Document and Entity Information	9 Months Ended
Document and Entity Information	Sep. 30, 2018 shares
Document And Entity Information [Abstract]
Entity Registrant Name	QEP RESOURCES, INC.
Entity Central Index Key	0001108827
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	236,770,924
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
REVENUES
Oil and condensate, gas and NGL sales	$ 544.0	$ 380.9	$ 1,474.1	$ 1,139.1
Other revenue	3.8	3.6	11.8	10.3
Purchased oil and gas sales	13.0	5.6	36.2	44.5
Total Revenues	560.8	390.1	1,522.1	1,193.9
OPERATING EXPENSES
Purchased oil and gas expense	13.3	6.9	38.6	45.4
Lease operating expense	64.6	76.2	203.6	215.4
Transportation and processing costs	28.0	60.2	93.2	202.6
Gathering and other expense	4.6	1.7	10.8	5.0
General and administrative	48.3	43.4	164.2	108.3
Production and property taxes	37.4	28.5	103.9	86.1
Depreciation, depletion and amortization	234.9	176.9	673.6	560.2
Exploration expenses	0.0	21.3	0.1	21.7
Impairment	0.0	28.3	404.4	28.4
Total Operating Expenses	431.1	443.4	1,692.4	1,273.1
Net gain (loss) from asset sales, inclusive of restructuring costs	27.1	185.4	26.7	205.2
OPERATING INCOME (LOSS)	156.8	132.1	(143.6)	126.0
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(108.0)	(104.3)	(240.3)	163.3
Interest and other income (expense)	(0.3)	0.1	(4.1)	2.5
Interest expense	(38.7)	(34.4)	(111.9)	(103.1)
INCOME (LOSS) BEFORE INCOME TAXES	9.8	(6.5)	(499.9)	188.7
Income tax (provision) benefit	(2.5)	3.2	117.6	(69.7)
Net income (loss)	$ 7.3	$ (3.3)	$ (382.3)	$ 119.0
Earnings (loss) per common share
Basic	$ 0.03	$ (0.01)	$ (1.60)	$ 0.49
Diluted	$ 0.03	$ (0.01)	$ (1.60)	$ 0.49
Weighted-average common shares outstanding
Used in basic calculation	236.9	240.7	238.3	240.5
Used in diluted calculation	237.0	240.7	238.3	240.5

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

3 Months Ended

9 Months Ended

Sep. 30, 2018

Sep. 30, 2017

Sep. 30, 2018

Sep. 30, 2017

Statement of Comprehensive Income [Abstract]

Net income (loss)

$ 7.3

$ (3.3)

$ (382.3)

$ 119.0

Postretirement medical plan change(1)

^[1]

0.0

1.6

Fair value of plan assets adjustment(2)

^[2]

0.0

0.3

0.0

Pension and other postretirement plans adjustments:

Amortization of prior service costs(3)

^[3]

0.2

0.1

0.4

Amortization of actuarial losses(4)

^[4]

0.1

0.5

0.2

Other comprehensive income

0.3

0.2

1.2

2.2

Comprehensive income (loss)

7.6

(3.1)

(381.1)

121.2

Postretirement medical plan changes, income tax expense

0.0

(1.0)

Amortization of prior service cost, income tax expense

0.0

(0.1)

(0.3)

Amortization of net actuarial loss, income tax expense

$ 0.1

$ 0.0

$ (0.1)

[1]	Presented net of income tax expense of $1.0 million during the nine months ended September 30, 2017.
[2]	Adjustment recorded during the nine months ended September 30, 2018, related to a change in the fair value of plan assets as of December 31, 2017.
[3]	Presented net of income tax expense of $0.1 million during the nine months ended September 30, 2018. Presented net of income tax expense of $0.1 million and $0.3 million during the three and nine months ended September 30, 2017, respectively.
[4]	Presented net of income tax benefit of $0.1 million and expense of $0.1 million during the three and nine months ended September 30, 2018, respectively. Presented net of income tax expense of $0.1 million during the nine months ended September 30, 2017.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Postretirement medical plan changes, income tax expense	$ 0.0	$ 0.0	$ 0.0	$ (1.0)
Pension and other postretirement plans adjustments:
Amortization of prior service cost, income tax expense	0.0	(0.1)	(0.1)	(0.3)
Amortization of net actuarial loss, income tax expense	$ 0.1	$ 0.0	$ (0.1)	$ (0.1)

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 0.0	$ 0.0
Accounts receivable, net	191.7	141.8
Income tax receivable	4.1	4.9
Fair value of derivative contracts	14.0	3.4
Prepaid expenses	11.4	10.1
Other current assets	0.2	4.3
Total Current Assets	221.4	164.5
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	11,717.8	11,873.6
Unproved properties	1,034.4	1,086.4
Gathering and other	369.6	318.7
Materials and supplies	37.3	32.9
Total Property, Plant and Equipment	13,159.1	13,311.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,160.3	6,642.9
Gathering and other	121.4	124.3
Total Accumulated Depreciation, Depletion and Amortization	6,281.7	6,767.2
Net Property, Plant and Equipment	6,877.4	6,544.4
Fair value of derivative contracts	0.1	0.1
Other noncurrent assets	58.3	53.0
Noncurrent assets held for sale	0.0	632.8
TOTAL ASSETS	7,157.2	7,394.8
Current Liabilities
Checks outstanding in excess of cash balances	15.3	44.0
Accounts payable and accrued expenses	335.6	363.8
Production and property taxes	40.9	31.6
Interest payable	33.1	26.0
Fair value of derivative contracts	200.7	103.6
Asset retirement obligations	5.0	3.5
Total Current Liabilities	630.6	572.5
Long-term debt	2,451.1	2,160.8
Deferred income taxes	398.8	518.0
Asset retirement obligations	155.5	159.0
Fair value of derivative contracts	52.6	31.8
Other long-term liabilities	93.7	102.2
Other long-term liabilities held for sale	0.0	52.6
Commitments and contingencies (Note 10)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 239.8 million and 243.0 million shares issued, respectively	2.4	2.4
Treasury stock – 3.0 million and 2.0 million shares, respectively	(44.2)	(34.2)
Additional paid-in capital	1,424.6	1,398.2
Retained earnings	2,002.0	2,442.6
Accumulated other comprehensive income (loss)	(9.9)	(11.1)
Total Common Shareholders' Equity	3,374.9	3,797.9
TOTAL LIABILITIES AND EQUITY	$ 7,157.2	$ 7,394.8

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares shares in Millions	Sep. 30, 2018	Dec. 31, 2017
EQUITY
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500.0	500.0
Common stock, shares issued (in shares)	239.8	243.0
Treasury stock (in shares)	3.0	2.0

CONDENSED CONSOLIDATED STATEMENT OF EQUITY (Unaudited) Statement - 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]

Total [Member]

Common Stock, Shares

243.0

Treasury Stock, Shares

(2.0)

Stockholders' Equity

$ 3,797.9

$ 2.4

$ (34.2)

$ 1,398.2

$ 2,442.6

$ (11.1)

$ 3,797.9

Net income (loss), Shares

0.0

Net income (loss)

(382.3)

$ 0.0

0.0

(382.3)

0.0

(382.3)

Common stock repurchased and retired, Shares

(6.2)

0.0

Common stock repurchased and retired

58.4

$ (0.1)

$ 0.0

0.0

(58.3)

0.0

58.4

Share-based compensation, Shares

3.0

Share-based compensation

$ 0.1

Stock Issued During Period, Shares, Treasury Stock Reissued

(1.0)

Share-based compensation

$ (10.0)

26.4

0.0

16.5

Stock Issued During Period, Shares, Employee Benefit Plan

0.0

Change in pension and postretirement liability, net of tax

$ 0.0

^[1]

$ 0.0

0.0

1.2

Common Stock, Shares

239.8

Treasury Stock, Shares

(3.0)

Stockholders' Equity

$ 3,374.9

$ 2.4

$ (44.2)

$ 1,424.6

$ 2,002.0

$ (9.9)

$ 3,374.9

[1]	Presented net of income tax expense of $1.0 million during the nine months ended September 30, 2017.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
OPERATING ACTIVITIES
Net income (loss)	$ (382.3)	$ 119.0
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	673.6	560.2
Deferred income taxes (benefit)	(119.6)	68.5
Impairment	404.4	28.4
Results of Operations, Dry Hole Costs	0.0	21.2
Share-based compensation	28.3	13.5
Amortization of debt issuance costs and discounts	4.0	4.8
Bargain purchase gain from acquisition	0.0	0.4
Net (gain) loss from asset sales, inclusive of restructuring costs	(26.7)	(205.2)
Unrealized (gains) losses on marketable securities	(1.1)	(2.1)
Unrealized (gains) losses on derivative contracts	113.2	(161.6)
Other Operating Activities, Cash Flow Statement	0.0	(9.4)
Changes in operating assets and liabilities	(18.9)	45.1
Net Cash Provided by (Used in) Operating Activities	674.9	482.8
INVESTING ACTIVITIES
Property acquisitions	(48.3)	(94.5)
Property, plant and equipment, including exploratory well expense	(1,032.1)	(779.6)
Proceeds from disposition of assets	217.5	787.9
Net Cash Provided by (Used in) Investing Activities	(862.9)	(86.2)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(28.7)	(12.3)
Long-term debt issuance costs paid	0.1	(1.1)
Proceeds from credit facility	2,616.0	2.0
Repayments of credit facility	(2,329.5)	(2.0)
Common stock repurchased and retired	(58.4)	0.0
Treasury stock repurchases	(7.8)	(6.8)
Other capital contributions	0.3	0.0
Net Cash Provided by (Used in) Financing Activities	191.8	(20.2)
Change in cash, cash equivalents and restricted cash	3.8	376.4
Beginning cash, cash equivalents and restricted cash(1)	23.4	465.4
Ending cash, cash equivalents and restricted cash(1)	27.2	841.8
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	100.2	96.6
Cash paid for income taxes, net	0.3	0.5
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$ (43.9)	$ 68.0

Basis of Presentation

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation [Text Block]

Nature of Business

QEP Resources, Inc. 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 Louisiana) 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".

Basis of Presentation of Interim Condensed Consolidated Financial Statements

The interim Condensed Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Condensed Consolidated Financial Statements were prepared in accordance with Generally Accepted Accounting Principles (GAAP) in the United States and with the instructions for Quarterly Reports on Form 10-Q and Regulation S-X. All significant intercompany accounts and transactions have been eliminated in consolidation.

The Condensed Consolidated Financial Statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the interim periods presented. Interim Condensed Consolidated Financial Statements and the year-end balance sheet do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.

The preparation of the Condensed Consolidated Financial Statements and Notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three and nine months ended September 30, 2018, are not necessarily indicative of the results that may be expected for the year ending December 31, 2018.

Reclassifications

Certain prior period balances on the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows have been reclassified due to noncurrent held for sale classification related to the divestiture of the Uinta Basin assets and to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share or retained earnings previously reported.

Impairment of Long-Lived Assets

During the nine months ended September 30, 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment related to the Uinta Basin Divestiture (defined below). Additionally, QEP recorded $1.6 million related to expiring leaseholds on unproved properties and impairment of proved properties for a divestiture in the Other Northern area.

During the nine months ended September 30, 2017, QEP recorded an impairment charge of $28.4 million, which was primarily related to unproved leasehold acreage in the Central Basin Platform.

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 Condensed Consolidated Balance Sheets to the amounts shown in the Condensed Consolidated Statements of Cash Flows:



	September 30,
	2018		2017
	(in millions)
Cash and cash equivalents	$	—	$	782.6
Restricted cash⁽¹⁾	27.2		59.2
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	27.2	$	841.8

_______________________

⁽¹⁾

As of September 30, 2018, the restricted cash balance consisted of $27.2 million related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin and is included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet. As of September 30, 2017, the restricted cash balance consisted of $59.2 million related to cash deposited into an escrow account related to the 2017 Permian Basin Acquisition (defined below) and cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin and is included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet provided within the Quarterly Report on Form 10-Q.

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when revenue is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In addition, new and enhanced disclosures are required. The amendment was effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption was permitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard were the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company selected the modified retrospective method and adopted this standard in the first quarter of 2018. Refer to Note 2 – Revenue for more information.

In conjunction with ASU No. 2014-09, in March 2016, the FASB issued ASU No. 2016-08, Revenue from contracts with customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from contracts with customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-11, Revenue recognition (Topic 605) and Derivatives and hedging (Topic 815): Rescission of SEC guidance because of ASU 2014-09 and 2014-16, which rescinds certain SEC staff observer comments that are codified in Topic 605, Revenue Recognition. In May 2016, the FASB issued ASU No. 2016-12, Revenue from contracts with customers (Topic 606): Narrow-scope improvements and practical expedients, which intends to reduce the cost and complexity of applying the new revenue standard by narrowing the scope of improvements to the guidance on collectability, non-cash consideration, and completed contracts at transition. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which intends to make corrections or improvements to the FASB Accounting Standards Codification which includes guidance and reference clarification, simplification and minor improvements. These amendments were effective prospectively for reporting periods beginning on or after December 31, 2017, and early adoption was permitted for periods beginning on or after December 31, 2016. The Company adopted these ASUs in the first quarter of 2018. Refer to Note 2 – Revenue for more information.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclosing key quantitative and qualitative information about leasing arrangements. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. QEP does not plan to early adopt this new standard. This standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources. QEP believes this new guidance will likely increase the recorded asset and liability balances on the Company's Condensed Consolidated Balance Sheets due to the required recognition of right-of-use assets and corresponding lease liabilities, but has not determined the aggregate amount of change.

In October 2016, the FASB issued ASU No. 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory, which intends to reduce the complexity in accounting standards related to intra-entity asset transfers by requiring a reporting entity to recognize the tax effects from the sale of assets when a transfer occurs, even though the pre-tax effects of the transaction are eliminated in consolidation. This amendment was effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption was permitted. The Company adopted this standard in the first quarter of 2018 and the adoption did not have a material impact on the Company's Condensed Consolidated Financial Statements.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted cash, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting periods after December 15, 2017, and early adoption was permitted. The Company adopted this standard in the first quarter of 2018 and the adoption did not have a material impact on the Company's Condensed Consolidated Statements of Cash Flows.

In February 2018, the FASB issued ASU No. 2018-02, Income statement - Reporting comprehensive income (Topic 220) - Reclassification of certain tax effects from accumulated other comprehensive income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740) - Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118, which amends guidance on certain investments and income taxes as a result of the Tax Cuts and Jobs Act of 2017. The amendment was effective upon issuance. The adoption did not have a material impact on the Company's Condensed Consolidated Financial Statements.

In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842) - Targeted Improvements, which provides entities with relief from the costs of implementing certain aspects of the new leasing standard. Specifically, under the amendments in ASU 2018-11, entities may elect not to recast the comparative periods presented when transitioning to ASC 842 and lessors may elect not to separate lease and nonlease components when certain conditions are met. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. QEP does not plan to early adopt this new standard. The Company is currently assessing the impact of the ASU, however, QEP believes this new guidance will likely increase the recorded asset and liability balances on the Company's Condensed Consolidated Balance Sheets due to the required recognition of right-of-use assets and corresponding lease liabilities, but has not determined the aggregate amount of change.

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

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

Revenue Revenue

9 Months Ended

Sep. 30, 2018

Revenue Recognition [Abstract]

Revenue Recognition [Text Block]

Note 2 – Revenue

Adoption of ASC Topic 606, Revenue from Contracts with Customers

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

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

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



	Three Months Ended								Nine Months Ended
	September 30, 2018								September 30, 2018
	As Reported			ASC Topic 606 Adjustments		As Adjusted⁽¹⁾			As Reported			ASC Topic 606 Adjustments		As Adjusted⁽¹⁾
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	544.0		$	15.8	$	559.8		$	1,474.1		$	40.9	$	1,515.0
Other revenue	3.8			—		3.8			11.8			—		11.8
Purchased oil and gas sales	13.0			—		13.0			36.2			—		36.2
Total Revenues	560.8			15.8		576.6			1,522.1			40.9		1,563.0
OPERATING EXPENSES
Purchased oil and gas expense	13.3			—		13.3			38.6			—		38.6
Lease operating expense	64.6			—		64.6			203.6			—		203.6
Transportation and processing costs	28.0			15.8		43.8			93.2			40.9		134.1
Gathering and other expense	4.6			—		4.6			10.8			—		10.8
General and administrative	48.3			—		48.3			164.2			—		164.2
Production and property taxes	37.4			—		37.4			103.9			—		103.9
Depreciation, depletion and amortization	234.9			—		234.9			673.6			—		673.6
Exploration expenses	—			—		—			0.1			—		0.1
Impairment	—			—		—			404.4			—		404.4
Total Operating Expenses	431.1			15.8		446.9			1,692.4			40.9		1,733.3
Net gain (loss) from asset sales, inclusive of restructuring costs	27.1			—		27.1			26.7			—		26.7
OPERATING INCOME (LOSS)	156.8			—		156.8			(143.6		)	—		(143.6		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(108.0		)	—		(108.0		)	(240.3		)	—		(240.3		)
Interest and other income (expense)	(0.3		)	—		(0.3		)	(4.1		)	—		(4.1		)
Interest expense	(38.7		)	—		(38.7		)	(111.9		)	—		(111.9		)
INCOME (LOSS) BEFORE INCOME TAXES	9.8			—		9.8			(499.9		)	—		(499.9		)
Income tax (provision) benefit	(2.5		)	—		(2.5		)	117.6			—		117.6
NET INCOME (LOSS)	$	7.3		$	—	$	7.3		$	(382.3	)	$	—	$	(382.3	)

Earnings (loss) per common share
Basic	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)
Diluted	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)

Weighted-average common shares outstanding
Used in basic calculation	236.9			—		236.9			238.3			—		238.3
Used in diluted calculation	237.0			—		237.0			238.3			—		238.3

_______________________


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

Revenue Recognition

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

QEP's oil is typically sold at specific delivery points under contract terms that are common in our industry. QEP's gas and NGL are also sold under contract types that are common in our industry; however, under these contracts, the gas and its components, including NGL, may be sold to a single purchaser or the residue gas and NGL may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate the Company for the value of the residue gas and NGL constituent components at market prices for each product. QEP also purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. QEP recognizes revenue from these resale activities in the period that the performance obligations are satisfied. A wellhead imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property.

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



	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Three Months Ended September 30, 2018
Northern Region
Williston Basin	$	203.4	$	12.0	$	19.2	$	(12.3	)	$	222.3
Uinta Basin	7.3		6.8		1.4		—			15.5
Other Northern	1.1		0.5		0.1		—			1.7
Southern Region
Permian Basin	204.0		5.4		21.3		(3.5		)	227.2
Haynesville/Cotton Valley	0.2		76.9		—		—			77.1
Other Southern	0.1		0.1		—		—			0.2
Total oil and condensate, gas and NGL sales	$	416.1	$	101.7	$	42.0	$	(15.8	)	$	544.0

	Three Months Ended September 30, 2017⁽¹⁾
Northern Region
Williston Basin	$	125.7	$	9.5	$	13.0	$	—		$	148.2
Pinedale	5.2		43.0		10.1		—			58.3
Uinta Basin	7.5		12.2		1.6		—			21.3
Other Northern	1.2		4.2		0.1		—			5.5
Southern Region
Permian Basin	78.1		4.5		7.3		—			89.9
Haynesville/Cotton Valley	0.3		57.2		0.1		—			57.6
Other Southern	—		0.1		—		—			0.1
Total oil and condensate, gas and NGL sales	$	218.0	$	130.7	$	32.2	$	—		$	380.9

_______________________


⁽¹⁾	Prior period amounts have not been adjusted under the modified retrospective method.



	Oil and condensate sales			Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Nine Months Ended September 30, 2018
Northern Region
Williston Basin	$	571.5		$	30.2	$	45.7	$	(32.9	)	$	614.5
Uinta Basin	25.2			24.8		4.8		—			54.8
Other Northern	3.9			1.7		—		—			5.6
Southern Region
Permian Basin	524.1			13.2		37.7		(8.0		)	567.0
Haynesville/Cotton Valley	0.8			231.2		—		—			232.0
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,125.3		$	301.5	$	88.2	$	(40.9	)	$	1,474.1

	Nine Months Ended September 30, 2017⁽¹⁾
Northern Region
Williston Basin	$	416.5		$	32.5	$	34.8	$	—		$	483.8
Pinedale	18.0			154.8		30.1		—			202.9
Uinta Basin	21.8			39.1		4.3		—			65.2
Other Northern	4.0			15.0		0.3		—			19.3
Southern Region
Permian Basin	194.3			11.3		14.2		—			219.8
Haynesville/Cotton Valley	0.9			146.4		0.3		—			147.6
Other Southern	0.2			0.3		—		—			0.5
Total oil and condensate, gas and NGL sales	$	655.7		$	399.4	$	84.0	$	—		$	1,139.1

_______________________


⁽¹⁾	Prior period amounts have not been adjusted under the modified retrospective method.

Acquisitions & Divestitures	9 Months Ended
Acquisitions & Divestitures	Sep. 30, 2018
Business Combinations [Abstract]
Acquisitions & Divestitures [Text Block]	Acquisitions During the nine months ended September 30, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $48.3 million, subject to post-closing purchase price adjustments. Of the $48.3 million, $37.6 million was related to acquisitions from various entities that owned additional oil and gas interests in certain properties included in the 2017 acquisition of oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) on substantially the same terms and conditions as the 2017 Permian Basin Acquisition in the fourth quarter of 2017. During the nine months ended September 30, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired in 2017. Divestitures In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives (Strategic Initiatives) including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. As of September 30, 2018, the Company closed the sale of its Uinta Basin assets and continued to engage in discussions with potential buyers for its Williston Basin and Haynesville/Cotton Valley assets. Assets are considered held for sale once it is deemed unlikely that there will be any significant changes to QEP's divestiture plan, which QEP believes is generally upon the execution of purchase and sale agreements (refer to Note 13 – Subsequent Event for an update on the Williston Basin assets). Uinta Basin Divestiture In early 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, subject to post-closing purchase price adjustments (the Uinta Basin Divestiture). Pursuant to signing a purchase and sale agreement for the Uinta Basin Divestiture, QEP recorded $402.8 million of proved and unproved properties impairment during the nine months ended September 30, 2018 (refer to Note 1 – Basis of Presentation for more information). In addition, QEP recorded $5.5 million of estimated restructuring costs related to this divestiture during the nine months ended September 30, 2018, included in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations (refer to Note 8 – Restructuring for more information). QEP accounted for revenues and expenses related to the Uinta Basin, including the pre-tax loss on sale of $12.4 million, during the three and nine months ended September 30, 2018, as income from continuing operations on the Condensed Consolidated Statements of Operations because the Uinta Basin Divestiture did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. For the three and nine months ended September 30, 2018, QEP recorded net loss before income taxes related to the divested Uinta Basin properties of $4.4 million and $419.3 million, respectively, which both include the pre-tax loss on sale of $12.4 million. The net loss before income taxes for the nine months ended September 30, 2018 was primarily due to an impairment charge on proved and unproved properties of $402.8 million recognized as a result of signing the purchase and sale agreement. For the three and nine months ended September 30, 2017, QEP recorded a net loss before income taxes related to the divested Uinta properties of $4.3 million and $12.8 million, respectively. Pinedale Divestiture In September 2017, QEP sold its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds of $718.2 million. For the nine months ended September 30, 2018, QEP recorded a pre-tax gain on sale of $1.2 million, due to additional post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. For the three and nine months ended September 30, 2017, QEP had net income before income taxes related to the divested Pinedale properties of $208.2 million and $251.2 million, respectively. As a part of the Pinedale Divestiture, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. As of September 30, 2018, the remaining liability associated with estimated future payments for this commitment was $23.0 million, which is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses". Other Divestitures During the nine months ended September 30, 2018, QEP received net cash proceeds of $64.5 million and recorded a net pre-tax gain on sale of $37.9 million related to the divestiture of properties outside our main operating areas. In addition to the Pinedale Divestiture, during the nine months ended September 30, 2017, QEP received net cash proceeds of $69.7 million, resulting in a net pre-tax gain on sale of $26.4 million, primarily related to the divestiture of certain non-core properties in the Other Northern area. The gains and losses were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

Earnings Per Share

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

Basic earnings per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings 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. During the three and nine months ended September 30, 2018 and 2017, there were no anti-dilutive shares.

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



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2018	2017	2018	2017
	(in millions)
Weighted-average basic common shares outstanding	236.9	240.7	238.3	240.5
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	0.1	—	—	—
Average diluted common shares outstanding	237.0	240.7	238.3	240.5

Asset Retirement Obligations

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations [Text Block]

QEP records asset retirement obligations (ARO) associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $160.5 million and $214.1 million ARO liability for the periods ended September 30, 2018 and December 31, 2017, respectively, $5.0 million and $3.5 million, respectively, were included as a current liability within "Asset retirement obligations" on the Condensed Consolidated Balance Sheets.

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



	Asset Retirement Obligations
	(in millions)
ARO liability at December 31, 2017⁽¹⁾	$	214.1
Accretion	5.0
Additions	3.2
Revisions	(3.4		)
Liabilities related to assets sold⁽²⁾	(51.7		)
Liabilities settled	(6.7		)
ARO liability at September 30, 2018	$	160.5

_______________________


⁽¹⁾	Includes $51.6 million of ARO classified as "Other long-term liabilities held for sale" on the Condensed Consolidated Balance Sheets as of December 31, 2017 related to the Uinta Basin Divestiture.


⁽²⁾	Liabilities related to assets sold during the nine months ended September 30, 2018, includes $51.0 million related to the Uinta Basin Divestiture (refer to Note 3 – Acquisitions and Divestitures for more information).

Fair Value Measurements

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

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

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 7 – Derivative Contracts) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.

Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists.

The fair value of financial assets and liabilities at September 30, 2018 and December 31, 2017, is shown in the table below:



	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
	September 30, 2018
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	16.6	$	—	$	(2.6	)	$	14.0
Fair value of derivative contracts – long-term	—		1.2		—		(1.1		)	0.1
Total financial assets	$	—	$	17.8	$	—	$	(3.7	)	$	14.1

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	203.3	$	—	$	(2.6	)	$	200.7
Fair value of derivative contracts – long-term	—		53.7		—		(1.1		)	52.6
Total financial liabilities	$	—	$	257.0	$	—	$	(3.7	)	$	253.3

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

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

_______________________


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

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q:



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	September 30, 2018				December 31, 2017
Financial Assets	(in millions)
Cash and cash equivalents	$	—	$	—	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	15.3	$	15.3	$	44.0	$	44.0
Long-term debt	$	2,451.1	$	2,465.7	$	2,160.8	$	2,256.2

The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company's debt at the end of the quarter.

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

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO includes plugging costs and reserve lives. A reconciliation of the Company's ARO is presented in Note 5 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a periodic basis, at least annually, to review its proved oil and gas properties for potential impairment when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. The fair value of property is measured utilizing the income approach and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. 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. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. During the nine months ended September 30, 2018, the Company recorded impairments on certain proved oil and gas properties of $397.6 million, resulting in a reduction of the associated carrying amount to fair value. During the nine months ended September 30, 2017, the Company recorded no impairments on proved oil and gas properties.

Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date which utilizes the following inputs to estimate future net cash flows: (i) estimated quantities of oil and condensate, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy.

- 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

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. In addition, QEP has historically entered into commodity derivative contracts on a portion of its storage transactions. QEP does not enter into commodity derivative contracts for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps or costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma. Gas price derivative instruments are typically structured as fixed-price swaps or collars at NYMEX Henry Hub or regional price indices. QEP also enters into oil and gas basis swaps to achieve a fixed-price swap for a portion of its oil and gas sales at prices that reference specific regional index prices.

QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. QEP's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties' public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

Derivative Contracts – Production

The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of September 30, 2018:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2018	NYMEX WTI	4.1	$	52.45
2019	NYMEX WTI	11.0	$	54.49
2020	NYMEX WTI	2.9	$	62.37
Gas sales		(MMBtu)	($/MMBtu)
2018	NYMEX HH	25.2	$	3.01
2019	NYMEX HH	43.8	$	2.86

QEP uses oil and gas basis swaps, combined with NYMEX WTI and NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil and gas basis swaps as of September 30, 2018:



Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2018	NYMEX WTI	Argus WTI Midland	2.3	$	(0.99	)
2018	NYMEX WTI	Argus WTI Houston⁽¹⁾	0.1	$	6.30
2019	NYMEX WTI	Argus WTI Midland	6.6	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston⁽¹⁾	0.4	$	4.35
2020	NYMEX WTI	Argus WTI Midland	1.5	$	(1.01	)
Gas sales			(MMBtu)	($/MMBtu)
2018	NYMEX HH	IFNPCR	1.8	$	(0.16	)

___________________________


⁽¹⁾	Argus WTI Houston is an index price reflecting the weighted average price of WTI at Magellan's East Houston crude oil terminal.

QEP Derivative Financial Statement Presentation

The following table identifies the Condensed Consolidated Balance Sheet location of QEP's outstanding derivative contracts on a gross contract basis as opposed to the net contract basis presentation on the Condensed Consolidated Balance Sheets and the related fair values at the balance sheet dates:



		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	September 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	16.6	$	20.6	$	203.3	$	120.8
Long-term:
Commodity	Fair value of derivative contracts	1.2		2.3		53.7		34.0
Total derivative instruments		$	17.8	$	22.9	$	257.0	$	154.8

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



	Three Months Ended						Nine Months Ended
Derivative contracts	September 30,						September 30,
Derivative contracts	2018⁽¹⁾			2017⁽²⁾			2018⁽¹⁾			2017⁽²⁾
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(41.7	)	$	12.1		$	(138.0	)	$	21.6
Gas derivative contracts	3.3			(0.4		)	10.6			(19.7		)
Gas Storage
Gas derivative contracts	—			—			0.3			(0.2		)
Realized gains (losses) on commodity derivative contracts	(38.4		)	11.7			(127.1		)	1.7
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(60.6		)	(86.1		)	(88.1		)	88.7
Gas derivative contracts	(3.1		)	—			(18.9		)	100.5
Gas Storage
Gas derivative contracts	—			—			(0.3		)	2.3
Unrealized gains (losses) on commodity derivative contracts	(63.7		)	(86.1		)	(107.3		)	191.5
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	(102.1	)	$	(74.4	)	$	(234.4	)	$	193.2

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

Total realized and unrealized gains (losses) on commodity derivative contracts	$	(108.0	)	$	(104.3	)	$	(240.3	)	$	163.3

_______________________

⁽¹⁾

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 Condensed Consolidated Statements of Operations.

⁽²⁾

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

Restructuring Costs

9 Months Ended

Sep. 30, 2018

Restructuring [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

On February 28, 2018, QEP announced its intention to become a pure-play Permian Basin company, which includes plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley. As of September 30, 2018, the Company closed the sale of its Uinta Basin assets and continued to engage in discussions with potential buyers for its Williston Basin and Haynesville/Cotton Valley assets. As a part of the Strategic Initiatives, QEP has incurred or expects to incur costs associated with contractual termination benefits including severance and accelerated vesting of share-based compensation. These termination benefits will be accounted for under ASC 712, Compensation - Nonretirement Postemployment Benefits and ASC 718, Compensation - Stock Compensation.

Restructuring costs recognized associated with the restructuring are summarized below:



	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)
	Three Months Ended September 30, 2018
Termination benefits	$	6.7	$	5.3	$	1.4	$	—
Office lease termination costs	0.7		0.7		—		—
Accelerated share-based compensation	3.2		1.0		2.2		—
Retention expense	5.8		5.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	16.7	$	12.8	$	3.6	$	0.3

	Nine Months Ended September 30, 2018
Termination benefits	$	13.7	$	10.4	$	3.3	$	—
Office lease termination costs	1.0		1.0		—		—
Accelerated share-based compensation	7.2		5.0		2.2		—
Retention expense	13.8		13.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	36.0	$	30.2	$	5.5	$	0.3



	Costs recognized period from inception to September 30, 2018		Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	13.7	$	—	⁽¹⁾
Office lease termination costs	1.0		—		⁽¹⁾
Accelerated share-based compensation	7.2		—		⁽¹⁾
Retention expense	13.8		10.5		⁽²⁾
Pension curtailment	0.3		—		⁽¹⁾
Total restructuring costs	$	36.0	$	10.5

____________________________


⁽¹⁾	Due to the nature of the Strategic Initiatives and uncertain factors such as the timing and terms of the potential divestitures, the Company is not able to reasonably estimate the total cost to be incurred as a part of this restructuring.


⁽²⁾	QEP expects to incur an additional $6.3 million of expense in 2018 and $4.2 million in 2019 related to the retention program.

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



	Restructuring liability
	Termination benefits			Office lease termination costs			Accelerated share-based compensation			Retention expense			Pension curtailment			Total
	(in millions)
Balance at December 31, 2017	$	—		$	—		$	—		$	—		$	—		$	—
Costs incurred and charged to expense	13.7			1.0			7.2			13.8			0.3			36.0
Costs paid or otherwise settled	(8.4		)	(1.0		)	(7.2		)	(8.0		)	(0.3		)	(24.9		)
Balance at September 30, 2018	$	5.3		$	—		$	—		$	5.8		$	—		$	11.1

Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Debt [Text Block]

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



	September 30, 2018			December 31, 2017
	(in millions)
Revolving Credit Facility due 2022	$	375.5		$	89.0
6.80% Senior Notes due 2020	51.7			51.7
6.875% Senior Notes due 2021	397.6			397.6
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
5.625% Senior Notes due 2026	500.0			500.0
Less: unamortized discount and unamortized debt issuance costs	(23.7		)	(27.5		)
Total long-term debt outstanding	$	2,451.1		$	2,160.8

Of the total debt outstanding on September 30, 2018, the 6.80% Senior Notes due March 1, 2020, the 6.875% Senior Notes due March 1, 2021, the 5.375% Senior Notes due October 1, 2022 and the 5.25% Senior Notes due May 1, 2023, will mature within the next five years. In addition, the revolving credit facility matures on September 1, 2022.

Credit Facility

QEP's revolving credit facility, which matures, subject to satisfaction of certain conditions, in September 2022, provides for loan commitments of $1.25 billion. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit agreement contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.00 times consolidated EBITDA (as defined in the credit agreement) commencing with the fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings trigger period (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2019, must exceed net funded debt by 1.40 times commencing on January 1, 2019 through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. The Company is currently not subject to the present value coverage ratio. At September 30, 2018 and December 31, 2017, QEP was in compliance with the covenants under the credit agreement.

During the nine months ended September 30, 2018, QEP's weighted-average interest rates on borrowings from its credit facility were 4.30%. As of September 30, 2018, QEP had $375.5 million of borrowings outstanding and $0.3 million in letters of credit outstanding under the credit facility. As of December 31, 2017, QEP had $89.0 million of borrowings outstanding and $1.0 million in letters of credit outstanding under the credit facility.

Senior Notes

At September 30, 2018, the Company had $2,099.3 million in principal amount of senior notes outstanding with maturities ranging from March 2020 to March 2026 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP's senior notes contain customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets.

Commitment and Contingencies	9 Months Ended
Commitment and Contingencies	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitment and Contingencies [Text Block]	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 Condensed Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Legal proceedings are inherently unpredictable and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter. Landowner Litigation – In October, 2017, the owners of certain surface and mineral interests in Martin and Andrews County, Texas filed suit against QEP, alleging QEP improperly used the surface of the properties and failed to correctly pay royalties, and are seeking money damages and a declaratory judgment that portions of the oil and gas leases covering the properties are no longer in effect. The Company continues to evaluate the allegations and its defenses. The Company is unable to make an estimate of the reasonably possible loss at this early stage.

Share-Based Compensation

9 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation [Text Block]

In 2018, QEP's Board of Directors and QEP's shareholders approved the QEP Resources, Inc. 2018 Long-Term Incentive Plan (LTIP), which replaces the 2010 Long-Term Stock Incentive Plan (LTSIP) and provides for the issuance of up to 10.0 million shares such that the Board of Directors may grant long-term incentive compensation. QEP issues stock options, restricted share awards, and restricted share units under its LTIP and awards performance share units under its Cash Incentive Plan (CIP) to certain officers, employees and non-employee directors. Grants issued prior to May 15, 2018 are under the LTSIP and the grants issued on or after May 15, 2018 are under the LTIP. QEP recognizes the expense over the vesting periods for the stock options, restricted share awards, restricted share units and performance share units. There were 10.1 million shares available for future grants under the LTIP at September 30, 2018.

Share-based compensation expense is recognized within "General and administrative" expense on the Condensed Consolidated Statements of Operations and is summarized in the table below. During the three and nine months ended September 30, 2018, the Company recorded an additional $3.2 million and $7.2 million, respectively, of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program, of which $2.2 million for the three and nine months ended September 30, 2018 was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations and the remaining $1.0 million and $5.0 million, respectively, are included in share-based compensation expense below (refer to Note 8 – Restructuring for additional information):



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018		2017
	(in millions)
Stock options	$	0.2		$	0.5		$	0.9	$	1.7
Restricted share awards	5.3			5.4			20.9		18.7
Performance share units	(2.9		)	(0.1		)	4.1		(6.9		)
Restricted share units	0.1			—			0.2		—
Total share-based compensation expense	$	2.7		$	5.8		$	26.1	$	13.5

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of grant. Fair value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for calculating the value of stock options not traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company recognizes forfeitures of stock options as they occur.

In 2018, to better align our long-term incentive awards with those typical of the industry, 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, 2017	2,354,277		$	23.62
Exercised	(23,337	)	10.12
Canceled	(232,007	)	37.16
Outstanding at September 30, 2018	2,098,933		$	22.27	3.12	$	0.5
Options Exercisable at September 30, 2018	1,707,915		$	24.04	2.68	$	0.3
Unvested Options at September 30, 2018	391,018		$	14.56	5.05	$	0.2

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 nine months ended September 30, 2018. During the nine months ended September 30, 2017, there were no exercises of stock options. As of September 30, 2018, $0.6 million of unrecognized compensation expense related to stock options granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.40 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program (refer to Note 8 – Restructuring for additional information).

Restricted Share Awards

Restricted share award grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company recognizes restricted share forfeitures as they occur. The total fair value of restricted share awards that vested during the nine months ended September 30, 2018 and 2017 was $30.7 million and $22.9 million, respectively. The weighted-average grant date fair value of restricted share awards was $9.56 per share and $14.13 per share for the nine months ended September 30, 2018 and 2017, respectively. As of September 30, 2018, $22.0 million of unrecognized compensation expense related to restricted share awards granted under the LTSIP and LTIP is expected to be recognized over a weighted-average vesting period of 2.18 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program (refer to Note 8 – Restructuring for additional information).

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



	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2017	3,721,334		$	13.23
Granted	2,981,589		9.56
Vested	(2,344,304	)	13.11
Forfeited	(223,222	)	10.94
Unvested balance at September 30, 2018	4,135,397		$	10.77

Performance Share Units

The payouts for performance share units are dependent upon the Company's total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units and have historically been paid in cash. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTIP; however, as of September 30, 2018, the Company expects to settle all awards in cash under the CIP. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Condensed Consolidated Balance Sheets. As these awards are dependent upon the Company's total shareholder return and stock price, they are remeasured at fair value at the end of each reporting period. The weighted-average grant date fair value of the performance share units was $9.55 per share and $16.90 per share for the nine months ended September 30, 2018 and 2017, respectively. As of September 30, 2018, $9.2 million of unrecognized compensation expense, 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 2.00 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program (refer to Note 8 – Restructuring for additional information).

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



	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2017	1,199,336		$	14.59
Granted	724,095		9.55
Vested	(277,604	)	19.73
Unvested balance at September 30, 2018	1,645,827		$	11.47

Restricted Share Units

Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately paid in cash. They are classified as liabilities and are included in "Other long-term liabilities" on the Condensed Consolidated Balance Sheets and are measured at fair value at the end of each reporting period. The weighted-average grant date fair value of the restricted share units was $9.55 and $16.98 per share for the nine months ended September 30, 2018 and 2017, respectively. As of September 30, 2018, $0.3 million of unrecognized compensation expense, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.25 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program (refer to Note 8 – Restructuring for additional information).

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



	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2017	21,946		$	13.22
Granted	31,835		9.55
Vested	(11,106	)	13.27
Unvested balance at September 30, 2018	42,675		$	10.47

Employee Benefits

9 Months Ended

Sep. 30, 2018

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

Employee Benefits [Text Block]

Pension and Other Postretirement Benefits

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

The Pension Plan is a closed, qualified, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the nine months ended September 30, 2018, the Company made contributions of $4.0 million to the Pension Plan and expects to contribute an additional $1.0 million to the Pension Plan during the remainder of 2018. Contributions to the Pension Plan increase plan assets. The Pension Plan was amended in June 2015 and was frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services.

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the nine months ended September 30, 2018, the Company made contributions of $0.6 million to its SERP and expects to contribute an additional $0.1 million to its SERP during the remainder of 2018. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and was closed to new participants effective January 1, 2016.

The Medical Plan is 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. During the nine months ended September 30, 2018, the Company made contributions of $0.2 million to its Medical Plan and does not expect to make additional contributions to its Medical Plan during the remainder of 2018. Contributions to the Medical Plan are used to fund current benefit payments.

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 retirees and spouses that are both Medicare eligible. In addition, the Company no longer offers life insurance to individuals retiring on or after July 1, 2017.

The Company's Strategic Initiatives may trigger curtailments related to the Pension Plan, SERP and/or Medical Plan at the closing of the various transactions (refer to Note 8 – Restructuring for more information). The Company recognized a $0.3 million pension curtailment as part of the Uinta Basin Divestiture included in "Interest and other income (expense)" on the Condensed Consolidated Statements of Operations.

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

The following table sets forth the Company's net periodic benefit costs related to its Pension Plan, SERP and Medical Plan:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.2		$	0.2		$	0.6		$	0.6
Interest cost	1.2			1.2			3.4			3.6
Expected return on plan assets	(1.4		)	(1.3		)	(4.3		)	(4.0		)
Amortization of prior service costs⁽¹⁾	0.2			0.3			0.6			0.9
Amortization of actuarial losses⁽¹⁾	—			0.1			0.6			0.3
Curtailment loss⁽²⁾	0.3			0.7			0.3			0.7
Periodic expense	$	0.5		$	1.2		$	1.2		$	2.1

Medical Plan benefits
Interest cost	$	—		$	—		$	0.1		$	0.1
Amortization of prior service costs⁽¹⁾	(0.1		)	(0.1		)	(0.2		)	(0.2		)
Periodic expense	$	(0.1	)	$	(0.1	)	$	(0.1	)	$	(0.1	)

____________________________


⁽¹⁾	Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income are recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)".

⁽²⁾

A curtailment is recognized when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses relate to the Uinta Basin Divestiture for the three and nine months ended September 30, 2018 and the Pinedale Divestiture for the three and nine months ended September 30, 2017. The Uinta Basin Divestiture curtailment is recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)" for the three and nine months ended September 30, 2018. The Pinedale Divestiture curtailment is recognized on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of severance costs" for the three and nine months ended September 30, 2017.

Subsequent Event (Notes)	9 Months Ended
Subsequent Event (Notes)	Sep. 30, 2018
Subsequent Event [Line Items]
Subsequent Events [Text Block]	On November 6, 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a definitive agreement to sell its assets in the Williston Basin for a purchase price of up to $1,725.0 million, subject to purchase price adjustments which may be material (the Williston Basin Divestiture). The purchase price is comprised of $1,650.0 million in cash and contractual rights to receive up to $50.0 million and $25.0 million in the buyer's common stock if the daily volume weighted average trading price of the buyer's common stock for 10 out of 20 consecutive trading days is at or above $12.00 per share and $15.00 per share, respectively. QEP shall be entitled to the equity consideration if the share price thresholds are met at any time during the five year period following closing of the transaction. The net book value of the Williston Basin assets being sold is approximately $2,521.8 million as of September 30, 2018, which consists primarily of property, plant and equipment and asset retirement obligations included on the Condensed Consolidated Balance Sheets. The transaction is subject to certain conditions, including, but not limited to, approval of buyer's shareholder and regulatory approvals and is expected to close late in the first quarter or early in the second quarter of 2019. At September 30, 2018, the Williston Basin assets were classified as held and used because the assets did not meet the held for sale criteria. Beginning in the fourth quarter of 2018, the assets and liabilities of the Williston Basin will be classified as held for sale in our Consolidated Balance Sheets for all comparative periods presented.

Basis of Presentation Restricted Cash (Tables)

9 Months Ended

Sep. 30, 2018

Restricted Cash [Abstract]

Restrictions on Cash and Cash Equivalents [Table Text Block]



	September 30,
	2018		2017
	(in millions)
Cash and cash equivalents	$	—	$	782.6
Restricted cash⁽¹⁾	27.2		59.2
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	27.2	$	841.8

_______________________

⁽¹⁾

Revenue (Tables)

9 Months Ended

Sep. 30, 2018

Revenue Recognition [Abstract]

Revenue Recognition 606 [Table Text Block]

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



	Three Months Ended								Nine Months Ended
	September 30, 2018								September 30, 2018
	As Reported			ASC Topic 606 Adjustments		As Adjusted⁽¹⁾			As Reported			ASC Topic 606 Adjustments		As Adjusted⁽¹⁾
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	544.0		$	15.8	$	559.8		$	1,474.1		$	40.9	$	1,515.0
Other revenue	3.8			—		3.8			11.8			—		11.8
Purchased oil and gas sales	13.0			—		13.0			36.2			—		36.2
Total Revenues	560.8			15.8		576.6			1,522.1			40.9		1,563.0
OPERATING EXPENSES
Purchased oil and gas expense	13.3			—		13.3			38.6			—		38.6
Lease operating expense	64.6			—		64.6			203.6			—		203.6
Transportation and processing costs	28.0			15.8		43.8			93.2			40.9		134.1
Gathering and other expense	4.6			—		4.6			10.8			—		10.8
General and administrative	48.3			—		48.3			164.2			—		164.2
Production and property taxes	37.4			—		37.4			103.9			—		103.9
Depreciation, depletion and amortization	234.9			—		234.9			673.6			—		673.6
Exploration expenses	—			—		—			0.1			—		0.1
Impairment	—			—		—			404.4			—		404.4
Total Operating Expenses	431.1			15.8		446.9			1,692.4			40.9		1,733.3
Net gain (loss) from asset sales, inclusive of restructuring costs	27.1			—		27.1			26.7			—		26.7
OPERATING INCOME (LOSS)	156.8			—		156.8			(143.6		)	—		(143.6		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(108.0		)	—		(108.0		)	(240.3		)	—		(240.3		)
Interest and other income (expense)	(0.3		)	—		(0.3		)	(4.1		)	—		(4.1		)
Interest expense	(38.7		)	—		(38.7		)	(111.9		)	—		(111.9		)
INCOME (LOSS) BEFORE INCOME TAXES	9.8			—		9.8			(499.9		)	—		(499.9		)
Income tax (provision) benefit	(2.5		)	—		(2.5		)	117.6			—		117.6
NET INCOME (LOSS)	$	7.3		$	—	$	7.3		$	(382.3	)	$	—	$	(382.3	)

Earnings (loss) per common share
Basic	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)
Diluted	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)

Weighted-average common shares outstanding
Used in basic calculation	236.9			—		236.9			238.3			—		238.3
Used in diluted calculation	237.0			—		237.0			238.3			—		238.3

_______________________


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

Revenue Recognition [Table Text Block]



	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Three Months Ended September 30, 2018
Northern Region
Williston Basin	$	203.4	$	12.0	$	19.2	$	(12.3	)	$	222.3
Uinta Basin	7.3		6.8		1.4		—			15.5
Other Northern	1.1		0.5		0.1		—			1.7
Southern Region
Permian Basin	204.0		5.4		21.3		(3.5		)	227.2
Haynesville/Cotton Valley	0.2		76.9		—		—			77.1
Other Southern	0.1		0.1		—		—			0.2
Total oil and condensate, gas and NGL sales	$	416.1	$	101.7	$	42.0	$	(15.8	)	$	544.0

	Three Months Ended September 30, 2017⁽¹⁾
Northern Region
Williston Basin	$	125.7	$	9.5	$	13.0	$	—		$	148.2
Pinedale	5.2		43.0		10.1		—			58.3
Uinta Basin	7.5		12.2		1.6		—			21.3
Other Northern	1.2		4.2		0.1		—			5.5
Southern Region
Permian Basin	78.1		4.5		7.3		—			89.9
Haynesville/Cotton Valley	0.3		57.2		0.1		—			57.6
Other Southern	—		0.1		—		—			0.1
Total oil and condensate, gas and NGL sales	$	218.0	$	130.7	$	32.2	$	—		$	380.9

_______________________


⁽¹⁾	Prior period amounts have not been adjusted under the modified retrospective method.



	Oil and condensate sales			Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Nine Months Ended September 30, 2018
Northern Region
Williston Basin	$	571.5		$	30.2	$	45.7	$	(32.9	)	$	614.5
Uinta Basin	25.2			24.8		4.8		—			54.8
Other Northern	3.9			1.7		—		—			5.6
Southern Region
Permian Basin	524.1			13.2		37.7		(8.0		)	567.0
Haynesville/Cotton Valley	0.8			231.2		—		—			232.0
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,125.3		$	301.5	$	88.2	$	(40.9	)	$	1,474.1

	Nine Months Ended September 30, 2017⁽¹⁾
Northern Region
Williston Basin	$	416.5		$	32.5	$	34.8	$	—		$	483.8
Pinedale	18.0			154.8		30.1		—			202.9
Uinta Basin	21.8			39.1		4.3		—			65.2
Other Northern	4.0			15.0		0.3		—			19.3
Southern Region
Permian Basin	194.3			11.3		14.2		—			219.8
Haynesville/Cotton Valley	0.9			146.4		0.3		—			147.6
Other Southern	0.2			0.3		—		—			0.5
Total oil and condensate, gas and NGL sales	$	655.7		$	399.4	$	84.0	$	—		$	1,139.1

_______________________


⁽¹⁾	Prior period amounts have not been adjusted under the modified retrospective method.

Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Components of basic and diluted shares used in EPS [Table Text Block]

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



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2018	2017	2018	2017
	(in millions)
Weighted-average basic common shares outstanding	236.9	240.7	238.3	240.5
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	0.1	—	—	—
Average diluted common shares outstanding	237.0	240.7	238.3	240.5

Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation [Abstract]

Asset retirement obligations rollforward [Table Text Block]

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



	Asset Retirement Obligations
	(in millions)
ARO liability at December 31, 2017⁽¹⁾	$	214.1
Accretion	5.0
Additions	3.2
Revisions	(3.4		)
Liabilities related to assets sold⁽²⁾	(51.7		)
Liabilities settled	(6.7		)
ARO liability at September 30, 2018	$	160.5

_______________________


⁽¹⁾	Includes $51.6 million of ARO classified as "Other long-term liabilities held for sale" on the Condensed Consolidated Balance Sheets as of December 31, 2017 related to the Uinta Basin Divestiture.


⁽²⁾	Liabilities related to assets sold during the nine months ended September 30, 2018, includes $51.0 million related to the Uinta Basin Divestiture (refer to Note 3 – Acquisitions and Divestitures for more information).

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2018

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair value of financial assets and liabilities [Table Text Block]

The fair value of financial assets and liabilities at September 30, 2018 and December 31, 2017, is shown in the table below:



	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
	September 30, 2018
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	16.6	$	—	$	(2.6	)	$	14.0
Fair value of derivative contracts – long-term	—		1.2		—		(1.1		)	0.1
Total financial assets	$	—	$	17.8	$	—	$	(3.7	)	$	14.1

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	203.3	$	—	$	(2.6	)	$	200.7
Fair value of derivative contracts – long-term	—		53.7		—		(1.1		)	52.6
Total financial liabilities	$	—	$	257.0	$	—	$	(3.7	)	$	253.3

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

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

_______________________


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

Fair value and related carrying amount of certain financial instruments [Table Text Block]



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	September 30, 2018				December 31, 2017
Financial Assets	(in millions)
Cash and cash equivalents	$	—	$	—	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	15.3	$	15.3	$	44.0	$	44.0
Long-term debt	$	2,451.1	$	2,465.7	$	2,160.8	$	2,256.2

- Definition

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

+ References + Details

Derivative Contracts (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

Derivative Contracts – Production

The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of September 30, 2018:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2018	NYMEX WTI	4.1	$	52.45
2019	NYMEX WTI	11.0	$	54.49
2020	NYMEX WTI	2.9	$	62.37
Gas sales		(MMBtu)	($/MMBtu)
2018	NYMEX HH	25.2	$	3.01
2019	NYMEX HH	43.8	$	2.86



Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2018	NYMEX WTI	Argus WTI Midland	2.3	$	(0.99	)
2018	NYMEX WTI	Argus WTI Houston⁽¹⁾	0.1	$	6.30
2019	NYMEX WTI	Argus WTI Midland	6.6	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston⁽¹⁾	0.4	$	4.35
2020	NYMEX WTI	Argus WTI Midland	1.5	$	(1.01	)
Gas sales			(MMBtu)	($/MMBtu)
2018	NYMEX HH	IFNPCR	1.8	$	(0.16	)

___________________________


⁽¹⁾	Argus WTI Houston is an index price reflecting the weighted average price of WTI at Magellan's East Houston crude oil terminal.

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]



		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	September 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	16.6	$	20.6	$	203.3	$	120.8
Long-term:
Commodity	Fair value of derivative contracts	1.2		2.3		53.7		34.0
Total derivative instruments		$	17.8	$	22.9	$	257.0	$	154.8

Derivative Instruments, Gain (Loss) [Table Text Block]



	Three Months Ended						Nine Months Ended
Derivative contracts	September 30,						September 30,
Derivative contracts	2018⁽¹⁾			2017⁽²⁾			2018⁽¹⁾			2017⁽²⁾
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(41.7	)	$	12.1		$	(138.0	)	$	21.6
Gas derivative contracts	3.3			(0.4		)	10.6			(19.7		)
Gas Storage
Gas derivative contracts	—			—			0.3			(0.2		)
Realized gains (losses) on commodity derivative contracts	(38.4		)	11.7			(127.1		)	1.7
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(60.6		)	(86.1		)	(88.1		)	88.7
Gas derivative contracts	(3.1		)	—			(18.9		)	100.5
Gas Storage
Gas derivative contracts	—			—			(0.3		)	2.3
Unrealized gains (losses) on commodity derivative contracts	(63.7		)	(86.1		)	(107.3		)	191.5
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	(102.1	)	$	(74.4	)	$	(234.4	)	$	193.2

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

Total realized and unrealized gains (losses) on commodity derivative contracts	$	(108.0	)	$	(104.3	)	$	(240.3	)	$	163.3

_______________________

⁽¹⁾

⁽²⁾

Restructuring Costs Restructuring Costs (Tables)

9 Months Ended

Sep. 30, 2018

Restructuring and Related Activities [Abstract]

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

Restructuring costs recognized associated with the restructuring are summarized below:



	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)
	Three Months Ended September 30, 2018
Termination benefits	$	6.7	$	5.3	$	1.4	$	—
Office lease termination costs	0.7		0.7		—		—
Accelerated share-based compensation	3.2		1.0		2.2		—
Retention expense	5.8		5.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	16.7	$	12.8	$	3.6	$	0.3

	Nine Months Ended September 30, 2018
Termination benefits	$	13.7	$	10.4	$	3.3	$	—
Office lease termination costs	1.0		1.0		—		—
Accelerated share-based compensation	7.2		5.0		2.2		—
Retention expense	13.8		13.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	36.0	$	30.2	$	5.5	$	0.3

Restructuring Costs [Table Text Block]



	Costs recognized period from inception to September 30, 2018		Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	13.7	$	—	⁽¹⁾
Office lease termination costs	1.0		—		⁽¹⁾
Accelerated share-based compensation	7.2		—		⁽¹⁾
Retention expense	13.8		10.5		⁽²⁾
Pension curtailment	0.3		—		⁽¹⁾
Total restructuring costs	$	36.0	$	10.5

____________________________


⁽¹⁾	Due to the nature of the Strategic Initiatives and uncertain factors such as the timing and terms of the potential divestitures, the Company is not able to reasonably estimate the total cost to be incurred as a part of this restructuring.


⁽²⁾	QEP expects to incur an additional $6.3 million of expense in 2018 and $4.2 million in 2019 related to the retention program.

Restructuring Costs, Liability [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 Condensed Consolidated Balance Sheets.



	Restructuring liability
	Termination benefits			Office lease termination costs			Accelerated share-based compensation			Retention expense			Pension curtailment			Total
	(in millions)
Balance at December 31, 2017	$	—		$	—		$	—		$	—		$	—		$	—
Costs incurred and charged to expense	13.7			1.0			7.2			13.8			0.3			36.0
Costs paid or otherwise settled	(8.4		)	(1.0		)	(7.2		)	(8.0		)	(0.3		)	(24.9		)
Balance at September 30, 2018	$	5.3		$	—		$	—		$	5.8		$	—		$	11.1

Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-based Compensation Expense [Table Text Block]



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018		2017
	(in millions)
Stock options	$	0.2		$	0.5		$	0.9	$	1.7
Restricted share awards	5.3			5.4			20.9		18.7
Performance share units	(2.9		)	(0.1		)	4.1		(6.9		)
Restricted share units	0.1			—			0.2		—
Total share-based compensation expense	$	2.7		$	5.8		$	26.1	$	13.5

Share-based Compensation, Stock Options, Activity [Table Text Block]

Stock option transactions under the terms of the LTSIP are summarized below:



	Options Outstanding		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2017	2,354,277		$	23.62
Exercised	(23,337	)	10.12
Canceled	(232,007	)	37.16
Outstanding at September 30, 2018	2,098,933		$	22.27	3.12	$	0.5
Options Exercisable at September 30, 2018	1,707,915		$	24.04	2.68	$	0.3
Unvested Options at September 30, 2018	391,018		$	14.56	5.05	$	0.2

Schedule of Share-based Compensation, Restricted Share Awards Activity [Table Text Block]

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



	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2017	3,721,334		$	13.23
Granted	2,981,589		9.56
Vested	(2,344,304	)	13.11
Forfeited	(223,222	)	10.94
Unvested balance at September 30, 2018	4,135,397		$	10.77

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



	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2017	21,946		$	13.22
Granted	31,835		9.55
Vested	(11,106	)	13.27
Unvested balance at September 30, 2018	42,675		$	10.47

Schedule of Other Share-based Compensation, PSUs & RSUs [Table Text Block]

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



	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2017	1,199,336		$	14.59
Granted	724,095		9.55
Vested	(277,604	)	19.73
Unvested balance at September 30, 2018	1,645,827		$	11.47

Employee Benefits (Tables)

9 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

The following table sets forth the Company's net periodic benefit costs related to its Pension Plan, SERP and Medical Plan:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.2		$	0.2		$	0.6		$	0.6
Interest cost	1.2			1.2			3.4			3.6
Expected return on plan assets	(1.4		)	(1.3		)	(4.3		)	(4.0		)
Amortization of prior service costs⁽¹⁾	0.2			0.3			0.6			0.9
Amortization of actuarial losses⁽¹⁾	—			0.1			0.6			0.3
Curtailment loss⁽²⁾	0.3			0.7			0.3			0.7
Periodic expense	$	0.5		$	1.2		$	1.2		$	2.1

Medical Plan benefits
Interest cost	$	—		$	—		$	0.1		$	0.1
Amortization of prior service costs⁽¹⁾	(0.1		)	(0.1		)	(0.2		)	(0.2		)
Periodic expense	$	(0.1	)	$	(0.1	)	$	(0.1	)	$	(0.1	)

____________________________


⁽¹⁾	Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income are recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)".

⁽²⁾

Basis of Presentation ImpaIrment of Long Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			$ 404.4
Impairment	$ 0.0	$ 28.3	404.4	$ 28.4
Other impairment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			1.6
Uinta Basin Divestiture [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			$ 402.8

Basis of Presentation Restricted Cash (Details) - USD ($)
$ in Millions

Sep. 30, 2018

Dec. 31, 2017

Sep. 30, 2017

Dec. 31, 2016

Restricted Cash and Cash Equivalents Items [Line Items]

Cash and cash equivalents

$ 0.0

$ 782.6

Restricted cash(1)

^[1]

27.2

59.2

Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows

27.2

$ 23.4

841.8

$ 465.4

Long-term [Member]

Restricted Cash and Cash Equivalents Items [Line Items]

Restricted cash(1)

$ 27.2

$ 59.2

[1]

Revenue (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
REVENUES
Oil and condensate, gas and NGL sales	$ 544.0	$ 380.9	$ 1,474.1	$ 1,139.1
Other revenue	3.8	3.6	11.8	10.3
Purchased oil and gas sales	13.0	5.6	36.2	44.5
Total Revenues	560.8	390.1	1,522.1	1,193.9
OPERATING EXPENSES
Purchased oil and gas expense	13.3	6.9	38.6	45.4
Lease operating expense	64.6	76.2	203.6	215.4
Transportation and processing costs	28.0	60.2	93.2	202.6
Gathering and other expense	4.6	1.7	10.8	5.0
General and administrative	48.3	43.4	164.2	108.3
Production and property taxes	37.4	28.5	103.9	86.1
Depreciation, depletion and amortization	234.9	176.9	673.6	560.2
Exploration expenses	0.0	21.3	0.1	21.7
Impairment	0.0	28.3	404.4	28.4
Total Operating Expenses	431.1	443.4	1,692.4	1,273.1
Net gain (loss) from asset sales, inclusive of restructuring costs	27.1	185.4	26.7	205.2
OPERATING INCOME (LOSS)	156.8	132.1	(143.6)	126.0
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(108.0)	(104.3)	(240.3)	163.3
Interest and other income (expense)	(0.3)	0.1	(4.1)	2.5
Interest expense	(38.7)	(34.4)	(111.9)	(103.1)
INCOME (LOSS) BEFORE INCOME TAXES	9.8	(6.5)	(499.9)	188.7
Income tax (provision) benefit	(2.5)	3.2	117.6	(69.7)
Net income (loss)	$ 7.3	$ (3.3)	$ (382.3)	$ 119.0
Earnings (loss) per common share
Basic	$ 0.03	$ (0.01)	$ (1.60)	$ 0.49
Diluted	$ 0.03	$ (0.01)	$ (1.60)	$ 0.49
Weighted-average common shares outstanding
Used in basic calculation	236.9	240.7	238.3	240.5
Used in diluted calculation	237.0	240.7	238.3	240.5
As reported [Member]
REVENUES
Oil and condensate, gas and NGL sales	$ 544.0	$ 380.9	$ 1,474.1	$ 1,139.1
Other revenue	3.8		11.8
Purchased oil and gas sales	13.0		36.2
Total Revenues	560.8		1,522.1
OPERATING EXPENSES
Purchased oil and gas expense	13.3		38.6
Lease operating expense	64.6		203.6
Transportation and processing costs	28.0		93.2
Gathering and other expense	4.6		10.8
General and administrative	48.3		164.2
Production and property taxes	37.4		103.9
Depreciation, depletion and amortization	234.9		673.6
Exploration expenses	0.0		0.1
Impairment	0.0		404.4
Total Operating Expenses	431.1		1,692.4
Net gain (loss) from asset sales, inclusive of restructuring costs	27.1		26.7
OPERATING INCOME (LOSS)	156.8		(143.6)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(108.0)		(240.3)
Interest and other income (expense)	(0.3)		(4.1)
Interest expense	(38.7)		(111.9)
INCOME (LOSS) BEFORE INCOME TAXES	9.8		(499.9)
Income tax (provision) benefit	(2.5)		117.6
Net income (loss)	$ 7.3		$ (382.3)
Earnings (loss) per common share
Basic	$ 0.03		$ (1.60)
Diluted	$ 0.03		$ (1.60)
Weighted-average common shares outstanding
Used in basic calculation	236.9		238.3
Used in diluted calculation	237.0		238.3
Adjustments for New Accounting Pronouncement [Member]
REVENUES
Oil and condensate, gas and NGL sales	$ 15.8		$ 40.9
Other revenue	0.0		0.0
Purchased oil and gas sales	0.0		0.0
Total Revenues	15.8		40.9
OPERATING EXPENSES
Purchased oil and gas expense	0.0		0.0
Lease operating expense	0.0		0.0
Transportation and processing costs	15.8		40.9
Gathering and other expense	0.0		0.0
General and administrative	0.0		0.0
Production and property taxes	0.0		0.0
Depreciation, depletion and amortization	0.0		0.0
Exploration expenses	0.0		0.0
Impairment	0.0		0.0
Total Operating Expenses	15.8		40.9
Net gain (loss) from asset sales, inclusive of restructuring costs	0.0		0.0
OPERATING INCOME (LOSS)	0.0		0.0
Realized and unrealized gains (losses) on derivative contracts (Note 7)	0.0		0.0
Interest and other income (expense)	0.0		0.0
Interest expense	0.0		0.0
INCOME (LOSS) BEFORE INCOME TAXES	0.0		0.0
Income tax (provision) benefit			0.0
Net income (loss)	$ 0.0		$ 0.0
Earnings (loss) per common share
Basic	$ 0.00		$ 0.00
Diluted	$ 0.00		$ 0.00
Weighted-average common shares outstanding
Used in basic calculation	0.0		0.0
Used in diluted calculation	0.0		0.0
Income Statement, as adjusted [Member]
REVENUES
Oil and condensate, gas and NGL sales	$ 559.8		$ 1,515.0
Other revenue	3.8		11.8
Purchased oil and gas sales	13.0		36.2
Total Revenues	576.6		1,563.0
OPERATING EXPENSES
Purchased oil and gas expense	13.3		38.6
Lease operating expense	64.6		203.6
Transportation and processing costs	43.8		134.1
Gathering and other expense	4.6		10.8
General and administrative	48.3		164.2
Production and property taxes	37.4		103.9
Depreciation, depletion and amortization	234.9		673.6
Exploration expenses	0.0		0.1
Impairment	0.0		404.4
Total Operating Expenses	446.9		1,733.3
Net gain (loss) from asset sales, inclusive of restructuring costs	27.1		26.7
OPERATING INCOME (LOSS)	156.8		(143.6)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(108.0)		(240.3)
Interest and other income (expense)	(0.3)		(4.1)
Interest expense	(38.7)		(111.9)
INCOME (LOSS) BEFORE INCOME TAXES	9.8		(499.9)
Income tax (provision) benefit	(2.5)		117.6
Net income (loss)	$ 7.3		$ (382.3)
Earnings (loss) per common share
Basic	$ 0.03		$ (1.60)
Diluted	$ 0.03		$ (1.60)
Weighted-average common shares outstanding
Used in basic calculation	236.9		238.3
Used in diluted calculation	237.0		238.3

Revenue Disaggregated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Transportation and processing costs	$ 28.0	$ 60.2	$ 93.2	$ 202.6
Oil and condensate, gas and NGL sales	544.0	380.9	1,474.1	1,139.1
As reported [Member]
Oil and condensate sales	416.1	218.0	1,125.3	655.7
Gas sales	101.7	130.7	301.5	399.4
NGL sales	42.0	32.2	88.2	84.0
Transportation and processing costs	28.0		93.2
Oil and condensate, gas and NGL sales	544.0	380.9	1,474.1	1,139.1
As reported [Member] \| Williston Basin [Member]
Oil and condensate sales	203.4	125.7	571.5	416.5
Gas sales	12.0	9.5	30.2	32.5
NGL sales	19.2	13.0	45.7	34.8
Transportation and processing costs	(12.3)	0.0	(32.9)	0.0
Oil and condensate, gas and NGL sales	222.3	148.2	614.5	483.8
As reported [Member] \| Pinedale [Member]
Oil and condensate sales		5.2		18.0
Gas sales		43.0		154.8
NGL sales		10.1		30.1
Transportation and processing costs		0.0		0.0
Oil and condensate, gas and NGL sales		58.3		202.9
As reported [Member] \| Uinta Basin [Member]
Oil and condensate sales	7.3	7.5	25.2	21.8
Gas sales	6.8	12.2	24.8	39.1
NGL sales	1.4	1.6	4.8	4.3
Transportation and processing costs	0.0	0.0	0.0	0.0
Oil and condensate, gas and NGL sales	15.5	21.3	54.8	65.2
As reported [Member] \| Other Northern [Member]
Oil and condensate sales	1.1	1.2	3.9	4.0
Gas sales	0.5	4.2	1.7	15.0
NGL sales	0.1	0.1	0.0	0.3
Transportation and processing costs	0.0	0.0	0.0	0.0
Oil and condensate, gas and NGL sales	1.7	5.5	5.6	19.3
As reported [Member] \| Permian Basin [Member]
Oil and condensate sales	204.0	78.1	524.1	194.3
Gas sales	5.4	4.5	13.2	11.3
NGL sales	21.3	7.3	37.7	14.2
Transportation and processing costs	(3.5)	0.0	(8.0)	0.0
Oil and condensate, gas and NGL sales	227.2	89.9	567.0	219.8
As reported [Member] \| Haynesville/Cotton Valley [Member]
Oil and condensate sales	0.2	0.3	0.8	0.9
Gas sales	76.9	57.2	231.2	146.4
NGL sales	0.0	0.1	0.0	0.3
Transportation and processing costs	0.0	0.0	0.0	0.0
Oil and condensate, gas and NGL sales	77.1	57.6	232.0	147.6
As reported [Member] \| Other Southern [Member]
Oil and condensate sales	0.1	0.0	(0.2)	0.2
Gas sales	0.1	0.1	0.4	0.3
NGL sales	0.0	0.0	0.0	0.0
Transportation and processing costs	0.0	0.0	0.0	0.0
Oil and condensate, gas and NGL sales	0.2	0.1	0.2	0.5
As reported [Member] \| Total [Member]
Transportation and processing costs	$ (15.8)	$ 0.0	$ (40.9)	$ 0.0

Acquisitions & Divestitures Acquisitions (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Business Acquisition [Line Items]
Payments to acquire oil and gas property	$ 48.3	$ 94.5
Goodwill		$ 5.3
2017 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property	$ 37.6

Acquisitions & Divestitures Uinta Basin (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
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			$ 217.5	$ 787.9
Impairment of Oil and Gas Properties			404.4
Noncurrent assets held for sale	$ 0.0		0.0		$ 632.8
Gain (Loss) on Disposition of Oil and Gas Property	27.1	$ 185.4	26.7	205.2
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
Impairment of Oil and Gas Properties			402.8
Gain (Loss) on Disposition of Oil and Gas Property			(12.4)
Results of Operations, Loss before Income Taxes	$ (4.4)	$ (4.3)	(419.3)	$ (12.8)
Restructuring Charges			$ 5.5

Acquisitions & Divestitures Pinedale Divestiture (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Divestitures [Line Items]
Proceeds from disposition of assets			$ 217.5	$ 787.9
Net gain (loss) from asset sales, inclusive of restructuring costs	$ 27.1	$ 185.4	26.7	205.2
Income (loss) before income taxes	9.8	(6.5)	(499.9)	188.7
Pinedale Divestiture [Member]
Divestitures [Line Items]
Proceeds from disposition of assets		718.2
Net gain (loss) from asset sales, inclusive of restructuring costs			1.2
Income (loss) before income taxes		$ 208.2		$ 251.2
Minimum volume commitment			45.0
Minimum volume commitment remaining	$ 23.0		$ 23.0

Acquisitions & Divestitures Other Divestitures (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Divestitures [Line Items]
Proceeds from disposition of assets			$ 217.5	$ 787.9
Net gain (loss) from asset sales, inclusive of restructuring costs	$ 27.1	$ 185.4	26.7	205.2
Non-core properties Divestitures [Member]
Divestitures [Line Items]
Proceeds from disposition of assets			64.5	69.7
Net gain (loss) from asset sales, inclusive of restructuring costs			$ 37.9	$ 26.4

Earnings Per Share Components of Basic and Diluted Shares Used In EPS Calculation (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	0.0	0.0	0.0	0.0
Weighted-average basic common shares outstanding	236.9	240.7	238.3	240.5
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	0.1	0.0	0.0	0.0
Average diluted common shares outstanding	237.0	240.7	238.3	240.5

Asset Retirement Obligations (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Divestitures [Line Items]
Asset Retirement Obligation, Current	$ 5.0	$ 3.5
ARO Liability [Roll Forward]
ARO liability at December 31, 2017(1)	(214.1)
Accretion	5.0
Additions	3.2
Revisions	(3.4)
Liabilities related to assets sold(2)	(6.7)
Liabilities settled	(51.7)
ARO liability at September 30, 2018	(160.5)
Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
ARO Liability [Roll Forward]
ARO liability at December 31, 2017(1)	(51.6)
Uinta Basin [Member]
ARO Liability [Roll Forward]
Liabilities related to assets sold(2)	$ 51.0

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

Sep. 30, 2018

Dec. 31, 2017

Financial Assets

Derivative Asset, Netting Adjustments

^[1]

$ (3.7)

$ (19.4)

Derivative Asset, Net

14.1

3.5

Financial liabilities

Derivative Liability, Netting Adjustments

^[1]

(3.7)

(19.4)

Derivative Liability, Net

253.3

135.4

Level 1 [Member]

Financial Assets

Derivative Asset, Fair Value, Gross

0.0

Financial liabilities

Derivative Liability, Fair Value, Gross

0.0

Level 2 [Member]

Financial Assets

Derivative Asset, Fair Value, Gross

17.8

22.9

Financial liabilities

Derivative Liability, Fair Value, Gross

257.0

154.8

Level 3 [Member]

Financial Assets

Derivative Asset, Fair Value, Gross

0.0

Financial liabilities

Derivative Liability, Fair Value, Gross

0.0

Short-term [Member]

Financial Assets

Derivative Asset, Netting Adjustments

^[1]

(2.6)

(17.2)

Derivative Asset, Net

14.0

3.4

Financial liabilities

Derivative Liability, Netting Adjustments

^[1]

(2.6)

(17.2)

Derivative Liability, Net

200.7

103.6

Short-term [Member] | Level 1 [Member]

Financial Assets

Derivative Asset, Fair Value, Gross

0.0

Financial liabilities

Derivative Liability, Fair Value, Gross

0.0

Short-term [Member] | Level 2 [Member]

Financial Assets

Derivative Asset, Fair Value, Gross

16.6

20.6

Financial liabilities

Derivative Liability, Fair Value, Gross

203.3

120.8

Short-term [Member] | Level 3 [Member]

Financial Assets

Derivative Asset, Fair Value, Gross

0.0

Financial liabilities

Derivative Liability, Fair Value, Gross

0.0

Long-term [Member]

Financial Assets

Derivative Asset, Netting Adjustments

^[1]

(1.1)

(2.2)

Derivative Asset, Net

0.1

Financial liabilities

Derivative Liability, Netting Adjustments

^[1]

(1.1)

(2.2)

Derivative Liability, Net

52.6

31.8

Long-term [Member] | Level 1 [Member]

Financial Assets

Derivative Asset, Fair Value, Gross

0.0

Financial liabilities

Derivative Liability, Fair Value, Gross

0.0

Long-term [Member] | Level 2 [Member]

Financial Assets

Derivative Asset, Fair Value, Gross

1.2

2.3

Financial liabilities

Derivative Liability, Fair Value, Gross

53.7

34.0

Long-term [Member] | Level 3 [Member]

Financial Assets

Derivative Asset, Fair Value, Gross

0.0

Financial liabilities

Derivative Liability, Fair Value, Gross

$ 0.0

[1]

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

Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 0.0	$ 0.0	$ 782.6
Checks outstanding in excess of cash balances	15.3	44.0
Long-term debt	2,451.1	2,160.8
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	0.0	0.0
Checks outstanding in excess of cash balances	15.3	44.0
Long-term debt, fair value	$ 2,465.7	$ 2,256.2

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Oil and Gas Properties		$ 404.4
Proved Property [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Oil and Gas Properties	$ 0.0	$ 397.6

Derivative Contracts (Narrative) (Details)	9 Months Ended
Derivative Contracts (Narrative) (Details)	Sep. 30, 2018
Derivative [Line Items]
Maximum Forecasted Production Covered By Derivatives	100.00%
Minimum [Member]
Derivative [Line Items]
Expected Annual Production Covered By Derivatives	50.00%
Maximum [Member]
Derivative [Line Items]
Expected Annual Production Covered By Derivatives	75.00%

Derivative Contracts Schedule Of Commodity Derivative Contracts (Details) MMBTU in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) MMBTU $ / MMBTU
Oil Swaps [Member] \| Year 2018 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	4.1
Average Swap Price per Unit \| $	$ 52.45
Oil Swaps [Member] \| Year 2019 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	11.0
Average Swap Price per Unit \| $	$ 54.49
Oil Swaps [Member] \| Year 2020 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	2.9
Average Swap Price per Unit \| $	$ 62.37
Gas Swaps [Member] \| Year 2018 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	25.2
Average Swap Price per Unit \| $	$ 3.01
Gas Swaps [Member] \| Year 2019 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	43.8
Average Swap Price per Unit \| $	$ 2.86
Oil Basis Swaps [Member] \| Year 2018 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	2.3
Weighted-Average Differential \| $ / MMBTU	(0.99)
Oil Basis Swaps [Member] \| Year 2018 [Member] \| NYMEX WTI less Argus WTI Houston [Member]
Derivative [Line Items]
Derivative Volumes	0.1
Weighted-Average Differential \| $ / MMBTU	6.30
Oil Basis Swaps [Member] \| Year 2019 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	6.6
Weighted-Average Differential \| $ / MMBTU	(2.22)
Oil Basis Swaps [Member] \| Year 2019 [Member] \| NYMEX WTI less Argus WTI Houston [Member]
Derivative [Line Items]
Derivative Volumes	0.4
Weighted-Average Differential \| $ / MMBTU	4.35
Oil Basis Swaps [Member] \| Year 2020 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	1.5
Weighted-Average Differential \| $ / MMBTU	(1.01)
Gas Basis Swaps [Member] \| Year 2018 [Member] \| NYMEX HH LESS IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	1.8
Weighted-Average Differential \| $ / MMBTU	(0.16)

Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Inputs, Level 2 [Member] - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	$ 17.8	$ 22.9
Derivative Liability, Fair Value, Gross	257.0	154.8
Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	16.6	20.6
Derivative Liability, Fair Value, Gross	203.3	120.8
Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	1.2	2.3
Derivative Liability, Fair Value, Gross	53.7	34.0
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	17.8	22.9
Derivative Liability, Fair Value, Gross	257.0	154.8
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member] \| Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	16.6	20.6
Derivative Liability, Fair Value, Gross	203.3	120.8
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member] \| Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	1.2	2.3
Derivative Liability, Fair Value, Gross	$ 53.7	$ 34.0

Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	$ (38.4)	$ 11.7	$ (127.1)	$ 1.7
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(108.0)	(104.3)	(240.3)	163.3
Oil derivative contracts [Member] \| Production [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	(41.7)	12.1	(138.0)	21.6
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(60.6)	(86.1)	(88.1)	88.7
Gas derivative contracts [Member] \| Production [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	3.3	(0.4)	10.6	(19.7)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(3.1)	0.0	(18.9)	100.5
Gas derivative contracts [Member] \| Storage [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.0	0.3	(0.2)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.0	(0.3)	2.3
Total [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(63.7)	(86.1)	(107.3)	191.5
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	(102.1)	(74.4)	(234.4)	193.2
Uinta Basin Divestiture [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(5.9)		(5.9)
Uinta Basin Divestiture [Member] \| Oil derivative contracts [Member] \| Production [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	(2.7)		(2.7)
Uinta Basin Divestiture [Member] \| Gas derivative contracts [Member] \| Production [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0		0.0
Uinta Basin Divestiture [Member] \| NGL derivative contracts [Member] \| Production [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	$ (3.2)		$ (3.2)
Pinedale Divestiture [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		(29.9)		(29.9)
Pinedale Divestiture [Member] \| Oil derivative contracts [Member] \| Production [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		(1.3)		(1.3)
Pinedale Divestiture [Member] \| Gas derivative contracts [Member] \| Production [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		(23.5)		(23.5)
Pinedale Divestiture [Member] \| NGL derivative contracts [Member] \| Production [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		$ (5.1)		$ (5.1)

Restructuring Costs Narrative (Details) $ in Millions	Sep. 30, 2018 USD ($)
Year 2018 [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	$ 6.3
Year 2019 [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	$ 4.2

Restructuring Costs Restructuring Expense Table (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2017
Accelerated share-based compensation	$ 3.2		$ 7.2
Termination Benefits [Member]
Costs recognized period from inception to September 30, 2018	13.7	$ 13.7
Total remaining costs expected to be incurred		0.0
Office lease Termination Costs [Member]
Costs recognized period from inception to September 30, 2018	1.0	1.0
Total remaining costs expected to be incurred		0.0
Accelerated Share Based Compensation [Member]
Costs recognized period from inception to September 30, 2018	7.2	7.2
Total remaining costs expected to be incurred		0.0
Retention Expense [Member]
Costs recognized period from inception to September 30, 2018	13.8	13.8
Total remaining costs expected to be incurred		10.5
Pension curtailment [Member]
Costs recognized period from inception to September 30, 2018	0.3	0.3
Total remaining costs expected to be incurred		0.0
Total [Member]
Termination benefits	6.7	13.7
Office lease termination costs	0.7	1.0
Accelerated share-based compensation	3.2	7.2
Retention expense	5.8	13.8
Pension curtailment	0.3	0.3
Total restructuring costs	16.7	36.0
Costs recognized period from inception to September 30, 2018	36.0	36.0
Total remaining costs expected to be incurred		10.5
General and Administrative Expense [Member]
Termination benefits	5.3	10.4
Office lease termination costs	0.7	1.0
Accelerated share-based compensation	1.0	5.0
Retention expense	5.8	13.8
Pension curtailment	0.0	0.0
Total restructuring costs	12.8	30.2
Net gain (loss) from asset sales [Member]
Termination benefits	1.4	3.3
Office lease termination costs	0.0	0.0
Accelerated share-based compensation	2.2	2.2
Retention expense	0.0	0.0
Pension curtailment	0.0	0.0
Total restructuring costs	3.6	5.5
Interest and other income (expense) [Member]
Termination benefits	0.0	0.0
Office lease termination costs	0.0	0.0
Accelerated share-based compensation	0.0	0.0
Retention expense	0.0	0.0
Pension curtailment	0.3	0.3
Total restructuring costs	$ 0.3	$ 0.3

Restructuring Costs Restructuring Liability (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	$ 5.3	$ 0.0
Costs incurred and charged to expense	13.7
Costs paid or otherwise settled	(8.4)
Office lease Termination Costs [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	0.0	0.0
Costs incurred and charged to expense	1.0
Costs paid or otherwise settled	(1.0)
Accelerated Share Based Compensation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	0.0	0.0
Costs incurred and charged to expense	7.2
Costs paid or otherwise settled	(7.2)
Retention Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	5.8	0.0
Costs incurred and charged to expense	13.8
Costs paid or otherwise settled	(8.0)
Pension curtailment [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	0.0	0.0
Costs incurred and charged to expense	0.3
Costs paid or otherwise settled	(0.3)
Total [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	11.1	$ 0.0
Costs incurred and charged to expense	36.0
Costs paid or otherwise settled	$ (24.9)

Debt (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended
Debt (Narrative) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt Maturity Period	5 years
Long-term Debt, Weighted Average Interest Rate, at Point in Time	4.30%
Principal amount of senior notes outstanding	$ 2,099.3
Senior Notes, stated interest rate, minimum (in hundredths)	5.25%
Senior Notes, stated interest rate, maximim (in hundredths)	6.875%
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 375.5	$ 89.0
Maturity date of long-term debt	Sep. 01, 2022
Borrowing capacity	$ 1,250.0
Letters of credit outstanding	0.3	1.0
6.80% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 51.7	51.7
Long-term debt, interest rate (in hundredths)	6.80%
Maturity date of long-term debt	Mar. 01, 2020
6.875% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 397.6	397.6
Long-term debt, interest rate (in hundredths)	6.875%
Maturity date of long-term debt	Mar. 01, 2021
5.375% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 500.0	$ 500.0
Long-term debt, interest rate (in hundredths)	5.375%
Maturity date of long-term debt	Oct. 01, 2022
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate (in hundredths)	5.25%
Maturity date of long-term debt	May 01, 2023
Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Maturity date of long-term debt	Mar. 01, 2026

Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Less unamortized discount	$ (23.7)	$ (27.5)
Long-term debt	2,451.1	2,160.8
Total long-term debt outstanding	2,451.1	2,160.8
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	375.5	89.0
6.80% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	51.7	51.7
6.875% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	397.6	397.6
5.375% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	500.0	500.0
5.25% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	650.0	650.0
5.625% Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 500.0	$ 500.0

Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	10.0
Shares available for future grants	10.1
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option exercises, intrinsic value	$ 0.1
Unrecognized compensation costs	$ 0.6
Weighted average vesting period	1 year 4 months 24 days
Restricted Share Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 9.56	$ 14.13
Unrecognized compensation costs	$ 22.0
Weighted average vesting period	2 years 2 months 5 days
Award vesting period	3 years
Total fair value of stock that vested during the period	$ 30.7	$ 22.9
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 9.55	$ 16.90
Unrecognized compensation costs	$ 9.2
Weighted average vesting period	2 years
Restricted Share Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 9.55	$ 16.98
Unrecognized compensation costs	$ 0.3
Weighted average vesting period	1 year 2 months 30 days

Share-Based Compensation Share-based compensation expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	$ 3.2			$ 7.2
Share-based Compensation	2.7	$ 5.8	$ 26.1	13.5
Stock Options [Member]
Share-based Compensation Expense [Line Items]
Share-based Compensation	0.2	0.5	0.9	1.7
Restricted Share Awards [Member]
Share-based Compensation Expense [Line Items]
Share-based Compensation	5.3	5.4	20.9	18.7
Performance Share Units [Member]
Share-based Compensation Expense [Line Items]
Share-based Compensation	(2.9)	(0.1)	4.1	(6.9)
Restricted Share Units (RSUs) [Member]
Share-based Compensation Expense [Line Items]
Share-based Compensation	0.1	$ 0.0	0.2	$ 0.0
Net gain (loss) from asset sales [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	2.2		2.2
General and Administrative Expense [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	$ 1.0		$ 5.0

Share-Based Compensation Schedule Of Stock Option Transactions (Details) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding at beginning of period \| shares	2,354,277
Options exercised \| shares	23,337
Options canceled \| shares	(232,007)
Outstanding at end of period \| shares	2,098,933
Options exercisable, shares \| shares	1,707,915
Unvested options, shares \| shares	391,018
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted average exercise price, beginning of year \| $ / shares	$ 23.62
Weighted average exercise price, exercised in period \| $ / shares	10.12
Weighted average exercise price, canceled in period \| $ / shares	37.16
Weighted average exercise price, end of year \| $ / shares	22.27
Options exercisable, weighted average exercise price \| $ / shares	24.04
Unvested options, weighted average exercise price \| $ / shares	$ 14.56
Weighted average remaining contractual term, options outstanding	3 years 1 month 13 days
Weighted average remaining contractual term, options exercisable	2 years 8 months 5 days
Weighted average remaining contractual term, options unvested	5 years 18 days
Aggregate intrinsic value, options outstanding \| $	$ 0.5
Aggregate intrinsic value, options exercisable \| $	0.3
Aggregate intrinsic value, options unvested \| $	$ 0.2

Share-Based Compensation Schedule of Restricted Share Awards Transactions (Details) - Restricted Share Awards [Member] - $ / shares	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	3,721,334
Shares granted	2,981,589
Shares vested	(2,344,304)
Shares forfeited	(223,222)
Unvested balance at end of period	4,135,397
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period	$ 13.23
Weighted average grant date fair value, grants	9.56	$ 14.13
Weighted average grant date fair value, vested	13.11
Weighted average grant date fair value, forfeited	10.94
Weighted average grant date fair value, end of period	$ 10.77

Share-Based Compensation Schedule Of Performance Share Unit Transactions (Details) - Performance Share Units [Member] - $ / shares	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	1,199,336
Shares granted	724,095
Shares vested	(277,604)
Unvested balance at end of period	1,645,827
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period	$ 14.59
Weighted average grant date fair value, grants	9.55	$ 16.90
Weighted average grant date fair value, vested	19.73
Weighted average grant date fair value, end of period	$ 11.47

Share-Based Compensation Schedule of Restricted Share Unit Transactions (Details) - Restricted Share Units (RSUs) [Member] - $ / shares	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested balance at beginning of period	21,946
Shares granted	31,835
Shares vested	(11,106)
Unvested balance at end of period	42,675
Weighted average grant date fair value, beginning of period	$ 13.22
Weighted average grant date fair value, grants	9.55	$ 16.98
Weighted average grant date fair value, vested	13.27
Weighted average grant date fair value, end of period	$ 10.47

Employee Benefits (Narrative) (Details) $ in Millions	9 Months Ended
Employee Benefits (Narrative) (Details) $ in Millions	Sep. 30, 2018 USD ($)
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer	$ 4.0
Estimated Future Employer Contributions in Current Fiscal Year	1.0
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer	0.6
Estimated Future Employer Contributions in Current Fiscal Year	0.1
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer	0.2
401(k) Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer	4.9
Estimated Future Employer Contributions in Current Fiscal Year	1.1
Pension Plan Discretionary Contribution [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year	$ 0.3

Employee Benefits Schedule of Net Periodic Benefit Cost (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2018

Sep. 30, 2017

Sep. 30, 2018

Sep. 30, 2017

Pension Plan and SERP [Member]

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

Service cost

$ 0.2

$ 0.6

Interest cost

1.2

3.4

3.6

Expected return on plan assets

(1.4)

(1.3)

(4.3)

(4.0)

Amortization of prior service costs(1)

^[1]

0.2

0.3

0.6

0.9

Amortization of actuarial losses(1)

^[1]

0.0

0.1

0.6

0.3

Curtailment loss(2)

^[2]

0.3

0.7

0.3

0.7

Periodic expense

0.5

(1.2)

(2.1)

Medical Plan [Member]

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

Interest cost

0.0

0.1

Amortization of prior service costs(1)

^[1]

(0.1)

(0.2)

Periodic expense

$ 0.1

[1]

Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income are recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)".

[2]

Subsequent Event (Details) - USD ($)	9 Months Ended
Subsequent Event (Details) - USD ($)	Sep. 30, 2018	Sep. 30, 2017
Subsequent Event [Line Items]
Purchase price to acquire oil and gas property	$ 48,300,000	$ 94,500,000
Williston Basin Divestiture [Member]
Subsequent Event [Line Items]
Purchase price to acquire oil and gas property	1,725,000,000
Cash Payments to Acquire Oil and Gas Property	1,650,000,000
Net book value of assets	2,521,800,000
Williston Basin Divestiture [Member] \| Threshold 1 [Member]
Subsequent Event [Line Items]
Contractual Rights	50,000,000
Buyer's Share Price	12.00
Williston Basin Divestiture [Member] \| Threshold 2 [Member]
Subsequent Event [Line Items]
Contractual Rights	25,000,000
Buyer's Share Price	$ 15.00