4		)
INCOME (LOSS) BEFORE INCOME TAXES	(1,329.0		)	—		(1,329.0		)
Income tax (provision) benefit	317.4			—		317.4
NET INCOME (LOSS)	$	(1,011.6	)	$	—	$	(1,011.6	)

Earnings (loss) per common share
Basic	$	(4.25	)	$	—	$	(4.25	)
Diluted	$	(4.25	)	$	—	$	(4.25	)

Weighted-average common shares outstanding
Used in basic calculation	237.9			—		237.9
Used in diluted calculation	237.9			—		237.9

____________________________


⁽¹⁾	This column excludes the impact of adopting ASC Topic 606 and is consistent with the presentation prior to January 1, 2018.

Disaggregation of Revenue [Table Text Block]



	Oil and condensate sales			Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Year Ended December 31, 2018
Northern Region
Williston Basin	$	707.0		$	45.3	$	56.5	$	(43.1	)	$	765.7
Uinta Basin	25.3			25.0		4.8		—			55.1
Other Northern⁽¹⁾	4.9			2.0		—		—			6.9
Southern Region
Permian Basin	684.4			17.3		49.5		(11.9		)	739.3
Haynesville/Cotton Valley	1.0			303.1		—		—			304.1
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,422.4		$	393.1	$	110.8	$	(55.0	)	$	1,871.3

	Year Ended December 31, 2017⁽²⁾
Northern Region
Williston Basin	$	586.5		$	42.3	$	51.5	$	—		$	680.3
Pinedale	18.0			154.8		31.8		—			204.6
Uinta Basin	29.6			50.0		5.9		—			85.5
Other Northern	4.9			16.6		0.3		—			21.8
Southern Region
Permian Basin	298.8			15.5		22.0		—			336.3
Haynesville/Cotton Valley	1.2			214.4		0.4		—			216.0
Other Southern	0.4			0.4		—		—			0.8
Total oil and condensate, gas and NGL sales	$	939.4		$	494.0	$	111.9	$	—		$	1,545.3

	Year Ended December 31, 2016⁽²⁾
Northern Region
Williston Basin	$	541.6		$	33.1	$	22.7	$	—		$	597.4
Pinedale	25.8			194.1		40.6		—			260.5
Uinta Basin	28.0			52.5		6.4		—			86.9
Other Northern	5.0			18.7		0.3		—			24.0
Southern Region
Permian Basin	166.1			11.6		12.9		—			190.6
Haynesville/Cotton Valley	1.1			106.6		0.4		—			108.1
Other Southern	1.5			0.5		0.2		—			2.2
Total oil and condensate, gas and NGL sales	$	769.1		$	417.1	$	83.5	$	—		$	1,269.7

_______________________


⁽¹⁾	For the year ended December 31, 2018, immaterial amounts of revenue associated with adjustments in Pinedale have been included in Other Northern.


⁽²⁾	Prior period amounts have not been adjusted under the modified retrospective method.

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2018

Dec. 31, 2016

Business Combinations [Abstract]

Schedule of Purchase Price Allocation [Table Text Block]

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



Consideration:
Total consideration	$	591.0

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	(17.8		)
Total fair value	$	591.0

Business Acquisition, Pro Forma Information [Table Text Block]



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

Noncurrent Assets and Liabilities Held for Sale [Line Items]

Noncurrent Assets and Liabilities Held for Sale [Table Text Block]

The following table presents the carrying amounts of the major classes of assets and liabilities classified as noncurrent assets and liabilities held for sale on the Consolidated Balance Sheets:



	December 31, 2018		December 31, 2017⁽¹⁾
	(in millions)
Assets
Current assets, total	$	1.2	$	3.4
Property, Plant and Equipment	683.7		1,290.3
Other noncurrent assets	7.8		27.2
Noncurrent assets held for sale	$	692.7	$	1,320.9
Liabilities
Current liabilities, total	$	3.4	$	4.5
Asset retirement obligations, current	0.7		4.7
Asset retirement obligations, long-term	56.9		102.5
Fair value of derivative contracts, long-term	—		(3.0		)
Other long-term liabilities	0.3		0.5
Other long-term liabilities held for sale	$	61.3	$	109.2

____________________________


⁽¹⁾	For the year ended December 31, 2017, the asset and liabilities held for sale also includes the Uinta Basin Divestiture.

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation [Abstract]

asset retirement obligation liability [Table Text Block]

The Consolidated Balance Sheet line items of QEP's ARO liability are presented in the table below:



	Asset Retirement Obligations
	December 31,
	2018		2017
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	5.1	$	2.8
Long-term:
Asset retirement obligations	96.9		104.1
Other long-term liabilities held for sale	57.6		107.2
Total ARO Liability	$	159.6	$	214.1

Schedule of Change in Asset Retirement Obligation [Table Text Block]

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



	Asset Retirement Obligations
	2018			2017
	(in millions)
ARO liability at January 1,	$	214.1		$	231.6
Accretion	6.4			7.7
Additions⁽¹⁾	4.1			23.5
Revisions	(4.9		)	8.5
Liabilities related to assets sold⁽²⁾	(56.8		)	(34.9		)
Liabilities settled	(3.3		)	(22.3		)
ARO liability at December 31,	$	159.6		$	214.1

___________________________


⁽¹⁾	Additions for the year ended December 31, 2017, include $14.2 million related to the 2017 Permian Basin Acquisition. Refer to Note 3 – Acquisitions and Divestitures for more information.


⁽²⁾	Liabilities related to assets sold for the year ended December 31, 2018, includes $51.0 million related to the Uinta Basin Divestiture. Liabilities related to assets sold for the year ended December 31, 2017 includes $34.9 million related to the Pinedale Divestiture. Refer to Note 3 – Acquisitions and Divestitures for more information.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value Measurements, Recurring and Nonrecurring [Table Text Block]

The fair value of financial assets and liabilities at December 31, 2018 and 2017, 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 Sheets
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Net Amounts Presented on the Consolidated Balance Sheets
	(in millions)
	December 31, 2018
Financial Assets
Fair value of derivative contracts – short-term⁽²⁾	$	—	$	88.2	$	—	$	(0.4	)	$	87.8
Fair value of derivative contracts – long-term	—		35.4		—		—			35.4
Total financial assets	$	—	$	123.6	$	—	$	(0.4	)	$	123.2

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	0.4	$	—	$	(0.4	)	$	—
Fair value of derivative contracts – long-term	—		0.7		—		—			0.7
Total financial liabilities	$	—	$	1.1	$	—	$	(0.4	)	$	0.7

	December 31, 2017
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	20.6	$	—	$	(17.2	)	$	3.4
Fair value of derivative contracts – long-term	—		2.3		—		(2.2		)	0.1
Total financial assets	$	—	$	22.9	$	—	$	(19.4	)	$	3.5

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	120.8	$	—	$	(17.2	)	$	103.6
Fair value of derivative contracts – long-term⁽²⁾	—		34.0		—		(2.2		)	31.8
Total financial liabilities	$	—	$	154.8	$	—	$	(19.4	)	$	135.4

____________________________


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


⁽²⁾	Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 and "Other long-term liabilities held for sale" of $3.0 million as of December 31, 2017 on the Consolidated Balance Sheets related to the Haynesville Divestiture.

Fair value and related carrying amount of certain financial instruments



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2018				December 31, 2017
Financial Assets	(in millions)
Cash and cash equivalents	$	—	$	—	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	14.6	$	14.6	$	44.0	$	44.0
Long-term debt	$	2,507.1	$	2,350.5	$	2,160.8	$	2,256.2

- Definition

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

+ References + Details

Derivative Contracts (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	11.0	$	54.49
2020	NYMEX WTI	2.9	$	62.37
Gas sales		(MMBtu)	($/MMBtu)
2019	NYMEX HH	43.8	$	2.86

derivative volumes and weighted average differential [Table Text Block]



Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2019	NYMEX WTI	Argus WTI Midland	6.6	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.4	$	4.35
2020	NYMEX WTI	Argus WTI Midland	1.5	$	(1.01	)

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	2018		2017		2018		2017
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	88.2	$	20.6	$	0.4	$	120.8
Long-term:
Commodity	Fair value of derivative contracts	35.4		2.3		0.7		34.0
Total derivative instruments⁽¹⁾		$	123.6	$	22.9	$	1.1	$	154.8

_______________________


⁽¹⁾	Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 and "Other long-term liabilities held for sale" of $3.0 million as of December 31, 2017 on the Consolidated Balance Sheets related to the Haynesville Divestiture.

Effects of Derivative Transactions



Derivative contracts	Year Ended December 31,
Derivative contracts	2018			2017			2016
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(153.4	)	$	6.8		$	86.3
Gas derivative contracts	(5.0		)	(22.3		)	44.8
Gas Storage
Gas derivative contracts	0.3			—			2.9
Realized gains (losses) on commodity derivative contracts	(158.1		)	(15.5		)	134.0
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	277.0			(66.2		)	(217.2		)
Gas derivative contracts	(22.3		)	133.6			(145.4		)
Gas Storage
Gas derivative contracts	(0.3		)	2.5			(4.4		)
Unrealized gains (losses) on commodity derivative contracts	254.4			69.9			(367.0		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	96.3		$	54.4		$	(233.0	)

Derivatives associated with Uinta and Pinedale divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(2.7	)	$	(1.3	)	$	—
Gas derivative contracts	—			(23.5		)	—
NGL derivative contracts	(3.2		)	(5.1		)	—
Unrealized gains (losses) on commodity derivative contracts related to divestitures⁽¹⁾⁽²⁾	$	(5.9	)	$	(29.9	)	$	—

Total realized and unrealized gains (losses) on commodity derivative contracts	$	90.4		$	24.5		$	(233.0	)

_______________________

⁽¹⁾

⁽²⁾

Restructuring Costs Restructuring Costs (Tables)

12 Months Ended

Dec. 31, 2018

Restructuring Cost and Reserve [Line Items]

Restructuring Costs [Table Text Block]

Restructuring costs recognized associated with the 2018 restructuring (2018 Restructuring) are summarized below:



	Year Ended December 31, 2018
	Total recognized		Recognized in "General and administrative"		Recognized in "Net gain (loss) from asset sales, inclusive of restructuring costs"			Recognized in "Interest and other income (expense)"
	(in millions)
Termination benefits	$	32.3	$	25.7	$	6.6		—
Office lease termination costs	1.0		1.0		—			—
Accelerated share-based compensation⁽¹⁾	11.0		8.8		2.2			—
Retention expense (including share-based compensation)	18.8		18.8		—			—
Pension and Medical Plan curtailment	0.1		—		(0.2		)	0.3
Total restructuring costs	$	63.2	$	54.3	$	8.6		$	0.3

____________________________


⁽¹⁾	Accelerated share based compensation represents the additional expense or loss recognized in the Consolidated Statement of Operations for the year ended December 31, 2018. Total accelerated share based compensation was $11.2 million and was determined based on the contractual vesting date, with $11.0 million recognized in 2018 as shown above, and the remaining amount recognized in prior periods.

Restructuring and Related Costs [Table Text Block]



	Costs recognized period from inception to December 31, 2018		Total remaining costs expected to be incurred⁽⁴⁾
	(in millions)
Termination benefits	$	32.3	$	—	⁽¹⁾
Office lease termination costs	1.0		—		⁽¹⁾
Accelerated share-based compensation	11.2		15.5		⁽¹⁾⁽²⁾
Retention expense (including share-based compensation)	18.8		21.4		⁽³⁾
Pension and Medical Plan curtailment	0.1		—		⁽¹⁾
Total restructuring costs	$	63.4	$	36.9

____________________________


⁽¹⁾	Due to the nature of the strategic initiatives and uncertain factors such as the timing and terms of the potential divestitures, the Company is not able to reasonably estimate the total cost to be incurred as a part of these restructurings.


⁽²⁾	In January 2019, QEP had $15.5 million of accelerated share-based compensation due to the departure of two officers. The accelerated share-based compensation of $15.5 million was determined based on the contractual vesting date with $6.0 million expected to be recognized in the first quarter of 2019 and the remaining amount previously recognized in 2018 and prior periods.


⁽³⁾	QEP expects to incur an additional $3.9 million in 2019 related to the 2018 retention program and $17.5 million related to the 2019 retention program, which includes $16.0 million of cash and $1.5 million of share-based compensation.


⁽⁴⁾	Refer to the Note 16 – Subsequent Events for more information regarding expected restructuring costs.

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

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



	Restructuring liability
	Termination benefits			Office lease termination costs			Accelerated share-based compensation			Retention expense			Pension curtailment			Total
	(in millions)
Balance at December 31, 2017	$	—		$	—		$	0.2		$	—		$	—		$	0.2
Costs incurred and charged to expense	32.3			1.0			11.0			18.8			0.1			63.2
Costs paid or otherwise settled	(12.8		)	(1.0		)	(11.2		)	(8.0		)	(0.1		)	(33.1		)
Balance at December 31, 2018	$	19.5		$	—		$	—		$	10.8		$	—		$	30.3

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

Annual payments and the corresponding years for gathering, processing, transportation, drilling and fractionation contracts are as follows:



Year	Amount
	(in millions)
2019	$	72.2
2020	$	55.4
2021	$	31.3
2022	$	27.1
2023	$	15.3
After 2023	$	66.0

Lessee, Operating Lease, Disclosure [Table Text Block]

Minimum future payments under the terms of long-term operating leases are as follows:



Year	Amount
	(in millions)
2019	$	17.4
2020	$	13.8
2021	$	9.1
2022	$	7.4
2023	$	4.5
After 2023	$	—

Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

Share-based Compensation [Abstract]

Share-based Compensation Expense [Table Text Block]



	Year Ended December 31,
	2018		2017			2016
	(in millions)
Stock options	$	1.2	$	2.3		$	2.3
Restricted share awards	27.5		24.6			23.7
Performance share units	8.1		(4.5		)	9.4
Restricted share units	0.1		—			0.2
Total share-based compensation expense	$	36.9	$	22.4		$	35.6

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,
	2017			2016
Weighted-average grant date fair value of awards granted during the period	$	6.44		$	3.77
Risk-free interest rate range	1.66% - 1.81%			0.99% - 1.15%
Weighted-average risk-free interest rate	1.8		%	1.2		%
Expected price volatility range	43.82% - 46.70%			43.42% - 43.66%
Weighted-average expected price volatility	43.9		%	43.4		%
Expected dividend yield	—		%	—		%
Expected term in years at the date of grant	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, 2017	2,354,277		$	23.62
Exercised	(23,337	)	10.12
Cancelled	(232,007	)	37.16
Outstanding at December 31, 2018	2,098,933		$	22.27	2.87	$	—
Options Exercisable at December 31, 2018	1,732,827		$	23.90	2.46	$	—
Unvested Options at December 31, 2018	366,106		$	14.57	4.81	$	—

Restricted Share Awards Activity [Table Text Block]

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



	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2017	3,721,334		$	13.23
Granted	2,997,743		9.56
Vested	(2,630,959	)	12.87
Forfeited	(265,985	)	10.96
Unvested balance at December 31, 2018	3,822,133		$	10.76

Performance Share Units Activity [Table Text Block]

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, 2017	1,199,336		$	14.59
Granted	724,095		9.55
Vested	(364,119	)	17.26
Unvested balance at December 31, 2018	1,559,312		$	11.47

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, 2017	21,946		$	13.22
Granted	31,835		9.55
Vested	(11,106	)	13.27
Unvested balance at December 31, 2018	42,675		$	10.47

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2018

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
	2018			2017			2018			2017
Change in benefit obligation	(in millions)
Benefit obligation at January 1,	$	130.0		$	129.2		$	2.9		$	5.4
Service cost	0.8			0.8			—			—
Interest cost	4.6			4.7			0.1			0.1
Curtailments	0.1			(0.3		)	—			—
Benefit payments	(5.8		)	(6.9		)	(0.4		)	(0.1		)
Plan amendments	—			—			—			(2.4		)
Actuarial loss (gain)	(7.6		)	2.5			(0.1		)	(0.1		)
Benefit obligation at December 31,	$	122.1		$	130.0		$	2.5		$	2.9
Change in plan assets
Fair value of plan assets at January 1,	$	100.5		$	86.1		$	—		$	—
Actual return on plan assets	(7.1		)	15.3			—			—
Company contributions to the plan	5.7			6.0			0.4			0.1
Benefit payments	(5.8		)	(6.9		)	(0.4		)	(0.1		)
Fair value of plan assets at December 31,	93.3			100.5			—			—
Underfunded status (current and long-term)	$	(28.8	)	$	(29.5	)	$	(2.5	)	$	(2.9	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(1.1	)	$	(1.5	)	$	(0.2	)	$	(0.2	)
Other long-term liabilities	(27.7		)	(27.9		)	(2.3		)	(2.6		)
Total amount recognized in balance sheet	$	(28.8	)	$	(29.4	)	$	(2.5	)	$	(2.8	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	19.4		$	15.0		$	(0.5	)	$	(0.5	)
Prior service cost	0.4			1.2			(0.8		)	(1.2		)
Total amount recognized in AOCI	$	19.8		$	16.2		$	(1.3	)	$	(1.7	)

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
	2018			2017			2016			2018			2017			2016
Components of net periodic benefit cost	(in millions)
Service cost	$	0.8		$	0.8		$	1.2		$	—		$	—		$	—
Interest cost	4.6			4.7			5.2			0.1			0.1			0.2
Expected return on plan assets	(5.8		)	(5.4		)	(5.6		)	—			—			—
Curtailment loss	0.3			0.7			—			(0.2		)	—			—
Settlements	—			0.2			—			—			—			—
Amortization of prior service costs	0.8			1.0			1.1			(0.3		)	(0.3		)	0.2
Amortization of actuarial loss	0.8			0.5			0.8			—			(0.1		)	—
Periodic expense	$	1.5		$	2.5		$	2.7		$	(0.4	)	$	(0.3	)	$	0.4
Components recognized in accumulated other comprehensive income
Current period prior service cost	$	—		$	(0.7	)	$	—		$	0.2		$	(2.5	)	$	—
Current period actuarial (gain) loss	5.6			(7.5		)	8.5			(0.1		)	(0.1		)	0.4
Amortization of prior service cost	(0.8		)	(1.0		)	(1.1		)	0.3			0.3			(0.2		)
Amortization of actuarial gain (loss)	(0.8		)	(0.5		)	(0.8		)	—			0.1			—
Loss on curtailment in current period	(0.1		)	(0.3		)	—			—			—			—
Settlements	—			(0.2		)	—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	3.9		$	(10.2	)	$	6.6		$	0.4		$	(2.2	)	$	0.2

Schedule of Assumptions Used [Table Text Block]



	Pension Plan and SERP benefits				Medical Plan benefits
	2018		2017		2018		2017
Discount rate	4.19	%	3.52	%	4.30	%	3.60	%
Rate of increase in compensation⁽¹⁾	3.00	%	3.50	%	n/a		n/a

_______________________


⁽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 years ended December 31, 2018 and 2017, the rate of increase in compensation is only used for the SERP.

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, 2018 and 2017, respectively:



	December 31, 2018				December 31, 2017
	Total		Percentage of total		Total		Percentage of total
	(in millions, except percentages)
Cash and short-term investments	$	0.7	1	%	$	0.5	—	%
Equity securities:
Domestic	20.7		22	%	35.0		35	%
International	10.0		11	%	15.3		15	%
Fixed income	61.9		66	%	49.7		50	%
Total investments	$	93.3	100	%	$	100.5	100	%

Schedule of Expected Benefit Payments [Table Text Block]

Expected Benefit Payments

As of December 31, 2018, the following future benefit payments are expected to be paid:



	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2019	$	6.6	$	0.2
2020	$	16.7	$	0.2
2021	$	6.4	$	0.2
2022	$	6.4	$	0.2
2023	$	8.1	$	0.2
2024 through 2026	$	32.7	$	0.5

Compensation and Employee Benefit Plans [Text Block]

Participants receive 100% employer matching contributions on participant 401(k) plan contributions up to a percentage of qualifying earnings as described below.



	Year Ended December 31,
	2018		2017		2016
Employees who do not accrue a benefit in the SERP
Maximum employer matching of qualifying earnings	8	%	8	%	8	%

Employees who accrue a benefit in the SERP
Maximum employer matching of qualifying earnings	6	%	6	%	6	%

Pension plan, SERP and medical plan [Member]

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

Schedule of Assumptions Used [Table Text Block]



	Pension Plan and SERP benefits						Medical Plan benefits
	2018		2017		2016		2018		2017		2016
Discount rate	3.50	%	4.00	%	4.23	%	3.60	%	4.10	%	4.40	%
Expected long-term return on plan assets	6.00	%	6.00	%	6.50	%	n/a		n/a		n/a
Rate of increase in compensation⁽¹⁾	3.50	%	3.50	%	4.00	%	n/a		3.50	%	4.00	%

_______________________

⁽¹⁾

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

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

The components of income tax provisions and benefits were as follows:



	Year Ended December 31,
	2018			2017			2016
Federal income tax provision (benefit)	(in millions)
Current	$	(71.3	)	$	2.1		$	(55.5	)
Deferred	(257.8		)	(339.8		)	(614.3		)
State income tax provision (benefit)
Current	1.5			0.5			(1.5		)
Deferred	10.2			25.0			(36.9		)
Total income tax provision (benefit)	$	(317.4	)	$	(312.2	)	$	(708.2	)

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,
	2018		2017		2016
Federal income taxes statutory rate	21.0	%	35.0	%	35.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit⁽¹⁾	(0.7	)%	(40.1	)%	2.4	%
Federal rate change⁽²⁾	—	%	741.3	%	—	%
State rate change	—	%	2.1	%	(1.1	)%
Permanent adjustments	(0.1	)%	(0.4	)%	—	%
Return to provision adjustment	(0.1	)%	(0.7	)%	—	%
Uncertain tax provision (federal rate change)	—	%	(7.7	)%	—	%
AMT Credit Reclass due to NOL Carryback⁽³⁾	3.8	%	(1.8	)%	—	%
Effective income tax rate	23.9	%	727.7	%	36.3	%

____________________________


⁽¹⁾	State income taxes changed significantly from prior years mainly due to the change in valuation allowance recorded during 2017 of $36.2 million.


⁽²⁾	The Tax Legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets as of December 31, 2017 from a 35% to 21% federal corporate income tax rate which caused the majority of the change in rate.


⁽³⁾	In 2018, QEP agreed to an IRS proposed change to the initial treatment of the 2016 carryback of net operating losses. This change resulted in a reduction of available net operating loss carryforwards valued at $75.7 million and an increase in alternative minimum tax (AMT) credit carryforwards of $126.0 million. The net change in value of $50.3 million was recorded in deferred income taxes.

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

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



	December 31,
	2018		2017
Deferred tax liabilities	(in millions)
Property, plant and equipment	$	665.1	$	898.7
Commodity price derivatives	30.1		—
Deferred tax assets
Net operating loss and tax credit carryforwards	$	385.6	$	308.8
Employee benefits and compensation costs	26.1		26.4
Bonus and vacation accrual	7.1		6.2
Commodity price derivatives	—		29.9
Other	7.2		9.4
Total deferred tax assets	426.0		380.7
Net deferred income tax liability	$	269.2	$	518.0
Balance sheet classification
Deferred income tax liability – noncurrent	269.2		518.0
Net deferred income tax liability	$	269.2	$	518.0

Summary of Operating Loss Carryforwards [Table Text Block]

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2018, are as follows:



	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2019-2038	$	121.4
State net operating loss valuation allowance		$	(82.3	)
U.S. net operating loss⁽¹⁾	2036-2037	$	272.3
U.S. alternative minimum tax credit	Indefinite	$	74.2

____________________________


⁽¹⁾	Net operating losses created in tax years beginning after December 31, 2017 can be carried forward indefinitely under the Tax Legislation (limited to 80% of taxable income computed without the net operating loss deduction).

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, 2018 and 2017:



	Unrecognized Tax Benefits
	2018		2017
	(in millions)
Balance as of January 1,	$	19.0	$	15.6
Federal benefit of state (change from 35% to 21%)	—		3.4
Balance as of December 31,	$	19.0	$	19.0

Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

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
2018	(in millions, except per share amounts or otherwise specified)
Revenues	$	428.9		$	532.4		$	560.8	$	410.5		$	1,932.6
Operating income (loss)	$	21.4		$	(321.8	)	$	156.8	$	(1,116.8	)	$	(1,260.4	)
Net income (loss)	$	(53.6	)	$	(336.0	)	$	7.3	$	(629.3	)	$	(1,011.6	)
Net gain (loss) from asset sales, inclusive of restructuring costs and impairment	$	2.8		$	(407.6	)	$	27.1	$	(1,158.2	)	$	(1,535.9	)
Per share information
Basic EPS	$	(0.22	)	$	(1.42	)	$	0.03	$	(2.66	)	$	(4.25	)
Diluted EPS	$	(0.22	)	$	(1.42	)	$	0.03	$	(2.66	)	$	(4.25	)
Production information
Total equivalent production (Mboe)	11,724.6			14,106.1			14,400.0		11,627.2			51,857.9



2017
Revenues	$	420.1		$	383.7		$	390.1		$	429.0		$	1,622.9
Operating income (loss)	$	(5.2	)	$	(0.9	)	$	132.1		$	(24.5	)	$	101.5
Net income (loss)	$	76.9		$	45.4		$	(3.3	)	$	150.3		$	269.3
Net gain (loss) from asset sales and impairment	$	(0.1	)	$	19.8		$	157.1		$	(42.2	)	$	134.6
Nonrecurring items in operating income (loss)⁽¹⁾	$	—		$	—		$	8.2		$	—		$	8.2
Per share information
Basic EPS	$	0.32		$	0.19		$	(0.01	)	$	0.62		$	1.12
Diluted EPS	$	0.32		$	0.19		$	(0.01	)	$	0.62		$	1.12
Production information
Total equivalent production (Mboe)	13,090.3			13,860.6			14,124.1			12,069.9			53,144.9

____________________________


⁽¹⁾	Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017.

Supplemental Gas and Oil Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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



	December 31,
	2018			2017
	(in millions)
Proved properties	$	12,140.7		$	12,470.9
Unproved properties, net	759.1			1,095.8
Total proved and unproved properties	12,899.8			13,566.7
Accumulated depreciation, depletion and amortization	(7,450.5		)	(6,642.9		)
Net capitalized costs	$	5,449.3		$	6,923.8

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



	Year Ended December 31,
	2018		2017		2016
	(in millions)
Proved property acquisitions	$	39.1	$	269.6	$	431.6
Unproved property acquisitions	25.8		532.4		208.7
Other acquisitions	0.8		13.2		—
Exploration costs (capitalized and expensed)	0.3		32.7		13.4
Development costs	1,133.1		1,189.3		509.2
Total costs incurred	$	1,199.1	$	2,037.2	$	1,162.9

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



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Revenues	$	1,920.3		$	1,548.1		$	1,271.0
Production costs	507.3			675.4			616.7
Exploration expenses	0.3			22.0			1.7
Depreciation, depletion and amortization	836.4			735.1			852.3
Impairment	1,560.9			72.3			1,194.3
Total expenses	2,904.9			1,504.8			2,665.0
Income (loss) before income taxes	(984.6		)	43.3			(1,394.0		)
Income tax benefit (expense)	243.2			(16.0		)	517.2
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(741.4	)	$	27.3		$	(876.8	)

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



	Oil and condensate		Gas		NGL		Total⁽¹³⁾
	(MMbbl)		(Bcf)		(MMbbl)		(MMboe)
Balance at December 31, 2015	193.1		2,108.9		58.8		603.4
Revisions of previous estimates⁽¹⁾	(9.7	)	412.8		(0.3	)	58.8
Extensions and discoveries⁽²⁾	13.0		158.1		3.3		42.6
Purchase of reserves in place⁽³⁾	62.7		54.6		11.5		83.3
Sale of reserves in place⁽⁴⁾	(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
Revisions of previous estimates⁽⁵⁾	3.7		12.5		(3.1	)	2.7
Extensions and discoveries⁽⁶⁾	59.1		101.9		10.4		86.4
Purchase of reserves in place⁽⁷⁾	46.6		125.5		8.7		76.3
Sale of reserves in place⁽⁸⁾	(7.9	)	(831.2	)	(12.6	)	(159.0	)
Production	(19.6	)	(168.9	)	(5.4	)	(53.1	)
Balance at December 31, 2017	320.5		1,793.6		65.2		684.7
Revisions of previous estimates⁽⁹⁾	2.1		314.0		6.7		61.0
Extensions and discoveries⁽¹⁰⁾	57.1		56.5		9.8		76.3
Purchase of reserves in place⁽¹¹⁾	8.2		7.9		1.3		10.9
Sale of reserves in place⁽¹²⁾	(24.9	)	(544.8	)	(7.1	)	(122.8	)
Production	(23.9	)	(139.6	)	(4.7	)	(51.9	)
Balance at December 31, 2018	339.1		1,487.6		71.2		658.2
Proved developed reserves
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
Balance at December 31, 2017	116.0		655.5		27.9		253.1
Balance at December 31, 2018	133.6		382.3		31.5		228.9
Proved undeveloped reserves
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
Balance at December 31, 2017	204.5		1,138.1		37.3		431.6
Balance at December 31, 2018	205.5		1,105.3		39.7		429.3

___________________________

⁽¹⁾


⁽²⁾	Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.


⁽³⁾	Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 3 – Acquisitions and Divestitures.


⁽⁴⁾	Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 3 – Acquisitions and Divestitures.

⁽⁵⁾


⁽⁶⁾	Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin.


⁽⁷⁾	Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 3 – Acquisitions and Divestitures.


⁽⁸⁾	Sale of reserves in place in 2018 was primarily related to QEP's Pinedale Divestiture as discussed in Note 3 – Acquisitions and Divestitures.

⁽⁹⁾


⁽¹⁰⁾	Extensions and discoveries in 2018 primarily related to new well completions and associated new PUD locations in the Permian Basin.


⁽¹¹⁾	Purchase of reserves in place in 2018 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.


⁽¹²⁾	Sale of reserves in place in 2018 was primarily related to QEP's Uinta Basin Divestiture as discussed in Note 3 – Acquisitions and Divestitures.


⁽¹³⁾	Generally, gas consumed in operations was excluded from reserves, however, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.

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

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



	For the year ended December 31,
	2018		2017		2016
Average benchmark price per unit:
Oil price (per bbl)	$	65.56	$	51.34	$	42.75
Gas price (per MMBtu)	$	3.10	$	2.98	$	2.48

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

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



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Future cash inflows	$	26,482.6		$	22,028.9		$	16,239.8
Future production costs	(9,539.9		)	(9,074.2		)	(7,789.0		)
Future development costs⁽¹⁾	(4,441.5		)	(4,726.0		)	(3,432.9		)
Future income tax expenses⁽²⁾	(2,553.6		)	(1,439.1		)	(913.4		)
Future net cash flows	9,947.6			6,789.6			4,104.5
10% annual discount for estimated timing of net cash flows	(4,991.9		)	(3,692.3		)	(2,176.5		)
Standardized measure of discounted future net cash flows	$	4,955.7		$	3,097.3		$	1,928.0

___________________________


⁽¹⁾	Future development costs include future abandonment and salvage costs.


⁽²⁾	The standardized measure of discounted future net cash flows for the year ended December 31, 2018 and 2017, were estimated assuming a 21% federal tax rate from the Tax Legislation enacted in December 2017.

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

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



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Balance at January 1,	$	3,097.3		$	1,928.0		$	2,476.3
Sales of oil and condensate, gas and NGL produced, net of production costs	(1,413.0		)	(872.7		)	(654.3		)
Net change in sales prices and in production (lifting) costs related to future production	1,632.5			1,457.2			(739.4		)
Net change due to extensions and discoveries	692.6			556.8			81.8
Net change due to revisions of quantity estimates	732.0			9.9			122.7
Net change due to purchases of reserves in place	117.0			342.7			256.5
Net change due to sales of reserves in place	(369.6		)	(504.7		)	(4.3		)
Previously estimated development costs incurred during the period	735.6			475.4			374.6
Changes in estimated future development costs	(28.3		)	(283.4		)	(476.5		)
Accretion of discount	375.4			235.7			311.1
Net change in income taxes	(615.7		)	(227.4		)	205.4
Other	(0.1		)	(20.2		)	(25.9		)
Net change	1,858.4			1,169.3			(548.3		)
Balance at December 31,	$	4,955.7		$	3,097.3		$	1,928.0

- 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=82851474&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
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62299-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62094-109447

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 Cash and Cash Equivalents (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Restricted Cash and Cash Equivalents Items [Line Items]

Cash and cash equivalents

$ 0.0

Restricted Cash and Investments

^[1]

28.1

23.4

Restricted Cash and Cash Equivalents

28.1

23.4

$ 465.4

$ 394.2

Supplemental Disclosures

Cash paid for interest, net of capitalized interest

136.9

134.9

139.1

Cash paid (refund received) for income taxes, net

0.8

(0.3)

(123.5)

Non-cash investing activities

Change in capital expenditure accrual balance

$ (57.4)

$ 60.2

$ (32.8)

[1]	As of December 31, 2018 and 2017, the restricted cash balance related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Consolidated Balance Sheets.

Summary of Significant Accounting Policies Accounts Receivable (Details) - Allowance for Doubtful Accounts [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Bad Debt Expense	$ 0.6	$ (1.0)	$ 1.8
Allowance for Doubtful Accounts Receivable	$ 1.3	$ 1.6

Summary of Significant Accounting Policies Property, plant and equipment (Details)	12 Months Ended
	Dec. 31, 2018
Buildings \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years
Buildings \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	30 years
Leasehold improvements \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Leasehold improvements \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years
Service, transportation and field service equipment \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Service, transportation and field service equipment \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	7 years
Furniture and office equipment \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Furniture and office equipment \| 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 ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 1,560.9	$ 78.9	$ 1,194.3
Williston Basin Divestiture [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Divestiture, buyer's common stock	5.8
Williston Basin and Uinta Basin Divestiture [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 1,559.3
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
Other Northern [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			3.4
Other Southern [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			0.6
Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 1,524.6	38.1	1,172.7
Unproved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		29.0	17.9
Gas storage facility [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		6.5
Goodwill [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		$ 5.3	$ 3.7

Summary of Significant Accounting Policies Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill	$ 5.3	$ 3.7
Goodwill [Member]
Goodwill [Line Items]
Impairment of Oil and Gas Properties	$ 5.3	$ 3.7

Summary of Significant Accounting Policies Credit Risk (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Concentration Risk [Line Items]
Concentration Risk, Percentage	49.00%	59.00%	48.00%
Plains Marketing & Transportation [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%
Shell Trading Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		14.00%	14.00%
Occidental Energy Marketing [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%	13.00%
Andeavor Logistics LP [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		13.00%
BP Energy Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%	10.00%
Plains Marketing LP [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%

Summary of Significant Accounting Policies Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income tax rate [Line Items]
Unrecognized Tax Benefits	$ 19.0	$ 19.0	$ 15.6
Interest Related to Uncertain Tax Positions	$ 0.7	$ 0.7	0.7
Penalties Related to Uncertain Tax Positions			$ 0.6
Federal income tax rate	21.00%	35.00%

Summary of Significant Accounting Policies Earnings Per Share (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0.0	0.0	0.1
Weighted-average basic common shares outstanding	237.9	240.6	221.7
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	0.0	0.0	0.0
Average diluted common shares outstanding	237.9	240.6	221.7

Revenue (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Revenue Recognition [Line Items]

Oil and condensate, gas and NGL sales

$ 1,871.3

$ 1,545.3

$ 1,269.7

Other revenues

12.5

15.0

6.2

Purchased oil and gas sales

48.8

62.6

101.2

Total Revenues

$ 410.5

$ 560.8

$ 532.4

$ 428.9

$ 429.0

$ 390.1

$ 383.7

$ 420.1

1,932.6

1,622.9

1,377.1

Operating Expenses [Abstract]

Purchased oil and gas expense

51.0

64.3

105.5

Lease operating expense

263.1

294.8

224.7

Transportation and processing costs

117.6

245.3

289.2

Gathering and other expense

15.5

7.3

5.0

General and administrative

221.7

153.5

196.5

Production and property taxes

130.8

114.3

94.8

Depreciation, depletion and amortization

857.1

754.5

871.1

Exploration expenses

0.3

22.0

1.7

Impairment

1,560.9

78.9

1,194.3

Total Operating Expenses

3,218.0

1,734.9

2,982.8

Net gain (loss) from asset sales, inclusive of restructuring costs

25.0

213.5

5.0

OPERATING INCOME (LOSS)

(1,116.8)

156.8

(321.8)

21.4

(24.5)

132.1

(0.9)

(5.2)

(1,260.4)

101.5

(1,600.7)

Realized and unrealized gains (losses) on derivative contracts (Note 7)

90.4

24.5

(233.0)

Interest and other income (expense)

(9.6)

1.6

23.7

Interest expense

(149.4)

(137.8)

(143.2)

INCOME (LOSS) BEFORE INCOME TAXES

(1,329.0)

(42.9)

(1,953.2)

Total income tax provision (benefit)

(317.4)

(312.2)

(708.2)

NET INCOME (LOSS)

$ (629.3)

$ 7.3

$ (336.0)

$ (53.6)

$ 150.3

$ (3.3)

$ 45.4

$ 76.9

$ (1,011.6)

$ 269.3

$ (1,245.0)

Earnings (loss) per common share

Basic

$ (2.66)

$ 0.03

$ (1.42)

$ (0.22)

$ 0.62

$ (0.01)

$ 0.19

$ 0.32

$ (4.25)

$ 1.12

$ (5.62)

Diluted

$ (2.66)

$ 0.03

$ (1.42)

$ (0.22)

$ 0.62

$ (0.01)

$ 0.19

$ 0.32

$ (4.25)

$ 1.12

$ (5.62)

Weighted-average common shares outstanding

Used in basic calculation

237.9

240.6

221.7

Used in diluted calculation

237.9

240.6

221.7

As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate, gas and NGL sales

$ 1,871.3

Other revenues

12.5

Purchased oil and gas sales

48.8

Total Revenues

1,932.6

Operating Expenses [Abstract]

Purchased oil and gas expense

51.0

Lease operating expense

263.1

Transportation and processing costs

117.6

Gathering and other expense

15.5

General and administrative

221.7

Production and property taxes

130.8

Depreciation, depletion and amortization

857.1

Exploration expenses

0.3

Impairment

1,560.9

Total Operating Expenses

3,218.0

Net gain (loss) from asset sales, inclusive of restructuring costs

25.0

OPERATING INCOME (LOSS)

(1,260.4)

Realized and unrealized gains (losses) on derivative contracts (Note 7)

90.4

Interest and other income (expense)

(9.6)

Interest expense

(149.4)

INCOME (LOSS) BEFORE INCOME TAXES

(1,329.0)

Total income tax provision (benefit)

(317.4)

NET INCOME (LOSS)

$ (1,011.6)

Earnings (loss) per common share

Basic

$ (4.25)

Diluted

$ (4.25)

Weighted-average common shares outstanding

Used in basic calculation

237.9

Used in diluted calculation

237.9

Adjustments for New Accounting Pronouncement [Member]

Revenue Recognition [Line Items]

Oil and condensate, gas and NGL sales

$ 55.0

Other revenues

0.0

Purchased oil and gas sales

0.0

Total Revenues

55.0

Operating Expenses [Abstract]

Purchased oil and gas expense

0.0

Lease operating expense

0.0

Transportation and processing costs

55.0

Gathering and other expense

0.0

General and administrative

0.0

Production and property taxes

0.0

Depreciation, depletion and amortization

0.0

Exploration expenses

0.0

Impairment

0.0

Total Operating Expenses

55.0

Net gain (loss) from asset sales, inclusive of restructuring costs

0.0

OPERATING INCOME (LOSS)

0.0

Realized and unrealized gains (losses) on derivative contracts (Note 7)

0.0

Interest and other income (expense)

0.0

Interest expense

0.0

INCOME (LOSS) BEFORE INCOME TAXES

0.0

Total income tax provision (benefit)

0.0

NET INCOME (LOSS)

$ 0.0

Earnings (loss) per common share

Basic

$ 0.00

Diluted

$ 0.00

Weighted-average common shares outstanding

Used in basic calculation

0.0

Used in diluted calculation

0.0

Income Statement, as adjusted [Member]

Revenue Recognition [Line Items]

Oil and condensate, gas and NGL sales

^[1]

$ 1,926.3

Other revenues

^[1]

12.5

Purchased oil and gas sales

^[1]

48.8

Total Revenues

^[1]

1,987.6

Operating Expenses [Abstract]

Purchased oil and gas expense

^[1]

51.0

Lease operating expense

^[1]

263.1

Transportation and processing costs

^[1]

172.6

Gathering and other expense

^[1]

15.5

General and administrative

^[1]

221.7

Production and property taxes

^[1]

130.8

Depreciation, depletion and amortization

^[1]

857.1

Exploration expenses

^[1]

0.3

Impairment

^[1]

1,560.9

Total Operating Expenses

^[1]

3,273.0

Net gain (loss) from asset sales, inclusive of restructuring costs

^[1]

25.0

OPERATING INCOME (LOSS)

^[1]

(1,260.4)

Realized and unrealized gains (losses) on derivative contracts (Note 7)

^[1]

90.4

Interest and other income (expense)

^[1]

(9.6)

Interest expense

^[1]

149.4

INCOME (LOSS) BEFORE INCOME TAXES

^[1]

(1,329.0)

Total income tax provision (benefit)

^[1]

317.4

NET INCOME (LOSS)

^[1]

$ (1,011.6)

Earnings (loss) per common share

Basic

^[1]

$ (4.25)

Diluted

^[1]

$ (4.25)

Weighted-average common shares outstanding

Used in basic calculation

^[1]

237.9

Used in diluted calculation

^[1]

237.9

[1]	(1) This column excludes the impact of adopting ASC Topic 606 and is consistent with the presentation prior to January 1, 2018.

Revenue Revenue by area (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Revenue Recognition [Line Items]

Oil and condensate sales

$ 1,871.3

$ 1,545.3

$ 1,269.7

Transportation and processing costs included in revenue

15.5

7.3

5.0

As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate sales

1,871.3

Transportation and processing costs included in revenue

15.5

Williston Basin [Member] | As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate sales

707.0

586.5

^[1]

541.6

^[1]

Gas sales

45.3

42.3

^[1]

33.1

^[1]

NGL sales

56.5

51.5

^[1]

22.7

^[1]

Transportation and processing costs included in revenue

(43.1)

0.0

^[1]

0.0

^[1]

Oil and condensate, gas and NGL sales, as reported

765.7

680.3

^[1]

597.4

^[1]

Pinedale [Member] | As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate sales

^[1]

18.0

25.8

Gas sales

^[1]

154.8

194.1

NGL sales

^[1]

31.8

40.6

Transportation and processing costs included in revenue

^[1]

0.0

Oil and condensate, gas and NGL sales, as reported

^[1]

204.6

260.5

Uinta Basin [Member] | As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate sales

25.3

29.6

^[1]

28.0

^[1]

Gas sales

25.0

50.0

^[1]

52.5

^[1]

NGL sales

4.8

5.9

^[1]

6.4

^[1]

Transportation and processing costs included in revenue

0.0

^[1]

0.0

^[1]

Oil and condensate, gas and NGL sales, as reported

55.1

85.5

^[1]

86.9

^[1]

Other Northern [Member] | As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate sales

4.9

^[2]

4.9

^[1]

5.0

^[1]

Gas sales

2.0

^[2]

16.6

^[1]

18.7

^[1]

NGL sales

0.0

^[2]

0.3

^[1]

0.3

^[1]

Transportation and processing costs included in revenue

0.0

^[2]

0.0

^[1]

0.0

^[1]

Oil and condensate, gas and NGL sales, as reported

6.9

^[2]

21.8

^[1]

24.0

^[1]

Permian Basin [Member] | As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate sales

684.4

298.8

^[1]

166.1

^[1]

Gas sales

17.3

15.5

^[1]

11.6

^[1]

NGL sales

49.5

22.0

^[1]

12.9

^[1]

Transportation and processing costs included in revenue

(11.9)

0.0

^[1]

0.0

^[1]

Oil and condensate, gas and NGL sales, as reported

739.3

336.3

^[1]

190.6

^[1]

Haynesville [Member] | As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate sales

1.0

1.2

^[1]

1.1

^[1]

Gas sales

303.1

214.4

^[1]

106.6

^[1]

NGL sales

0.0

0.4

^[1]

0.4

^[1]

Transportation and processing costs included in revenue

0.0

^[1]

0.0

^[1]

Oil and condensate, gas and NGL sales, as reported

304.1

216.0

^[1]

108.1

^[1]

Other Southern [Member] | As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate sales

(0.2)

0.4

^[1]

1.5

^[1]

Gas sales

0.4

^[1]

0.5

^[1]

NGL sales

0.0

^[1]

0.2

^[1]

Transportation and processing costs included in revenue

0.0

^[1]

0.0

^[1]

Oil and condensate, gas and NGL sales, as reported

0.2

0.8

^[1]

2.2

^[1]

Total [Member] | As reported [Member]

Revenue Recognition [Line Items]

Oil and condensate sales

1,422.4

939.4

^[1]

769.1

^[1]

Gas sales

393.1

494.0

^[1]

417.1

^[1]

NGL sales

110.8

111.9

^[1]

83.5

^[1]

Transportation and processing costs included in revenue

(55.0)

0.0

^[1]

0.0

^[1]

Oil and condensate, gas and NGL sales, as reported

$ 1,871.3

$ 1,545.3

^[1]

$ 1,269.7

^[1]

[1]	Prior period amounts have not been adjusted under the modified retrospective method.
[2]	For the year ended December 31, 2018, immaterial amounts of revenue associated with adjustments in Pinedale have been included in Other Northern.

Acquisitions and Divestitures 2017 Permian Basin Acquisition (Details) - 2017 Permian Basin Acquisition [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) a
Business Acquisition [Line Items]
Aggregate purchase price \| $	$ 49.1	$ 721.0
Net acres of producing and undeveloped oil and gas properties \| a		15,100

Acquisitions and Divestitures 2016 Permian Basin Acquisition Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) a
Business Acquisition [Line Items]
Bargain purchase gain from acquisitions	$ 0.0	$ (0.4)	$ 22.6
2016 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Aggregate purchase price			$ 591.0
Net acres of producing and undeveloped oil and gas properties \| a			9,600
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	498.4	80.2	$ 3.8
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	$ 282.4	$ 221.4	(0.7)
Business Combination, Acquisition Related Costs			2.3
Bargain purchase gain from acquisitions			$ 17.8

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	$ 591.0
Recognized identifiable assets acquired and liabilities assumed, net	591.0
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	$ (17.8)

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Revenues	$ 410.5	$ 560.8	$ 532.4	$ 428.9	$ 429.0	$ 390.1	$ 383.7	$ 420.1	$ 1,932.6	$ 1,622.9	$ 1,377.1
Net income (loss)	$ (629.3)	$ 7.3	$ (336.0)	$ (53.6)	$ 150.3	$ (3.3)	$ 45.4	$ 76.9	$ (1,011.6)	$ 269.3	$ (1,245.0)
Earnings Per Share, Basic	$ (2.66)	$ 0.03	$ (1.42)	$ (0.22)	$ 0.62	$ (0.01)	$ 0.19	$ 0.32	$ (4.25)	$ 1.12	$ (5.62)
Diluted	$ (2.66)	$ 0.03	$ (1.42)	$ (0.22)	$ 0.62	$ (0.01)	$ 0.19	$ 0.32	$ (4.25)	$ 1.12	$ (5.62)
2016 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Revenues											$ 1,377.1
Net income (loss)											$ (1,245.0)
Earnings Per Share, Basic											$ (5.62)
Diluted											$ (5.62)
Business Acquisition, Pro Forma Revenue											$ 1,392.5
Business Acquisition, Pro Forma Net Income (Loss)											$ (1,246.8)
Business Acquisition, Pro Forma Earnings Per Share, Basic											$ (5.62)
Business Acquisition, Pro Forma Earnings Per Share, Diluted											$ (5.62)

Acquisitions and Divestitures Other Acquisitions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Goodwill		$ 5.3	$ 3.7
Bargain purchase gain from acquisitions	$ 0.0	(0.4)	22.6
Additional acquisitions in the Permian Basin [Member]
Business Acquisition [Line Items]
Aggregate purchase price	$ 16.5	$ 94.5	54.6
Williston & Permian Basins [Member]
Business Acquisition [Line Items]
Goodwill			3.7
Other Acquisitions [Member]
Business Acquisition [Line Items]
Bargain purchase gain from acquisitions			$ (4.4)

Acquisitions and Divestitures Haynesville/Cotton Valley Divestiture (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Divestitures [Line Items]
Payments to Acquire Oil and Gas Property	$ 65.6	$ 815.2	$ 639.0
Proceeds from Sale of Oil and Gas Property and Equipment	243.6	806.8	$ 29.0
Escrow Deposit	32.2
Haynesville Divestiture [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	735.0
Restructuring Charges	3.0
Other Current Assets [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	1.2	3.4
Property, Plant and Equipment [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	683.7	1,290.3
Other Noncurrent Assets [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	7.8	27.2
Noncurrent Assets Held for Sale [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	692.7	1,320.9
Other Current Liabilities [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	3.4	4.5
Asset Retirement Obligations, Current [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	0.7	4.7
Asset Retirement Obligations, Long Term [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	56.9	102.5
Derivative Financial Instruments, Liabilities [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	0.0	(3.0)
Other Noncurrent Liabilities [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	0.3	0.5
Other Long-Term Liabilities Held for Sale [Member] \| Haynesville Divestiture [Member]
Divestitures [Line Items]
Held for Sale, Assets, Noncurrent	$ 61.3	$ 109.2

Acquisitions and Divestitures Planned Williston Basin Divestiture (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 243.6	$ 806.8	$ 29.0
Williston Basin Divestiture [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	1,725.0
Cash Payments to Acquire Oil and Gas Property	1,650.0
Payments to Acquire Oil and Gas Property, Contractual Rights	$ 75.0

Acquisitions and Divestitures Uinta Basin Divestiture (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Divestitures [Line Items]
Net gain (loss) from asset sales, inclusive of restructuring costs	$ 25.0	$ 213.5	$ 5.0
Proceeds from Sale of Oil and Gas Property and Equipment	243.6	$ 806.8	$ 29.0
Uinta Basin Divestiture [Member]
Divestitures [Line Items]
Net gain (loss) from asset sales, inclusive of restructuring costs	(12.6)
Proceeds from Sale of Oil and Gas Property and Equipment	153.0
Restructuring Charges	(5.4)
Impairment of Oil and Gas Properties	$ 402.8

Acquisitions and Divestitures Pinedale Divestiture (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 243.6	$ 806.8	$ 29.0
Net gain (loss) from asset sales, inclusive of restructuring costs	25.0	213.5	5.0
Results of Operations, Income before Income Taxes	(1,329.0)	(42.9)	(1,953.2)
Pinedale Divestiture [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		718.2
Net gain (loss) from asset sales, inclusive of restructuring costs	1.2	180.4
Long-term Purchase Commitment, Amount	45.0
Purchase Commitment, Remaining Minimum Amount Committed	$ 9.3
Results of Operations, Income before Income Taxes		$ 251.0	(1,152.7)
Pinedale [Member]
Divestitures [Line Items]
Impairment of Oil and Gas Properties			1,164.0
Proved Property [Member] \| Pinedale [Member]
Divestitures [Line Items]
Impairment of Oil and Gas Properties			$ 1,164.0

Acquisitions and Divestitures Other Divestitures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 243.6	$ 806.8	$ 29.0
Net gain (loss) from asset sales, inclusive of restructuring costs	25.0	213.5	5.0
Other Property [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	90.6
Net gain (loss) from asset sales, inclusive of restructuring costs	$ 38.5
Central Basin Platform [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		3.5
Other Northern [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		85.1
Net gain (loss) from asset sales, inclusive of restructuring costs		$ 33.1
Other Southern [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			29.0
Net gain (loss) from asset sales, inclusive of restructuring costs			$ 8.6

Capitalized Exploratory Well Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Capitalized Exploratory Well Costs [Line Items]
Balance at January 1,	$ 0.0	$ 14.2	$ 2.6
Additions to capitalized exploratory well costs	0.0	10.7	11.7
Reclassifications to proved properties	0.0	(3.6)	0.0
Capitalized exploratory well costs charged to expense	0.0	(21.3)	0.1
Balance at December 31,	0.0	0.0	14.2
Proceeds from Sale of Oil and Gas Property and Equipment	243.6	806.8	29.0
Impairment	1,560.9	$ 78.9	$ 1,194.3
Central Basin Platform [Member]
Capitalized Exploratory Well Costs [Line Items]
Reclassifications to proved properties	(3.6)
Proceeds from Sale of Oil and Gas Property and Equipment	3.5
Impairment	$ 28.3

Asset Retirement Obligations Balance Sheet Classification (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Current	$ 5.1	$ 2.8
Asset Retirement Obligations, Noncurrent	96.9	104.1
Asset Retirement Obligation	159.6	214.1	$ 231.6
Other Long-Term Liabilities Held for Sale [Member]
Asset Retirement Obligation, Current	5.1	2.8
Asset Retirement Obligations, Noncurrent	96.9	104.1
Liabilities, Noncurrent	57.6	107.2
Asset Retirement Obligation	$ 159.6	$ 214.1

Asset Retirement Obligations ARO Rollforward(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	$ 214.1	$ 231.6
Accretion	6.4	7.7
Liabilities incurred	4.1	23.5
Revisions of Estimates	(4.9)	8.5
Liabilities related to assets sold	56.8	(34.9)
Liabilities settled	(3.3)	(22.3)
ARO liability, Ending Balance	159.6	214.1
2017 Permian Basin Acquisition [Member]
ARO Liability [Roll Forward]
Liabilities incurred		14.2
Uinta Basin Divestiture [Member]
ARO Liability [Roll Forward]
Liabilities related to assets sold	$ (51.0)
Pinedale Divestiture [Member]
ARO Liability [Roll Forward]
Liabilities related to assets sold		$ (34.9)

Fair Value Measurements (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Proved properties [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Impairment of Oil and Gas Properties	$ 1,524.6	$ 38.1	$ 1,172.7
Williston Basin Divestiture [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Payments to Acquire Oil and Gas Property, Contractual Rights	$ 75.0
Fair Value Assumptions, Risk Free Interest Rate	5.00%
Fair Value Assumptions, Weighted Average Volatility Rate	49.30%
Williston Basin Divestiture [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Divestiture, buyer's common stock	5.8

Fair Value of Financial Assets and Liabilities (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Financial Assets

Netting Adjustments

^[1]

$ (0.4)

$ (19.4)

Derivative Asset

123.2

3.5

Financial liabilities

Netting Adjustments

^[1]

(0.4)

(19.4)

Derivative Liability

0.7

135.4

Level 1 [Member]

Financial Assets

Derivative instruments

0.0

Financial liabilities

Derivative instruments

0.0

Level 2 [Member]

Financial Assets

Derivative instruments

123.6

22.9

Financial liabilities

Derivative instruments

1.1

154.8

Level 3 [Member]

Financial Assets

Derivative instruments

0.0

Financial liabilities

Derivative instruments

0.0

Long term [Member]

Financial Assets

Netting Adjustments

^[1]

0.0

(2.2)

Derivative Asset

35.4

0.1

Financial liabilities

Netting Adjustments

^[1]

0.0

(2.2)

Derivative Liability

0.7

31.8

Long term [Member] | Level 1 [Member]

Financial Assets

Derivative instruments

0.0

Financial liabilities

Derivative instruments

0.0

Long term [Member] | Level 2 [Member]

Financial Assets

Derivative instruments

35.4

2.3

Financial liabilities

Derivative instruments

0.7

34.0

Long term [Member] | Level 3 [Member]

Financial Assets

Derivative instruments

0.0

Financial liabilities

Derivative instruments

0.0

Short term [Member]

Financial Assets

Netting Adjustments

^[1]

(0.4)

(17.2)

Derivative Asset

87.8

3.4

Financial liabilities

Netting Adjustments

^[1]

(0.4)

(17.2)

Derivative Liability

0.0

103.6

Short term [Member] | Level 1 [Member]

Financial Assets

Derivative instruments

0.0

Financial liabilities

Derivative instruments

0.0

Short term [Member] | Level 2 [Member]

Financial Assets

Derivative instruments

88.2

20.6

Financial liabilities

Derivative instruments

0.4

120.8

Short term [Member] | Level 3 [Member]

Financial Assets

Derivative instruments

0.0

Financial liabilities

Derivative instruments

0.0

Derivative Financial Instruments, Assets [Member] | Haynesville Divestiture [Member]

Financial liabilities

Held for Sale, Assets, Noncurrent

$ 0.3

Derivative Financial Instruments, Liabilities [Member] | Haynesville Divestiture [Member]

Financial liabilities

Held for Sale, Liabilities, Noncurrent

$ (3.0)

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

Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	$ 0.0	$ 0.0
Cash and cash equivalents, Level 1 Fair Value	0.0	0.0
Checks outstanding in excess of cash balances	14.6	44.0
Checks outstanding in excess of cash balances, Level 1 Fair Value	14.6	44.0
Long-term debt	2,507.1	2,160.8
Long-term debt, Level 1 Fair Value	$ 2,350.5	$ 2,256.2

Derivative Contracts (Narrative) (Details)	12 Months Ended
Derivative Contracts (Narrative) (Details)	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Forecasted production from proved reserves (in hundredths)	100.00%
Expected Annual Production Covered By Derivatives, Low	50.00%
Expected Annual Production Covered By Derivatives, High	75.00%

Derivative Contracts Schedule of Commodity Derivative Contracts (Details) bbl in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) MMBTU bbl $ / MMBTU $ / bbl
Oil Swaps [Member] \| Year 2019 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount \| bbl	11.0
Underlying, Derivative Asset \| $ / bbl	54.49
Oil Swaps [Member] \| Year 2020 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount \| bbl	2.9
Underlying, Derivative Asset \| $ / bbl	62.37
Gas Swaps [Member] \| Year 2019 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	43.8
Underlying, Derivative Asset \| $ / MMBTU	2.86
Oil Basis Swaps [Member] \| Year 2019 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6.6
Derivatives, Weighted Average Differential \| $	$ (2.22)
Oil Basis Swaps [Member] \| Year 2019 [Member] \| NYMEX WTI less Argus WTI Houston [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.4
Derivatives, Weighted Average Differential \| $	$ 4.35
Oil Basis Swaps [Member] \| Year 2020 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1.5
Derivatives, Weighted Average Differential \| $	$ (1.01)

Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Inputs, Level 2 [Member]
Derivative [Line Items]
Derivative instruments - assets	$ 123.6	$ 22.9
Derivative instruments - liabilities	1.1	154.8
Fair Value, Inputs, Level 2 [Member] \| Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	88.2	20.6
Derivative instruments - liabilities	0.4	120.8
Fair Value, Inputs, Level 2 [Member] \| Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	35.4	2.3
Derivative instruments - liabilities	0.7	34.0
Fair Value, Inputs, Level 2 [Member] \| Fair Value, Measurements, Recurring [Member]
Derivative [Line Items]
Derivative instruments - assets	123.6	22.9
Derivative instruments - liabilities	1.1	154.8
Fair Value, Inputs, Level 2 [Member] \| Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member] \| Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	88.2	20.6
Derivative instruments - liabilities	0.4	120.8
Fair Value, Inputs, Level 2 [Member] \| Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member] \| Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	35.4	2.3
Derivative instruments - liabilities	0.7	34.0
Derivative Financial Instruments, Assets [Member] \| Haynesville Divestiture [Member]
Derivative [Line Items]
Held for Sale, Assets, Noncurrent	$ 0.3
Derivative Financial Instruments, Liabilities [Member] \| Haynesville Divestiture [Member]
Derivative [Line Items]
Held for Sale, Liabilities, Noncurrent		$ (3.0)

Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Derivative Instruments, Gain (Loss) [Line Items]

Realized gain (loss) on commodity derivative contracts not designated as hedging instruments

$ (158.1)

$ (15.5)

$ 134.0

Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments

90.4

24.5

(233.0)

^[1]

Oil derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Realized gain (loss) on commodity derivative contracts not designated as hedging instruments

(153.4)

6.8

86.3

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

277.0

(66.2)

(217.2)

Gas derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Realized gain (loss) on commodity derivative contracts not designated as hedging instruments

(5.0)

(22.3)

44.8

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

(22.3)

133.6

(145.4)

Gas derivative contracts [Member] | Storage [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Realized gain (loss) on commodity derivative contracts not designated as hedging instruments

0.3

0.0

2.9

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

(0.3)

2.5

(4.4)

Total [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

254.4

69.9

(367.0)

Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments

96.3

54.4

(233.0)

Uinta Basin Divestiture [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[1]

(5.9)

Uinta Basin Divestiture [Member] | Oil derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[1]

(2.7)

Uinta Basin Divestiture [Member] | Gas derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[1]

0.0

Uinta Basin Divestiture [Member] | NGL derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[1]

$ (3.2)

Pinedale Divestiture [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[2]

(29.9)

Pinedale Divestiture [Member] | Oil derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[2]

(1.3)

Pinedale Divestiture [Member] | Gas derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[2]

(23.5)

Pinedale Divestiture [Member] | NGL derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[2]

$ (5.1)

No Divestiture [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[1]

0.0

No Divestiture [Member] | Oil derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

0.0

No Divestiture [Member] | Gas derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[1]

0.0

No Divestiture [Member] | NGL derivative contracts [Member] | Production [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments

^[1]

$ 0.0

[1]

(1) During the year ended December 31, 2018, the unrealized gains (losses) on commodity derivative contracts related to the Uinta Basin Divestiture are comprised of derivatives entered into in conjunction with the execution of the Uinta Basin purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2018. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Uinta Basin Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.

[2]

Restructuring Costs (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restructuring Cost and Reserve [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 243.6	$ 806.8	$ 29.0
Haynesville Divestiture [Member]
Restructuring Cost and Reserve [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	735.0
Williston Basin Divestiture [Member]
Restructuring Cost and Reserve [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 1,725.0

Restructuring Costs Costs recognized and remaining costs expected to be incurred (Details)
$ in Millions

12 Months Ended

Dec. 31, 2018

USD ($)

Termination benefits

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Cost Incurred to Date

$ 32.3

Restructuring Costs, Expected Costs

0.0

^[1],[2]

Office lease termination costs

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Cost Incurred to Date

1.0

Restructuring Costs, Expected Costs

0.0

^[1]

Accelerated share-based compensation

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Cost Incurred to Date

11.2

Restructuring Costs, Expected Costs

15.5

^[1],[2],[3]

Accelerated share-based compensation | Year 2019 [Member]

Restructuring Cost and Reserve [Line Items]

Restructuring Costs, Expected Costs

6.0

^[1],[2],[3]

Retention expense (including share-based compensation)

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Cost Incurred to Date

18.8

Restructuring Costs, Expected Costs

21.4

^[2],[4]

Pension and Medical Plan curtailment

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Cost Incurred to Date

0.1

Restructuring Costs, Expected Costs

0.0

^[1]

Total restructuring costs

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Cost Incurred to Date

63.4

Restructuring Costs, Expected Costs

36.9

2018 Retention Program [Member] | Year 2018 [Member]

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Expected Cost

3.9

2019 Retention Program [Member] | Year 2019 [Member]

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Expected Cost

17.5

2019 Retention Program [Member] | Cash [Member] | Year 2019 [Member]

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Expected Cost

16.0

2019 Retention Program [Member] | Share based compensation [Member] | Year 2019 [Member]

Restructuring Cost and Reserve [Line Items]

Restructuring and Related Cost, Expected Cost

$ 1.5

[1]	Due to the nature of the strategic initiatives and uncertain factors such as the timing and terms of the potential divestitures, the Company is not able to reasonably estimate the total cost to be incurred as a part of these restructurings.
[2]	Refer to the Note 16 – Subsequent Events for more information regarding expected restructuring costs.
[3]	In January 2019, QEP had $15.5 million of accelerated share-based compensation due to the departure of two officers. The accelerated share-based compensation of $15.5 million was determined based on the contractual vesting date with $6.0 million expected to be recognized in the first quarter of 2019 and the remaining amount previously recognized in 2018 and prior periods.
[4]	QEP expects to incur an additional $3.9 million in 2019 related to the 2018 retention program and $17.5 million related to the 2019 retention program, which includes $16.0 million of cash and $1.5 million of share-based compensation.

Restructuring Costs Restructuring Liability (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2017	$ 0.0
Costs incurred and charged to expense	32.3
Costs paid or otherwise settled	(12.8)
Balance at December 31, 2018	19.5
Office lease termination costs
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2017	0.0
Costs incurred and charged to expense	1.0
Costs paid or otherwise settled	(1.0)
Balance at December 31, 2018	0.0
Accelerated Share Based Compensation [Member]
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2017	0.2
Costs incurred and charged to expense	11.0
Costs paid or otherwise settled	(11.2)
Balance at December 31, 2018	0.0
Retention Expense [Member]
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2017	0.0
Costs incurred and charged to expense	18.8
Costs paid or otherwise settled	(8.0)
Balance at December 31, 2018	10.8
Pension and Medical Plan curtailment
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2017	0.0
Costs incurred and charged to expense	0.1
Costs paid or otherwise settled	(0.1)
Balance at December 31, 2018	0.0
Total [Member]
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2017	0.2
Costs incurred and charged to expense	63.2
Costs paid or otherwise settled	(33.1)
Balance at December 31, 2018	$ 30.3

Debt (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
Debt (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt	$ 2,507.1	$ 2,160.8
Long-term Debt, Weighted Average Interest Rate, at Point in Time	4.43%	3.52%
Long-term Debt	$ 2,099.3
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	5.25%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	6.875%
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 430.0	$ 89.0
Long-term Line of Credit	1,250.0
Letters of Credit Outstanding, Amount	0.3	1.0
Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 51.7	51.7
Debt Instrument, Maturity Date	Mar. 01, 2020
Debt Instrument, Interest Rate, Stated Percentage	6.80%
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 397.6	397.6
Debt Instrument, Maturity Date	Mar. 01, 2021
Debt Instrument, Interest Rate, Stated Percentage	6.875%
Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 500.0	500.0
Debt Instrument, Maturity Date	Oct. 01, 2022
Debt Instrument, Interest Rate, Stated Percentage	5.375%
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 650.0	650.0
Debt Instrument, Maturity Date	May 01, 2023
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 500.0	$ 500.0
Debt Instrument, Maturity Date	Mar. 01, 2026
Debt Instrument, Interest Rate, Stated Percentage	5.625%

Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total principal amount of debt	$ 2,507.1	$ 2,160.8
Less unamortized discount	(22.2)	(27.5)
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	430.0	89.0
Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	51.7	51.7
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	397.6	397.6
Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	500.0	500.0
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	650.0	650.0
Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	$ 500.0	$ 500.0

Commitments and Contingencies Other Commitments (Details) $ in Millions	Dec. 31, 2018 USD ($)
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 72.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	55.4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	31.3
Unrecorded Unconditional Purchase Obligation, Due within Four Years	27.1
Unrecorded Unconditional Purchase Obligation, Due within Five Years	15.3
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 66.0

Commitments and Contingencies Long-term Operating lease commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating lease commitments [Abstract]
Operating Leases, Rent Expense	$ 30.3	$ 24.9	$ 21.7
Operating Leases, Future Minimum Payments Due, Next Twelve Months	17.4
Operating Leases, Future Minimum Payments, Due in Two Years	13.8
Operating Leases, Future Minimum Payments, Due in Three Years	9.1
Operating Leases, Future Minimum Payments, Due in Four Years	7.4
Operating Leases, Future Minimum Payments, Due in Five Years	4.5
Operating Leases, Future Minimum Payments, Due Thereafter	$ 0.0

Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized	10.0
Shares available for future grants	10.1
Share-based compensation expense	$ 36.9	$ 22.4	$ 35.6
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	1.2	$ 2.3	2.3
Intrinsic value of options exercised	0.1
Tax benefit from equity-based compensation expense			$ 0.2
Unrecognized compensation costs	$ 0.4
Weighted average period for recognition of equity-based compensation expense	1 year 2 months 8 days
Restricted Share Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 9.56	$ 13.90	$ 10.50
Share-based compensation expense	$ 27.5	$ 24.6	$ 23.7
Unrecognized compensation costs	$ 15.2
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	$ 21.5	$ 18.4	$ 24.3
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 9.55	$ 16.90	$ 10.16
Share-based compensation expense	$ 8.1	$ (4.5)	$ 9.4
Unrecognized compensation costs	$ 7.3
Weighted average period for recognition of equity-based compensation expense	1 year 10 months 3 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 2.8	$ 5.3	$ 2.8
Restricted Share Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 9.55	$ 16.98	$ 10.12
Share-based compensation expense	$ 0.1	$ 0.0	$ 0.2
Unrecognized compensation costs	$ 0.1
Weighted average period for recognition of equity-based compensation expense	10 months 17 days

Share-Based Compensation Schedule of Share-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Expense [Line Items]
Share-based compensation expense	$ 36.9	$ 22.4	$ 35.6
Accelerated Share Based Compensation	11.0
Stock Options [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	1.2	2.3	2.3
Restricted Share Awards [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	27.5	24.6	23.7
Performance Share Units [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	8.1	(4.5)	9.4
Restricted Share Units (RSUs) [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	0.1	$ 0.0	$ 0.2
General and administrative expense [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	8.8
Net gain (loss) from asset sales, inclusive of restructuring costs [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	$ 2.2

Share-Based Compensation Fair Value of Options Granted and Major Assumptions Used (Details) - Stock Options [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value	$ 0.00	$ 6.44	$ 3.77
Risk free interest rate, minimum	0.00%	1.66%	0.99%
Risk free interest rate, maximum	0.00%	1.81%	1.15%
Weighted average risk-free interest rate	0.00%	1.80%	1.20%
Expected price volatility range, minimum	0.00%	43.82%	43.42%
Expected price volatility range, maximum	0.00%	46.70%	43.66%
Weighted average expected price volatility	0.00%	43.90%	43.40%
Expected dividend yield	0.00%	0.00%	0.00%
Expected term in years at the date of grant	0 years	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, 2018 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Stock options outstanding, beginning of year \| shares	2,354,277
Options exercised \| shares	(23,337)
Options Cancelled \| shares	(232,007)
Stock options outstanding, end of year \| shares	2,098,933
Options exercisable, shares \| shares	1,732,827
Unvested options, shares \| shares	366,106
Share-based Compensation Arrangement by Share-based Payment Award, Additional General Disclosures [Abstract]
Weighted average exercise price, beginning of year \| $ / shares	$ 23.62
Weighted average exercise price, granted in period \| $ / shares	10.12
Weighted average exercise price, cancelled in period \| $ / shares	37.16
Weighted average exercise price, end of year \| $ / shares	22.27
Options exercisable, weighted average exercise price \| $ / shares	23.90
Unvested options, weighted average exercise price \| $ / shares	$ 14.57
Weighted average remaining contractual term, options outstanding	2 years 10 months 14 days
Weighted average remaining contractual term, options exercisable	2 years 5 months 16 days
Weighted average remaining contractual term, options unvested	4 years 9 months 22 days
Aggregate intrinsic value, options outstanding \| $	$ 0.0
Aggregate intrinsic value, options exercisable \| $	0.0
Aggregate intrinsic value, options unvested \| $	$ 0.0

Share-Based Compensation Schedule of Restricted Stock Transactions (Details) - Restricted Share Awards [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	3,721,334
Shares granted	2,997,743
Shares vested	(2,630,959)
Shares forfeited	(265,985)
Unvested balance at end of period	3,822,133	3,721,334
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	$ 13.23
Weighted average grant date fair value, grants	9.56	$ 13.90	$ 10.50
Weighted average grant date fair value, vested	12.87
Weighted average grant date fair value, forfeited	10.96
Weighted average grant date fair value, end of period	$ 10.76	$ 13.23

Share-Based Compensation Schedule of Performance Share Unit Transactions (Details) - Performance Share Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	1,199,336
Shares granted	724,095
Shares vested and paid out	(364,119)
Unvested balance at end of period	1,559,312	1,199,336
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	$ 14.59
Weighted average grant date fair value, grants	9.55	$ 16.90	$ 10.16
Weighted average grant date fair value, vested and paid out	17.26
Weighted average grant date fair value, end of period	$ 11.47	$ 14.59

Share-Based Compensation Schedule of Restricted Share Unit Transactions (Details) - Restricted Share Units (RSUs) [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested balance at beginning of period	21,946
Shares granted	31,835
Shares vested	(11,106)
Unvested balance at end of period	42,675	21,946
Weighted average grant date fair value, beginning of period	$ 13.22
Weighted average grant date fair value, grants	9.55	$ 16.98	$ 10.12
Weighted average grant date fair value, vested	13.27
Weighted average grant date fair value, end of period	$ 10.47	$ 13.22

Employee Benefits (Narrative) (Details) $ in Millions	12 Months Ended
Employee Benefits (Narrative) (Details) $ in Millions	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 121.6	$ 128.7
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	5.0
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	$ 5.0
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	20
Defined Benefit Plan, Percentage Of Employees Covered	4.00%
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	194
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 0.7
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	0.5
Defined Benefit Plan, Curtailment loss	$ 0.3	0.7
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Eligible	12
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 0.4	0.1
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	0.2
Defined Benefit Plan, Curtailment loss	(0.2)	0.0	$ 0.0
Defined Benefit Plan, Expected Amortization, Next Fiscal Year	$ (0.3)
Medical 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 Enrolled	35
Pension Plan and SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 5.7	$ 6.0
Defined Benefit Plan, Curtailment loss	0.3		$ 0.0
Defined Benefit Plan, Expected Amortization, Next Fiscal Year	$ 1.8

Employee Benefits Schedule of Changes in Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Change in plan assets
Fair value of plan assets at January 1,	$ 100.5
Fair value of plan assets at December 31,	93.3	$ 100.5
Pension Plan and SERP [Member]
Change in benefit obligation
Benefit obligation at January 1,	130.0	129.2
Service cost	0.8	0.8	$ 1.2
Interest cost	4.6	4.7	5.2
Curtailments	0.1	(0.3)
Benefit payments	5.8	6.9
Plan amendments	0.0	0.0
Actuarial loss (gain)	(7.6)	2.5
Benefit obligation at December 31,	122.1	130.0	129.2
Change in plan assets
Fair value of plan assets at January 1,	100.5	86.1
Actual return on plan assets	(7.1)	15.3
Company contributions to the plan	5.7	6.0
Benefit payments	5.8	6.9
Fair value of plan assets at December 31,	93.3	100.5	86.1
Underfunded status (current and long-term)	(28.8)	(29.5)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(1.1)	(1.5)
Other long-term liabilities	(27.7)	(27.9)
Total amount recognized in balance sheet	(28.8)	(29.4)
Amounts recognized in AOCI
Net actuarial loss (gain)	19.4	15.0
Prior service cost	0.4	1.2
Total amount recognized in AOCI	19.8	16.2
Medical Plan [Member]
Change in benefit obligation
Benefit obligation at January 1,	2.9	5.4
Service cost	0.0	0.0	0.0
Interest cost	0.1	0.1	0.2
Curtailments	0.0	0.0
Benefit payments	0.4	0.1
Plan amendments	0.0	(2.4)
Actuarial loss (gain)	(0.1)	(0.1)
Benefit obligation at December 31,	2.5	2.9	5.4
Change in plan assets
Fair value of plan assets at January 1,	0.0	0.0
Actual return on plan assets	0.0	0.0
Company contributions to the plan	0.4	0.1
Benefit payments	0.4	0.1
Fair value of plan assets at December 31,	0.0	0.0	$ 0.0
Underfunded status (current and long-term)	(2.5)	(2.9)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(0.2)	(0.2)
Other long-term liabilities	(2.3)	(2.6)
Total amount recognized in balance sheet	(2.5)	(2.8)
Amounts recognized in AOCI
Net actuarial loss (gain)	(0.5)	(0.5)
Prior service cost	(0.8)	(1.2)
Total amount recognized in AOCI	$ (1.3)	$ (1.7)

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Plan and SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Benefit payments	$ 5.8	$ 6.9
Benefit payments	5.8	6.9
Defined Benefit Plan, Benefit Obligation	122.1	130.0	$ 129.2
Components of net periodic benefit cost
Service cost	0.8	0.8	1.2
Interest cost	4.6	4.7	5.2
Expected return on plan assets	(5.8)	(5.4)	(5.6)
Curtailment loss	0.3		0.0
Settlements	0.0	0.2	0.0
Amortization of prior service costs	0.8	1.0	1.1
Amortization of actuarial loss	0.8	0.5	0.8
Periodic expense	1.5	2.5	2.7
Components recognized in accumulated other comprehensive income
Current period prior service cost	0.0	(0.7)	0.0
Current period actuarial (gain) loss	5.6	(7.5)	8.5
Amortization of prior service cost	(0.8)	(1.0)	(1.1)
Amortization of actuarial gain (loss)	(0.8)	(0.5)	(0.8)
Loss on curtailment in current period	(0.1)	(0.3)	0.0
Settlements	0.0	(0.2)	0.0
Total amount recognized in accumulated other comprehensive income	3.9	(10.2)	6.6
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Benefit payments	0.4	0.1
Benefit payments	0.4	0.1
Defined Benefit Plan, Benefit Obligation	2.5	2.9	5.4
Components of net periodic benefit cost
Service cost	0.0	0.0	0.0
Interest cost	0.1	0.1	0.2
Expected return on plan assets	0.0	0.0	0.0
Curtailment loss	(0.2)	0.0	0.0
Settlements	0.0	0.0	0.0
Amortization of prior service costs	(0.3)	(0.3)	0.2
Amortization of actuarial loss	0.0	(0.1)	0.0
Periodic expense	(0.4)	(0.3)	0.4
Components recognized in accumulated other comprehensive income
Current period prior service cost	0.2	(2.5)	0.0
Current period actuarial (gain) loss	(0.1)	(0.1)	0.4
Amortization of prior service cost	0.3	0.3	(0.2)
Amortization of actuarial gain (loss)	0.0	0.1	0.0
Loss on curtailment in current period	0.0	0.0	0.0
Settlements	0.0	0.0	0.0
Total amount recognized in accumulated other comprehensive income	$ 0.4	$ (2.2)	$ 0.2

Employee Benefits Schedule of Weighted Average Actuarial Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Costs (Details)

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Medical Plan [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Discount rate used in calculating benefit obligation

4.30%

3.60%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Discount rate used in calculating net periodic benefit cost

3.60%

4.10%

4.40%

Pension Plan and SERP [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Discount rate used in calculating benefit obligation

4.19%

3.52%

Rate of increase in compensation used for calculating benefit obligation

^[1]

3.00%

3.50%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Discount rate used in calculating net periodic benefit cost

3.50%

4.00%

4.23%

Expected long-term return on plan assets used in calculating net periodic benefit cost

6.00%

6.50%

Medical Plan [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Rate of increase in compensation used in calculating net periodic benefit cost

^[2]

3.50%

4.00%

Pension Plan and SERP [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Rate of increase in compensation used in calculating net periodic benefit cost

^[2]

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 years ended December 31, 2018 and 2017, the rate of increase in compensation is only used for the SERP.

[2]

Employee Benefits Schedule of Fair Values of Pension and Postretirement Benefit Assets by Asset Class (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 93.3	$ 100.5
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	$ 0.7	$ 0.5
Defined Benefit Plan, Actual Plan Asset Allocations	1.00%	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	$ 20.7	$ 35.0
Defined Benefit Plan, Actual Plan Asset Allocations	22.00%	35.00%
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	$ 10.0	$ 15.3
Defined Benefit Plan, Actual Plan Asset Allocations	11.00%	15.00%
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	$ 61.9	$ 49.7
Defined Benefit Plan, Actual Plan Asset Allocations	66.00%	50.00%

Employee Benefits Schedule of Expected Benefit Payments for Pension and Other Postretirement Benefits (Details) $ in Millions	Dec. 31, 2018 USD ($)
Pension Plan and SERP [Member]
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2019	$ 6.6
2020	16.7
2021	6.4
2022	6.4
2023	8.1
2024 through 2026	32.7
Medical Plan [Member]
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2019	0.2
2020	0.2
2021	0.2
2022	0.2
2023	0.2
2024 through 2026	$ 0.5

Employee Benefits EIP (Details) - USD ($) $ in Millions	12 Months Ended
Employee Benefits EIP (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	8.00%	8.00%	8.00%
401(k) Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 5.8	$ 6.0	$ 5.6
SERP [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	6.00%	6.00%	6.00%
Pension Plan Discretionary Contribution [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined benefit plan, employer contribution	$ 0.3	$ 0.4	$ 0.5

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Valuation Allowance [Line Items]
Federal income tax rate	21.00%	35.00%
Operating Loss Carryforwards, Valuation Allowance	$ 82.3
Alternative minimum tax	(148.4)		$ 126.0
Oklahoma [Member]
Valuation Allowance [Line Items]
Operating Loss Carryforwards, Valuation Allowance	26.4
Louisiana [Member]
Valuation Allowance [Line Items]
Operating Loss Carryforwards, Valuation Allowance	49.0
Utah [Member]
Valuation Allowance [Line Items]
Operating Loss Carryforwards, Valuation Allowance	6.7
2019 [Member]
Valuation Allowance [Line Items]
Alternative minimum tax	$ 74.2

Income Taxes Schedule of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Federal income tax provision (benefit)
Current	$ (71.3)	$ 2.1	$ (55.5)
Deferred	(257.8)	(339.8)	(614.3)
State income tax provision (benefit)
Current	1.5	0.5	(1.5)
Deferred	10.2	25.0	(36.9)
Total income tax provision (benefit)	$ (317.4)	$ (312.2)	$ (708.2)

Income Taxes Reconciliation of Statutory Federal Income Tax Rate and Effective Tax Rate (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Investments, Owned, Federal Income Tax Note [Line Items]

Federal income tax rate

21.00%

35.00%

Valuation allowance

$ 36.2

Operating Loss Carryforwards

$ 75.7

Alternative minimum tax

$ (148.4)

126.0

Deferred Tax Assets, Tax Credit Carryforwards

$ 50.3

Federal income taxes statutory rate

21.00%

35.00%

Increase (decrease) in rate as a result of:

State income taxes, net of federal income tax benefit(1)

(0.70%)

(40.10%)

^[1]

2.40%

Federal rate change(2)

0.00%

741.30%

^[2]

0.00%

State rate change

0.00%

2.10%

(1.10%)

Permanent adjustments

(0.10%)

(0.40%)

0.00%

Return to provision adjustment

(0.10%)

(0.70%)

0.00%

Uncertain tax provision (federal rate change)

0.00%

(7.70%)

0.00%

AMT Credit Reclass due to NOL Carryback(3)

3.80%

^[3]

(1.80%)

0.00%

Effective income tax rate

23.90%

727.70%

36.30%

[1]	State income taxes changed significantly from prior years mainly due to the change in valuation allowance recorded during 2017 of $36.2 million.
[2]	The Tax Legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets as of December 31, 2017 from a 35% to 21% federal corporate income tax rate which caused the majority of the change in rate.
[3]	In 2018, QEP agreed to an IRS proposed change to the initial treatment of the 2016 carryback of net operating losses. This change resulted in a reduction of available net operating loss carryforwards valued at $75.7 million and an increase in alternative minimum tax (AMT) credit carryforwards of $126.0 million. The net change in value of $50.3 million was recorded in deferred income taxes.

Income Taxes Schedule of Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred tax liabilities
Property, plant and equipment	$ 665.1	$ 898.7
Commodity price derivatives	30.1	0.0
Deferred tax assets
Net operating loss and tax credit carryforwards	385.6	308.8
Employee benefits and compensation costs	26.1	26.4
Bonus and vacation accrual	7.1	6.2
Commodity price derivatives	0.0	29.9
Other	7.2	9.4
Total deferred tax assets	426.0	380.7
Net deferred income tax liability	269.2	518.0
Balance sheet classification
Deferred income tax liability – noncurrent	269.2	518.0
Net deferred income tax liability	$ 269.2	$ 518.0

Income Taxes Amounts and Expiration Dates of Net Operating Loss and Tax Credit Carryforwards (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2016

Operating Loss Carryforwards [Line Items]

State net operating loss and tax credit carryforwards

$ 121.4

State net operating loss valuation allowance

(82.3)

U.S. net operating loss(1)

^[1]

272.3

U.S. alternative minimum tax credit

$ (148.4)

$ 126.0

State [Member]

Operating Loss Carryforwards [Line Items]

Operating Loss Carryforwards Minimum Expiration Date

2019

Operating Loss Carryforwards Maximum Expiration Date

2038

U.S. (Federal) [Member]

Operating Loss Carryforwards [Line Items]

Operating Loss Carryforwards Minimum Expiration Date

2036

Operating Loss Carryforwards Maximum Expiration Date

2037

2019 [Member]

Operating Loss Carryforwards [Line Items]

U.S. alternative minimum tax credit

$ 74.2

[1]	Net operating losses created in tax years beginning after December 31, 2017 can be carried forward indefinitely under the Tax Legislation (limited to 80% of taxable income computed without the net operating loss deduction).

Income Taxes Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Interest Related to Uncertain Tax Positions	$ 0.7	$ 0.7	$ 0.7
Penalties Related to Uncertain Tax Positions			0.6
Balance as of January 1,	19.0	15.6
Federal benefit of state (change from 35% to 21%)	0.0	3.4
Balance as of December 31,	$ 19.0	$ 19.0	$ 15.6

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

USD ($)

MMBoe

$ / shares

Sep. 30, 2018

USD ($)

MMBoe

$ / shares

Jun. 30, 2018

USD ($)

MMBoe

$ / shares

Mar. 31, 2018

USD ($)

MMBoe

$ / shares

Dec. 31, 2017

USD ($)

MBoe

$ / shares

Sep. 30, 2017

USD ($)

MBoe

$ / shares

Jun. 30, 2017

USD ($)

MBoe

$ / shares

Mar. 31, 2017

USD ($)

MBoe

$ / shares

Dec. 31, 2018

USD ($)

MMBoe

$ / shares

Dec. 31, 2017

USD ($)

MBoe

$ / shares

Dec. 31, 2016

USD ($)

$ / shares

Quarterly Financial Information Disclosure [Line Items]

Revenues

$ 410.5

$ 560.8

$ 532.4

$ 428.9

$ 429.0

$ 390.1

$ 383.7

$ 420.1

$ 1,932.6

$ 1,622.9

$ 1,377.1

Operating income (loss)

(1,116.8)

156.8

(321.8)

21.4

(24.5)

132.1

(0.9)

(5.2)

(1,260.4)

101.5

(1,600.7)

Net income (loss)

(629.3)

7.3

(336.0)

(53.6)

150.3

(3.3)

45.4

76.9

$ (1,011.6)

$ 269.3

$ (1,245.0)

Net gain (loss) from asset sales, inclusive of restructuring costs and impairment

$ (1,158.2)

$ 27.1

$ (407.6)

$ 2.8

(42.2)

157.1

19.8

(0.1)

Nonrecurring items in operating income (loss)(1)

^[1]

$ 0.0

$ 8.2

$ 0.0

Basic | $ / shares

$ (2.66)

$ 0.03

$ (1.42)

$ (0.22)

$ 0.62

$ (0.01)

$ 0.19

$ 0.32

$ (4.25)

$ 1.12

$ (5.62)

Diluted | $ / shares

$ (2.66)

$ 0.03

$ (1.42)

$ (0.22)

$ 0.62

$ (0.01)

$ 0.19

$ 0.32

$ (4.25)

$ 1.12

$ (5.62)

Total equivalent production (Mboe)

11,627,200

14,400,000

14,106,100

11,724,600

12,069,900

14,124,100

13,860,600

13,090,300

Total [Member]

Quarterly Financial Information Disclosure [Line Items]

Revenues

$ 1,932.6

$ 1,622.9

Operating income (loss)

(1,260.4)

101.5

Net income (loss)

(1,011.6)

269.3

Net gain (loss) from asset sales, inclusive of restructuring costs and impairment

$ (1,535.9)

134.6

Nonrecurring items in operating income (loss)(1)

^[1]

$ 8.2

Basic | $ / shares

$ (4.25)

$ 1.12

Diluted | $ / shares

$ (4.25)

$ 1.12

Total equivalent production (Mboe)

51,857,900

53,144,900

[1]	Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017.

Supplemental Gas and Oil Information (Unaudited) Capitalized costs (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
Proved properties	$ 12,140.7	$ 12,470.9
Unproved properties, net	759.1	1,095.8
Total proved and unproved properties	12,899.8	13,566.7
Accumulated depreciation, depletion and amortization	(7,450.5)	(6,642.9)
Net capitalized costs	$ 5,449.3	$ 6,923.8

Supplemental Gas and Oil Information (Unaudited) Costs incurred (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract]
Accrued capital costs included in development costs	$ (59.2)
ARO additions and revisions	(0.8)
Costs incurred related to the development of proved undeveloped reserves	606.5	$ 389.3	$ 258.1
Proved property acquisitions	39.1	269.6	431.6
Unproved property acquisitions	25.8	532.4	208.7
Other acquisitions	0.8	13.2	0.0
Exploration costs (capitalized and expensed)	0.3	32.7	13.4
Development costs	1,133.1	1,189.3	509.2
Total costs incurred	$ 1,199.1	$ 2,037.2	$ 1,162.9

Supplemental Gas and Oil Information (Unaudited) Results of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Income (loss) before income taxes	$ (1,329.0)	$ (42.9)	$ (1,953.2)
Exploration and Production [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues	1,920.3	1,548.1	1,271.0
Production costs	507.3	675.4	616.7
Exploration expenses	0.3	22.0	1.7
Depreciation, depletion and amortization	836.4	735.1	852.3
Impairment	1,560.9	72.3	1,194.3
Total expenses	2,904.9	1,504.8	2,665.0
Income (loss) before income taxes	(984.6)	43.3	(1,394.0)
Income tax benefit (expense)	243.2	(16.0)	517.2
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$ (741.4)	$ 27.3	$ (876.8)

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

12 Months Ended

Dec. 31, 2018

MMBoe

Bcf

MMBbls

Dec. 31, 2017

MMBoe

Bcf

MMBbls

Dec. 31, 2016

MMBoe

Bcf

MMBbls

Oil [Member]

Reserve Quantities [Line Items]

Proved reserves balance, beginning balance

320.5

238.6

193.1

Revisions of previous estimates

2.1

^[1]

3.7

^[2]

(9.7)

^[3]

Extensions and discoveries

57.1

^[4]

59.1

^[5]

13.0

^[6]

Purchase of reserves in place

8.2

^[7]

46.6

^[8]

62.7

^[9]

Sale of reserves in place

(24.9)

^[10]

(7.9)

^[11]

(0.2)

^[12]

Production

(23.9)

(19.6)

(20.3)

Proved reserves balance, ending balance

339.1

320.5

238.6

Proved undeveloped reserves, beginning balance

204.5

135.4

83.4

Proved undeveloped reserve, ending balance

205.5

204.5

135.4

Proved developed reserves, beginning balance

116.0

103.2

109.7

Proved developed reserves, ending balance

133.6

116.0

103.2

Gas [Member]

Reserve Quantities [Line Items]

Proved reserves balance, beginning balance | Bcf

1,793.6

2,553.8

2,108.9

Revisions of previous estimates | Bcf

314.0

^[1]

12.5

^[2]

412.8

^[3]

Extensions and discoveries | Bcf

56.5

^[4]

101.9

^[5]

158.1

^[6]

Purchase of reserves in place | Bcf

7.9

^[7]

125.5

^[8]

54.6

^[9]

Sale of reserves in place | Bcf

(544.8)

^[10]

(831.2)

^[11]

(3.6)

^[12]

Production | Bcf

(139.6)

(168.9)

(177.0)

Proved reserves balance, ending balance | Bcf

1,487.6

1,793.6

2,553.8

Proved undeveloped reserves, beginning balance | Bcf

1,138.1

1,244.0

863.6

Proved undeveloped reserve, ending balance | Bcf

1,105.3

1,138.1

1,244.0

Proved developed reserves, beginning balance | Bcf

655.5

1,309.8

1,245.3

Proved developed reserves, ending balance | Bcf

382.3

655.5

1,309.8

Natural Gas Liquids [Member]

Reserve Quantities [Line Items]

Proved reserves balance, beginning balance

65.2

67.2

58.8

Revisions of previous estimates

6.7

^[1]

(3.1)

^[2]

(0.3)

^[3]

Extensions and discoveries

9.8

^[4]

10.4

^[5]

3.3

^[6]

Purchase of reserves in place

1.3

^[7]

8.7

^[8]

11.5

^[9]

Sale of reserves in place

(7.1)

^[10]

(12.6)

^[11]

(0.1)

^[12]

Production

(4.7)

(5.4)

(6.0)

Proved reserves balance, ending balance

71.2

65.2

67.2

Proved undeveloped reserves, beginning balance

37.3

31.5

24.4

Proved undeveloped reserve, ending balance

39.7

37.3

31.5

Proved developed reserves, beginning balance

27.9

35.7

34.4

Proved developed reserves, ending balance

31.5

27.9

35.7

Barrels of oil equivalent production [Member]

Reserve Quantities [Line Items]

Proved developed and undeveloped reserves, beginning balance | MMBoe

^[13]

684.7

731.4

603.4

Revisions of previous estimates | MMBoe

^[13]

61.0

^[1]

2.7

^[2]

58.8

^[3]

Extensions and discoveries | MMBoe

^[13]

76.3

^[4]

86.4

^[5]

42.6

^[6]

Purchase of reserves in place | MMBoe

^[13]

10.9

^[7]

76.3

^[8]

83.3

^[9]

Sale of reserves in place | MMBoe

^[13]

(122.8)

^[10]

(159.0)

^[11]

(0.9)

^[12]

Production | MMBoe

^[13]

(51.9)

(53.1)

(55.8)

Proved developed and undeveloped reserves, ending balance | MMBoe

^[13]

658.2

684.7

731.4

Proved undeveloped reserves, beginning balance | MMBoe

431.6

374.2

251.8

Proved undeveloped reserves, ending balance | MMBoe

429.3

431.6

374.2

Proved developed reserves, beginning balance | MMBoe

253.1

357.2

351.6

Proved developed reserves, ending balance | MMBoe

228.9

253.1

357.2

Pricing Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

17.3

32.0

(18.5)

Performance Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

8.7

2.2

5.5

Positive revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

61.0

2.7

77.3

Operating Cost Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

11.7

11.0

Development plan change [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

23.4

20.5

[1]	Revisions of previous estimates in 2018 totaling 61.0 MMboe of positive revisions include 23.4 MMboe of other revisions, primarily related to changing our development plans in the Haynesville/Cotton Valley; 17.3 MMboe of positive revisions related to pricing, primarily driven by higher oil prices; 11.7 MMboe of positive revisions related to lower operating costs; and 8.7 MMboe of positive performance revisions.
[2]	Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related to pricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by 11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontal development plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. These negative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the Williston Basin.
[3]	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.
[4]	Extensions and discoveries in 2018 primarily related to new well completions and associated new PUD locations in the Permian Basin.
[5]	Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin.
[6]	Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.
[7]	Purchase of reserves in place in 2018 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.
[8]	Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 3 – Acquisitions and Divestitures.
[9]	Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 3 – Acquisitions and Divestitures.
[10]	Sale of reserves in place in 2018 was primarily related to QEP's Uinta Basin Divestiture as discussed in Note 3 – Acquisitions and Divestitures.
[11]	Sale of reserves in place in 2018 was primarily related to QEP's Pinedale Divestiture as discussed in Note 3 – Acquisitions and Divestitures.
[12]	Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 3 – Acquisitions and Divestitures.
[13]	Generally, gas consumed in operations was excluded from reserves, however, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.

Supplemental Gas and Oil Information (Unaudited) Average price per unit (Details)	12 Months Ended
	Dec. 31, 2018 $ / bbl $ / Mcf	Dec. 31, 2017 $ / bbl $ / Mcf	Dec. 31, 2016 $ / 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	65.56	51.34	42.75
Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
12 month average first-of the month commodity price \| $ / Mcf	3.10	2.98	2.48

Supplemental Gas and Oil Information (Unaudited) Future Development Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Next Twelve Months	$ 620.1
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Two	882.0
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Three	$ 1,025.1

Supplemental Gas and Oil Information (Unaudited) Standardized Measure Of Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Federal income tax rate	21.00%	35.00%
Future cash inflows	$ 26,482.6	$ 22,028.9	$ 16,239.8
Future production costs	(9,539.9)	(9,074.2)	(7,789.0)
Future development costs	(4,441.5)	(4,726.0)	(3,432.9)
Future income tax expenses	(2,553.6)	(1,439.1)	(913.4)
Future net cash flows	9,947.6	6,789.6	4,104.5
10% annual discount for estimated timing of net cash flows	(4,991.9)	(3,692.3)	(2,176.5)
Standardized measure of discounted future net cash flows	$ 4,955.7	$ 3,097.3	$ 1,928.0	$ 2,476.3

Supplemental Gas and Oil Information (Unaudited) Change in Standardized Measure of Future Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Change in Standardized Measure of Future Cash Flows [Abstract]
Beginning Balance	$ 3,097.3	$ 1,928.0	$ 2,476.3
Sales of gas, oil and NGL produced during the period, net of production costs	(1,413.0)	(872.7)	(654.3)
Net change in sales prices and in production (lifting) costs related to future production	1,632.5	1,457.2	(739.4)
Net change due to extensions and discoveries	692.6	556.8	81.8
Net change due to revisions of quantity estimates	732.0	9.9	122.7
Changes due to purchases of reserves in place	117.0	342.7	256.5
Changes due to sales of reserves in place	(369.6)	(504.7)	(4.3)
Previously estimated development costs incurred during the period	735.6	475.4	374.6
Changes in estimated future development costs	(28.3)	(283.4)	(476.5)
Accretion of discount	375.4	235.7	311.1
Net change in income taxes	(615.7)	(227.4)	205.4
Other	(0.1)	(20.2)	(25.9)
Net change	1,858.4	1,169.3	(548.3)
Ending Balance	$ 4,955.7	$ 3,097.3	$ 1,928.0

Subsequent Event (Details) - USD ($) $ in Millions	12 Months Ended
Subsequent Event (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Subsequent Event [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 243.6	$ 806.8	$ 29.0
Escrow Deposit	32.2
Haynesville Divestiture [Member]
Subsequent Event [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	735.0
Closed Divestiture [Member] \| Haynesville Divestiture [Member]
Subsequent Event [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 605.1