0001108827-21-000012 | 10-K | XBRL Viewer

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Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2020	Jun. 30, 2020	Jan. 31, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Entity File Number	001-34778
Entity Registrant Name	QEP RESOURCES, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	87-0287750
Entity Address, Address Line One	1050 17th Street
Entity Address, Address Line Two	Suite 800
Entity Address, City or Town	Denver
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80265
City Area Code	303
Local Phone Number	672-6900
Title of 12(b) Security	Common stock, $0.01 par value
Trading Symbol	QEP
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float		$ 312,599,033
Entity Common Stock, Shares Outstanding			242,565,822
Entity Central Index Key	0001108827
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
REVENUES
Revenues	$ 724.4	$ 1,206.2	$ 1,932.6
OPERATING EXPENSES
General and administrative	93.0	155.8	221.7
Production and property taxes	57.9	95.9	130.8
Depreciation, depletion and amortization	574.0	540.0	857.1
Exploration expenses	0.2	0.1	0.3
Impairment	8.7	5.0	1,560.9
Total Operating Expenses	949.3	1,052.6	3,218.0
Net gain (loss) from asset sales, inclusive of restructuring costs	1.2	3.9	25.0
OPERATING INCOME (LOSS)	(223.7)	157.5	(1,260.4)
Realized and unrealized gains (losses) on derivative contracts (Note 6)	232.7	(173.4)	90.4
Interest and other income (expense)	9.8	4.7	(9.6)
Gain (loss) from early extinguishment of debt	18.2	(1.0)	0.0
Interest expense	(113.7)	(128.1)	(149.4)
INCOME (LOSS) BEFORE INCOME TAXES	(76.7)	(140.3)	(1,329.0)
Income tax (provision) benefit	79.9	43.0	317.4
NET INCOME (LOSS)	$ 3.2	$ (97.3)	$ (1,011.6)
Earnings (loss) per common share
Basic	$ 0.01	$ (0.41)	$ (4.25)
Diluted	$ 0.01	$ (0.41)	$ (4.25)
Weighted-average common shares outstanding
Used in basic calculation	241.6	237.7	237.9
Used in diluted calculation	241.6	237.7	237.9
Oil and Gas, Exploration and Production [Member]
REVENUES
Revenues	$ 714.6	$ 1,187.4	$ 1,871.3
Product and Service, Other [Member]
REVENUES
Revenues	2.4	7.9	12.5
Oil and Gas, Purchased [Member]
REVENUES
Revenues	7.4	10.9	48.8
OPERATING EXPENSES
Other Cost and Expense, Operating	8.7	11.0	51.0
Lease Operating Expense [Member]
OPERATING EXPENSES
Other Cost and Expense, Operating	141.6	182.9	263.1
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
OPERATING EXPENSES
Other Cost and Expense, Operating	54.4	48.7	117.6
Gathering and other expense [Member]
OPERATING EXPENSES
Other Cost and Expense, Operating	$ 10.8	$ 13.2	$ 15.5

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

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Statement of Comprehensive Income [Abstract]

Net income (loss)

$ 3.2

$ (97.3)

$ (1,011.6)

Other comprehensive income, net of tax:

Net income (loss)

3.2

(97.3)

(1,011.6)

Pension and other postretirement plans adjustments:

Current period prior service cost(1)

^[1]

0.0

(0.1)

Current period net actuarial gain (loss)(2)

^[2]

(1.8)

1.1

(4.2)

Amortization of prior service cost(3)

^[3]

0.0

(0.3)

0.4

Amortization of net actuarial (gain) loss(4)

^[4]

0.7

0.4

0.6

Net curtailment and settlement cost incurred(5)

^[5]

0.8

0.6

0.1

Other comprehensive income (loss)

(0.3)

1.8

(3.2)

Comprehensive income (loss)

$ 2.9

$ (95.5)

$ (1,014.8)

[1]	Presented net of income tax benefit of $0.1 million for the year ended December 31, 2018.
[2]	Presented net of income tax benefit of $0.5 million for the year ended December 31, 2020, net of income tax expense of $0.3 million for the year ended December 31, 2019 and net of income tax benefit of $1.3 million for the year ended December 31, 2018.
[3]	Presented net of income tax benefit of $0.1 million for the year ended December 31, 2019 and net of income tax expense of $0.1 million for the year ended December 31, 2018.
[4]	Presented net of income tax expense of $0.2 million, $0.1 million and $0.2 million for the years ended December 31, 2020, 2019 and 2018, respectively.
[5]	Presented net of income tax expense $0.2 million and $0.2 million for the years ended December 31, 2020 and 2019, respectively.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension and other postretirement plans adjustments:
Current period prior service cost, tax	$ 0.0	$ 0.0	$ 0.1
Current period net actuarial (gain) loss, tax	(0.5)	0.3	(1.3)
Amortization of prior service cost, tax	0.0	(0.1)	0.1
Amortization of net actuarial (gain) loss, tax	0.2	0.1	0.2
Net curtailment and settlement cost incurred, tax	$ 0.2	$ 0.2	$ 0.0

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 60.4	$ 166.3
Accounts receivable, net	89.1	108.4
Income tax receivable	33.2	37.4
Fair value of derivative contracts	0.0	1.5
Prepaid expenses	14.1	11.4
Other current assets	0.2	0.2
Total Current Assets	197.0	325.2
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,941.2	9,574.9
Unproved properties	454.4	599.1
Gathering and other	167.3	164.2
Materials and supplies	18.7	15.6
Total Property, Plant and Equipment	10,581.6	10,353.8
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,728.0	5,250.5
Gathering and other	70.7	61.0
Total Accumulated Depreciation, Depletion and Amortization	5,798.7	5,311.5
Net Property, Plant and Equipment	4,782.9	5,042.3
Fair value of derivative contracts	0.0	0.2
Operating lease right-of-use assets, net	48.0	56.8
Other noncurrent assets	86.3	53.3
TOTAL ASSETS	5,114.2	5,477.8
Current Liabilities
Checks outstanding in excess of cash balances	2.1	18.3
Accounts payable and accrued expenses	159.3	227.2
Production and property taxes	12.2	18.9
Interest payable	21.5	31.0
Fair value of derivative contracts	76.4	18.7
Current operating lease liabilities	21.7	18.0
Asset retirement obligations	6.4	6.0
Total Current Liabilities	299.6	338.1
Long-term debt	1,591.3	2,015.6
Deferred income taxes	385.2	274.5
Asset retirement obligations	96.3	94.9
Fair value of derivative contracts	0.3	0.5
Operating lease liabilities	31.3	44.8
Other long-term liabilities	40.0	48.8
Commitments and Contingencies (Note 10)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 248.0 million and 242.1 million shares issued, respectively	2.5	2.4
Treasury stock - 5.4 million and 4.4 million shares, respectively	(57.6)	(55.4)
Additional paid-in capital	1,470.1	1,456.5
Retained earnings	1,268.0	1,269.6
Accumulated other comprehensive income (loss)	(12.8)	(12.5)
Total Common Shareholders' Equity	2,670.2	2,660.6
TOTAL LIABILITIES AND EQUITY	$ 5,114.2	$ 5,477.8

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares shares in Millions	Dec. 31, 2020	Dec. 31, 2019
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)	248.0	242.1
Treasury stock (in shares)	5.4	4.4

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]
Balance at Dec. 31, 2017	$ 3,797.9	$ 2.4	$ (34.2)	$ 1,398.2	$ 2,442.6	$ (11.1)
Shares at Dec. 31, 2017		243.0
Treasury shares at Dec. 31, 2017			(2.0)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,011.6)				(1,011.6)
Reclassification related to ASU 2018-02					3.8	(3.8)
Common stock repurchased and retired, Shares		(6.2)
Common stock repurchased and retired, Value	(58.4)	$ (0.1)			(58.3)
Share-based compensation, shares		3.0
Share-based compensation, treasury stock shares			(1.1)
Share-based compensation	22.4	$ 0.1	$ (11.4)	33.7	0.0	0.0
Change in pension and postretirement liability, net of tax	0.6					0.6
Balance at Dec. 31, 2018	2,750.9	$ 2.4	$ (45.6)	1,431.9	1,376.5	(14.3)
Shares at Dec. 31, 2018		239.8
Treasury shares at Dec. 31, 2018			(3.1)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(97.3)				(97.3)
Cash dividends declared, $0.02 per share	(9.6)				(9.6)
Share-based compensation, shares		2.3
Share-based compensation, treasury stock shares			(1.3)
Share-based compensation	14.8	$ 0.0	$ (9.8)	24.6	0.0	0.0
Change in pension and postretirement liability, net of tax	1.8					1.8
Balance at Dec. 31, 2019	$ 2,660.6	$ 2.4	$ (55.4)	1,456.5	1,269.6	(12.5)
Shares at Dec. 31, 2019		242.1
Treasury shares at Dec. 31, 2019	(4.4)		(4.4)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 3.2				3.2
Cash dividends declared, $0.02 per share	(4.8)				(4.8)
Share-based compensation, shares		5.9
Share-based compensation, treasury stock shares			(1.0)
Share-based compensation	11.5	$ 0.1	$ (2.2)	13.6	0.0	0.0
Change in pension and postretirement liability, net of tax	(0.3)					(0.3)
Balance at Dec. 31, 2020	$ 2,670.2	$ 2.5	$ (57.6)	$ 1,470.1	$ 1,268.0	$ (12.8)
Shares at Dec. 31, 2020		248.0
Treasury shares at Dec. 31, 2020	(5.4)		(5.4)

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
OPERATING ACTIVITIES
Net income (loss)	$ 3.2	$ (97.3)	$ (1,011.6)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	574.0	540.0	857.1
Deferred income taxes (benefit)	110.6	4.3	(247.6)
Impairment	8.7	5.0	1,560.9
Non-cash share-based compensation	12.4	20.8	30.9
Amortization of debt issuance costs and discounts	4.7	5.4	5.4
Net (gain) loss from asset sales, inclusive of restructuring costs	(1.2)	(3.9)	(25.0)
(Gain) loss from early extinguishment of debt	(18.2)	1.0	0.0
Unrealized (gains) losses on marketable securities	(3.2)	(3.9)	1.2
Unrealized (gains) losses on derivative contracts	59.2	138.3	(248.5)
Accounts receivable	19.2	(4.1)	33.7
Prepaid expenses	(2.9)	(0.4)	(2.0)
Accounts payable and accrued expenses	(42.4)	(40.4)	(74.2)
Income taxes receivable	4.2	38.4	(71.0)
Other	(55.1)	(36.3)	6.9
Net Cash Provided by (Used in) Operating Activities	673.2	566.9	816.2
INVESTING ACTIVITIES
Property acquisitions	(4.1)	(3.5)	(65.6)
Expenditures for property, plant and equipment	(353.5)	(562.7)	(1,234.1)
Proceeds from disposition of assets	13.8	678.9	243.6
Net Cash Provided by (Used in) Investing Activities	(343.8)	112.7	(1,056.1)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(16.1)	3.7	(29.5)
Long-term debt issuance costs paid	(0.6)	0.0	(0.1)
Long-term debt extinguishment costs paid	0.0	(1.0)	0.0
Repurchases and redemptions of senior notes	(410.3)	(66.9)	0.0
Proceeds from credit facility	37.0	56.1	3,608.0
Repayments of credit facility	(37.0)	(486.0)	(3,267.0)
Common stock repurchased and retired	0.0	0.0	(58.4)
Treasury stock repurchases	(1.7)	(7.6)	(8.7)
Dividends paid	(4.8)	(9.6)	0.0
Other capital contributions	0.0	0.0	0.3
Net Cash Provided by (Used in) Financing Activities	(433.5)	(511.3)	244.6
Change in cash, cash equivalents and restricted cash(1)	(104.1)	168.3	4.7
Beginning cash, cash equivalents and restricted cash(1)	196.4	28.1	23.4
Ending cash, cash equivalents and restricted cash(1)	$ 92.3	$ 196.4	$ 28.1

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

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). 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 (financial statements) contain the accounts of QEP and its majority-owned or controlled subsidiaries. The financial statements were prepared in accordance with GAAP and with the instructions for annual reports on Form 10-K and Regulation S-X. All intercompany accounts and transactions have been eliminated in consolidation.

All dollar and share amounts in these financial statements are in millions, except per share information and where otherwise noted.

Merger

On December 20, 2020, the Company entered into an Agreement and Plan of Merger (Merger Agreement) with Diamondback Energy, Inc. (Diamondback) and Bohemia Merger Sub, Inc., a wholly owned subsidiary of Diamondback (Merger Sub), which provides that, among other things, and subject to the terms and conditions of the Merger Agreement, Merger Sub will be merged with and into QEP, with QEP surviving as a direct, wholly owned subsidiary of Diamondback (Merger). Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of the Company (other than any Excluded Shares, any Converted Shares and Company Restricted Stock Awards (each as defined in the Merger Agreement)) will be converted into the right to receive 0.05 shares, par value $0.01 per share, of common stock of Diamondback (Merger Consideration). The Merger Agreement provides that, among other things, during the period from the date of the Merger Agreement until the effective time of the Merger, the Company and its subsidiaries are not permitted to declare, set aside or pay any dividends on any shares of capital stock of the Company or its subsidiaries. The Merger Agreement also addresses the treatment of QEP equity awards in the Merger. Diamondback’s common stock is listed and traded on the NASDAQ Global Select Market under the symbol "FANG". The transaction was unanimously approved by the Boards of Directors of both companies. The Merger is expected to close late in the first quarter of 2021, and is subject to the approval of the Company's stockholders and other customary closing conditions. During the year ended December 31, 2020, the Company incurred $4.5 million of merger costs recognized in "General and administrative" expense on the Consolidated Statements of Operations (statements of operations) and $5.0 million of additional merger costs recognized in "Prepaid expenses" on the Consolidated Balance Sheets (balance sheets) as of December 31, 2020.

Business Segments

QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that the Company's two operating segments (Permian Basin and Williston Basin) should be aggregated into one reportable segment.

Use of Estimates

The preparation of the 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 significant estimates and assumptions include income taxes and impairment. 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. The novel coronavirus disease (COVID-19) pandemic and related shut-down of various sectors of the global economy resulted in a significant reduction in global demand for crude oil in 2020. Changes in market supply and demand are also impacted by Organization of Petroleum Exporting Countries (OPEC) production levels, weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. Field-level prices received for QEP's oil and gas production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future oil and condensate production. Refer to Note 6 – Derivative Contracts for the Company's open oil commodity derivative contracts.

Revenue Recognition

QEP recognizes revenue from the sale 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 QEP has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sale 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 indices 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 and condensate is typically sold at specific delivery points under contract terms that are common in the industry. QEP's gas and NGL are also sold under contract types that are common in the 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 QEP 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 fulfill volume commitments when production does not fulfill contractual commitments and to capture additional margin from subsequent sales of third party purchases. QEP recognizes revenue from these resale activities in the period that the performance obligations are satisfied.

For product sales that have a contract term greater than one year, the Company follows ASC 606-10-50-14(a), which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each monthly product delivery generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

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 balance sheets to the amounts shown in the statements of cash flows:


	December 31,
	2020		2019
	(in millions)
Cash and cash equivalents	$	60.4	$	166.3
Restricted cash(1)	31.9		30.1
Total cash, cash equivalents and restricted cash shown in the Consolidated Statements of Cash Flows	$	92.3	$	196.4

_______________________

(1)As of December 31, 2020 and 2019, the restricted cash balance primarily 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 balance sheets.

Supplemental cash flow information is shown in the table below:


	Year Ended December 31,
	2020		2019		2018
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	118.4	$	126.9	$	136.9
Cash paid (refund received) for income taxes, net	$	(164.0)	$	(66.7)	$	0.8
Cash paid for amounts included in the measurement of lease liabilities	$	25.7	$	25.3	$	—
Other Non-cash Activities:
Right-of-use assets obtained in exchange for operating lease obligations	$	11.0	$	16.6	$	—
Non-cash Investing Activities:
Capital expenditure accruals as of December 31,	$	37.8	$	63.3	$	54.5

Accounts Receivable

Accounts receivable consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. The sale of oil, gas and NGLs exposes the Company to credit losses. The Company's expected loss allowance methodology for accounts receivable is developed using historical collection experience, current and future economic and market conditions and a review of the current status of customers' trade accounts receivables. 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 credit losses 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 recovery associated with accounts receivable for the year ended December 31, 2020 was $0.3 million, and bad debt expense for the years ended December 31, 2019 and 2018 was $0.3 million, and $0.6 million, respectively. Bad debt expense or recovery is included in "General and administrative" expense on the Consolidated Statements of Operations (statements of operations). The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. As of December 31, 2020 and 2019, the allowance for cumulative expected credit losses was $1.7 million and $1.6 million, respectively.

Property, Plant and Equipment

Property, plant and equipment balances are stated at historical cost. 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 accumulated impairment 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 upon initial recognition.

DD&A for the Company's remaining property, plant and equipment 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 impairment. Other property, plant, and equipment are evaluated on a specific asset basis or in groups of similar assets, as applicable. When an indicator of impairment, or a "triggering event," is identified, the Company uses a cash flow model to assess its proved properties and operating lease right-of-use assets for impairment. 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, merger transactions and declines in oil, gas and NGL prices. When a triggering event is identified, the undiscounted future net cash flows of an evaluated asset are compared to the asset's carrying value. Cash flow estimates require forecasts and significant estimates and assumptions for many years into the future for a variety of factors, including estimates of future production, future oil and gas prices, future operating costs, future development costs and our five-year development plan. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors. If the asset's carrying value exceeds the related undiscounted net cash flows, fair value of the evaluated asset is estimated using a discounted cash flow approach. The signing of a merger or purchase and sale agreement could also cause the Company to evaluate for, or recognize, an impairment of proved properties. For assets subject to a merger or purchase and sale agreement, the evaluation of terms of the merger or 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 in which the likelihood of possible outcomes is taken into consideration.

As of March 31, 2020, December 31, 2020 and December 31, 2019, the Company performed an assessment of recoverability and determined that the carrying value of proved properties was less than the respective undiscounted future cash flows, and therefore recorded no impairment. In the evaluation of recoverability as of December 31, 2020, the Company considered the estimated future pricing used by management in evaluating and entering into the Merger Agreement.

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, 2020, QEP recorded unproved property impairment charges of $8.7 million related to anticipated leasehold expirations.

During the year ended December 31, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.

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.

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. The ARO liability is recorded at estimated fair value upon initial recognition, 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 4 – Asset Retirement Obligations for more information.

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 financial statements. The amount of ultimate loss may differ from these estimates. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Refer to Note 10 – Commitments and Contingencies for more information.

QEP accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as 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, basis swaps, costless collars and calendar month average (CMA) rolls 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 statements of operations in the month of settlement and are also marked-to-market monthly. Refer to Note 6 – 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. Reserves for expected credit losses are periodically reviewed for adequacy. 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, among other things, 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 63%, 66%, and 49% of QEP's revenues for the years ended December 31, 2020, 2019 and 2018, respectively. The following table presents the percentages by customer that accounted for 10% or more of QEP's total revenues.


Year Ended December 31, 2020
Valero Marketing & Supply Company	30	%
Phillips 66 Company	12	%

Year Ended December 31, 2019
Occidental Energy Marketing	21	%
Valero Marketing & Supply Company	18	%
Plains Marketing LP	17	%

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

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, or recognizes a valuation allowance against deferred tax assets in cases where we do not forecast sufficient future income to recognize the deferred tax asset. All federal income tax returns prior to 2019 have been examined by the Internal Revenue Service and are closed or have been pre-reviewed before filing. The federal income tax return for 2019 remains subject to examination and the 2020 return has not yet been filed. Most state tax returns for 2017 and subsequent years remain subject to examination. Should the Company utilize any of its state loss carryforwards, their carryforward losses would be 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.

Tax legislation enacted in December 2017 (Tax Cuts and Jobs Act) changed several aspects of corporate taxation, including reducing our federal corporate statutory tax from 35% to 21%, limiting the amount of interest the Company could potentially deduct and eliminating the corporate Alternative Minimum Tax (AMT). The elimination of the corporate AMT allowed the Company to claim refunds for AMT credits carried forward from prior tax years. The Coronavirus Aid, Relief, and Economic Security Act (CARES Act) enacted in March 2020 permitted the Company to carry back its net operating loss (NOL) generated in 2018 and 2019, creating additional AMT credits, and to accelerate all of its AMT refunds. Guidance issued by the relevant regulatory authorities regarding tax legislation may materially impact QEP's financial statements. As additional guidance to the Tax Cuts and Jobs Act and the CARES Act 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 statements of operations.

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 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 and Long-Term 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.

The Company's unvested restricted share awards, once granted, are considered issued and outstanding, the historical forfeiture rate is minimal, are eligible to receive dividends, and do not have a contractual obligation to share in losses of the Company. Accordingly, restricted share awards are considered participating securities. 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 year ended December 31, 2020, there were no anti-dilutive shares. For the years ended December 31, 2019 and 2018, the Company was in a loss position, therefore, all potentially dilutive securities were anti-dilutive.

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


	December 31,
	2020	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	241.6	237.7	237.9
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	241.6	237.7	237.9

Share-Based and Long-Term Compensation

QEP issues restricted share awards, restricted cash awards and restricted share units to certain officers, employees and non-employee directors under its 2018 LTIP. QEP historically issued stock options. QEP used 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 grant. Restricted cash award grants vest in equal installments over three years from the grant date. Share-based compensation cost for restricted cash awards is equal to its fair value as of the end of the period and is classified as a liability. The Company also issues performance share unit awards under its Cash Incentive Plan 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 and Long-Term 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 balance sheets and the amount of benefit expense recorded to the 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 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 June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-13, Financial Instruments - Credit Losses (Topic 326) - Measurement of credit losses on financial instruments, which requires a company to consider forward-looking information to determine current estimated credit losses (CECL), for all financial instruments that are not accounted for at fair value through net income. Previously, credit losses on financial assets were only required to be recognized when they were incurred. The Company adopted ASU 2016-13 on January 1, 2020. The guidance did not have a significant impact on the financial statements or notes accompanying the 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 Company adopted ASU 2018-13 on January 1, 2020. The guidance did not have a significant impact on the financial statements or notes accompanying the financial statements.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform, which provides temporary optional guidance to companies impacted by the transition away from the London Interbank Offered Rate (LIBOR). The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the burden when contracts, hedging relationships and other transactions that reference LIBOR as a benchmark are modified. This amendment is effective upon issuance and expires on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition and this ASU on the Company's financial statements.

In October 2020, the FASB issued ASU No. 2020-10, Codification Improvements, which amends and clarifies various Topics within the Codification in order to improve clarity and consistency. The amendment will be effective for periods beginning after December 15, 2020, and early adoption is permitted. The Company is currently assessing the impact of this ASU on the Company's financial statements.

Revenue (Notes)

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

Revenue Recognition

QEP recognizes revenue in accordance with ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). Refer to Note 1 – Summary of Significant Accounting Policies for more information regarding revenue recognition.

The following tables present QEP's revenues that are disaggregated by revenue source and by geographic area.


	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue		Oil and condensate, gas and NGL sales
	(in millions)
	Year Ended December 31, 2020
Northern Region
Williston Basin	$	249.9	$	18.1	$	14.4	$	(37.8)	$	244.6
Other Northern	0.2		1.1		—		—		1.3
Southern Region
Permian Basin	441.7		20.4		31.3		(24.7)		468.7
Other Southern	—		—		—		—		—
Total oil and condensate, gas and NGL sales	$	691.8	$	39.6	$	45.7	$	(62.5)	$	714.6

	Year Ended December 31, 2019
Northern Region
Williston Basin	$	420.8	$	33.1	$	19.4	$	(34.4)	$	438.9
Other Northern	1.1		0.4		0.1		—		1.6
Southern Region
Permian Basin	710.6		12.8		37.8		(20.5)		740.7
Other Southern(1)	0.1		6.1		—		—		6.2
Total oil and condensate, gas and NGL sales	$	1,132.6	$	52.4	$	57.3	$	(54.9)	$	1,187.4

	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	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

_______________________

(1)For the year ended December 31, 2019, $5.9 million of revenues associated with Haynesville/Cotton Valley have been included in Other Southern.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

+ Details

Acquisitions and Divestitures (Notes)	12 Months Ended
Acquisitions and Divestitures (Notes)	Dec. 31, 2020
Discontinued Operations and Disposal Groups [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	Acquisitions During the years ended December 31, 2020, 2019 and 2018, QEP acquired various oil and gas properties, which primarily included proved leasehold acreage in the Permian Basin for an aggregate purchase price of $4.1 million, $3.5 million and $65.6 million, respectively, subject to post-closing purchase price adjustments. Divestitures In February 2018, QEP's Board of Directors (Board) unanimously approved certain strategic and financial initiatives including plans to market its assets in the Williston Basin, Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. The Company subsequently sold its Uinta Basin assets in September 2018 and sold its Haynesville/Cotton Valley assets in January 2019. In addition, the Company entered into a purchase and sale agreement for its Williston Basin assets in November 2018. However, in February 2019, the Company agreed with the buyer to terminate the purchase and sale agreement (Terminated Williston Basin Divestiture). 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 their 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 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. In January 2019, QEP closed the Haynesville Divestiture and during the year ended December 31, 2019 reached final settlement on asserted title defects and received net cash proceeds of $633.9 million. During the years ended December 31, 2019 and 2018, QEP recorded a pre-tax loss, including restructuring costs, of $1.0 million and $3.0 million, respectively, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations. During the year ended December 31, 2019, QEP accounted for revenues and expenses related to Haynesville/Cotton Valley, including the pre-tax loss on sale of $1.0 million as income from continuing operations on the statements of operations because the Haynesville Divestiture did not cause a strategic shift for the Company and therefore did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. During the year ended December 31, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley assets, prior to divestiture, of $3.2 million which includes the pre-tax loss on sale of $1.0 million. During the year ended December 31, 2018, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley assets of $76.0 million. In addition, QEP recorded $1.4 million and $3.0 million of restructuring costs related to this divestiture during the years ended December 31, 2019 and 2018, respectively, included in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations. Refer to Note 8 – Restructuring for more information. Terminated 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. The purchase price was 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 were met. The transaction was subject to certain conditions, including, but not limited to, approval of buyer's shareholders and regulatory approvals. As a result of signing the purchase and sale agreement, the Company recorded impairments of proved and unproved properties of $1,560.9 million. In February 2019, the Company agreed with the buyer to terminate the purchase and sale agreement (Terminated Williston Basin Divestiture). As a part of our strategic initiatives, QEP has incurred costs associated with contractual termination benefits, including severance, accelerated vesting of share-based compensation and other expenses. Refer to Note 8 – Restructuring for more information. Uinta Basin Divestiture In September 2018, QEP sold 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, (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 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. For the year ended December 31, 2019, QEP recorded a pre-tax loss of $0.2 million, due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs". Refer to Note 1 – Summary of Significant Accounting Policies and Note 8 – Restructuring for more information. Other Divestitures During the year ended December 31, 2020, QEP received net cash proceeds of $13.8 million and recorded a net pre-tax gain on sale of $1.2 million primarily related to the divestiture of properties outside our main operating areas. In addition to the Haynesville and Uinta Basin divestitures, during the year ended December 31, 2019, QEP received net cash proceeds of $45.1 million and recorded a net pre-tax gain on sale of $5.1 million related to the divestiture of properties outside our main operating areas. 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 pre-tax gain on sale of $38.5 million, primarily related to the divestiture of properties outside our main operating areas. These gains and losses are reported on the statements of operations within "Net gain (loss) from asset sales, inclusive of restructuring costs".

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2020

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 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,
	2020		2019
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.4	$	6.0
Long-term:
Asset retirement obligations	96.3		94.9

Total ARO Liability	$	102.7	$	100.9

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


	Asset Retirement Obligations
	2020		2019
	(in millions)
ARO liability at January 1,	$	100.9	$	159.6
Accretion	4.0		5.2
Additions	1.2		1.1
Revisions	—		(2.2)
Liabilities related to assets sold(1)	(1.4)		(60.7)
Liabilities settled	(2.0)		(2.1)
ARO liability at December 31,	$	102.7	$	100.9

___________________________

(1)Liabilities related to assets sold for the year ended December 31, 2019, includes $57.6 million related to the Haynesville Divestiture. Refer to Note 3 – Acquisitions and Divestitures for more information.

Fair Value Measurements

12 Months Ended

Dec. 31, 2020

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 maximizes its use of observable inputs and minimizes its use of unobservable inputs. 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.

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 6 – Derivative Contracts for more information) is based on market prices posted for the respective commodity on the last trading day of the reporting period and industry standard discounted cash flow models. 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.

QEP offers a nonqualified, unfunded deferred compensation wrap plan (Wrap Plan) to certain individuals. The Company established a trust (Rabbi Trust) to hold the investments associated with the Wrap Plan (other than phantom QEP shares) and to pay Wrap Plan obligations as they arise. QEP has determined that the marketable securities held by the Rabbi Trust and the Wrap Plan obligations are Level 1. The fair value of the marketable securities in the Rabbi Trust is based on actively traded mutual funds. The Wrap Plan obligations, which represent the underlying liabilities to the participants in the Wrap Plan, are recorded at amounts due to participants, based on the fair value of the participants' selected investments, including both actively traded funds and phantom QEP shares. Refer to Note 12 – Employee Benefits for additional information.

The fair value of financial assets and liabilities at December 31, 2020 and 2019, 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
	(in millions)
	December 31, 2020
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	1.4	$	—	$	(1.4)	$	—
Fair value of derivative contracts – long-term	—		—		—		—		—
Fair value of Rabbi Trust marketable securities	23.4		—		—		—		23.4
Total financial assets	$	23.4	$	1.4	$	—	$	(1.4)	$	23.4

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	77.8	$	—	$	(1.4)	$	76.4
Fair value of derivative contracts – long-term	—		0.3		—		—		0.3
Fair value of Wrap Plan obligations	25.5		—		—		—		25.5
Total financial liabilities	$	25.5	$	78.1	$	—	$	(1.4)	$	102.2

	December 31, 2019
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	1.5	$	—	$	—	$	1.5
Fair value of derivative contracts – long-term	—		0.2		—		—		0.2
Fair value of Rabbi Trust marketable securities	23.1		—		—		—		23.1
Total financial assets	$	23.1	$	1.7	$	—	$	—	$	24.8

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	18.7	$	—	$	—	$	18.7
Fair value of derivative contracts – long-term	—		0.5		—		—		0.5
Fair value of Wrap Plan obligations	26.8		—		—		—		26.8
Total financial liabilities	$	26.8	$	19.2	$	—	$	—	$	46.0

____________________________

(1)The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the balance sheets for the contracts that contain netting provisions. Refer to Note 6 – Derivative Contracts for more information regarding the Company's derivative contracts.

The following table discloses the fair value and related carrying amount of long-term debt not disclosed in other Notes to the Consolidated Financial Statements:


	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2020				December 31, 2019
Financial Liabilities	(in millions)
Long-term debt	$	1,591.3	$	1,702.8	$	2,015.6	$	2,029.4

The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable 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. At times when the Company has outstanding debt under the credit facility, the carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt is set for periods of one month or less.

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 4 – 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 reviews its proved oil and gas properties and operating lease ROU assets for potential impairment when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. If the asset's carrying value exceeds the related undiscounted future net cash flows, 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 merger or purchase and sale agreements could also trigger an impairment of proved properties. For assets subject to a merger or purchase and sale agreement, the evaluation of terms of the merger or 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 Terminated 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 year ended December 31, 2019, the Company recorded impairments of $5.0 million related to an office building lease. During the year ended December 31, 2018, the Company recorded impairments on certain proved oil and gas properties of $1,524.6 million 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.

- 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, 2020

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. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated oil and gas production for the next 12 to 24 months. 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 or costless collars based at Cushing, Oklahoma. Gas price derivative instruments are typically structured as fixed-price swaps or costless collars at NYMEX HH or regional price indices. QEP 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 also enters into calendar month average (CMA) rolls in order to reduce pricing volatility between the trade month and the physical delivery month for a portion of its oil 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, 2020:


Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2021 (January - June)	NYMEX WTI	7.3	$	44.54
2021 (July - December)	NYMEX WTI	6.3	$	42.64
2022 (January - June)	NYMEX WTI	0.2	$	45.00
Gas Sales		(MMbtu)	($/MMbtu)
2021	IF Waha	18.3	$	1.92
2021	NYMEX HH	9.1	$	2.44

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. QEP uses CMA rolls, combined with NYMEX CMA or NYMEX WTI fixed price swaps, to reduce the volatility in oil pricing between the trade month and the physical delivery month. The following table presents details of QEP's oil basis swaps as of December 31, 2020:


Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2021	NYMEX WTI	Argus WTI Midland	5.8	$	0.88
2021	NYMEX CMA	Argus WTI	1.5	$	0.00
2021	NYMEX WTI	NYMEX Roll	1.8	$	(0.05)

The following table presents QEP's volumes and average prices for its commodity derivative costless oil collars as of December 31, 2020:


Year	Index	Total Volumes	Average Price Floor		Average Price Ceiling
		(in millions)
		(bbls)	($/bbl)		($/bbl)
2021 (January - June)	NYMEX WTI	0.3	$	40.73	$	50.17
2021 (July - December)	NYMEX WTI	0.8	$	40.16	$	49.89

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


Derivative contracts	Year Ended December 31,
	2020		2019		2018
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	296.4	$	(32.2)	$	(153.4)
Gas derivative contracts	(4.5)		(2.9)		(5.0)
Gas Storage
Gas derivative contracts	—		—		0.3
Realized gains (losses) on commodity derivative contracts	291.9		(35.1)		(158.1)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(48.7)		(139.8)		277.0
Gas derivative contracts	(10.5)		(0.3)		(22.3)
Gas Storage
Gas derivative contracts	—		—		(0.3)
Unrealized gains (losses) on commodity derivative contracts	(59.2)		(140.1)		254.4
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	232.7	$	(175.2)	$	96.3

Derivatives associated with divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	—	$	—	$	(2.7)
Gas derivative contracts	—		1.8		—
NGL derivative contracts	—		—		(3.2)
Unrealized gains (losses) on commodity derivative contracts related to divestitures(1)(2)	$	—	$	1.8	$	(5.9)

Total realized and unrealized gains (losses) on commodity derivative contracts	$	232.7	$	(173.4)	$	90.4

_______________________

(1)During the year ended December 31, 2019, the unrealized gains (losses) on commodity derivative contracts related to the Haynesville Divestiture are comprised of derivatives included as part of the Haynesville/Cotton Valley purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in January 2019. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Haynesville Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations.

(2)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 statements of operations.

Leases

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Leases of Lessee Disclosure [Text Block]

Adoption of ASC Topic 842, Leases

On January 1, 2019 QEP adopted ASC Topic 842, Leases, using the modified retrospective approach, which was applied to historical leases that were still effective as of January 1, 2019. Results for the reporting periods beginning with January 1, 2019, are presented in accordance with ASC Topic 842, while prior period amounts are reported in accordance with historical accounting treatment under ASC Topic 840, Leases.

In accordance with the adoption of ASC Topic 842, Leases, QEP now records a net operating lease ROU asset and operating lease liability on the balance sheets for all operating leases with a contract term in excess of 12 months. Prior to the adoption of ASC Topic 842, these same leases were treated as operating leases under Topic ASC 840 and therefore were not recorded on the December 31, 2018 balance sheet. There was no impact to retained earnings and no significant impact on the statements of operations or statements of cash flows as a result of adopting ASC Topic 842.

Lease Recognition

QEP enters into contractual lease arrangements to rent office space, compressors, generators, drilling rigs and other equipment from third-party lessors. ROU assets represent QEP’s right to use an underlying asset for the lease term and lease liabilities represent QEP’s obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on the balance sheets. The Company recognizes lease expense for these short-term leases on a straight-line basis over the lease term. With the exception of generators, QEP does not account for lease components separately from the non-lease components. The contractual consideration provided under QEP's leased generators is allocated between lease components, such as equipment, and non-lease components, such as maintenance service fees, based on estimated costs from the vendor. QEP uses the implicit interest rate when readily determinable. However, most of QEP's lease agreements do not provide an implicit interest rate. As such, QEP uses its incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for QEP's risk. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. Certain of QEP's leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that QEP will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

QEP determines if an arrangement is a lease at inception of the contract and records the resulting operating lease asset on the balance sheets as “Operating lease right-of-use assets, net” with offsetting liabilities recorded as “Current operating lease liabilities” and “Operating lease liabilities.” QEP recognizes a lease in the financial statements when the arrangement either explicitly or implicitly involves property, plant, or equipment (PP&E), the contract terms are dependent on the use of the PP&E, and QEP has the ability or right to operate the PP&E or to direct others to operate the PP&E and receive the majority of the economic benefits of the assets. As of December 31, 2020 and 2019, QEP does not have any financing leases.

Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows:


	As of December 31,
	2020		2019
	(in millions)
Lease Cost included in the Consolidated Balance Sheets
Property, Plant and Equipment additions(1)	$	11.7	$	13.8

	Year Ended December 31,
	2020		2019
	(in millions)
Lease Cost included in the Consolidated Statement of Operations
Lease operating expense(2)	$	14.0	$	11.9
Gathering and other expense(2)	5.7		7.7
General and administrative(2)	6.0		5.7

Total lease cost	$	25.7	$	25.3

____________________________

(1)Represents short-term lease capital expenditures related to drilling rigs for the years ended December 31, 2020 and 2019. These costs are capitalized as a part of "Proved properties" on the balance sheets.

(2)Amounts for the year ended December 31, 2018 are not presented as 2018 amounts have not been adjusted under the modified retrospective method for ASC Topic 842 - Leases, which the Company adopted in 2019. During the year ended December 31, 2018, $30.3 million of expense from operating leases was reported in accordance with historical accounting treatment under ASC Topic 840, Leases.

Lease term and discount rate related to the Company's leases are as follows:


	As of December 31,
	2020		2019
Weighted-average remaining lease term (years)	3.6		5.4
Weighted-average discount rate	7.2	%	8.0	%

As of December 31, 2020, the maturity analysis for long-term operating leases under the scope of ASC 842 is as follows:


Year	December 31, 2020
	(in millions)
2021	$	24.9
2022	17.2
2023	11.5
2024	2.4
2025	0.8
After 2025	2.9
Less: Interest(1)	(6.7)
Present Value of Lease Liabilities(2)	$	53.0

____________________________

(1)Calculated using the estimated or stated interest rate for each lease.

(2)Of the total present value of lease liabilities, $21.7 million was recorded in "Current operating lease liabilities" and $31.3 million was recorded in "Operating lease liabilities" on the balance sheets as of December 31, 2020.

Restructuring Costs

12 Months Ended

Dec. 31, 2020

Restructuring and Related Activities [Abstract]

Restructuring Costs

In February 2018, QEP's Board approved certain strategic and financial initiatives. In February 2019, QEP's Board commenced a comprehensive review of strategic alternatives to maximize shareholder value. In connection with these activities, QEP has incurred various restructuring costs associated with contractual termination benefits including severance, accelerated vesting of share-based compensation and other expenses. The termination benefits have been accounted for under ASC 712, Compensation – Nonretirement Postemployment Benefits and ASC 718, Compensation – Stock Compensation.

Restructuring costs recognized are summarized below:


	Year Ended December 31, 2020
	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	$	1.0	$	1.0	$	—	$	—
Accelerated share-based compensation	0.5		0.5		—		—
Retention expense (including share-based compensation)	0.4		0.4		—		—
Total restructuring costs	$	1.9	$	1.9	$	—	$	—


	Year Ended December 31, 2019
	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	$	12.3	$	12.2	$	0.1	$	—
Office lease termination costs	0.6		0.6		—		—
Accelerated share-based compensation	12.6		11.1		1.5		—
Retention expense (including share-based compensation)	19.5		19.5		—		—
Pension and Medical Plan curtailment	1.2		—		(0.2)		1.4
Total restructuring costs	$	46.2	$	43.4	$	1.4	$	1.4


	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	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


	Costs recognized from inception through December 31, 2020 (1)		Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	45.6	$	—
Office lease termination costs	1.6		—
Accelerated share-based compensation	24.1		—
Retention expense (including share-based compensation)	38.7		—
Pension and Medical Plan curtailment	1.3		—
Total restructuring costs	$	111.3	$	—

____________________________

(1)Represents costs incurred since February 2018 when QEP's Board approved certain strategic and financial initiatives.

The following table is a reconciliation of QEP's restructuring liability, which is included within "Accounts payable and accrued expenses" on the 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, 2019	$	1.2	$	—	$	—	$	6.5	$	—	$	7.7
Costs incurred and charged to expense	1.0		—		0.5		0.4		—		1.9
Costs paid or otherwise settled	(2.2)		—		(0.5)		(6.9)		—		(9.6)
Balance at December 31, 2020	$	—	$	—	$	—	$	—	$	—	$	—

Debt

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt

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


	December 31,
	2020		2019
	(in millions)
Revolving Credit Facility due 2022	$	—	$	—
6.875% Senior Notes due 2021	—		382.4
5.375% Senior Notes due 2022	465.1		500.0
5.25% Senior Notes due 2023	636.8		650.0
5.625% Senior Notes due 2026	500.0		500.0
Less: unamortized discount and unamortized debt issuance costs	(10.6)		(16.8)
Total long-term debt outstanding	$	1,591.3	$	2,015.6

Of the total debt outstanding on December 31, 2020, 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

In June 2020, QEP entered into the Eighth Amendment to its credit agreement, which, among other things, reduced the aggregate principal amount of commitments to $850.0 million, requires the Company's material subsidiaries to guarantee the obligations under the credit agreement, including certain swap obligations, and modified the leverage ratio and present value financial covenants, such that they only pertain to net priority guaranteed debt (primarily consisting of borrowings under the credit facility and letters of credit). The amended credit agreement also provides the ability to use up to $500.0 million of loan proceeds to repurchase outstanding senior notes, provides the ability to issue subsidiary guarantees of up to $500.0 million of unsecured debt, with such guarantees being subordinated to the obligations under the credit agreement, and may limit the Company’s ability to make certain restricted payments, including dividends. The amended credit agreement, which matures on September 1, 2022, provides for borrowings at short-term interest rates and contains customary covenants and restrictions and 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 minimum liquidity amount of at least $100.0 million, (ii) a net priority guaranteed leverage ratio under which net priority guaranteed debt may not exceed 2.50 times consolidated EBITDAX (as defined in the credit agreement), and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net priority guaranteed debt by at least 1.50 times. At December 31, 2020 and 2019, QEP was in compliance with the covenants under the credit agreement. During the year ended December 31, 2020, the Company recorded a $1.5 million loss associated with the write-off of non-cash deferred financing costs as part of amending the credit facility and recorded the loss within "Gain (loss) from early extinguishment of debt" on the statements of operations.

During the years ended December 31, 2020 and 2019, QEP's weighted-average interest rates on borrowings from its credit facility were 2.60% and 4.73%, respectively. As of December 31, 2020, QEP had no borrowings outstanding and $14.1 million in letters of credit outstanding under the credit facility. As of December 31, 2019, QEP had no borrowings outstanding and $2.9 million in letters of credit outstanding under the credit facility.

Senior Notes

At December 31, 2020, the Company had $1,601.9 million principal amount of senior notes outstanding with maturities ranging from October 1, 2022 to March 1, 2026, and coupons ranging from 5.25% to 5.625%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indenture governing QEP's senior notes contains customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets. During the year ended December 31, 2020, QEP repurchased, at a discount, $107.1 million in principal amount of its 6.875% Senior Notes due March 1, 2021, $34.9 million in principal amount of its 5.375% Senior Notes due October 1, 2022, and $13.2 million in principal amount of its 5.25% Senior Notes due May 1, 2023, resulting in a $27.1 million gain from early extinguishment of debt. In addition, QEP redeemed the remaining $275.3 million in principal amount of its 6.875% Senior Notes due March 1, 2021, resulting in a loss on early extinguishment of debt of $7.4 million. In total, during the year ended December 31, 2020, the Company recorded a $19.7 million gain in "Gain (loss) from early extinguishment of debt" in the statements of operations related to the redemption and repurchase of senior notes.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2020

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 financial statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

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.

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. In May 2020, the Office of the Solicitor of the United States Department of the Interior issued an opinion finding that the State of North Dakota, not the MHA nation, is the legal owner of the minerals underlying the Missouri River. The MHA Nation has filed actions in two federal courts seeking to overturn the May 2020 decision.

Overriding Royalty Interest Litigation – In July 2019, owners of small overriding royalty interests in certain wells in the South Antelope oil and gas field in North Dakota filed suit against QEP, alleging QEP has improperly taken deductions for post-production expenses.

In many cases, the Company is unable to make an estimate of the range of reasonably possible loss related to its contingencies. To the extent that the Company can reasonably estimate losses for contingencies where the risk of material loss (in excess of accruals, if any) is reasonably possible, the Company estimates such losses to be in a range of zero to approximately $10.0 million, in the aggregate.

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)
2021	$	28.0
2022	$	22.4
2023	$	12.2
2024	$	6.9
2025	$	4.9
After 2025	$	2.1

Share-Based Compensation

12 Months Ended

Dec. 31, 2020

Share-based Payment Arrangement, Noncash Expense [Abstract]

Share-Based Compensation

In 2018, QEP's Board and 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 may grant long-term incentive compensation. QEP issues restricted share awards, restricted cash awards and restricted share units under its LTSIP or LTIP and issues performance share unit awards under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP historically issued stock options under its LTSIP. 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 cash awards, restricted share units and performance share units. There were 2.9 million shares available for future grants under the LTIP at December 31, 2020.

Share-based compensation expense is generally recognized within "General and administrative" expense on the statements of operations and is summarized in the table below.


	Year Ended December 31,
	2020(1)(2)		2019(3)		2018(4)
	(in millions)
Non-cash share-based compensation
Stock options	$	—	$	0.4	$	1.2
Restricted share awards	12.4		20.4		27.5
Total non-cash share-based compensation	12.4		20.8		28.7
Cash share-based compensation
Restricted cash awards	1.7		—		—
Performance share units	1.0		4.3		8.1
Restricted share units	0.1		0.3		0.1
Total cash share-based compensation	2.8		4.6		8.2
Total share-based compensation expense	$	15.2	$	25.4	$	36.9

__________________________

(1)During the year ended December 31, 2020, the Company incurred $0.4 million of share-based compensation expense related to restricted share awards in which vesting was accelerated in accordance with the Merger Agreement. Refer to Note 1 – Summary of Significant Accounting Policies for more information on the Merger Agreement.

(2)During the year ended December 31, 2020, the Company incurred $0.5 million of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program and is included in the table above. Refer to Note 8 – Restructuring for more information.

(3)During the year ended December 31, 2019, the Company recorded $12.6 million of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program. Of the $12.6 million, $1.5 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statement of operations, and the remaining $11.1 million is included in the table above. Refer to Note 8 – Restructuring for more information.

(4)During the year ended December 31, 2018, the Company recorded $11.0 million of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program. Of the $11.0 million, $2.2 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statement of operations, and the remaining $8.8 million is included in the table above. Refer to Note 8 – Restructuring for more information.

Stock Options

QEP used the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of grant. Fair value calculations relied upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model, which was intended for calculating the value of options not traded on an exchange, was historically used by the Company when QEP granted stock options. The Company utilized the "simplified" method to estimate the expected term of the stock options granted as there was limited historical exercise data available in estimating the expected term of the stock options. QEP used a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate was 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 three years 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. During the years ended December 31, 2020, 2019 and 2018, QEP did not issue stock options.

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, 2019	1,802,387	$	20.87
Exercised	—	—
Cancelled	(311,203)	30.08
Outstanding at December 31, 2020	1,491,184	$	18.94	1.77	$	—
Options Exercisable at December 31, 2020	1,491,184	$	18.94	1.77	$	—
Unvested Options at December 31, 2020	—	$	—	0.00	$	—

During the years ended December 31, 2020 and 2019, there were no exercises of stock options. The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of stock options exercised was $0.1 million during the year ended December 31, 2018. The Company recognized $1.1 million and $2.3 million of income tax expense for the years ended December 31, 2020 and 2019, respectively, and no income tax expense for the year ended December 31, 2018. As of December 31, 2020, there was no unrecognized compensation cost related to stock options granted under the LTSIP.

Restricted Share Awards

Restricted share award grants typically vest in equal installments over three years 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, 2020, 2019 and 2018, was $4.5 million, $32.5 million and $21.5 million, respectively. The Company recognized $2.5 million and $5.4 million of income tax expense for the years ended December 31, 2020 and 2019, respectively, and no tax impact for the year ended December 31, 2018. The weighted-average grant date fair value of restricted share awards granted was $2.10 per share, $7.72 per share and $9.56 per share for the years ended December 31, 2020, 2019 and 2018, respectively. As of December 31, 2020, $7.0 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 1.93 years.

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, 2019	2,845,033	$	8.67
Granted	5,080,589	2.10
Vested	(2,240,899)	7.09
Forfeited	(109,925)	4.79
Unvested balance at December 31, 2020	5,574,798	$	3.39

Restricted Cash Awards

Beginning in March 2020, QEP issued restricted cash awards under its LTIP to certain employees. Restricted cash award grants vest in equal installments over three years from the grant date. The Company recognizes restricted cash forfeitures as they occur. There were no restricted cash awards granted or outstanding during the year ended December 31, 2019. As of December 31, 2020, $1.6 million of unrecognized compensation expense related to restricted cash awards granted under the LTIP is expected to be recognized over a weighted-average vesting period of 2.25 years.

Transactions involving restricted cash awards under the terms of the LTIP are summarized below:


	Restricted Cash Awards Outstanding

Unvested balance at December 31, 2019	$	—
Granted	3,249,925
Vested	(7,000)
Forfeited	(75,250)
Unvested balance at December 31, 2020	$	3,167,675

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 three years. The awards are denominated in share units and have historically been paid in cash. 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, 2020, 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 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 $0.3 million, $13.0 million and $2.8 million for vested performance share units during the years ended December 31, 2020, 2019 and 2018, respectively. The weighted-average grant date fair value of the performance share units granted during the years ended December 31, 2020, 2019 and 2018, was $2.17, $7.93, and $9.55 per share, respectively. As of December 31, 2020, $2.1 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 1.91 years.

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


	Performance Share Units Outstanding	Weighted-Average Grant Date Fair Value
		(per share)
Unvested balance at December 31, 2019	625,922	$	9.04
Granted	1,926,026	2.17
Vested	(96,734)	13.06
Unvested balance at December 31, 2020	2,455,214	$	3.56

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 three years and are deferred into the Company's Wrap Plan at the time of grant. These awards are ultimately paid in cash, are classified as liabilities in "Other long-term liabilities" on the 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 $2.08, $7.87 and $9.55 per share for the years ended December 31, 2020, 2019 and 2018, respectively. As of December 31, 2020, $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 0.83 years.

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


	Restricted Share Units Outstanding	Weighted-Average Grant Date Fair Value
		(per share)
Unvested balance at December 31, 2019	34,393	$	8.16
Granted	76,083	2.08
Vested and paid	(26,770)	8.20
Unvested balance at December 31, 2020	83,706	$	2.62

Employee Benefits

12 Months Ended

Dec. 31, 2020

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, 2020, covers two active and suspended participants, or 1%, of QEP's active employees, and 212 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. The Pension Plan was amended and restated in June 2015, is closed to new participants and was frozen such that active participants do not earn any additional accrued benefits on or after January 1, 2016. During the year ended December 31, 2020, the Company made contributions of $4.0 million to the Pension Plan and expects to contribute approximately $4.0 million to the Pension Plan in 2021. 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, 2020, the Company made contributions of $9.7 million to its SERP and expects to contribute approximately $3.1 million in 2021. 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.

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 two active, pension eligible employees, neither is eligible for the Medical Plan when they retire. As of December 31, 2020, 27 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, 2020, the Company made contributions of $0.7 million and expects to contribute approximately $0.2 million of benefits in 2021. At December 31, 2020 and 2019, 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 recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the 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 statements of operations.

The Company's execution of its 2018 and 2019 strategic initiatives, including divestitures and corporate restructurings, triggered curtailments related to the Pension Plan, SERP and/or Medical Plan at the closing of the various transactions. Refer to Note 8 – Restructuring for more information. Curtailments were included in "Interest and other income (expense)" and "Net gain (loss) from asset sales, inclusive of restructuring costs" on the statements of operations depending on the associated participants triggering the curtailment and are summarized in the following table:


	Year ended December 31,
Statements of Operations Line	2020		2019		2018
Interest and other income (expense)	$	—	$	(1.4)	$	(0.3)
Net gain (loss) from asset sales, inclusive of restructuring costs	—		0.2		0.2
Total curtailment gain (loss)	$	—	$	(1.2)	$	(0.1)

The accumulated benefit obligation for the Pension and SERP defined-benefit pension plans was $135.3 million and $135.2 million as of December 31, 2020 and 2019, 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, 2020 and 2019, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2020 and 2019:


	Pension Plan and SERP benefits				Medical Plan benefits
	2020		2019		2020		2019
Change in benefit obligation	(in millions)
Benefit obligation at January 1,	$	135.2	$	122.1	$	2.6	$	2.5
Service cost	—		0.3		—		—
Interest cost	4.1		4.8		0.1		0.1
Curtailments	—		1.2		—		—
Benefit payments	(10.3)		(6.2)		(0.7)		(0.9)
Plan amendments	—		—		—		—
Actuarial loss (gain)	11.7		13.0		0.7		0.9
Settlement loss	(5.4)		—		—		—
Benefit obligation at December 31,	$	135.3	$	135.2	$	2.7	$	2.6
Change in plan assets
Fair value of plan assets at January 1,	$	113.9	$	93.3	$	—	$	—
Actual return on plan assets	16.1		21.3		—		—
Company contributions to the plan	13.7		5.5		0.7		0.9
Benefit payments	(10.3)		(6.2)		(0.7)		(0.9)
Settlement loss	(5.4)		—		—		—
Fair value of plan assets at December 31,	128.0		113.9		—		—
Underfunded status (current and long-term)	$	(7.3)	$	(21.3)	$	(2.7)	$	(2.6)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(3.1)	$	(9.2)	$	(0.1)	$	(0.2)
Other long-term liabilities	(4.2)		(12.1)		(2.6)		(2.4)
Total amount recognized in balance sheet	$	(7.3)	$	(21.3)	$	(2.7)	$	(2.6)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	15.4	$	15.7	$	1.0	$	0.4
Prior service cost	—		—		—		—
Total amount recognized in AOCI	$	15.4	$	15.7	$	1.0	$	0.4

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


	Pension Plan and SERP benefits						Medical Plan benefits
	2020		2019		2018		2020		2019		2018
Components of net periodic benefit cost	(in millions)
Service cost	$	—	$	0.3	$	0.8	$	—	$	—	$	—
Interest cost	4.1		4.8		4.6		0.1		0.1		0.1
Expected return on plan assets	(6.1)		(5.9)		(5.8)		—		—		—
Curtailment (gain) loss	—		2.0		0.3		—		(0.8)		(0.2)
Settlement loss	1.0		—		—		—		—		—
Amortization of prior service costs	—		0.4		0.8		—		—		(0.3)
Amortization of actuarial loss	0.9		0.5		0.8		—		—		—
Periodic expense	$	(0.1)	$	2.1	$	1.5	$	0.1	$	(0.7)	$	(0.4)
Components recognized in accumulated other comprehensive income
Current period prior service cost	$	—	$	—	$	—	$	—	$	—	$	0.2
Current period actuarial (gain) loss	1.6		(2.4)		5.6		0.7		0.9		(0.1)
Amortization of prior service cost	—		(0.4)		(0.8)		—		0.8		0.3
Amortization of actuarial gain (loss)	(0.9)		(0.5)		(0.8)		—		—		—
Loss on curtailment in current period	—		(0.8)		(0.1)		—		—		—
Settlement loss	(1.0)		—		—		—		—		—
Total amount recognized in accumulated other comprehensive income	$	(0.3)	$	(4.1)	$	3.9	$	0.7	$	1.7	$	0.4

The estimated portion of net actuarial loss cost for the Pension Plan and SERP that will be amortized from AOCI into net periodic benefit cost in 2021 is $1.0 million, which represents amortization of actuarial losses. The estimated portion of net actuarial loss for the Medical Plan that will be amortized from AOCI into net periodic benefit cost in 2021 is less than $0.1 million, which represents amortization of actuarial losses. Amortization of actuarial gains or losses out of AOCI are recognized in the statements of operations in "Interest and other income (expense)".

Following are the weighted-average discount rates (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, 2020 and 2019:


	Pension Plan and SERP benefits				Medical Plan benefits
	2020		2019		2020		2019
Discount rate	2.45	%	3.13	%	2.70	%	3.40	%

The discount rate assumptions used by the Company represent 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
	2020		2019		2018		2020		2019		2018
Discount rate	3.21	%	4.19	%	3.50	%	3.40	%	4.30	%	3.60	%
Expected long-term return on plan assets	5.70	%	5.70	%	6.00	%	n/a		n/a		n/a
Rate of increase in compensation(1)	n/a		3.00	%	3.50	%	n/a		n/a		n/a

_______________________

(1) As the Pension Plan was frozen, such that employees do not accrue additional defined benefits for future service or compensation on or after January 1, 2016, 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 of January 1, 2020, there were no longer any active employees eligible for the SERP. As such, the rate of increase in compensation is only used for the SERP for the years ended December 31, 2019 and 2018.

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 2021. 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, 2020 and 2019, respectively:


	December 31, 2020				December 31, 2019
	Total		Percentage of total		Total		Percentage of total
	(in millions, except percentages)
Cash and short-term investments	$	0.6	—	%	$	0.6	1	%
Equity securities:
Domestic	23.8		19	%	30.6		27	%
International	8.5		7	%	10.5		9	%
Fixed income	95.1		74	%	72.2		63	%
Total investments	$	128.0	100	%	$	113.9	100	%

Expected Benefit Payments

As of December 31, 2020, the following future benefit payments are expected to be paid:


	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2021	$	9.0	$	0.2
2022	$	9.1	$	0.2
2023	$	7.6	$	0.1
2024	$	7.5	$	0.1
2025	$	6.8	$	0.1
2026 through 2030	$	31.4	$	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, 2020, 2019 and 2018, the Company made contributions of $3.0 million, $3.6 million and $5.8 million to the 401(k) Plan, respectively. The Company recognizes expense equal to its yearly contributions. 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,
	2020		2019		2018
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 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, 2020 and 2019, the Company made a discretionary contribution of less than $0.1 million to active participants of the Pension Plan. During the year ended December 31, 2018, the Company made a discretionary contribution of $0.3 million to active participants of the Pension Plan.

Nonqualified, Unfunded Deferred Compensation Wrap Plan

QEP offers a nonqualified, unfunded deferred compensation wrap plan to certain individuals. The Wrap Plan provides participants with certain tax planning benefits as well as supplemental funds for retirement and allows participants to defer the receipt of various types of compensation. Participants are able to select from a variety of investment options, including mutual funds and phantom QEP shares. As of December 31, 2020 and 2019, the Wrap Plan obligations for participants' future benefits were $25.5 million and $26.8 million, respectively, and are included in "Other long-term liabilities" on the balance sheets. The Company established a Rabbi Trust to hold the investments associated with the Wrap Plan (other than phantom QEP shares) and to pay Wrap Plan obligations as they arise. As of December 31, 2020 and 2019, the marketable securities held in the Rabbi Trust were $23.4 million and $23.1 million, respectively, and are included in "Other noncurrent assets" on the balance sheets.

Changes in the fair value of Wrap Plan obligations and marketable securities are recorded as "Deferred compensation mark-to-market adjustments" and "Unrealized gain/loss on marketable securities" within "General and administrative" and "Interest and other income (expense)", respectively, on the statements of operations. "Deferred compensation mark-to-market adjustments" and "Unrealized gain/loss on marketable securities" for the years ended December 31, 2020, 2019 and 2018, respectively, are summarized in the table below:


	Year Ended December 31,
	(in millions)
	2020		2019		2018
Deferred compensation mark-to-market adjustments	$	1.0	$	2.3	$	(3.9)
Unrealized (gain)/loss on marketable securities	(3.2)		(3.9)		1.2

Refer to Note 5 – Fair Value Measurements for more information on the fair value measurement of the marketable securities held in the Rabbi Trust and the Wrap Plan obligations.

- Definition

The entire disclosure for retirement benefits.

+ References

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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

The Tax Cuts and Jobs Act enacted in December 2017 changed several aspects of corporate taxation, including decreasing our federal corporate statutory tax rate from 35% to 21%, limiting the amount of interest the Company could potentially deduct and eliminating the corporate AMT. The elimination of the corporate AMT allowed the Company to claim AMT refunds for AMT credits carried forward from prior tax years. The CARES Act enacted in March 2020 permitted the Company to carry back its NOL generated in 2018 and 2019, creating additional AMT credits, and to accelerate all of its AMT refunds. Guidance issued by the relevant regulatory authorities regarding tax legislation may materially impact QEP's financial statements. As additional guidance to the Tax Cuts and Jobs Act and the CARES Act 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 statements of operations.

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,
	2020		2019		2018
Federal income tax provision (benefit)	(in millions)
Current	$	(189.5)	$	(32.2)	$	(71.3)
Deferred	116.0		55.7		(257.8)
State income tax provision (benefit)
Current	(1.0)		(15.1)		1.5
Deferred	(5.4)		(51.4)		10.2
Total income tax provision (benefit)	$	(79.9)	$	(43.0)	$	(317.4)

The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:


	Year Ended December 31,
	2020		2019		2018
Federal income taxes statutory rate	21.0	%	21.0	%	21.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	(1.6)	%	(2.5)	%	4.1	%

State rate change(1)	8.0	%	20.9	%	(2.9)	%
Valuation allowance(2)	3.3	%	(18.0)	%	(1.9)	%
Permanent adjustments(3)	(7.2)	%	(7.1)	%	(0.1)	%
Return to provision adjustment	1.1	%	2.7	%	(0.1)	%
Uncertain tax provision(4)	—	%	13.6	%	—	%
NOL rate re-measurements(5)	79.6	%	—	%	3.8	%
Effective income tax rate	104.2	%	30.6	%	23.9	%

____________________________

(1)During the year ended December 31, 2020, the state rate change was primarily the result of the re-measurement of QEP's deferred tax assets and liabilities at a lower blended state rate due to the changing apportionment of the Company's revenues and property in its remaining operating areas. During the year ended December 31, 2019, the state rate change was primarily the result of the re-measurement of QEP's deferred tax assets and liabilities at a lower blended state tax rate due to exiting the state of Louisiana.

(2)During the year ended December 31, 2019, the Company recognized an additional valuation allowance of $25.3 million on its Louisiana state NOL. The Company did not expect that it would have sufficient taxable income to utilize the state NOL it is carrying forward due to the Haynesville Divestiture. During the year ended December 31, 2018, the Company also increased its valuation allowance by $25.5 million against its Louisiana net operating loss as the Company did not forecast sufficient taxable income to utilize the entire net operating loss in Louisiana at December 31, 2018.

(3)During the years ended December 31, 2020, and 2019, the permanent items primarily related to disallowed officer compensation under Section 162(m) of the Internal Revenue Code of $1.9 million and $6.1 million and share-based compensation shortfalls of $3.6 million and $4.0 million, respectively.

(4)During the year ended December 31, 2019, the Company recognized a tax benefit of $19.0 million due to the expiration of the statute of limitations related to the Company's uncertain tax position.

(5)During the year ended December 31, 2020, QEP had a remeasurement of deferred taxes due to NOL carrybacks under the CARES Act to a year with a higher federal tax rate. This remeasurement provided a tax benefit of $61.0 million during the year ended December 31, 2020. During the year ended December 31, 2018, QEP agreed to an IRS proposed change to the initial treatment of the 2016 carryback of NOL. This change resulted in a reduction of available NOL carryforwards valued at $75.7 million and an increase in 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,
	2020		2019
Deferred tax liabilities	(in millions)
Property, plant and equipment	$	627.5	$	592.9

Operating lease right-of-use assets	10.7		12.7
Other	2.4		0.9
Total deferred tax liabilities	640.6		606.5
Deferred tax assets
NOL and tax credit carryforwards	$	306.2	$	337.7
State NOL valuation allowance	(101.9)		(98.8)
Employee benefits and compensation costs	15.9		22.3
Interest carryforward (1)	—		45.7
Commodity price derivatives	17.0		3.9
Operating lease liabilities	11.7		14.1
Other	6.5		7.1
Total deferred tax assets	255.4		332.0
Net deferred income tax liability	$	385.2	$	274.5
Balance sheet classification
Deferred income tax liability – noncurrent	385.2		274.5
Net deferred income tax liability	$	385.2	$	274.5

____________________________

(1)The decrease in the interest expense carry forward is due to the issuance of final regulations by the U.S. Department of Treasury in July 2020 that relate to the deductibility of interest expense. After the application of these regulations the Company expects to fully deduct all of its remaining interest that was carried forward at December 31, 2019.

As of December 31, 2020, the Company had a gross U.S. NOL of $863.5 million and various gross state NOL's of $5,059.8 million. The tax effected amounts and expiration dates of NOL and tax credit carryforwards at December 31, 2020, are as follows:


	Expiration Dates	Amounts
		(in millions)
State NOL and tax credit carryforwards	2021-Indefinite	$	121.1
U.S. NOL(1)	2037-Indefinite	181.3
General business credits	2036-2037	3.8
Total NOL and tax credit carryforwards		$	306.2

____________________________

(1)Federal NOLs created in tax years beginning after December 31, 2017 can be carried forward indefinitely under the Tax Cuts and Jobs Act (limited to 80% of taxable income computed without the NOL deduction). Of the Company's U.S. NOL, $18.7 million has an indefinite carryforward period but its use is limited to 80% of taxable income.

The Company assesses the available positive and negative evidence to determine if sufficient future taxable income will be generated to use the existing deferred tax assets. The Company maintains a valuation allowance to offset the uncertain realization of certain of its state NOL's on the basis that they are not more likely than not to be realized. The Company had a valuation allowance of $101.9 million and $98.8 million as of December 31, 2020 and 2019, respectively, for state NOL's outside of our current core operations and primarily relate to state NOL's in Colorado, Louisiana, Utah and Oklahoma. Due to the various divestitures over the last several years, and focus of our operations, we do not expect to have sufficient taxable income in these states to utilize the NOL's we are carrying forward.

The Tax Cuts and Jobs Act eliminated corporate AMT which allowed QEP 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 CARES Act permitted the Company to carry back its NOL generated in 2018 and 2019, creating additional AMT credits, and to accelerate all of its AMT refunds. The Company received $170.7 million, including interest income, and $73.9 million of AMT credit refunds in 2020 and 2019, respectively, and anticipates it will realize approximately $61.6 million in AMT credit refunds, with $30.7 million expected to be realized within the next 12 months, which is shown in "Income tax receivable" with the remaining $30.9 million included in "Other noncurrent assets" on the balance sheets as of December 31, 2020.

Pursuant to Section 382 and 383 of the Internal Revenue Code, utilization of the Company’s NOL's and credits may be subject to annual limitations in the event of any significant future changes in its ownership structure. These annual limitations may result in the expiration of NOL's and credits prior to utilization.

The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. For federal tax purposes, the Company has been a participant in the IRS Compliance Assurance Process through the 2019 tax year, which provides examination of the tax return either prior to or post filing. Generally, for state tax purposes, the Company’s 2017 through 2019 tax years remain open for examination by the taxing authorities under a three-year statute of limitations. Should the Company utilize any of its state loss carryforwards, their carryforward losses would be subject to examination.

Unrecognized Tax Benefit

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.

During the year ended December 31, 2019, the statute of limitations related to the Company's uncertain tax position expired, and upon expiration, the Company recognized a $19.0 million tax benefit and recorded a $4.1 million reduction in "Interest expense" and a $2.5 million reduction in "General and administrative" expense on the statements of operations related to accrued interest and penalties that were recorded in prior periods. During the year ended December 31, 2018 the Company incurred $0.7 million of estimated interest expense 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, 2020 and 2019:


	Unrecognized Tax Benefits
	2020		2019
	(in millions)
Balance as of January 1,	$	—	$	19.0
Recognized tax benefits	—		(19.0)
Balance as of December 31,	$	—	$	—

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References + Details

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2020

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
2020	(in millions, except per share amounts or otherwise specified)
Revenues	$	225.8	$	120.6	$	177.8	$	200.2	$	724.4
Operating income (loss)	$	(7.2)	$	(112.5)	$	(42.1)	$	(61.9)	$	(223.7)
Net income (loss)	$	367.4	$	(184.4)	$	(49.2)	$	(130.6)	$	3.2
Net gain (loss) from asset sales, inclusive of restructuring costs and impairment	$	3.7	$	—	$	0.1	$	(11.3)	$	(7.5)
Per share information
Basic EPS	$	1.54	$	(0.76)	$	(0.20)	$	(0.54)	$	0.01
Diluted EPS	$	1.54	$	(0.76)	$	(0.20)	$	(0.54)	$	0.01
Production information
Total equivalent production (Mboe)	7,930.9		7,972.9		7,057.0		7,364.1		30,324.9


2019
Revenues	$	280.6	$	296.2	$	307.5	$	321.9	$	1,206.2
Operating income (loss)	$	(15.8)	$	72.3	$	52.1	$	48.9	$	157.5
Net income (loss)	$	(116.7)	$	48.8	$	81.0	$	(110.4)	$	(97.3)
Net gain (loss) from asset sales, inclusive of restructuring costs and impairment	$	(18.2)	$	17.8	$	(2.1)	$	1.4	$	(1.1)
Per share information
Basic EPS	$	(0.49)	$	0.20	$	0.34	$	(0.46)	$	(0.41)
Diluted EPS	$	(0.49)	$	0.20	$	0.34	$	(0.46)	$	(0.41)
Production information
Total equivalent production (Mboe)	7,806.3		7,534.7		8,404.0		8,465.3		32,210.3

Supplemental Gas and Oil Information (Unaudited)

12 Months Ended

Dec. 31, 2020

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:


	December 31,
	2020		2019
	(in millions)
Proved properties	$	9,941.2	$	9,574.9
Unproved properties, net	454.4		599.1
Total proved and unproved properties	10,395.6		10,174.0
Accumulated depreciation, depletion and amortization	(5,728.0)		(5,250.5)
Net capitalized costs	$	4,667.6	$	4,923.5

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 $26.2 million and ARO additions and revisions of $1.2 million during the year ended December 31, 2020. The costs incurred for the development of reserves that were classified as proved undeveloped were approximately $222.3 million in 2020, $426.1 million in 2019 and $606.5 million in 2018.


	Year Ended December 31,
	2020		2019		2018
	(in millions)
Proved property acquisitions	$	2.9	$	1.5	$	39.1
Unproved property acquisitions	1.2		2.0		25.8
Other acquisitions	—		—		0.8
Exploration costs (capitalized and expensed)	0.2		0.1		0.3
Development costs	324.8		556.2		1,133.1
Total costs incurred	$	329.1	$	559.8	$	1,199.1

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,
	2020		2019		2018
	(in millions)
Revenues	$	721.0	$	1,200.6	$	1,920.3
Production costs	292.9		361.9		507.3
Exploration expenses	0.2		0.1		0.3
Depreciation, depletion and amortization	564.2		528.5		836.4
Impairment	8.7		—		1,560.9
Gathering and other expense	(0.2)		—		—
Total expenses	865.8		890.5		2,904.9
Income (loss) before income taxes	(144.8)		310.1		(984.6)
Income tax benefit (expense)	32.1		(69.5)		243.2
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(112.7)	$	240.6	$	(741.4)

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, 2020, 2019 and 2018. 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, 2020, 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, 2020, 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, 2018, 2019 and 2020 are as follows:


	Oil and condensate	Gas	NGL	Total(10)
	(MMbbl)	(Bcf)	(MMbbl)	(MMboe)
Balance at December 31, 2017	320.5	1,793.6	65.2	684.7
Revisions of previous estimates(1)	2.1	314.0	6.7	61.0
Extensions and discoveries(2)	57.1	56.5	9.8	76.3
Purchase of reserves in place(3)	8.2	7.9	1.3	10.9
Sale of reserves in place(4)	(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
Revisions of previous estimates(5)	(94.9)	(23.0)	(8.7)	(107.3)
Extensions and discoveries(6)	33.6	40.0	7.4	47.6
Purchase of reserves in place(7)	3.6	4.0	0.7	4.9
Sale of reserves in place(8)	(4.9)	(1,102.2)	(0.3)	(188.9)
Production	(21.6)	(33.1)	(5.1)	(32.2)
Balance at December 31, 2019	254.9	373.3	65.2	382.3
Revisions of previous estimates(9)	2.7	27.6	4.1	11.4
Extensions and discoveries	0.1	0.2	—	0.2

Sale of reserves in place	(0.1)	(0.3)	—	(0.2)
Production	(19.7)	(32.5)	(5.2)	(30.3)
Balance at December 31, 2020	237.9	368.3	64.1	363.4
Proved developed reserves
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
Balance at December 31, 2019	117.5	217.0	36.7	190.4
Balance at December 31, 2020	101.2	185.0	32.0	164.0
Proved undeveloped reserves
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
Balance at December 31, 2019	137.4	156.3	28.5	191.9
Balance at December 31, 2020	136.7	183.3	32.1	199.4

___________________________

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

(3)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.

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

(5)Revisions of previous estimates in 2019 totaling 107.3 MMboe of negative revisions includes 44.5 MMboe of negative PUD revisions as a result of changes to the development sequence in the Permian Basin, to maximize capital efficiency (see offset in extensions and discoveries footnote 6 below); 25.8 MMboe of PUD removals, primarily in the Williston Basin, that will not be developed within five years of the initial date of booking due to the reduction in future capital expenditures; 17.0 MMboe of negative revisions related to pricing, primarily driven by lower oil prices; 13.7 MMboe of negative performance revisions, primarily associated with updated volume projections for high-density wells and certain undrilled locations in the Permian Basin; 10.9 MMboe of other negative revisions, partially offset by 4.6 MMboe of positive revisions related to lower operating costs.

(6)Extensions and discoveries in 2019 primarily related to new PUD locations in the Permian Basin due to changes in the development sequence in the Permian Basin to maximize capital efficiency. See partial offset in revisions to previous estimates in footnote 9 above.

(7)Purchase of reserves in place in 2019 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.

(8)Sale of reserves in place in 2019 was primarily related to QEP's Haynesville Divestiture as discussed in Note 3 – Acquisitions and Divestitures.

(9)Revisions of previous estimates in 2020 totaling 11.4 MMboe of positive revisions includes 63.0 MMboe of positive revisions, of which 58.8 MMboe was positive PUD revisions, as a result of changes in development sequence in the Permian Basin to maximize Free Cash Flow. Additionally, there were 4.2 MMboe of positive revisions related to lower operating costs and 2.5 MMboe of other positive revisions, partially offset by 41.4 MMboe of negative price revisions, primarily driven by lower oil prices and 16.9 MMboe of PUD removals, primarily in Permian Basin, that will not be developed within five years of the initial date of booking due to the reduction in future capital expenditures.

(10)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, 2020, 2019 and 2018, 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 2020, 2019 and 2018, 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,
	2020		2019		2018
Average benchmark price per unit:
Oil price (per bbl)	$	39.57	$	55.51	$	65.56
Gas price (per MMbtu)	$	1.99	$	2.58	$	3.10

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 $202.6 million in 2021, $289.1 million in 2022 and $365.8 million in 2023. 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 condensate 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,
	2020		2019		2018
	(in millions)
Future cash inflows	$	9,657.0	$	14,447.6	$	26,482.6
Future production costs	(4,728.9)		(6,070.6)		(9,539.9)
Future development costs(1)	(1,671.0)		(2,275.2)		(4,441.5)
Future income tax expenses(2)	(294.8)		(845.8)		(2,553.6)
Future net cash flows	2,962.3		5,256.0		9,947.6
10% annual discount for estimated timing of net cash flows	(1,427.0)		(2,579.7)		(4,991.9)
Standardized measure of discounted future net cash flows	$	1,535.3	$	2,676.3	$	4,955.7

___________________________

(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, 2020, 2019 and 2018, were estimated assuming a 21% federal tax rate from the Tax Cuts and Jobs Act 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,
	2020		2019		2018
	(in millions)
Balance at January 1,	$	2,676.3	$	4,955.7	$	3,097.3
Sales of oil and condensate, gas and NGL produced, net of production costs	(428.1)		(838.7)		(1,413.0)
Net change in sales prices and in production (lifting) costs related to future production	(2,136.4)		(1,988.6)		1,632.5
Net change due to extensions and discoveries	2.4		220.9		692.6
Net change due to revisions of quantity estimates	159.6		(2,079.2)		732.0
Net change due to purchases of reserves in place	—		34.2		117.0
Net change due to sales of reserves in place	(1.9)		(617.8)		(369.6)
Previously estimated development costs incurred during the period	256.1		460.8		735.6
Changes in estimated future development costs	418.7		1,064.7		(28.3)
Accretion of discount	310.7		622.8		375.4
Net change in income taxes	277.9		841.5		(615.7)
Other	—		—		(0.1)
Net change	(1,141.0)		(2,279.4)		1,858.4
Balance at December 31,	$	1,535.3	$	2,676.3	$	4,955.7

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2020

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 these financial statements are in millions, except per share information and where otherwise noted.

Merger

Segment Reporting, Policy [Policy Text Block]

Business Segments

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

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the balance sheets to the amounts shown in the statements of cash flows:


	December 31,
	2020		2019
	(in millions)
Cash and cash equivalents	$	60.4	$	166.3
Restricted cash(1)	31.9		30.1
Total cash, cash equivalents and restricted cash shown in the Consolidated Statements of Cash Flows	$	92.3	$	196.4

_______________________

Supplemental cash flow information is shown in the table below:


	Year Ended December 31,
	2020		2019		2018
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	118.4	$	126.9	$	136.9
Cash paid (refund received) for income taxes, net	$	(164.0)	$	(66.7)	$	0.8
Cash paid for amounts included in the measurement of lease liabilities	$	25.7	$	25.3	$	—
Other Non-cash Activities:
Right-of-use assets obtained in exchange for operating lease obligations	$	11.0	$	16.6	$	—
Non-cash Investing Activities:
Capital expenditure accruals as of December 31,	$	37.8	$	63.3	$	54.5

Accounts Receivable [Policy Text Block]

Accounts Receivable

Property, Plant and Equipment [Policy Text Block]

Property, Plant and Equipment

Property, plant and equipment balances are stated at historical cost. Significant accounting policies for our property, plant and equipment are as follows:

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

During the year ended December 31, 2020, QEP recorded unproved property impairment charges of $8.7 million related to anticipated leasehold expirations.

During the year ended December 31, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.

Asset Retirement Obligations (ARO)

Litigation and Other Contingencies [Policy Text Block]

Litigation and Other Contingencies

Derivative Contracts [Policy Text Block]

Derivative Contracts

Credit Risk [Policy Text Block]

Credit Risk


Year Ended December 31, 2020
Valero Marketing & Supply Company	30	%
Phillips 66 Company	12	%

Year Ended December 31, 2019
Occidental Energy Marketing	21	%
Valero Marketing & Supply Company	18	%
Plains Marketing LP	17	%

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

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,
	2020	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	241.6	237.7	237.9
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	241.6	237.7	237.9

Share-based Compensation [Policy Text Block]

Share-Based and Long-Term 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, 2020

Summary of Significant Accounting Policies [Abstract]

Restrictions on Cash and Cash Equivalents [Table Text Block]

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the balance sheets to the amounts shown in the statements of cash flows:


	December 31,
	2020		2019
	(in millions)
Cash and cash equivalents	$	60.4	$	166.3
Restricted cash(1)	31.9		30.1
Total cash, cash equivalents and restricted cash shown in the Consolidated Statements of Cash Flows	$	92.3	$	196.4

_______________________

Supplemental Cash Flow Information [Table Text Block]

Supplemental cash flow information is shown in the table below:


	Year Ended December 31,
	2020		2019		2018
Supplemental Disclosures:	(in millions)
Cash paid for interest, net of capitalized interest	$	118.4	$	126.9	$	136.9
Cash paid (refund received) for income taxes, net	$	(164.0)	$	(66.7)	$	0.8
Cash paid for amounts included in the measurement of lease liabilities	$	25.7	$	25.3	$	—
Other Non-cash Activities:
Right-of-use assets obtained in exchange for operating lease obligations	$	11.0	$	16.6	$	—
Non-cash Investing Activities:
Capital expenditure accruals as of December 31,	$	37.8	$	63.3	$	54.5

Property, Plant and Equipment [Table Text Block]


Buildings			10 to 30 years
Leasehold improvements			3 to 10 years
Service, transportation and field service equipment			3 to 7 years
Furniture and office equipment			3 to 7 years

Credit Risk [Policy Text Block]

Credit Risk


Year Ended December 31, 2020
Valero Marketing & Supply Company	30	%
Phillips 66 Company	12	%

Year Ended December 31, 2019
Occidental Energy Marketing	21	%
Valero Marketing & Supply Company	18	%
Plains Marketing LP	17	%

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

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,
	2020	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	241.6	237.7	237.9
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	241.6	237.7	237.9

Revenue (Tables)

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

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
	(in millions)
	Year Ended December 31, 2020
Northern Region
Williston Basin	$	249.9	$	18.1	$	14.4	$	(37.8)	$	244.6
Other Northern	0.2		1.1		—		—		1.3
Southern Region
Permian Basin	441.7		20.4		31.3		(24.7)		468.7
Other Southern	—		—		—		—		—
Total oil and condensate, gas and NGL sales	$	691.8	$	39.6	$	45.7	$	(62.5)	$	714.6

	Year Ended December 31, 2019
Northern Region
Williston Basin	$	420.8	$	33.1	$	19.4	$	(34.4)	$	438.9
Other Northern	1.1		0.4		0.1		—		1.6
Southern Region
Permian Basin	710.6		12.8		37.8		(20.5)		740.7
Other Southern(1)	0.1		6.1		—		—		6.2
Total oil and condensate, gas and NGL sales	$	1,132.6	$	52.4	$	57.3	$	(54.9)	$	1,187.4

	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	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

_______________________

(1)For the year ended December 31, 2019, $5.9 million of revenues associated with Haynesville/Cotton Valley have been included in Other Southern.

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation [Abstract]

Schedule of Asset Retirement Obligations [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,
	2020		2019
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.4	$	6.0
Long-term:
Asset retirement obligations	96.3		94.9

Total ARO Liability	$	102.7	$	100.9

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
	2020		2019
	(in millions)
ARO liability at January 1,	$	100.9	$	159.6
Accretion	4.0		5.2
Additions	1.2		1.1
Revisions	—		(2.2)
Liabilities related to assets sold(1)	(1.4)		(60.7)
Liabilities settled	(2.0)		(2.1)
ARO liability at December 31,	$	102.7	$	100.9

___________________________

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

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

The fair value of financial assets and liabilities at December 31, 2020 and 2019, 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
	(in millions)
	December 31, 2020
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	1.4	$	—	$	(1.4)	$	—
Fair value of derivative contracts – long-term	—		—		—		—		—
Fair value of Rabbi Trust marketable securities	23.4		—		—		—		23.4
Total financial assets	$	23.4	$	1.4	$	—	$	(1.4)	$	23.4

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	77.8	$	—	$	(1.4)	$	76.4
Fair value of derivative contracts – long-term	—		0.3		—		—		0.3
Fair value of Wrap Plan obligations	25.5		—		—		—		25.5
Total financial liabilities	$	25.5	$	78.1	$	—	$	(1.4)	$	102.2

	December 31, 2019
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	1.5	$	—	$	—	$	1.5
Fair value of derivative contracts – long-term	—		0.2		—		—		0.2
Fair value of Rabbi Trust marketable securities	23.1		—		—		—		23.1
Total financial assets	$	23.1	$	1.7	$	—	$	—	$	24.8

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	18.7	$	—	$	—	$	18.7
Fair value of derivative contracts – long-term	—		0.5		—		—		0.5
Fair value of Wrap Plan obligations	26.8		—		—		—		26.8
Total financial liabilities	$	26.8	$	19.2	$	—	$	—	$	46.0

____________________________

Fair value and related carrying amount of certain financial instruments

The following table discloses the fair value and related carrying amount of long-term debt not disclosed in other Notes to the Consolidated Financial Statements:


	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2020				December 31, 2019
Financial Liabilities	(in millions)
Long-term debt	$	1,591.3	$	1,702.8	$	2,015.6	$	2,029.4

- 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, 2020

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, 2020:


Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2021 (January - June)	NYMEX WTI	7.3	$	44.54
2021 (July - December)	NYMEX WTI	6.3	$	42.64
2022 (January - June)	NYMEX WTI	0.2	$	45.00
Gas Sales		(MMbtu)	($/MMbtu)
2021	IF Waha	18.3	$	1.92
2021	NYMEX HH	9.1	$	2.44

derivative volumes and weighted average differential [Table Text Block]


Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2021	NYMEX WTI	Argus WTI Midland	5.8	$	0.88
2021	NYMEX CMA	Argus WTI	1.5	$	0.00
2021	NYMEX WTI	NYMEX Roll	1.8	$	(0.05)

The following table presents QEP's volumes and average prices for its commodity derivative costless oil collars as of December 31, 2020:


Year	Index	Total Volumes	Average Price Floor		Average Price Ceiling
		(in millions)
		(bbls)	($/bbl)		($/bbl)
2021 (January - June)	NYMEX WTI	0.3	$	40.73	$	50.17
2021 (July - December)	NYMEX WTI	0.8	$	40.16	$	49.89

Effects of Derivative Transactions


Derivative contracts	Year Ended December 31,
	2020		2019		2018
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	296.4	$	(32.2)	$	(153.4)
Gas derivative contracts	(4.5)		(2.9)		(5.0)
Gas Storage
Gas derivative contracts	—		—		0.3
Realized gains (losses) on commodity derivative contracts	291.9		(35.1)		(158.1)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(48.7)		(139.8)		277.0
Gas derivative contracts	(10.5)		(0.3)		(22.3)
Gas Storage
Gas derivative contracts	—		—		(0.3)
Unrealized gains (losses) on commodity derivative contracts	(59.2)		(140.1)		254.4
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	232.7	$	(175.2)	$	96.3

Derivatives associated with divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	—	$	—	$	(2.7)
Gas derivative contracts	—		1.8		—
NGL derivative contracts	—		—		(3.2)
Unrealized gains (losses) on commodity derivative contracts related to divestitures(1)(2)	$	—	$	1.8	$	(5.9)

Total realized and unrealized gains (losses) on commodity derivative contracts	$	232.7	$	(173.4)	$	90.4

_______________________

Leases (Tables)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Lease, Cost [Table Text Block]

Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows:


	As of December 31,
	2020		2019
	(in millions)
Lease Cost included in the Consolidated Balance Sheets
Property, Plant and Equipment additions(1)	$	11.7	$	13.8

	Year Ended December 31,
	2020		2019
	(in millions)
Lease Cost included in the Consolidated Statement of Operations
Lease operating expense(2)	$	14.0	$	11.9
Gathering and other expense(2)	5.7		7.7
General and administrative(2)	6.0		5.7

Total lease cost	$	25.7	$	25.3

____________________________

Lease Term and Discount Rate [Table Text Block]

Lease term and discount rate related to the Company's leases are as follows:


	As of December 31,
	2020		2019
Weighted-average remaining lease term (years)	3.6		5.4
Weighted-average discount rate	7.2	%	8.0	%

Lessee, Operating Leases [Text Block]

As of December 31, 2020, the maturity analysis for long-term operating leases under the scope of ASC 842 is as follows:


Year	December 31, 2020
	(in millions)
2021	$	24.9
2022	17.2
2023	11.5
2024	2.4
2025	0.8
After 2025	2.9
Less: Interest(1)	(6.7)
Present Value of Lease Liabilities(2)	$	53.0

____________________________

(1)Calculated using the estimated or stated interest rate for each lease.

Restructuring Costs Restructuring Costs (Tables)

12 Months Ended

Dec. 31, 2020

Restructuring and Related Activities [Abstract]

Restructuring Costs [Table Text Block]

Restructuring costs recognized are summarized below:


	Year Ended December 31, 2020
	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	$	1.0	$	1.0	$	—	$	—
Accelerated share-based compensation	0.5		0.5		—		—
Retention expense (including share-based compensation)	0.4		0.4		—		—
Total restructuring costs	$	1.9	$	1.9	$	—	$	—


	Year Ended December 31, 2019
	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	$	12.3	$	12.2	$	0.1	$	—
Office lease termination costs	0.6		0.6		—		—
Accelerated share-based compensation	12.6		11.1		1.5		—
Retention expense (including share-based compensation)	19.5		19.5		—		—
Pension and Medical Plan curtailment	1.2		—		(0.2)		1.4
Total restructuring costs	$	46.2	$	43.4	$	1.4	$	1.4


	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	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

Restructuring and Related Costs [Table Text Block]


	Costs recognized from inception through December 31, 2020 (1)		Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	45.6	$	—
Office lease termination costs	1.6		—
Accelerated share-based compensation	24.1		—
Retention expense (including share-based compensation)	38.7		—
Pension and Medical Plan curtailment	1.3		—
Total restructuring costs	$	111.3	$	—

____________________________

(1)Represents costs incurred since February 2018 when QEP's Board approved certain strategic and financial initiatives.

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 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, 2019	$	1.2	$	—	$	—	$	6.5	$	—	$	7.7
Costs incurred and charged to expense	1.0		—		0.5		0.4		—		1.9
Costs paid or otherwise settled	(2.2)		—		(0.5)		(6.9)		—		(9.6)
Balance at December 31, 2020	$	—	$	—	$	—	$	—	$	—	$	—

Debt (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt Outstanding

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


	December 31,
	2020		2019
	(in millions)
Revolving Credit Facility due 2022	$	—	$	—
6.875% Senior Notes due 2021	—		382.4
5.375% Senior Notes due 2022	465.1		500.0
5.25% Senior Notes due 2023	636.8		650.0
5.625% Senior Notes due 2026	500.0		500.0
Less: unamortized discount and unamortized debt issuance costs	(10.6)		(16.8)
Total long-term debt outstanding	$	1,591.3	$	2,015.6

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2020

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)
2021	$	28.0
2022	$	22.4
2023	$	12.2
2024	$	6.9
2025	$	4.9
After 2025	$	2.1

Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2020

Share-based Payment Arrangement, Noncash Expense [Abstract]

Share-based Compensation Expense [Table Text Block]

Share-based compensation expense is generally recognized within "General and administrative" expense on the statements of operations and is summarized in the table below.


	Year Ended December 31,
	2020(1)(2)		2019(3)		2018(4)
	(in millions)
Non-cash share-based compensation
Stock options	$	—	$	0.4	$	1.2
Restricted share awards	12.4		20.4		27.5
Total non-cash share-based compensation	12.4		20.8		28.7
Cash share-based compensation
Restricted cash awards	1.7		—		—
Performance share units	1.0		4.3		8.1
Restricted share units	0.1		0.3		0.1
Total cash share-based compensation	2.8		4.6		8.2
Total share-based compensation expense	$	15.2	$	25.4	$	36.9

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, 2019	1,802,387	$	20.87
Exercised	—	—
Cancelled	(311,203)	30.08
Outstanding at December 31, 2020	1,491,184	$	18.94	1.77	$	—
Options Exercisable at December 31, 2020	1,491,184	$	18.94	1.77	$	—
Unvested Options at December 31, 2020	—	$	—	0.00	$	—

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, 2019	2,845,033	$	8.67
Granted	5,080,589	2.10
Vested	(2,240,899)	7.09
Forfeited	(109,925)	4.79
Unvested balance at December 31, 2020	5,574,798	$	3.39

Schedule Of Long Term Incentive Compensation Restricted Cash Awards [Table Text Block]

Transactions involving restricted cash awards under the terms of the LTIP are summarized below:


	Restricted Cash Awards Outstanding

Unvested balance at December 31, 2019	$	—
Granted	3,249,925
Vested	(7,000)
Forfeited	(75,250)
Unvested balance at December 31, 2020	$	3,167,675

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, 2019	625,922	$	9.04
Granted	1,926,026	2.17
Vested	(96,734)	13.06
Unvested balance at December 31, 2020	2,455,214	$	3.56

Restricted Share Units Activity [Table Text Block]

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


	Restricted Share Units Outstanding	Weighted-Average Grant Date Fair Value
		(per share)
Unvested balance at December 31, 2019	34,393	$	8.16
Granted	76,083	2.08
Vested and paid	(26,770)	8.20
Unvested balance at December 31, 2020	83,706	$	2.62

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2020

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

Summary of Curtailments in Statements of Operations [Table Text Block]


	Year ended December 31,
Statements of Operations Line	2020		2019		2018
Interest and other income (expense)	$	—	$	(1.4)	$	(0.3)
Net gain (loss) from asset sales, inclusive of restructuring costs	—		0.2		0.2
Total curtailment gain (loss)	$	—	$	(1.2)	$	(0.1)

Schedule of Defined Benefit Plans Disclosures [Table Text Block]


	Pension Plan and SERP benefits				Medical Plan benefits
	2020		2019		2020		2019
Change in benefit obligation	(in millions)
Benefit obligation at January 1,	$	135.2	$	122.1	$	2.6	$	2.5
Service cost	—		0.3		—		—
Interest cost	4.1		4.8		0.1		0.1
Curtailments	—		1.2		—		—
Benefit payments	(10.3)		(6.2)		(0.7)		(0.9)
Plan amendments	—		—		—		—
Actuarial loss (gain)	11.7		13.0		0.7		0.9
Settlement loss	(5.4)		—		—		—
Benefit obligation at December 31,	$	135.3	$	135.2	$	2.7	$	2.6
Change in plan assets
Fair value of plan assets at January 1,	$	113.9	$	93.3	$	—	$	—
Actual return on plan assets	16.1		21.3		—		—
Company contributions to the plan	13.7		5.5		0.7		0.9
Benefit payments	(10.3)		(6.2)		(0.7)		(0.9)
Settlement loss	(5.4)		—		—		—
Fair value of plan assets at December 31,	128.0		113.9		—		—
Underfunded status (current and long-term)	$	(7.3)	$	(21.3)	$	(2.7)	$	(2.6)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(3.1)	$	(9.2)	$	(0.1)	$	(0.2)
Other long-term liabilities	(4.2)		(12.1)		(2.6)		(2.4)
Total amount recognized in balance sheet	$	(7.3)	$	(21.3)	$	(2.7)	$	(2.6)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	15.4	$	15.7	$	1.0	$	0.4
Prior service cost	—		—		—		—
Total amount recognized in AOCI	$	15.4	$	15.7	$	1.0	$	0.4

Pension and Other Postretirement Benefit Costs

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


	Pension Plan and SERP benefits						Medical Plan benefits
	2020		2019		2018		2020		2019		2018
Components of net periodic benefit cost	(in millions)
Service cost	$	—	$	0.3	$	0.8	$	—	$	—	$	—
Interest cost	4.1		4.8		4.6		0.1		0.1		0.1
Expected return on plan assets	(6.1)		(5.9)		(5.8)		—		—		—
Curtailment (gain) loss	—		2.0		0.3		—		(0.8)		(0.2)
Settlement loss	1.0		—		—		—		—		—
Amortization of prior service costs	—		0.4		0.8		—		—		(0.3)
Amortization of actuarial loss	0.9		0.5		0.8		—		—		—
Periodic expense	$	(0.1)	$	2.1	$	1.5	$	0.1	$	(0.7)	$	(0.4)
Components recognized in accumulated other comprehensive income
Current period prior service cost	$	—	$	—	$	—	$	—	$	—	$	0.2
Current period actuarial (gain) loss	1.6		(2.4)		5.6		0.7		0.9		(0.1)
Amortization of prior service cost	—		(0.4)		(0.8)		—		0.8		0.3
Amortization of actuarial gain (loss)	(0.9)		(0.5)		(0.8)		—		—		—
Loss on curtailment in current period	—		(0.8)		(0.1)		—		—		—
Settlement loss	(1.0)		—		—		—		—		—
Total amount recognized in accumulated other comprehensive income	$	(0.3)	$	(4.1)	$	3.9	$	0.7	$	1.7	$	0.4

Weighted Average Discount Rates [Table Text Block]


	Pension Plan and SERP benefits				Medical Plan benefits
	2020		2019		2020		2019
Discount rate	2.45	%	3.13	%	2.70	%	3.40	%

Schedule of Assumptions Used [Table Text Block]


	Pension Plan and SERP benefits						Medical Plan benefits
	2020		2019		2018		2020		2019		2018
Discount rate	3.21	%	4.19	%	3.50	%	3.40	%	4.30	%	3.60	%
Expected long-term return on plan assets	5.70	%	5.70	%	6.00	%	n/a		n/a		n/a
Rate of increase in compensation(1)	n/a		3.00	%	3.50	%	n/a		n/a		n/a

_______________________

Schedule of Allocation of Plan Assets [Table Text Block]

The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2020 and 2019, respectively:


	December 31, 2020				December 31, 2019
	Total		Percentage of total		Total		Percentage of total
	(in millions, except percentages)
Cash and short-term investments	$	0.6	—	%	$	0.6	1	%
Equity securities:
Domestic	23.8		19	%	30.6		27	%
International	8.5		7	%	10.5		9	%
Fixed income	95.1		74	%	72.2		63	%
Total investments	$	128.0	100	%	$	113.9	100	%

Schedule of Expected Benefit Payments [Table Text Block]

Expected Benefit Payments

As of December 31, 2020, the following future benefit payments are expected to be paid:


	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2021	$	9.0	$	0.2
2022	$	9.1	$	0.2
2023	$	7.6	$	0.1
2024	$	7.5	$	0.1
2025	$	6.8	$	0.1
2026 through 2030	$	31.4	$	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,
	2020		2019		2018
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	%

Changes In WRAP Plan Obligations and Securities [Table Text Block]

"Deferred compensation mark-to-market adjustments" and "Unrealized gain/loss on marketable securities" for the years ended December 31, 2020, 2019 and 2018, respectively, are summarized in the table below:


	Year Ended December 31,
	(in millions)
	2020		2019		2018
Deferred compensation mark-to-market adjustments	$	1.0	$	2.3	$	(3.9)
Unrealized (gain)/loss on marketable securities	(3.2)		(3.9)		1.2

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018
Federal income tax provision (benefit)	(in millions)
Current	$	(189.5)	$	(32.2)	$	(71.3)
Deferred	116.0		55.7		(257.8)
State income tax provision (benefit)
Current	(1.0)		(15.1)		1.5
Deferred	(5.4)		(51.4)		10.2
Total income tax provision (benefit)	$	(79.9)	$	(43.0)	$	(317.4)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:


	Year Ended December 31,
	2020		2019		2018
Federal income taxes statutory rate	21.0	%	21.0	%	21.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	(1.6)	%	(2.5)	%	4.1	%

State rate change(1)	8.0	%	20.9	%	(2.9)	%
Valuation allowance(2)	3.3	%	(18.0)	%	(1.9)	%
Permanent adjustments(3)	(7.2)	%	(7.1)	%	(0.1)	%
Return to provision adjustment	1.1	%	2.7	%	(0.1)	%
Uncertain tax provision(4)	—	%	13.6	%	—	%
NOL rate re-measurements(5)	79.6	%	—	%	3.8	%
Effective income tax rate	104.2	%	30.6	%	23.9	%

____________________________

(4)During the year ended December 31, 2019, the Company recognized a tax benefit of $19.0 million due to the expiration of the statute of limitations related to the Company's uncertain tax position.

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

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


	December 31,
	2020		2019
Deferred tax liabilities	(in millions)
Property, plant and equipment	$	627.5	$	592.9

Operating lease right-of-use assets	10.7		12.7
Other	2.4		0.9
Total deferred tax liabilities	640.6		606.5
Deferred tax assets
NOL and tax credit carryforwards	$	306.2	$	337.7
State NOL valuation allowance	(101.9)		(98.8)
Employee benefits and compensation costs	15.9		22.3
Interest carryforward (1)	—		45.7
Commodity price derivatives	17.0		3.9
Operating lease liabilities	11.7		14.1
Other	6.5		7.1
Total deferred tax assets	255.4		332.0
Net deferred income tax liability	$	385.2	$	274.5
Balance sheet classification
Deferred income tax liability – noncurrent	385.2		274.5
Net deferred income tax liability	$	385.2	$	274.5

Summary of Operating Loss Carryforwards [Table Text Block]

The tax effected amounts and expiration dates of NOL and tax credit carryforwards at December 31, 2020, are as follows:


	Expiration Dates	Amounts
		(in millions)
State NOL and tax credit carryforwards	2021-Indefinite	$	121.1
U.S. NOL(1)	2037-Indefinite	181.3
General business credits	2036-2037	3.8
Total NOL and tax credit carryforwards		$	306.2

____________________________

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

The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2020 and 2019:


	Unrecognized Tax Benefits
	2020		2019
	(in millions)
Balance as of January 1,	$	—	$	19.0
Recognized tax benefits	—		(19.0)
Balance as of December 31,	$	—	$	—

Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

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
2020	(in millions, except per share amounts or otherwise specified)
Revenues	$	225.8	$	120.6	$	177.8	$	200.2	$	724.4
Operating income (loss)	$	(7.2)	$	(112.5)	$	(42.1)	$	(61.9)	$	(223.7)
Net income (loss)	$	367.4	$	(184.4)	$	(49.2)	$	(130.6)	$	3.2
Net gain (loss) from asset sales, inclusive of restructuring costs and impairment	$	3.7	$	—	$	0.1	$	(11.3)	$	(7.5)
Per share information
Basic EPS	$	1.54	$	(0.76)	$	(0.20)	$	(0.54)	$	0.01
Diluted EPS	$	1.54	$	(0.76)	$	(0.20)	$	(0.54)	$	0.01
Production information
Total equivalent production (Mboe)	7,930.9		7,972.9		7,057.0		7,364.1		30,324.9


2019
Revenues	$	280.6	$	296.2	$	307.5	$	321.9	$	1,206.2
Operating income (loss)	$	(15.8)	$	72.3	$	52.1	$	48.9	$	157.5
Net income (loss)	$	(116.7)	$	48.8	$	81.0	$	(110.4)	$	(97.3)
Net gain (loss) from asset sales, inclusive of restructuring costs and impairment	$	(18.2)	$	17.8	$	(2.1)	$	1.4	$	(1.1)
Per share information
Basic EPS	$	(0.49)	$	0.20	$	0.34	$	(0.46)	$	(0.41)
Diluted EPS	$	(0.49)	$	0.20	$	0.34	$	(0.46)	$	(0.41)
Production information
Total equivalent production (Mboe)	7,806.3		7,534.7		8,404.0		8,465.3		32,210.3

Supplemental Gas and Oil Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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

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


	December 31,
	2020		2019
	(in millions)
Proved properties	$	9,941.2	$	9,574.9
Unproved properties, net	454.4		599.1
Total proved and unproved properties	10,395.6		10,174.0
Accumulated depreciation, depletion and amortization	(5,728.0)		(5,250.5)
Net capitalized costs	$	4,667.6	$	4,923.5

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


	Year Ended December 31,
	2020		2019		2018
	(in millions)
Proved property acquisitions	$	2.9	$	1.5	$	39.1
Unproved property acquisitions	1.2		2.0		25.8
Other acquisitions	—		—		0.8
Exploration costs (capitalized and expensed)	0.2		0.1		0.3
Development costs	324.8		556.2		1,133.1
Total costs incurred	$	329.1	$	559.8	$	1,199.1

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


	Year Ended December 31,
	2020		2019		2018
	(in millions)
Revenues	$	721.0	$	1,200.6	$	1,920.3
Production costs	292.9		361.9		507.3
Exploration expenses	0.2		0.1		0.3
Depreciation, depletion and amortization	564.2		528.5		836.4
Impairment	8.7		—		1,560.9
Gathering and other expense	(0.2)		—		—
Total expenses	865.8		890.5		2,904.9
Income (loss) before income taxes	(144.8)		310.1		(984.6)
Income tax benefit (expense)	32.1		(69.5)		243.2
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	(112.7)	$	240.6	$	(741.4)

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


	Oil and condensate	Gas	NGL	Total(10)
	(MMbbl)	(Bcf)	(MMbbl)	(MMboe)
Balance at December 31, 2017	320.5	1,793.6	65.2	684.7
Revisions of previous estimates(1)	2.1	314.0	6.7	61.0
Extensions and discoveries(2)	57.1	56.5	9.8	76.3
Purchase of reserves in place(3)	8.2	7.9	1.3	10.9
Sale of reserves in place(4)	(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
Revisions of previous estimates(5)	(94.9)	(23.0)	(8.7)	(107.3)
Extensions and discoveries(6)	33.6	40.0	7.4	47.6
Purchase of reserves in place(7)	3.6	4.0	0.7	4.9
Sale of reserves in place(8)	(4.9)	(1,102.2)	(0.3)	(188.9)
Production	(21.6)	(33.1)	(5.1)	(32.2)
Balance at December 31, 2019	254.9	373.3	65.2	382.3
Revisions of previous estimates(9)	2.7	27.6	4.1	11.4
Extensions and discoveries	0.1	0.2	—	0.2

Sale of reserves in place	(0.1)	(0.3)	—	(0.2)
Production	(19.7)	(32.5)	(5.2)	(30.3)
Balance at December 31, 2020	237.9	368.3	64.1	363.4
Proved developed reserves
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
Balance at December 31, 2019	117.5	217.0	36.7	190.4
Balance at December 31, 2020	101.2	185.0	32.0	164.0
Proved undeveloped reserves
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
Balance at December 31, 2019	137.4	156.3	28.5	191.9
Balance at December 31, 2020	136.7	183.3	32.1	199.4

___________________________

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

(3)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.

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

(7)Purchase of reserves in place in 2019 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.

(8)Sale of reserves in place in 2019 was primarily related to QEP's Haynesville Divestiture as discussed in Note 3 – Acquisitions and Divestitures.

(10)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.

Stan

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,
	2020		2019		2018
Average benchmark price per unit:
Oil price (per bbl)	$	39.57	$	55.51	$	65.56
Gas price (per MMbtu)	$	1.99	$	2.58	$	3.10

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,
	2020		2019		2018
	(in millions)
Future cash inflows	$	9,657.0	$	14,447.6	$	26,482.6
Future production costs	(4,728.9)		(6,070.6)		(9,539.9)
Future development costs(1)	(1,671.0)		(2,275.2)		(4,441.5)
Future income tax expenses(2)	(294.8)		(845.8)		(2,553.6)
Future net cash flows	2,962.3		5,256.0		9,947.6
10% annual discount for estimated timing of net cash flows	(1,427.0)		(2,579.7)		(4,991.9)
Standardized measure of discounted future net cash flows	$	1,535.3	$	2,676.3	$	4,955.7

___________________________

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

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,
	2020		2019		2018
	(in millions)
Balance at January 1,	$	2,676.3	$	4,955.7	$	3,097.3
Sales of oil and condensate, gas and NGL produced, net of production costs	(428.1)		(838.7)		(1,413.0)
Net change in sales prices and in production (lifting) costs related to future production	(2,136.4)		(1,988.6)		1,632.5
Net change due to extensions and discoveries	2.4		220.9		692.6
Net change due to revisions of quantity estimates	159.6		(2,079.2)		732.0
Net change due to purchases of reserves in place	—		34.2		117.0
Net change due to sales of reserves in place	(1.9)		(617.8)		(369.6)
Previously estimated development costs incurred during the period	256.1		460.8		735.6
Changes in estimated future development costs	418.7		1,064.7		(28.3)
Accretion of discount	310.7		622.8		375.4
Net change in income taxes	277.9		841.5		(615.7)
Other	—		—		(0.1)
Net change	(1,141.0)		(2,279.4)		1,858.4
Balance at December 31,	$	1,535.3	$	2,676.3	$	4,955.7

- 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 Merger (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
General and Administrative Expense [Abstract]
Merger Related Costs	$ 4.5
Other Prepaid Expense, Current	$ 5.0

Summary of Significant Accounting Policies Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Cash, Cash Equivalents and Restricted Cash [Abstract]
Cash and cash equivalents	$ 60.4	$ 166.3
Restricted cash	31.9	30.1
Total cash, cash equivalents and restricted cash	$ 92.3	$ 196.4

Summary of Significant Accounting Policies Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Noncash Investing and Financing Items [Abstract]
Capital expenditure accrual balance	$ 37.8	$ 63.3	$ 54.5
Other Noncash Income (Expense) [Abstract]
Right-of-use assets obtained in exchange for operating lease obligations	11.0	16.6	0.0
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of capitalized interest	118.4	126.9	136.9
Cash paid (refund received) for income taxes, net	(164.0)	(66.7)	0.8
Cash paid for amounts included in the measurement of lease liabilities	$ 25.7	$ 25.3	$ 0.0

Summary of Significant Accounting Policies Accounts Receivable (Details) - SEC Schedule, 12-09, Allowance, Credit Loss [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Bad Debt Expense		$ 0.3	$ 0.6
Bad debt recoveries	$ (0.3)
Allowance for Doubtful Accounts Receivable	$ 1.7	$ 1.6

Summary of Significant Accounting Policies Property, plant and equipment (Details)	12 Months Ended
	Dec. 31, 2020
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 ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 8.7	$ 5.0	$ 1,560.9
Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			1,524.6
ProvedAndUnprovedProperties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment			$ 1,559.3

Summary of Significant Accounting Policies Credit Risk (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Concentration Risk [Line Items]
Concentration Risk, Percentage	63.00%	66.00%	49.00%
Occidental Energy Marketing [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		21.00%	16.00%
Plains Marketing LP [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		17.00%	12.00%
Valero Marketing And Supply Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	30.00%	18.00%
Phillips66 [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%

Summary of Significant Accounting Policies Income Taxes (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Federal statutory income tax rate	21.00%	21.00%	21.00%	35.00%

Summary of Significant Accounting Policies Earnings Per Share (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	0.0
Weighted-average basic common shares outstanding	241.6	237.7	237.9
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	241.6	237.7	237.9

Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
Revenue (Details) - USD ($) $ in Millions	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenues	$ 200.2	$ 177.8	$ 120.6	$ 225.8	$ 321.9	$ 307.5	$ 296.2	$ 280.6	$ 724.4	$ 1,206.2
As reported [Member]
Disaggregation of Revenue [Line Items]
Revenues									714.6	1,187.4	$ 1,871.3
Williston Basin [Member] \| As reported [Member]
Disaggregation of Revenue [Line Items]
Revenues									244.6	438.9	765.7
Other Northern [Member] \| As reported [Member]
Disaggregation of Revenue [Line Items]
Revenues									1.3	1.6	6.9
Permian Basin [Member] \| As reported [Member]
Disaggregation of Revenue [Line Items]
Revenues									468.7	740.7	739.3
Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenues										5.9
Haynesville [Member] \| As reported [Member]
Disaggregation of Revenue [Line Items]
Revenues											304.1
Other Southern [Member] \| As reported [Member]
Disaggregation of Revenue [Line Items]
Revenues									0.0	6.2	0.2
Uinta Basin [Member] \| As reported [Member]
Disaggregation of Revenue [Line Items]
Revenues											55.1
Oil and Condensate [Member]
Disaggregation of Revenue [Line Items]
Revenues									691.8	1,132.6	1,422.4
Oil and Condensate [Member] \| Williston Basin [Member]
Disaggregation of Revenue [Line Items]
Revenues									249.9	420.8	707.0
Oil and Condensate [Member] \| Other Northern [Member]
Disaggregation of Revenue [Line Items]
Revenues									0.2	1.1	4.9
Oil and Condensate [Member] \| Permian Basin [Member]
Disaggregation of Revenue [Line Items]
Revenues									441.7	710.6	684.4
Oil and Condensate [Member] \| Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenues											1.0
Oil and Condensate [Member] \| Other Southern [Member]
Disaggregation of Revenue [Line Items]
Revenues									0.0	0.1	(0.2)
Oil and Condensate [Member] \| Uinta Basin [Member]
Disaggregation of Revenue [Line Items]
Revenues											25.3
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues									39.6	52.4	393.1
Natural Gas [Member] \| Williston Basin [Member]
Disaggregation of Revenue [Line Items]
Revenues									18.1	33.1	45.3
Natural Gas [Member] \| Other Northern [Member]
Disaggregation of Revenue [Line Items]
Revenues									1.1	0.4	2.0
Natural Gas [Member] \| Permian Basin [Member]
Disaggregation of Revenue [Line Items]
Revenues									20.4	12.8	17.3
Natural Gas [Member] \| Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenues											303.1
Natural Gas [Member] \| Other Southern [Member]
Disaggregation of Revenue [Line Items]
Revenues									0.0	6.1	0.4
Natural Gas [Member] \| Uinta Basin [Member]
Disaggregation of Revenue [Line Items]
Revenues											25.0
Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenues									45.7	57.3	110.8
Natural Gas Liquids [Member] \| Williston Basin [Member]
Disaggregation of Revenue [Line Items]
Revenues									14.4	19.4	56.5
Natural Gas Liquids [Member] \| Other Northern [Member]
Disaggregation of Revenue [Line Items]
Revenues									0.0	0.1	0.0
Natural Gas Liquids [Member] \| Permian Basin [Member]
Disaggregation of Revenue [Line Items]
Revenues									31.3	37.8	49.5
Natural Gas Liquids [Member] \| Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenues											0.0
Natural Gas Liquids [Member] \| Other Southern [Member]
Disaggregation of Revenue [Line Items]
Revenues									0.0	0.0	0.0
Natural Gas Liquids [Member] \| Uinta Basin [Member]
Disaggregation of Revenue [Line Items]
Revenues											4.8
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold									(62.5)	(54.9)	(55.0)
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] \| Williston Basin [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold									(37.8)	(34.4)	(43.1)
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] \| Other Northern [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold									0.0	0.0	0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] \| Permian Basin [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold									(24.7)	(20.5)	(11.9)
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] \| Haynesville [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold											0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] \| Other Southern [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold									$ 0.0	$ 0.0	0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] \| Uinta Basin [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold											$ 0.0

Acquisitions and Divestitures Other Acquisitions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Additional acquisitions in the Permian Basin [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 4.1	$ 3.5	$ 65.6

Acquisitions and Divestitures Haynesville/Cotton Valley Divestiture (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 13.8	$ 678.9	$ 243.6
Gain (Loss) on Disposition of Oil and Gas Property	$ 1.2	3.9	25.0
Haynesville Divestiture [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Definitive Agreement Agreed Upon Sales Price			735.0
Proceeds from Sale of Oil and Gas Property and Equipment		633.9
Escrow Deposit			32.2
Restructuring Charges		1.4	3.0
Gain (Loss) on Disposition of Oil and Gas Property		(1.0)	(3.0)
Income before income taxes		$ 3.2	$ 76.0

Acquisitions and Divestitures Terminated Williston Basin Divestiture (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 13.8	$ 678.9	$ 243.6
Impairment	$ 8.7	$ 5.0	1,560.9
ProvedAndUnprovedProperties [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment			1,559.3
Williston Basin Divestiture [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Definitive Agreement Agreed Upon Sales Price			1,725.0
Cash and Contractual Rights			1,650.0
Rights To Acquire Common Stock			75.0
Impairment			$ 1,560.9

Acquisitions and Divestitures Uinta Basin Divestiture (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 13.8	$ 678.9	$ 243.6
Gain (Loss) on Disposition of Oil and Gas Property	$ 1.2	3.9	25.0
Uinta Basin Divestiture [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			153.0
Restructuring Charges			5.4
Impairment of Oil and Gas Properties			402.8
Gain (Loss) on Disposition of Oil and Gas Property		$ (0.2)	$ (12.6)

Acquisitions and Divestitures Other Divestitures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 13.8	$ 678.9	$ 243.6
Other Property [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	13.8	45.1	90.6
Gain (Loss) on Disposition of Oil and Gas and Timber Property	$ 1.2	$ 5.1	$ 38.5

Asset Retirement Obligations Balance Sheet Classification (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation, Current	$ 6.4	$ 6.0
Asset Retirement Obligations, Noncurrent	96.3	94.9
Asset Retirement Obligation	$ 102.7	$ 100.9	$ 159.6

Asset Retirement Obligations ARO Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation	$ 100.9	$ 159.6
Asset Retirement Obligation, Accretion Expense	4.0	5.2
Asset Retirement Obligation, Liabilities Incurred	1.2	1.1
Asset Retirement Obligation, Revision of Estimate	0.0	(2.2)
ARO Liabilities Transferred	1.4	60.7
Asset Retirement Obligation, Liabilities Settled	(2.0)	(2.1)
Asset Retirement Obligation	$ 102.7	100.9
Haynesville Divestiture [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO Liabilities Transferred		$ 57.6

Fair Value Measurements (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Option, Quantitative Disclosures [Line Items]
Impairment	$ 8.7	$ 5.0	$ 1,560.9
Proved properties [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Impairment of Oil and Gas Properties			$ 1,524.6
Williston Basin Divestiture [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Divestiture, buyer's common stock		5.8
Williston Basin Divestiture [Member] \| Measurement Input, Risk Free Interest Rate [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Risk Free Interest Rate		5.00%
Williston Basin Divestiture [Member] \| Measurement Input, Price Volatility [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Weighted Average Volatility Rate		49.30%

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

Dec. 31, 2020

Dec. 31, 2019

Financial Assets

Netting Adjustments

$ (1.4)

$ 0.0

^[1]

Assets, Fair Value Disclosure

23.4

24.8

Rabbi Trust Marketable Securities

23.4

23.1

Financial liabilities

Netting Adjustments

^[1]

(1.4)

0.0

Financial Liabilities Fair Value Disclosure

102.2

46.0

WRAP Plan Liabilities

25.5

26.8

Level 1 [Member]

Financial Assets

Assets, Fair Value Disclosure

23.4

23.1

Financial liabilities

Financial Liabilities Fair Value Disclosure

25.5

26.8

Level 2 [Member]

Financial Assets

Assets, Fair Value Disclosure

1.4

1.7

Financial liabilities

Financial Liabilities Fair Value Disclosure

78.1

19.2

Level 3 [Member]

Financial Assets

Assets, Fair Value Disclosure

0.0

Financial liabilities

Financial Liabilities Fair Value Disclosure

0.0

Long term [Member]

Financial Assets

Netting Adjustments

^[1]

0.0

Derivative Asset

0.0

0.2

Rabbi Trust Marketable Securities

23.4

23.1

Financial liabilities

Netting Adjustments

^[1]

0.0

Derivative Liability

0.3

0.5

WRAP Plan Liabilities

25.5

26.8

Long term [Member] | Level 1 [Member]

Financial Assets

Derivative instruments

0.0

Investments, Fair Value Disclosure

23.4

23.1

Financial liabilities

Derivative instruments

0.0

FairValueofDeferredCompensationLiabilities

25.5

26.8

Long term [Member] | Level 2 [Member]

Financial Assets

Derivative instruments

0.0

0.2

Financial liabilities

Derivative instruments

0.3

0.5

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]

(1.4)

0.0

Derivative Asset

0.0

1.5

Financial liabilities

Netting Adjustments

^[1]

(1.4)

0.0

Derivative Liability

76.4

18.7

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

1.4

1.5

Financial liabilities

Derivative instruments

77.8

18.7

Short term [Member] | Level 3 [Member]

Financial Assets

Derivative instruments

0.0

Financial liabilities

Derivative instruments

$ 0.0

[1]	The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the balance sheets for the contracts that contain netting provisions. Refer to Note 6 – 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, 2020	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Long-term debt	$ 1,591.3	$ 2,015.6
Long-term debt, Level 1 Fair Value	$ 1,702.8	$ 2,029.4

Derivative Contracts (Narrative) (Details)	12 Months Ended
Derivative Contracts (Narrative) (Details)	Dec. 31, 2019
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	12 Months Ended
	Dec. 31, 2020 USD ($) bbl bbl $ / bbl
Oil Swaps [Member] \| Year 2021 January to June [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,300,000
Underlying, Derivative Asset \| $ / bbl	44.54
Oil Swaps [Member] \| Year 2021 July To December [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,300,000
Underlying, Derivative Asset \| $ / bbl	42.64
Oil Swaps [Member] \| Year 2022 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	200,000
Underlying, Derivative Asset \| $ / bbl	45.00
Oil Basis Swaps [Member] \| Year 2021 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,800,000
Derivatives, Weighted Average Differential \| $	$ 0.88
Oil Basis Swaps [Member] \| Year 2021 [Member] \| Argus WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,500,000
Derivatives, Weighted Average Differential \| $	$ 0.00
Oil Basis Swaps [Member] \| Year 2021 [Member] \| NymexRoll [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,800,000
Derivatives, Weighted Average Differential \| $	$ (0.05)
Gas Sales [Member] \| Year 2021 [Member] \| IF Waha [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	18,300,000
Underlying, Derivative Asset \| $ / bbl	1.92
Gas Sales [Member] \| Year 2021 [Member] \| Nymex HH [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,100,000
Underlying, Derivative Asset \| $ / bbl	2.44
Costless Oil Collars [Member] \| Year 2021 January to June [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.3
Derivative, Average Floor Price \| $ / bbl	40.73
Derivative, Average Cap Price \| $ / bbl	50.17
Costless Oil Collars [Member] \| Year 2021 July To December [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.8
Derivative, Average Floor Price \| $ / bbl	40.16
Derivative, Average Cap Price \| $ / bbl	49.89

Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	$ 291.9	$ (35.1)	$ (158.1)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(59.2)	(140.1)	254.4
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	232.7	(175.2)	96.3
Realized and unrealized gains (losses) on derivative contracts	232.7	(173.4)	90.4
Oil derivative contracts [Member] \| Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	296.4	(32.2)	(153.4)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(48.7)	(139.8)	277.0
Gas derivative contracts [Member] \| Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	(4.5)	(2.9)	(5.0)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(10.5)	(0.3)	(22.3)
Gas derivative contracts [Member] \| Storage [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.0	0.3
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.0	(0.3)
Uinta Basin Divestiture [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments			(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			(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			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			$ (3.2)
Haynesville Divestiture [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	1.8
Haynesville 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	0.0
Haynesville 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	0.0	1.8
Haynesville 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	$ 0.0	$ 0.0

Lease Costs (Details) - USD ($) $ in Millions	12 Months Ended
Lease Costs (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Lessor, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	3 years 7 months 6 days	5 years 4 months 24 days
Operating Lease, Weighted Average Discount Rate, Percent	7.20%	8.00%
Operating Leases, Rent Expense	$ 25.7	$ 25.3	$ 30.3
Property, Plant and Equipment [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	11.7	13.8
Lease Operating Expense [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	14.0	11.9
Gathering and other expense [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	5.7	7.7
General and administrative expense [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	$ 6.0	$ 5.7

Leases Long-Term Operating Lease Commitments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 24.9
Operating Leases, Future Minimum Payments, Due in Two Years	17.2
Operating Leases, Future Minimum Payments, Due in Three Years	11.5
Operating Leases, Future Minimum Payments, Due in Four Years	2.4
Operating Leases, Future Minimum Payments, Due in Five Years	0.8
Operating Leases, Future Minimum Payments, Due Thereafter	2.9
Operating Leases, Undiscounted Interest	(6.7)
Operating Lease, Liability	53.0
Current operating lease liabilities	21.7	$ 18.0
Operating lease liabilities	$ 31.3	$ 44.8

Restructuring Costs Costs recognized and remaining costs expected to be incurred (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Cost Incurred to Date	$ 111.3
Restructuring Costs, Expected Costs	0.0
Termination benefits
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Cost Incurred to Date	45.6
Restructuring Costs, Expected Costs	0.0
Office lease termination costs
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Cost Incurred to Date	1.6
Restructuring Costs, Expected Costs	0.0
Accelerated share-based compensation
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Cost Incurred to Date	24.1
Restructuring Costs, Expected Costs	0.0
Retention expense (including share-based compensation)
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Cost Incurred to Date	38.7
Restructuring Costs, Expected Costs	0.0
Pension and Medical Plan curtailment
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Cost Incurred to Date	1.3
Restructuring Costs, Expected Costs	$ 0.0

Restructuring Costs Restructuring Liability (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2019	$ 7.7
Costs incurred and charged to expense	1.9
Costs paid or otherwise settled	(9.6)
Balance at December 31, 2020	0.0
Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2019	1.2
Costs incurred and charged to expense	1.0
Costs paid or otherwise settled	(2.2)
Balance at December 31, 2020	0.0
Office lease termination costs
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2019	0.0
Costs incurred and charged to expense	0.0
Costs paid or otherwise settled	0.0
Balance at December 31, 2020	0.0
Accelerated Share Based Compensation [Member]
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2019	0.0
Costs incurred and charged to expense	0.5
Costs paid or otherwise settled	(0.5)
Balance at December 31, 2020	0.0
Retention Expense [Member]
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2019	6.5
Costs incurred and charged to expense	0.4
Costs paid or otherwise settled	(6.9)
Balance at December 31, 2020	0.0
Pension and Medical Plan curtailment
Restructuring Cost and Reserve [Line Items]
Balance at December 31, 2019	0.0
Costs incurred and charged to expense	0.0
Costs paid or otherwise settled	0.0
Balance at December 31, 2020	$ 0.0

Debt (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
Debt (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Principal amount of debt	$ 1,591.3	$ 2,015.6
Long-term Debt, Weighted Average Interest Rate, at Point in Time	2.60%	4.73%
Long-term Debt	$ 1,601.9
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	5.25%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	5.625%
Gain (loss) from early extinguishment of debt	$ 18.2	$ (1.0)	$ 0.0
Senior Note Repurchase Capacity	500.0
Subsidiary Guarantee Issuance Capacity	500.0
Minimum Liquidity Amount	100.0
Gain (Loss) on Extinguishment of Debt, before Write off of Debt Issuance Cost	19.7
Debt Repurchases [Member]
Debt Instrument [Line Items]
Gain (loss) from early extinguishment of debt	27.1
Debt Redemptions [Member]
Debt Instrument [Line Items]
Gain (loss) from early extinguishment of debt	(7.4)
Revolving Credit Facility due 2022 [Member]
Debt Instrument [Line Items]
Principal amount of debt	0.0	0.0
Long-term Line of Credit	850.0
Letters of Credit Outstanding, Amount	14.1	2.9
Gain (Loss) on Extinguishment of Debt, before Write off of Debt Issuance Cost	(1.5)
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Principal amount of debt	0.0	382.4
Senior Notes Due 2021 [Member] \| Debt Repurchases [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	107.1
Senior Notes Due 2021 [Member] \| Debt Redemptions [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	275.3
Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Principal amount of debt	$ 465.1	500.0
Debt Instrument, Interest Rate, Stated Percentage	5.375%
Senior Notes Due 2022 [Member] \| Debt Repurchases [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 34.9
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Principal amount of debt	$ 636.8	650.0
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Senior Notes Due 2023 [Member] \| Debt Repurchases [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 13.2
Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Principal amount of debt	$ 500.0	$ 500.0
Debt Instrument, Interest Rate, Stated Percentage		5.625%

Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Principal amount of debt	$ 1,591.3	$ 2,015.6
Less unamortized discount	(10.6)	(16.8)
Revolving Credit Facility due 2022 [Member]
Debt Instrument [Line Items]
Principal amount of debt	0.0	0.0
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Principal amount of debt	0.0	382.4
Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Principal amount of debt	465.1	500.0
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Principal amount of debt	636.8	650.0
Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Principal amount of debt	$ 500.0	$ 500.0

Commitments and Contingencies Narrative (Details) $ in Millions	Dec. 31, 2020 USD ($)
Environmental Remediation Obligations [Abstract]
Loss Contingency, Estimate of Possible Loss	$ 10.0

Commitments and Contingencies Commitments (Details) $ in Millions	Dec. 31, 2020 USD ($)
Commitments [Abstract]
2020	$ 28.0
2021	22.4
2022	12.2
2023	6.9
2024	4.9
After 2024	$ 2.1

Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restructuring and Related Costs	$ 1.9	$ 46.2	$ 63.2
Number of Shares Authorized	10.0
Shares available for future grants	2.9
Share-based compensation expense	$ 15.2	25.4	36.9
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0.0	0.4	1.2
Intrinsic value of options exercised			$ 0.1
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 1.1	$ 2.3
Restricted Share Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 2.10	$ 7.72	$ 9.56
Share-based compensation expense	$ 12.4	$ 20.4	$ 27.5
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	2.5	5.4
Unrecognized compensation costs	$ 7.0
Weighted average period for recognition of equity-based compensation expense	1 year 11 months 4 days
Award vesting period	3 years
Total fair value of stock that vested during the period	$ 4.5	$ 32.5	$ 21.5
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 2.17	$ 7.93	$ 9.55
Share-based compensation expense	$ 1.0	$ 4.3	$ 8.1
Unrecognized compensation costs	$ 2.1
Weighted average period for recognition of equity-based compensation expense	1 year 10 months 28 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 0.3	$ 13.0	$ 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	$ 2.08	$ 7.87	$ 9.55
Share-based compensation expense	$ 0.1	$ 0.3	$ 0.1
Unrecognized compensation costs	$ 0.1
Weighted average period for recognition of equity-based compensation expense	9 months 29 days
Award vesting period	3 years
Restricted Cash Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1.7	0.0	0.0
Unrecognized compensation costs	$ 1.6
Weighted average period for recognition of equity-based compensation expense	2 years 3 months
Award vesting period	3 years
Net gain (loss) from asset sales, inclusive of restructuring costs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restructuring and Related Costs	$ 0.0	1.4	8.6
General and administrative expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restructuring and Related Costs	1.9	43.4	54.3
Accelerated Share Based Compensation [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restructuring and Related Costs	0.5	12.6	11.0
Accelerated Share Based Compensation [Member] \| Net gain (loss) from asset sales, inclusive of restructuring costs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restructuring and Related Costs	0.0	1.5	2.2
Accelerated Share Based Compensation [Member] \| General and administrative expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restructuring and Related Costs	$ 0.5	$ 11.1	$ 8.8

Share-Based Compensation Schedule of Share-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Expense [Line Items]
Share-based compensation expense	$ 15.2	$ 25.4	$ 36.9
Cash Shared Based Compensation	2.8	4.6	8.2
Noncash Share Based Compensation	12.4	20.8	28.7
Restructuring and Related Costs	1.9	46.2	63.2
Accelerated share-based compensation
Share-based Compensation Expense [Line Items]
Restructuring and Related Costs	0.5	12.6	11.0
Stock Options [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	0.0	0.4	1.2
Restricted Share Awards [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	12.4	20.4	27.5
Restricted Share Awards [Member] \| Accelerated share-based compensation
Share-based Compensation Expense [Line Items]
Merger Expenses	0.4
Performance Share Units [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	1.0	4.3	8.1
Restricted Share Units (RSUs) [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	0.1	0.3	0.1
Restricted Cash Awards [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	$ 1.7	$ 0.0	$ 0.0

Share-Based Compensation Schedule of Stock Option Transactions (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Stock options outstanding, beginning of year	1,802,387
Options exercised	0
Options Cancelled	(311,203)
Stock options outstanding, end of year	1,491,184	1,802,387
Options exercisable, shares	1,491,184
Unvested options, shares	0
Share-based Compensation Arrangement by Share-based Payment Award, Additional General Disclosures [Abstract]
Weighted average exercise price, beginning of year	$ 20.87
Weighted average exercise price, granted in period	0
Weighted average exercise price, cancelled in period	30.08
Weighted average exercise price, end of year	18.94	$ 20.87
Options exercisable, weighted average exercise price	18.94
Unvested options, weighted average exercise price	$ 0
Weighted average remaining contractual term, options outstanding	1 year 9 months 7 days
Weighted average remaining contractual term, options exercisable	1 year 9 months 7 days
Weighted average remaining contractual term, options unvested	0 years
Aggregate intrinsic value, options outstanding	$ 0.0
Aggregate intrinsic value, options exercisable	0.0
Aggregate intrinsic value, options unvested	0.0
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Additional General Disclosures [Abstract]
Intrinsic value of options exercised			$ 0.1
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 1.1	$ 2.3

Share-Based Compensation Schedule of Restricted Stock Transactions (Details) - Restricted Share Awards [Member] - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	2,845,033
Shares granted	5,080,589
Shares vested	(2,240,899)
Shares forfeited	(109,925)
Unvested balance at end of period	5,574,798	2,845,033
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	$ 8.67
Weighted average grant date fair value, grants	2.10	$ 7.72	$ 9.56
Weighted average grant date fair value, vested	7.09
Weighted average grant date fair value, forfeited	4.79
Weighted average grant date fair value, end of period	$ 3.39	$ 8.67

Share-Based Compensation Restricted Cash Awards (Details) - Restricted Cash Awards [Member] - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	3,167,675	0
Shares granted	3,249,925
Shares vested	(7,000)
Shares forfeited	(75,250)
Unvested balance at end of period	3,167,675

Share-Based Compensation Schedule of Performance Share Unit Transactions (Details) - Performance Share Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	625,922
Shares granted	1,926,026
Shares vested and paid out	(96,734)
Unvested balance at end of period	2,455,214	625,922
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	$ 9.04
Weighted average grant date fair value, grants	2.17	$ 7.93	$ 9.55
Weighted average grant date fair value, vested and paid out	13.06
Weighted average grant date fair value, end of period	$ 3.56	$ 9.04

Share-Based Compensation Schedule of Restricted Share Unit Transactions (Details) - Restricted Share Units (RSUs) [Member] - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested balance at beginning of period	34,393
Shares granted	76,083
Shares vested	(26,770)
Unvested balance at end of period	83,706	34,393
Weighted average grant date fair value, beginning of period	$ 8.16
Weighted average grant date fair value, grants	2.08	$ 7.87	$ 9.55
Weighted average grant date fair value, vested	8.20
Weighted average grant date fair value, end of period	$ 2.62	$ 8.16
Award vesting period	3 years

Employee Benefits (Narrative) (Details) $ in Millions	12 Months Ended
Employee Benefits (Narrative) (Details) $ in Millions	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Curtailment loss	$ 0.0	$ (1.2)	$ (0.1)
Defined Benefit Plan, Accumulated Benefit Obligation	135.3	135.2
401(k) Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Amount	3.0	3.6	5.8
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	4.0
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	$ 4.0
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	2
Defined Benefit Plan, Percentage Of Employees Covered	1.00%
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	212
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 9.7
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	3.1
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	0.7	0.9
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	0.2
Defined Benefit Plan, Curtailment loss	0.0	(0.8)	(0.2)
Defined Benefit Plan, Expected Amortization, Next Fiscal Year	$ 0.1
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	27
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	$ 13.7	5.5
Defined Benefit Plan, Curtailment loss	0.0	$ 2.0	$ 0.3
Defined Benefit Plan, Expected Amortization, Next Fiscal Year	$ 1.0

Employee Benefits Schedule of Curtailments in the Statements of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Curtailment loss	$ 0.0	$ (1.2)	$ (0.1)
Interest and other income (expense) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Curtailment loss	0.0	(1.4)	(0.3)
Net gain (loss) from asset sales, inclusive of restructuring costs [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Curtailment loss	$ 0.0	$ 0.2	$ 0.2

Employee Benefits Schedule of Changes in Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Change in plan assets
Fair value of plan assets at January 1,	$ 113.9
Fair value of plan assets at December 31,	128.0	$ 113.9
Pension Plan and SERP [Member]
Change in benefit obligation
Benefit obligation at January 1,	135.2	122.1
Service cost	0.0	0.3	$ 0.8
Interest cost	4.1	4.8	4.6
Curtailments	0.0	1.2
Benefit payments	(10.3)	(6.2)
Plan amendments	0.0	0.0
Actuarial loss (gain)	11.7	13.0
Settlement loss	(5.4)	0.0
Benefit obligation at December 31,	135.3	135.2	122.1
Change in plan assets
Fair value of plan assets at January 1,	113.9	93.3
Actual return on plan assets	16.1	21.3
Company contributions to the plan	13.7	5.5
Benefit payments	(10.3)	(6.2)
Fair value of plan assets at December 31,	128.0	113.9	93.3
Underfunded status (current and long-term)	(7.3)	(21.3)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(3.1)	(9.2)
Other long-term liabilities	(4.2)	(12.1)
Total amount recognized in balance sheet	(7.3)	(21.3)
Amounts recognized in AOCI
Net actuarial loss (gain)	15.4	15.7
Prior service cost	0.0	0.0
Total amount recognized in AOCI	15.4	15.7
Medical Plan [Member]
Change in benefit obligation
Benefit obligation at January 1,	2.6	2.5
Service cost	0.0	0.0	0.0
Interest cost	0.1	0.1	0.1
Curtailments	0.0	0.0
Benefit payments	(0.7)	(0.9)
Plan amendments	0.0	0.0
Actuarial loss (gain)	0.7	0.9
Settlement loss	0.0	0.0
Benefit obligation at December 31,	2.7	2.6	2.5
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	0.7	0.9
Benefit payments	(0.7)	(0.9)
Fair value of plan assets at December 31,	0.0	0.0	$ 0.0
Underfunded status (current and long-term)	(2.7)	(2.6)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(0.1)	(0.2)
Other long-term liabilities	(2.6)	(2.4)
Total amount recognized in balance sheet	(2.7)	(2.6)
Amounts recognized in AOCI
Net actuarial loss (gain)	1.0	0.4
Prior service cost	0.0	0.0
Total amount recognized in AOCI	$ 1.0	$ 0.4

Employee Benefits Schedule of Net Periodic Benefit Cost and Other Comprehensive Income for Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Components of net periodic benefit cost
Curtailment (gain) loss	$ 0.0	$ (1.2)	$ (0.1)
Pension Plan and SERP [Member]
Components of net periodic benefit cost
Service cost	0.0	0.3	0.8
Interest cost	4.1	4.8	4.6
Expected return on plan assets	(6.1)	(5.9)	(5.8)
Curtailment (gain) loss	0.0	2.0	0.3
Settlement loss	1.0	0.0	0.0
Amortization of prior service costs	0.0	0.4	0.8
Amortization of actuarial loss	0.9	0.5	0.8
Periodic expense	(0.1)	2.1	1.5
Components recognized in accumulated other comprehensive income
Current period prior service cost	0.0	0.0	0.0
Current period actuarial (gain) loss	1.6	(2.4)	5.6
Amortization of prior service cost	0.0	(0.4)	(0.8)
Amortization of actuarial gain (loss)	(0.9)	(0.5)	(0.8)
Loss on curtailment in current period	0.0	(0.8)	(0.1)
Settlement loss	(1.0)	0.0	0.0
Total amount recognized in accumulated other comprehensive income	(0.3)	(4.1)	3.9
Medical Plan [Member]
Components of net periodic benefit cost
Service cost	0.0	0.0	0.0
Interest cost	0.1	0.1	0.1
Expected return on plan assets	0.0	0.0	0.0
Curtailment (gain) loss	0.0	(0.8)	(0.2)
Settlement loss	0.0	0.0	0.0
Amortization of prior service costs	0.0	0.0	(0.3)
Amortization of actuarial loss	0.0	0.0	0.0
Periodic expense	0.1	(0.7)	(0.4)
Components recognized in accumulated other comprehensive income
Current period prior service cost	0.0	0.0	0.2
Current period actuarial (gain) loss	0.7	0.9	(0.1)
Amortization of prior service cost	0.0	0.8	0.3
Amortization of actuarial gain (loss)	0.0	0.0	0.0
Loss on curtailment in current period	0.0	0.0	0.0
Settlement loss	0.0	0.0	0.0
Total amount recognized in accumulated other comprehensive income	$ 0.7	$ 1.7	$ 0.4

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

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Medical Plan [Member]

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

Discount rate used in calculating benefit obligation

2.70%

3.40%

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

Discount rate used in calculating net periodic benefit cost

3.40%

4.30%

3.60%

Pension Plan and SERP [Member]

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

Discount rate used in calculating benefit obligation

2.45%

3.13%

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

Discount rate used in calculating net periodic benefit cost

3.21%

4.19%

3.50%

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

5.70%

6.00%

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

^[1]

3.00%

3.50%

[1]

As the Pension Plan was frozen, such that employees do not accrue additional defined benefits for future service or compensation on or after January 1, 2016, 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 of January 1, 2020, there were no longer any active employees eligible for the SERP. As such, the rate of increase in compensation is only used for the SERP for the years ended December 31, 2019 and 2018.

Employee Benefits Schedule of Fair Values of Pension and Postretirement Benefit Assets by Asset Class (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 128.0	$ 113.9
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	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, Plan Assets, Amount	$ 0.6	$ 0.6
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	0.00%	1.00%
Domestic equity securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 23.8	$ 30.6
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	19.00%	27.00%
International equity securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 8.5	$ 10.5
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	7.00%	9.00%
Fixed income securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 95.1	$ 72.2
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	74.00%	63.00%

- Definition

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

+ References + Details

Employee Benefits Schedule of Expected Benefit Payments for Pension and Other Postretirement Benefits (Details) $ in Millions	Dec. 31, 2020 USD ($)
Pension Plan and SERP [Member]
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2019	$ 9.0
2020	9.1
2021	7.6
2022	7.5
2023	6.8
2026 through 2030	31.4
Medical Plan [Member]
Defined Benefit Plan, Expected Future Benefit Payment [Abstract]
2019	0.2
2020	0.2
2021	0.1
2022	0.1
2023	0.1
2026 through 2030	$ 0.5

Employee Benefits EIP (Details) - USD ($) $ in Millions	12 Months Ended
Employee Benefits EIP (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 3.0	$ 3.6	$ 5.8
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		$ 0.1	$ 0.3

Employee Benefits WRAP Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Retirement Benefits [Abstract]
WRAP Plan Liabilities	$ 25.5	$ 26.8
Rabbi Trust Marketable Securities	23.4	23.1
Deferred Compensation Mark To Market Adjustments	1.0	2.3	$ (3.9)
Unrealized (gains) losses on marketable securities	$ (3.2)	$ (3.9)	$ 1.2

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Valuation Allowance [Line Items]
Interest Related to Uncertain Tax Positions	$ 0.0	$ 4.1	$ 0.7
Reduction In General And Administrative Expense Due To Uncertain Tax Positions Realized		$ 2.5
Federal statutory income tax rate	21.00%	21.00%	21.00%	35.00%
Operating Loss Carryforwards, Valuation Allowance	$ 101.9	$ 98.8
Alternative Minimum Tax Credit Refund Received	170.7	73.9
Alternative minimum tax		126.0
Unrecognized Tax Benefits	0.0	$ 0.0	$ 19.0
AMT Credit Refunds Receivable	61.6
Other Current Assets [Member]
Valuation Allowance [Line Items]
AMT Credit Refunds Receivable	30.7
Other Noncurrent Assets [Member]
Valuation Allowance [Line Items]
AMT Credit Refunds Receivable	$ 30.9

Income Taxes Schedule of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Federal income tax provision (benefit)
Current	$ (189.5)	$ (32.2)	$ (71.3)
Deferred	116.0	55.7	(257.8)
State income tax provision (benefit)
Current	(1.0)	(15.1)	1.5
Deferred	(5.4)	(51.4)	10.2
Total income tax provision (benefit)	$ (79.9)	$ (43.0)	$ (317.4)

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Income Taxes Reconciliation of Statutory Federal Income Tax Rate and Effective Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal income taxes statutory rate	21.00%	21.00%	21.00%	35.00%
Operating Loss Carryforwards		$ 75.7
Alternative minimum tax		126.0
Deferred Tax Assets, Tax Credit Carryforwards		$ 50.3
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	(1.60%)	(2.50%)	4.10%
State rate change(1)	8.00%	20.90%	(2.90%)
Valuation allowance (3)	3.30%	(18.00%)	(1.90%)
Permanent adjustments(3)	(7.20%)	(7.10%)	(0.10%)
Return to provision adjustment	1.10%	2.70%	(0.10%)
Uncertain tax provision(4)	0.00%	13.60%	0.00%
NOL rate re-measurements(5)	79.60%	0.00%	3.80%
Effective income tax rate	104.20%	30.60%	23.90%

Income Taxes Reconciliation of Statutory Federal Income Tax Rate and Effective Tax Rate Footnotes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Loss Carryforwards [Line Items]
Federal statutory income tax rate	21.00%	21.00%	21.00%	35.00%
Disallowed officer compensation	$ 1.9	$ 6.1
Share based compensation shortfalls	3.6	4.0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0.0	19.0
Operating Loss Carryforwards		75.7
Alternative minimum tax		126.0
Deferred Tax Assets, Tax Credit Carryforwards		50.3
Remeasurement Of Deferred Taxes Due To NOL Carrybacks	$ 61.0
Louisiana [Member]
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount		$ 25.3	$ 25.5

Income Taxes Schedule of Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred tax liabilities
Property, plant and equipment	$ 627.5	$ 592.9
Deferred Tax Liabilities Operating Lease Right Of Use Assets	10.7	12.7
Other	2.4	0.9
Deferred Tax Liabilities, Gross	640.6	606.5
Deferred tax assets
NOL and tax credit carryforwards	306.2	337.7
Deferred Tax Assets State NOL Valuation Allowance	(101.9)	(98.8)
Employee benefits and compensation costs	15.9	22.3
Interest carryforward (1)	0.0	45.7
Commodity price derivatives	17.0	3.9
Deferred Tax Assets Operating Lease Liabilities	11.7	14.1
Other	6.5	7.1
Total deferred tax assets	255.4	332.0
Net deferred income tax liability	385.2	274.5
Balance sheet classification
Deferred income tax liability – noncurrent	385.2	274.5
Net deferred income tax liability	$ 385.2	$ 274.5

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

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Operating Loss Carryforwards [Line Items]

Taxable Income Limitation for Net Operating Loss Carryforward

80.00%

Net Operating Loss Subject to Taxable Income Limitation

$ 18.7

State NOL and tax credit carryforwards

121.1

State net operating loss valuation allowance

(101.9)

$ (98.8)

U.S. NOL(1)

^[1]

181.3

Total NOL and tax credit carryforwards

306.2

Operating Loss Carryforwards

$ 75.7

State [Member]

Operating Loss Carryforwards [Line Items]

Operating Loss Carryforwards

5,059.8

U.S. (Federal) [Member]

Operating Loss Carryforwards [Line Items]

Operating Loss Carryforwards

863.5

General Business Tax Credit Carryforward [Member]

Operating Loss Carryforwards [Line Items]

Tax Credit Carryforward, Amount

$ 3.8

[1]

Federal NOLs created in tax years beginning after December 31, 2017 can be carried forward indefinitely under the Tax Cuts and Jobs Act (limited to 80% of taxable income computed without the NOL deduction). Of the Company's U.S. NOL, $18.7 million has an indefinite carryforward period but its use is limited to 80% of taxable income.

Income Taxes Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits, Beginning Balance	$ 0.0	$ 19.0
Uncertain Tax Position Benefit Recognized	0.0	(19.0)
Unrecognized Tax Benefits, Ending Balance	0.0	0.0	$ 19.0
Interest Related to Uncertain Tax Positions	$ 0.0	4.1	$ 0.7
Reduction In General And Administrative Expense Due To Uncertain Tax Positions Realized		$ 2.5

Quarterly Financial Information (Unaudited) (Details) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2020 USD ($) MMBoe $ / shares	Sep. 30, 2020 USD ($) MMBoe $ / shares	Jun. 30, 2020 USD ($) MMBoe $ / shares	Mar. 31, 2020 USD ($) MMBoe $ / shares	Dec. 31, 2019 USD ($) MBoe $ / shares	Sep. 30, 2019 USD ($) MBoe $ / shares	Jun. 30, 2019 USD ($) MBoe $ / shares	Mar. 31, 2019 USD ($) MBoe $ / shares	Dec. 31, 2020 USD ($) MMBoe $ / shares	Dec. 31, 2019 USD ($) MBoe $ / shares	Dec. 31, 2018 USD ($) $ / shares
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 200.2	$ 177.8	$ 120.6	$ 225.8	$ 321.9	$ 307.5	$ 296.2	$ 280.6	$ 724.4	$ 1,206.2
Operating income (loss)	(61.9)	(42.1)	(112.5)	(7.2)	48.9	52.1	72.3	(15.8)	(223.7)	157.5	$ (1,260.4)
Net income (loss)	(130.6)	(49.2)	(184.4)	367.4	(110.4)	81.0	48.8	(116.7)	3.2	(97.3)	$ (1,011.6)
Net gain (loss) from asset sales, inclusive of restructuring costs and impairment	$ (11.3)	$ 0.1	$ 0.0	$ 3.7	$ 1.4	$ (2.1)	$ 17.8	$ (18.2)	$ (7.5)	$ (1.1)
Basic \| $ / shares	$ (0.54)	$ (0.20)	$ (0.76)	$ 1.54	$ (0.46)	$ 0.34	$ 0.20	$ (0.49)	$ 0.01	$ (0.41)	$ (4.25)
Total equivalent production (Mboe)	7,364,100	7,057,000.0	7,972,900	7,930,900	8,465,300	8,404,000.0	7,534,700	7,806,300	30,324,900	32,210,300
Diluted \| $ / shares	$ (0.54)	$ (0.20)	$ (0.76)	$ 1.54	$ (0.46)	$ 0.34	$ 0.20	$ (0.49)	$ 0.01	$ (0.41)	$ (4.25)

- Definition

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

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- Definition

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

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- Definition

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

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+ Details

- Definition

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Supplemental Gas and Oil Information (Unaudited) Capitalized costs (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
Proved properties	$ 9,941.2	$ 9,574.9
Unproved properties, net	454.4	599.1
Total proved and unproved properties	10,395.6	10,174.0
Accumulated depreciation, depletion and amortization	(5,728.0)	(5,250.5)
Net capitalized costs	$ 4,667.6	$ 4,923.5

Supplemental Gas and Oil Information (Unaudited) Costs incurred (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract]
Accrued capital costs included in development costs	$ (26.2)
ARO additions and revisions	1.2
Costs incurred related to the development of proved undeveloped reserves	222.3	$ 426.1	$ 606.5
Proved property acquisitions	2.9	1.5	39.1
Unproved property acquisitions	1.2	2.0	25.8
Other acquisitions	0.0	0.0	0.8
Exploration costs (capitalized and expensed)	0.2	0.1	0.3
Development costs	324.8	556.2	1,133.1
Total costs incurred	$ 329.1	$ 559.8	$ 1,199.1

Supplemental Gas and Oil Information (Unaudited) Results of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Gathering and other expense	$ (0.2)	$ 0.0	$ 0.0
Income (loss) before income taxes	(76.7)	(140.3)	(1,329.0)
Exploration and Production [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues	721.0	1,200.6	1,920.3
Production costs	292.9	361.9	507.3
Exploration expenses	0.2	0.1	0.3
Depreciation, depletion and amortization	564.2	528.5	836.4
Impairment	8.7	0.0	1,560.9
Total expenses	865.8	890.5	2,904.9
Income (loss) before income taxes	(144.8)	310.1	(984.6)
Income tax benefit (expense)	32.1	(69.5)	243.2
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$ (112.7)	$ 240.6	$ (741.4)

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, 2020

MMBoe

MMBbls

Bcf

Dec. 31, 2019

MMBoe

MMBbls

Bcf

Dec. 31, 2018

MMBoe

MMBbls

Bcf

Oil [Member]

Reserve Quantities [Line Items]

Proved reserves balance, beginning balance

254.9

339.1

320.5

Revisions of previous estimates

2.7

(94.9)

2.1

^[1]

Extensions and discoveries

0.1

33.6

57.1

Purchase of reserves in place

3.6

8.2

Sale of reserves in place

(0.1)

(4.9)

(24.9)

Production

(19.7)

(21.6)

(23.9)

Proved reserves balance, ending balance

237.9

254.9

339.1

Proved undeveloped reserves, beginning balance

137.4

205.5

204.5

Proved undeveloped reserve, ending balance

136.7

137.4

205.5

Proved developed reserves, beginning balance

117.5

133.6

116.0

Proved developed reserves, ending balance

101.2

117.5

133.6

Gas [Member]

Reserve Quantities [Line Items]

Proved reserves balance, beginning balance | Bcf

373.3

1,487.6

1,793.6

Revisions of previous estimates | Bcf

27.6

(23.0)

314.0

^[1]

Extensions and discoveries | Bcf

0.2

40.0

56.5

Purchase of reserves in place | Bcf

4.0

7.9

Sale of reserves in place | Bcf

(0.3)

(1,102.2)

(544.8)

Production | Bcf

(32.5)

(33.1)

(139.6)

Proved reserves balance, ending balance | Bcf

368.3

373.3

1,487.6

Proved undeveloped reserves, beginning balance | Bcf

156.3

1,105.3

1,138.1

Proved undeveloped reserve, ending balance | Bcf

183.3

156.3

1,105.3

Proved developed reserves, beginning balance | Bcf

217.0

382.3

655.5

Proved developed reserves, ending balance | Bcf

185.0

217.0

382.3

Natural Gas Liquids [Member]

Reserve Quantities [Line Items]

Proved reserves balance, beginning balance

65.2

71.2

65.2

Revisions of previous estimates

4.1

(8.7)

6.7

^[1]

Extensions and discoveries

0.0

7.4

9.8

Purchase of reserves in place

0.7

1.3

Sale of reserves in place

0.0

(0.3)

(7.1)

Production

(5.2)

(5.1)

(4.7)

Proved reserves balance, ending balance

64.1

65.2

71.2

Proved undeveloped reserves, beginning balance

28.5

39.7

37.3

Proved undeveloped reserve, ending balance

32.1

28.5

39.7

Proved developed reserves, beginning balance

36.7

31.5

27.9

Proved developed reserves, ending balance

32.0

36.7

31.5

Barrels of oil equivalent production [Member]

Reserve Quantities [Line Items]

Proved developed and undeveloped reserves, beginning balance | MMBoe

^[2]

382.3

658.2

684.7

Revisions of previous estimates | MMBoe

11.4

(107.3)

^[2]

61.0

^[1],[2]

Extensions and discoveries | MMBoe

^[2]

0.2

47.6

76.3

Purchase of reserves in place | MMBoe

^[2]

4.9

10.9

Sale of reserves in place | MMBoe

^[2]

(0.2)

(188.9)

(122.8)

Production | MMBoe

^[2]

(30.3)

(32.2)

(51.9)

Proved developed and undeveloped reserves, ending balance | MMBoe

^[2]

363.4

382.3

658.2

Proved undeveloped reserves, beginning balance | MMBoe

191.9

429.3

431.6

Proved undeveloped reserves, ending balance | MMBoe

199.4

191.9

429.3

Proved developed reserves, beginning balance | MMBoe

190.4

228.9

253.1

Proved developed reserves, ending balance | MMBoe

164.0

190.4

228.9

Pricing Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

41.4

17.0

17.3

Performance Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

13.7

8.7

Positive revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

63.0

4.6

Operating Cost Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

4.2

11.7

Other Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

2.5

10.9

Development plan change [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

44.5

23.4

PUD Removals [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

16.9

25.8

Positive PUD Revisions [Member]

Reserve Quantities [Line Items]

Revisions of previous estimates | MMBoe

58.8

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

(3)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.

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

(7)Purchase of reserves in place in 2019 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.

(8)Sale of reserves in place in 2019 was primarily related to QEP's Haynesville Divestiture as discussed in Note 3 – Acquisitions and Divestitures.

(10)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.

[2]

Stand

Supplemental Gas and Oil Information (Unaudited) Average price per unit (Details)	12 Months Ended
	Dec. 31, 2020 $ / bbl $ / Mcf	Dec. 31, 2019 $ / bbl $ / Mcf	Dec. 31, 2018 $ / bbl $ / Mcf
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average benchmark price per unit \| $ / bbl	39.57	55.51	65.56
Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average benchmark price per unit \| $ / Mcf	1.99	2.58	3.10

Supplemental Gas and Oil Information (Unaudited) Future Development Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
Future Development Costs [Abstract]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Next Twelve Months	$ 202.6
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Two	289.1
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Three	$ 365.8

Supplemental Gas and Oil Information (Unaudited) Standardized Measure Of Future Net Cash Flows (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 9,657.0	$ 14,447.6	$ 26,482.6
Future production costs	(4,728.9)	(6,070.6)	(9,539.9)
Future development costs	(1,671.0)	(2,275.2)	(4,441.5)
Future income tax expenses	(294.8)	(845.8)	(2,553.6)
Future net cash flows	2,962.3	5,256.0	9,947.6
10% annual discount for estimated timing of net cash flows	(1,427.0)	(2,579.7)	(4,991.9)
Standardized measure of discounted future net cash flows	$ 1,535.3	$ 2,676.3	$ 4,955.7	$ 3,097.3

Supplemental Gas and Oil Information (Unaudited) Change in Standardized Measure of Future Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Change in Standardized Measure of Future Cash Flows [Abstract]
Beginning Balance	$ 2,676.3	$ 4,955.7	$ 3,097.3
Sales of gas, oil and NGL produced during the period, net of production costs	(428.1)	(838.7)	(1,413.0)
Net change in sales prices and in production (lifting) costs related to future production	(2,136.4)	(1,988.6)	1,632.5
Net change due to extensions and discoveries	2.4	220.9	692.6
Net change due to revisions of quantity estimates	159.6	(2,079.2)	732.0
Changes due to purchases of reserves in place	0.0	34.2	117.0
Changes due to sales of reserves in place	(1.9)	(617.8)	(369.6)
Previously estimated development costs incurred during the period	256.1	460.8	735.6
Changes in estimated future development costs	418.7	1,064.7	(28.3)
Accretion of discount	310.7	622.8	375.4
Net change in income taxes	277.9	841.5	(615.7)
Other	0.0	0.0	(0.1)
Net change	(1,141.0)	(2,279.4)	1,858.4
Ending Balance	$ 1,535.3	$ 2,676.3	$ 4,955.7