10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2019

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission File Number: 001-34778

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	87-0287750
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

1050 17^th Street, Suite 800, Denver, Colorado 80265

(Address of principal executive offices)

Registrant's telephone number, including area code (303) 672-6900

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, $0.01 par value	QEP	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act:

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐

No ☒

At June 30, 2019, there were 237,912,768 shares of the registrant's common stock, $0.01 par value, outstanding. 

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2019

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION			2
	ITEM 1.	FINANCIAL STATEMENTS	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019 AND 2018	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019 AND 2018	3
		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT JUNE 30, 2019 AND DECEMBER 31, 2018	4
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF EQUITY FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019 AND 2018	5
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2019 AND 2018	6
		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	7
	ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	49
	ITEM 4.	CONTROLS AND PROCEDURES	53
PART II. OTHER INFORMATION			53
	ITEM 1.	LEGAL PROCEEDINGS	53
	ITEM 1A.	RISK FACTORS	54
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	55
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	55
	ITEM 4.	MINE SAFETY DISCLOSURES	55
	ITEM 5.	OTHER INFORMATION	55
	ITEM 6.	EXHIBITS	57
SIGNATURES			58

1

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	294.6		$	520.3		$	570.2		$	930.1
Other revenues	1.6			3.0			5.3			8.0
Purchased oil and gas sales	—			9.1			1.3			23.2
Total Revenues	296.2			532.4			576.8			961.3
OPERATING EXPENSES
Purchased oil and gas expense	—			9.8			1.4			25.3
Lease operating expense	45.7			66.5			97.2			139.0
Transportation and processing costs	9.9			31.2			20.8			65.2
Gathering and other expense	3.0			3.4			6.8			6.2
General and administrative	31.5			55.8			94.8			115.9
Production and property taxes	23.6			37.6			47.6			66.5
Depreciation, depletion and amortization	128.0			242.2			251.3			438.7
Exploration expenses	—			0.1			—			0.1
Impairment	—			403.7			5.0			404.4
Total Operating Expenses	241.7			850.3			524.9			1,261.3
Net gain (loss) from asset sales, inclusive of restructuring costs	17.8			(3.9		)	4.6			(0.4		)
OPERATING INCOME (LOSS)	72.3			(321.8		)	56.5			(300.4		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	38.5			(79.1		)	(143.2		)	(132.3		)
Interest and other income (expense)	0.9			(3.1		)	3.7			(3.8		)
Interest expense	(33.2		)	(38.2		)	(67.2		)	(73.2		)
INCOME (LOSS) BEFORE INCOME TAXES	78.5			(442.2		)	(150.2		)	(509.7		)
Income tax (provision) benefit	(29.7		)	106.2			82.3			120.1
NET INCOME (LOSS)	$	48.8		$	(336.0	)	$	(67.9	)	$	(389.6	)
Earnings (loss) per common share
Basic	$	0.20		$	(1.42	)	$	(0.29	)	$	(1.63	)
Diluted	$	0.20		$	(1.42	)	$	(0.29	)	$	(1.63	)
Weighted-average common shares outstanding
Used in basic calculation	238.0			237.0			237.5			238.9
Used in diluted calculation	238.0			237.0			237.5			238.9

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

2

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2019		2018			2019			2018
	(in millions)
Net income (loss)	$	48.8	$	(336.0	)	$	(67.9	)	$	(389.6	)
Other comprehensive income (loss), net of tax:
Fair value of plan assets adjustment(1)	—		—			—			0.3
Pension and other postretirement plans adjustments:
Amortization of prior service costs(2)	—		0.1			0.1			0.2
Amortization of actuarial losses(3)	—		0.2			0.1			0.4
Net curtailment(4)	0.1		—			(0.3		)	—
Other comprehensive income (loss)	0.1		0.3			(0.1		)	0.9
Comprehensive income (loss)	$	48.9	$	(335.7	)	$	(68.0	)	$	(388.7	)

____________________________

⁽¹⁾  Adjustment recorded during the six months ended June 30, 2018, related to a change in the fair value of plan assets as of December 31, 2017.

⁽²⁾  Presented net of income tax expense of $0.1 million and $0.1 million for the three and six months ended June 30, 2018, respectively.

⁽³⁾  Presented net of income tax expense of $0.1 million and $0.2 million for the three and six months ended June 30, 2018, respectively.

⁽⁴⁾  Presented net of income tax expense of $0.1 million for the six months ended June 30, 2019, respectively.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2019			December 31, 2018
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	97.1		$	—
Accounts receivable, net	93.5			104.3
Income tax receivable	70.8			75.9
Fair value of derivative contracts	2.7			87.5
Prepaid expenses	7.1			12.7
Other current assets	0.2			0.2
Total Current Assets	271.4			280.6
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,316.0			9,096.9
Unproved properties	706.6			705.5
Gathering and other	169.1			167.7
Materials and supplies	20.9			29.9
Total Property, Plant and Equipment	10,212.6			10,000.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,050.9			4,882.4
Gathering and other	58.4			58.1
Total Accumulated Depreciation, Depletion and Amortization	5,109.3			4,940.5
Net Property, Plant and Equipment	5,103.3			5,059.5
Fair value of derivative contracts	15.2			35.4
Operating lease right-of-use assets, net	60.2			—
Other noncurrent assets	54.2			49.6
Noncurrent assets held for sale	—			692.7
TOTAL ASSETS	$	5,504.3		$	6,117.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	5.3		$	14.6
Accounts payable and accrued expenses	227.9			258.1
Production and property taxes	15.9			24.1
Current portion of long term debt	51.7			—
Interest payable	32.5			32.4
Fair value of derivative contracts	17.6			—
Current operating lease liabilities	18.8			—
Asset retirement obligations	6.8			5.1
Total Current Liabilities	376.5			334.3
Long-term debt	2,028.1			2,507.1
Deferred income taxes	181.4			269.2
Asset retirement obligations	94.6			96.9
Fair value of derivative contracts	0.9			0.7
Operating lease liabilities	47.9			—
Other long-term liabilities	85.6			97.4
Other long-term liabilities held for sale	—			61.3
Commitments and contingencies (Note 11)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 242.0 million and 239.8 million shares issued, respectively	2.4			2.4
Treasury stock – 4.1 million and 3.1 million shares, respectively	(53.6		)	(45.6		)
Additional paid-in capital	1,446.3			1,431.9
Retained earnings	1,308.6			1,376.5
Accumulated other comprehensive income (loss)	(14.4		)	(14.3		)
Total Common Shareholders' Equity	2,689.3			2,750.9
TOTAL LIABILITIES AND EQUITY	$	5,504.3		$	6,117.8

 

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

4

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

	Common Stock			Treasury Stock					Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income(Loss)			Total
	Shares	Amount		Shares		Amount
	(in millions)
Balance at March 31, 2019	242.0	$	2.4	(3.9	)	$	(51.8	)	$	1,440.2	$	1,259.8	$	(14.5	)	$	2,636.1
Net income (loss)	—	—		—		—			—		48.8		—			48.8
Share-based compensation	—	—		(0.2	)	(1.8		)	6.1		—		—			4.3
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—		0.1			0.1
Balance at June 30, 2019	242.0	$	2.4	(4.1	)	$	(53.6	)	$	1,446.3	$	1,308.6	$	(14.4	)	$	2,689.3

Balance at December 31, 2018	239.8	$	2.4	(3.1	)	$	(45.6	)	$	1,431.9	$	1,376.5		$	(14.3	)	$	2,750.9
Net income (loss)	—	—		—		—			—		(67.9		)	—			(67.9		)
Share-based compensation	2.2	—		(1.0	)	(8.0		)	14.4		—			—			6.4
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—			(0.1		)	(0.1		)
Balance at June 30, 2019	242.0	$	2.4	(4.1	)	$	(53.6	)	$	1,446.3	$	1,308.6		$	(14.4	)	$	2,689.3

Balance at March 31, 2018	240.3		$	2.4	(2.6	)	$	(39.5	)	$	1,408.0	$	2,336.3		$	(10.5	)	$	3,696.7
Net income (loss)	—		—		—		—			—		(336.0		)	—			(336.0		)
Common stock repurchased and retired	(0.6	)	—		—		—			—		(5.6		)	—			(5.6		)
Share-based compensation	—		—		(0.1	)	(1.7		)	7.7		—			—			6.0
Change in pension and postretirement liability, net of tax	—		—		—		—			—		—			0.3			0.3
Balance at June 30, 2018	239.7		$	2.4	(2.7	)	$	(41.2	)	$	1,415.7	$	1,994.7		$	(10.2	)	$	3,361.4

Balance at December 31, 2017	243.0		$	2.4		(2.0	)	$	(34.2	)	$	1,398.2	$	2,442.6		$	(11.1	)	$	3,797.9
Net income (loss)	—		—			—		—			—		(389.6		)	—			(389.6		)
Common stock repurchased and retired	(6.2	)	(0.1		)	—		—			—		(58.3		)	—			(58.4		)
Share-based compensation	2.9		0.1			(0.7	)	(7.0		)	17.5		—			—			10.6
Change in pension and postretirement liability, net of tax	—		—			—		—			—		—			0.9			0.9
Balance at June 30, 2018	239.7		$	2.4		(2.7	)	$	(41.2	)	$	1,415.7	$	1,994.7		$	(10.2	)	$	3,361.4

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

5

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2019			2018
OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	(67.9	)	$	(389.6	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	251.3			438.7
Deferred income taxes (benefit)	(87.7		)	(120.5		)
Impairment	5.0			404.4
Non-cash share-based compensation	11.2			16.3
Amortization of debt issuance costs and discounts	2.7			2.6
Net (gain) loss from asset sales, inclusive of restructuring costs	(4.6		)	0.4
Unrealized (gains) losses on marketable securities	(2.7		)	(0.4		)
Unrealized (gains) losses on derivative contracts	121.3			43.6
Changes in operating assets and liabilities	(32.9		)	(18.6		)
Net Cash Provided by (Used in) Operating Activities	195.7			376.9
INVESTING ACTIVITIES
Property acquisitions	(1.8		)	(45.1		)
Property, plant and equipment, including exploratory well expense	(316.8		)	(764.3		)
Proceeds from disposition of assets	666.7			48.8
Net Cash Provided by (Used in) Investing Activities	348.1			(760.6		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(9.3		)	(35.5		)
Proceeds from credit facility	56.0			2,029.5
Repayments of credit facility	(486.0		)	(1,543.5		)
Common stock repurchased and retired	—			(58.4		)
Treasury stock repurchases	(6.3		)	(5.9		)
Other capital contributions	—			0.2
Net Cash Provided by (Used in) Financing Activities	(445.6		)	386.4
Change in cash, cash equivalents and restricted cash(1)	98.2			2.7
Beginning cash, cash equivalents and restricted cash(1)	28.1			23.4
Ending cash, cash equivalents and restricted cash(1)	$	126.3		$	26.1
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	63.3		$	63.5
Cash paid for income taxes, net	$	1.5		$	0.2
Cash paid for amounts included in the measurement of lease liabilities	$	13.1		$	—
Non-cash Operating Activities:
Right-of-use assets obtained in exchange for operating lease obligations	$	9.8		$	—
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$	20.3		$	20.2

____________________________

⁽¹⁾  Refer to Cash, Cash Equivalents and Restricted Cash in Note 1 – Basis of Presentation.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

6

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation

Nature of Business

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

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, 2018.

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 six months ended June 30, 2019, are not necessarily indicative of the results that may be expected for the year ending December 31, 2019.

Reclassifications

Certain prior period balances on the Condensed Consolidated Statements of Cash Flows have been reclassified 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 six months ended June 30, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.

During the six months ended June 30, 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment was triggered due to the signing of a purchase and sale agreement for the divestiture of the Uinta Basin assets. 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.

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.

7

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:

	June 30,
	2019		2018
	(in millions)
Cash and cash equivalents	$	97.1	$	—
Restricted cash(1)	29.2		26.1
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	126.3	$	26.1

_______________________

⁽¹⁾ As of June 30, 2019 and 2018, the restricted cash balance is cash held in an escrow account related to a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Condensed Consolidated Balance Sheets.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance. The Company adopted ASU 2016-02 on January 1, 2019 using the modified retrospective approach and elected to not adjust periods prior to January 1, 2019. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed the carry forward of the historical lease classification, including accounting treatment for land easements. This standard does not apply to QEP's leases that provide the right to explore for minerals, oil or natural gas resources. The adoption of this guidance resulted in the recognition of net operating lease right-of-use assets and operating lease liabilities on QEP's Condensed Consolidated Balance Sheets. These leases primarily relate to office buildings, compressors and generators. This guidance did not have a significant impact on the Condensed Consolidated Statement of Operations or the Condensed Consolidated Statement of Cash Flows. Refer to Note 8 – Leases for more information.

Note 2 – Revenue

Revenue Recognition

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

QEP's oil is typically sold at specific delivery points under contract terms that are common in the industry. QEP's gas and NGL are also sold under contract types that are common in the industry; however, under these contracts, the gas and its components, including NGL, may be sold to a single purchaser or the residue gas and NGL may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate QEP for the value of the residue gas and NGL constituent components at market prices for each product. QEP also purchases and resells oil and gas primarily to mitigate credit risk related to third party purchasers, to fulfill volume commitments when production does not fulfill contractual commitments and to capture additional margin from subsequent sales of third party purchases. QEP recognizes revenue from these resale activities in the period that the performance obligations are satisfied.

The following tables present QEP's revenues that are disaggregated by revenue source and by geographic area. Transportation and processing costs in the following table are not all of the transportation and processing costs that QEP incurs, only the

8

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 June 30, 2019
Northern Region
Williston Basin	$	107.5	$	7.5		$	5.8	$	(8.9	)	$	111.9
Other Northern	0.5		0.1			—		—			0.6
Southern Region
Permian Basin	177.6		(0.6		)	8.5		(3.8		)	181.7
Other Southern	0.1		0.3			—		—			0.4
Total oil and condensate, gas and NGL sales	$	285.7	$	7.3		$	14.3	$	(12.7	)	$	294.6
	Three Months Ended June 30, 2018
Northern Region
Williston Basin	$	207.6	$	8.4		$	14.7	$	(10.7	)	$	220.0
Uinta Basin	9.5		7.9			1.7		—			19.1
Other Northern	0.9		0.2			0.1		—			1.2
Southern Region
Permian Basin	190.3		3.2			9.9		(1.7		)	201.7
Haynesville/Cotton Valley	0.2		77.9			—		—			78.1
Other Southern	—		0.2			—		—			0.2
Total oil and condensate, gas and NGL sales	$	408.5	$	97.8		$	26.4	$	(12.4	)	$	520.3

9

	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)
	Six Months Ended June 30, 2019
Northern Region
Williston Basin	$	217.4		$	20.0	$	13.2		$	(19.0	)	$	231.6
Other Northern	0.9			0.3		—			—			1.2
Southern Region
Permian Basin	316.8			4.0		18.0			(7.5		)	331.3
Other Southern	0.1			6.0		—			—			6.1
Total oil and condensate, gas and NGL sales	$	535.2		$	30.3	$	31.2		$	(26.5	)	$	570.2
	Six Months Ended June 30, 2018
Northern Region
Williston Basin	$	368.1		$	18.2	$	26.5		$	(20.6	)	$	392.2
Uinta Basin	17.9			18.0		3.4			—			39.3
Other Northern	2.8			1.2		(0.1		)	—			3.9
Southern Region
Permian Basin	320.1			7.8		16.4			(4.5		)	339.8
Haynesville/Cotton Valley	0.6			154.3		—			—			154.9
Other Southern	(0.3		)	0.3		—			—			—
Total oil and condensate, gas and NGL sales	$	709.2		$	199.8	$	46.2		$	(25.1	)	$	930.1

10

Note 3 – Acquisitions and Divestitures

Acquisitions

During the six months ended June 30, 2019, QEP acquired various oil and gas properties, which primarily included proved leasehold acreage in the Permian Basin for an aggregate purchase price of $1.8 million, subject to post-closing purchase price adjustments.

During the six months ended June 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 $45.1 million. Of the $45.1 million, $37.5 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.

Divestitures

In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial 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. The Company subsequently closed the sale of its Uinta Basin assets in the third quarter of 2018 and the sale of the Haynesville/Cotton Valley assets in the first quarter of 2019. In November 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a purchase and sale agreement for its assets in the Williston Basin, however, in February 2019, the Company agreed with the buyer to terminate the purchase and sale agreement.

Haynesville/Cotton Valley Divestiture

In January 2019, QEP closed the sale of its assets in Haynesville/Cotton Valley (Haynesville Divestiture), and in July 2019 QEP reached final settlement on asserted title defects. The purchase price, after adjustments, is $634.2 million. QEP received net cash proceeds of $627.1 million during the six months ended June 30, 2019, and, as of June 30, 2019, recorded a $9.5 million receivable and a $2.4 million payable which were included in "Accounts receivable, net" and "Accounts payable and accrued expenses", respectively. The total pre-tax loss on sale was $3.7 million, of which $0.7 million was recognized during the six months ended June 30, 2019, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. Included in the $0.7 million pre-tax loss on sale is $1.4 million of restructuring costs related to the Haynesville Divestiture. Refer to Note 9 – Restructuring for more information. As of December 31, 2018, it was deemed unlikely that there will be any significant changes to the Haynesville Divestiture. Accordingly, the assets and liabilities associated with the Haynesville Divestiture were classified as noncurrent assets and liabilities held for sale, on the Condensed Consolidated Balance Sheets.

During the six months ended June 30, 2019, QEP accounted for revenues and expenses related to Haynesville/Cotton Valley, including the pre-tax loss on sale of $0.7 million, as income from continuing operations on the Condensed Consolidated Statements of Operations because the Haynesville Divestiture did not cause a strategic shift for the Company and therefore did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. During the three months ended June 30, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $14.4 million, which includes a pre-tax gain on sale of $14.3 million. During the six months ended June 30, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $3.3 million, which includes the pre-tax loss on sale of $0.7 million. For the three and six months ended June 30, 2018, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $7.4 million and $19.7 million, respectively.

11

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

	December 31, 2018(1)
	(in millions)
Assets
Current assets, total	$	1.2
Net Property, Plant and Equipment	683.7
Other noncurrent assets	7.8
Noncurrent assets held for sale	$	692.7
Liabilities
Current liabilities, total	$	3.4
Asset retirement obligations, current	0.7
Asset retirement obligations, long-term	56.9
Other long-term liabilities	0.3
Other long-term liabilities held for sale	$	61.3

____________________________

⁽¹⁾  The Haynesville Divestiture closed in January 2019, therefore there are no assets and liabilities held for sale as of June 30, 2019.

Uinta Basin Divestiture

In September 2018, QEP sold its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of $153.0 million (Uinta Basin Divestiture). During the three and six months ended June 30, 2019, QEP recorded a pre-tax loss on sale of $0.3 million and $0.2 million, respectively, due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs". For the three and six months ended June 30, 2018, QEP recorded a net loss before income taxes related to the divested Uinta Basin assets of $409.9 million and $414.9 million, respectively. The net loss before income taxes 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.

Pinedale Divestiture

In September 2017, QEP sold its Pinedale assets (Pinedale Divestiture) for net cash proceeds (after purchase price adjustments) of $718.2 million. During the six months ended June 30, 2018, QEP recorded a pre-tax gain on sale of $0.8 million, due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs".

QEP agreed to reimburse the buyer of its Pinedale assets for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. As of June 30, 2019, the remaining liability associated with estimated future payments for this commitment was $2.0 million and is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses".

Other Divestitures

During the six months ended June 30, 2019, QEP received net cash proceeds of $39.7 million and recorded a net pre-tax gain on sale of $5.5 million related to the divestiture of properties outside its main operating areas.

During the six months ended June 30, 2018, QEP received net cash proceeds of $48.8 million and recorded a pre-tax gain on sale of $0.7 million, primarily related to the divestiture of properties outside its main operating areas in the Uinta Basin, Pinedale and Other Northern area, and the sale of an underground gas storage facility.

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

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Note 4 – Earnings Per Share

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

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. During the three and six months ended June 30, 2019 there were no anti-dilutive shares. During the three and six months ended June 30, 2018, 0.1 million shares were not included in diluted common shares outstanding as they were anti-dilutive to QEP's net loss.

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	238.0	237.0	237.5	238.9
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—	—
Average diluted common shares outstanding	238.0	237.0	237.5	238.9

Note 5 – Asset Retirement Obligations

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.

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

	Asset Retirement Obligations
	June 30,		December 31,
	2019		2018
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.8	$	5.1
Long-term:
Asset retirement obligations	94.6		96.9
Other long-term liabilities held for sale	—		57.6
Total ARO Liability	$	101.4	$	159.6

13

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 January 1, 2019	$	159.6
Accretion	3.1
Additions	0.4
Revisions	(0.3		)
Liabilities related to assets sold(1)	(60.7		)
Liabilities settled	(0.7		)
ARO liability at June 30, 2019	$	101.4

_______________________

⁽¹⁾  Liabilities related to assets sold during the six months ended June 30, 2019, includes $57.6 million related to the Haynesville Divestiture (refer to Note 3 – Acquisitions and Divestitures for more information).

Note 6 – Fair Value Measurements

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

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

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

14

The fair value of financial assets and liabilities at June 30, 2019 and December 31, 2018, 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
	(in millions)
Financial Assets	June 30, 2019
Fair value of derivative contracts – short-term	$	—	$	2.7	$	—	$	—		$	2.7
Fair value of derivative contracts – long-term	—		15.2		—		—			15.2
Total financial assets	$	—	$	17.9	$	—	$	—		$	17.9
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	17.6	$	—	$	—		$	17.6
Fair value of derivative contracts – long-term	—		0.9		—		—			0.9
Total financial liabilities	$	—	$	18.5	$	—	$	—		$	18.5
	December 31, 2018
Financial Assets
Fair value of derivative contracts – short-term(2)	$	—	$	88.2	$	—	$	(0.4	)	$	87.8
Fair value of derivative contracts – long-term	—		35.4		—		—			35.4
Total financial assets	$	—	$	123.6	$	—	$	(0.4	)	$	123.2
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	0.4	$	—	$	(0.4	)	$	—
Fair value of derivative contracts – long-term	—		0.7		—		—			0.7
Total financial liabilities	$	—	$	1.1	$	—	$	(0.4	)	$	0.7

_______________________

⁽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.

⁽²⁾  Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of

December 31, 2018 on the Condensed Consolidated Balance Sheets related to the Haynesville Divestiture.

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

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	June 30, 2019				December 31, 2018
Financial Assets	(in millions)
Cash and cash equivalents	$	97.1	$	97.1	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	5.3	$	5.3	$	14.6	$	14.6
Total debt outstanding	$	2,079.8	$	2,042.5	$	2,507.1	$	2,350.5

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 carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.

15

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

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and 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 and operating lease right-of-use assets for potential impairment when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. The fair value of property is measured utilizing the income approach and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. If a range is estimated for the amount of future cash flows, the fair value of property is measured utilizing a probability-weighted approach in which the likelihood of possible outcomes is taken into consideration. Given the unobservable nature of the inputs, fair value calculations associated with long-term operating lease right-of-use assets and proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. During the six months ended June 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease. During the six months ended June 30, 2018, the Company recorded impairments on certain proved oil and gas properties of $397.6 million.

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, and future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. Refer to Note 3 – Acquisitions and Divestitures for more information on the fair value of acquired properties.

Note 7 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. In addition, during the time that QEP owned gas storage facilities or had contracts for gas storage capacity, QEP 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 basis swaps to achieve a fixed-price swap for a portion of its oil sales at prices that reference specific regional index prices.

16

QEP does not currently have any commodity derivative instruments 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 June 30, 2019:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	6.6	$	55.24
2019	ICE Brent	0.9	$	66.73
2019	Argus WTI Houston	0.2	$	65.70
2020	NYMEX WTI	6.2	$	60.07
2020	Argus WTI Midland	0.7	$	60.00

QEP uses oil basis swaps, combined with NYMEX WTI fixed-price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil basis swaps as of June 30, 2019:

Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2019	NYMEX WTI	Argus WTI Midland	3.3	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.9	$	3.69
2020	NYMEX WTI	Argus WTI Midland	4.4	$	(0.02	)
2020 (January - June)	NYMEX WTI	Argus WTI Houston	0.4	$	3.75

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	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
Current:		(in millions)
Commodity(1)	Fair value of derivative contracts	$	2.7	$	88.2	$	17.6	$	0.4
Long-term:
Commodity	Fair value of derivative contracts	15.2		35.4		0.9		0.7
Total derivative instruments		$	17.9	$	123.6	$	18.5	$	1.1

_______________________

⁽¹⁾  Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 on the Condensed Consolidated Balance Sheet related to the Haynesville Divestiture.

17

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						Six Months Ended
Derivative contracts	June 30,						June 30,
	2019			2018			2019			2018
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(16.0	)	$	(52.0	)	$	(19.0	)	$	(96.3	)
Gas derivative contracts	—			6.4			(2.9		)	7.3
Gas Storage
Gas derivative contracts	—			0.1			—			0.3
Realized gains (losses) on commodity derivative contracts	(16.0		)	(45.5		)	(21.9		)	(88.7		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	54.5			(20.6		)	(122.8		)	(27.5		)
Gas derivative contracts	—			(13.0		)	(0.3		)	(15.8		)
Gas Storage
Gas derivative contracts	—			—			—			(0.3		)
Unrealized gains (losses) on commodity derivative contracts	54.5			(33.6		)	(123.1		)	(43.6		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	38.5		$	(79.1	)	$	(145.0	)	$	(132.3	)
Derivatives associated with Haynesville Divestiture
Unrealized gains (losses) on commodity derivative contracts
Production
Gas derivative contracts	—			—			1.8			—
Unrealized gains (losses) on commodity derivative contracts related to divestitures(1)	$	—		$	—		$	1.8		$	—
Total realized and unrealized gains (losses) on commodity derivative contracts	$	38.5		$	(79.1	)	$	(143.2	)	$	(132.3	)

_______________________

⁽¹⁾  During the three and six months ended June 30, 2019, the unrealized gains (losses) on commodity derivative contracts related to the Haynesville Divestiture were comprised of derivatives included as part of the Haynesville/Cotton Valley purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in January 2019. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Haynesville Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

Note 8 – Leases

Adoption of ASC Topic 842, Leases

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

18

In accordance with the adoption of ASC Topic 842, QEP now records a net operating lease right-of-use (ROU) asset and operating lease liability on the Condensed Consolidated Balance Sheets for all operating leases with a contract term in excess of 12 months. Prior to the adoption of ASC Topic 842, these same leases were treated as operating leases under ASC Topic 840 and therefore were not recorded on the December 31, 2018 Consolidated Balance Sheets. There was no impact to retained earnings and no significant impact on the Condensed Consolidated Statement of Operations or the Condensed Consolidated Statement of Cash Flows as a result of adopting ASC Topic 842.

Lease Recognition

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

QEP determines if an arrangement is a lease at inception of the contract and records the resulting operating lease asset on the Condensed Consolidated Balance Sheets as “Operating lease right-of-use assets, net” with offsetting liabilities recorded as “Current operating lease liabilities” and “Operating lease liabilities.” QEP recognizes a lease in the financial statements when the arrangement either explicitly or implicitly involves property, plant, or equipment (PP&E), the contract terms are dependent on the use of the PP&E, and QEP has the ability or right to operate the PP&E or to direct others to operate the PP&E and receive the majority of the economic benefits of the assets. As of June 30, 2019, QEP does not have any financing leases.

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

	Three Months Ended		Six Months Ended
	June 30, 2019(1)		June 30, 2019(1)
Lease Cost included in the Condensed Consolidated Balance Sheets	(in millions)
Property, Plant and Equipment acquisitions(2)	$	4.1	$	8.8
	Three Months Ended		Six Months Ended
	June 30, 2019(1)		June 30, 2019(1)
Lease Cost included in the Condensed Consolidated Statement of Operations	(in millions)
Lease operating expense	$	3.0	$	6.1
Gathering and other expense	2.3		3.8
General and administrative	1.6		3.2
Total lease cost	$	11.0	$	21.9

 ____________________________

⁽¹⁾  Prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective method for the new lease recognition rule. Refer to Note 1 – Basis of Presentation for additional information.

⁽²⁾  Represents short-term lease capital expenditures related to drilling rigs for the three and six months ended June 30, 2019. These costs are capitalized as a part of "Proved properties" on the Condensed Consolidated Balance Sheets.

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

	Three Months Ended		Six Months Ended
	June 30, 2019(1)		June 30, 2019(1)
Weighted-average remaining lease term (years)	3.6		3.6
Weighted-average discount rate	7.7	%	7.7	%

 ____________________________

⁽¹⁾  Prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective method for the new lease recognition rule. Refer to Note 1 – Basis of Presentation for additional information.

Refer to Note 11 – Commitments and Contingencies for a reconciliation of our minimum future lease payments to the Condensed Consolidated Balance Sheets.

Note 9 – Restructuring

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

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Restructuring costs recognized 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)"
	Three Months Ended June 30, 2019
	(in millions)
Termination benefits	$	(0.1	)	$	(0.1	)	$	—		$	—
Office lease termination costs	—			—			—			—
Accelerated share-based compensation(1)	1.3			1.3			—			—
Retention expense (including share-based compensation)	4.8			4.8			—			—
Pension and Medical Plan curtailment	0.1			—			—			0.1
Total restructuring costs	$	6.1		$	6.0		$	—		$	0.1
	Six Months Ended June 30, 2019
Termination benefits	$	6.7		$	6.6		$	0.1		$	—
Office lease termination costs	0.6			0.6			—			—
Accelerated share-based compensation(1)	9.7			8.2			1.5			—
Retention expense (including share-based compensation)	10.9			10.9			—			—
Pension and Medical Plan curtailment	(0.4		)	—			(0.2		)	(0.2		)
Total restructuring costs	$	27.5		$	26.3		$	1.4		$	(0.2	)
	Three Months Ended June 30, 2018
Termination benefits	$	3.6		$	1.7		$	1.9		—
Office lease termination costs	0.3			0.3			—			—
Accelerated share-based compensation	1.2			1.2			—			—
Retention expense (including share-based compensation)	6.3			6.3			—			—
Total restructuring costs	$	11.4		$	9.5		$	1.9		$	—
	Six Months Ended June 30, 2018
Termination benefits	$	7.0		$	5.1		$	1.9		—
Office lease termination costs	0.3			0.3			—			—
Accelerated share-based compensation	4.0			4.0			—			—
Retention expense (including share-based compensation)	8.0			8.0			—			—
Total restructuring costs	$	19.3		$	17.4		$	1.9		$	—

 ____________________________

⁽¹⁾  Accelerated share-based compensation represents the additional expense or loss recognized in the Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2019. Total accelerated share based compensation was $2.8 million and $21.7 million for the three and six months ended June 30, 2019, respectively, and was determined based on the contractual vesting date, with $1.3 million and $9.7 million recognized during the three and six months ended June 30, 2019, respectively, as shown above, and the remaining amount recognized in prior periods.

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	Costs recognized from inception to June 30, 2019(1)			Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	38.9		$	—	(2)
Office lease termination costs	1.6			—		(2)
Accelerated share-based compensation	21.0			—		(2)
Retention expense (including share-based compensation)	29.7			10.1
Pension and Medical Plan curtailment	(0.2		)	—		(2)
Total restructuring costs	$	91.0		$	10.1

 ____________________________

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

⁽²⁾  Due to the nature of the strategic initiatives, as of June 30, 2019, the Company is not able to reasonably estimate the total cost to be incurred in connection with these restructurings.

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, 2018	$	19.5		$	—		$	—		$	10.8		$	—		$	30.3
Costs incurred and charged to expense	6.7			0.6			9.7			10.9			(0.4		)	27.5
Costs paid or otherwise settled	(23.9		)	(0.6		)	(9.7		)	(15.9		)	0.4			(49.7		)
Balance at June 30, 2019	$	2.3		$	—		$	—		$	5.8		$	—		$	8.1

Note 10 – Debt

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

	June 30, 2019			December 31, 2018
	(in millions)
Revolving Credit Facility due 2022	$	—		$	430.0
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	(19.5		)	(22.2		)
Total principal amount of debt (including current portion)	2,079.8			2,507.1
Less: current portion of long-term debt	(51.7		)	—
Total long-term debt outstanding	$	2,028.1		$	2,507.1

Of the total debt outstanding on June 30, 2019, 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.

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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 governing QEP's revolving credit facility 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 3.75 times consolidated EBITDA (as defined in the credit agreement) and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.40 times through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. At June 30, 2019 and December 31, 2018, QEP was in compliance with the covenants under the credit agreement.

During the six months ended June 30, 2019, QEP's weighted-average interest rate on borrowings from its credit facility was 4.73%. As of June 30, 2019, QEP had no borrowings outstanding and $2.9 million in letters of credit outstanding under the credit facility. As of December 31, 2018, QEP had $430.0 million of borrowings outstanding and $0.3 million in letters of credit outstanding under the credit facility.

Senior Notes

At June 30, 2019, the Company had $2,099.3 million in principal amount of senior notes outstanding with maturities ranging from March 1, 2020 to March 1, 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 QEP's 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.

Note 11 – Commitments and Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its 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 and the ongoing discovery and/or development of information important to the matter.

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

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

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

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Commitments

QEP has entered into contractual lease arrangements to rent office space, compressors, generators, drilling rigs and other equipment from third-party lessors. On January 1, 2019, QEP adopted ASC Topic 842, Leases, using the modified retrospective approach. Refer to Note 8 – Leases for additional information.

As of June 30, 2019, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC 842 are as follows:

Year	Amount
	(in millions)
2019	$	12.4
2020	$	21.1
2021	$	19.4
2022	$	14.9
2023	$	9.4
After 2023	$	0.5
Less: Interest(1)	$	(11.0	)
Present value of lease liabilities(2)	$	66.7

 ____________________________

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

⁽²⁾  Of the total present value of lease liabilities, $18.8 million was recorded in "Current operating lease liabilities" and $47.9 million was recorded in "Operating lease liabilities" on the Condensed Consolidated Balance Sheets.

As of December 31, 2018, minimum future contractual payments for long-term operating leases under the scope of ASC 840 are as follows:

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

Note 12 – Share-Based Compensation

In 2018, QEP's Board of Directors and QEP's shareholders approved the QEP Resources, Inc. 2018 Long-Term Incentive Plan (LTIP), which replaces the 2010 Long-Term Stock Incentive Plan (LTSIP) and provides for the issuance of up to 10.0 million shares such that the Board of Directors may grant long-term incentive compensation. QEP has issued stock options, restricted share awards, and restricted share units under its LTSIP or 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 were under the LTSIP and 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 8.3 million shares available for future grants under the LTIP at June 30, 2019.

24

Share-based compensation expense is generally recognized within "General and administrative" expense on the Condensed Consolidated Statements of Operations and is summarized in the table below. During the three and six months ended June 30, 2019, the Company recorded an additional $1.3 million and $9.7 million, respectively, of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program, of which $1.5 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statement of Operations during the six months ended June 30, 2019 and the remaining $1.3 million and $8.2 million, respectively, is included in the table below. During the three and six months ended June 30, 2018, the Company recorded an additional $1.2 million and $4.0 million, respectively of share-based compensation expense, related to the acceleration of vesting that occurred as part of the restructuring program, all of which is included in the table below. Refer to Note 9 – Restructuring for additional information.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(in millions)
Stock options	$	—	$	0.2	$	0.3	$	0.7
Restricted share awards	4.8		6.8		10.9		15.6
Performance share units	0.3		5.1		5.5		7.0
Restricted share units	0.1		0.1		0.2		0.1
Total share-based compensation expense	$	5.2	$	12.2	$	16.9	$	23.4

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 option 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 three years from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company recognizes forfeitures of stock options as they occur. During the six months ended June 30, 2019, 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, 2018	2,098,933		$	22.27
Cancelled	(283,029	)	30.90
Outstanding at June 30, 2019	1,815,904		$	20.93	2.80	$	—
Options Exercisable at June 30, 2019	1,761,139		$	21.08	2.74	$	—
Unvested Options at June 30, 2019	54,765		$	15.92	4.69	$	—

During the six months ended June 30, 2019 there were no exercises of stock options. As of June 30, 2019, $0.1 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 0.78 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program. Refer to Note 9 – Restructuring for additional information.

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Restricted Share Awards

Restricted share award grants typically vest in equal installments over three years from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company recognizes restricted share forfeitures as they occur. The total fair value of restricted share awards that vested during the six months ended June 30, 2019 and 2018 was $25.0 million and $24.6 million, respectively. The weighted-average grant date fair value of restricted share awards was $7.98 per share and $9.55 per share for the six months ended June 30, 2019 and 2018, respectively. As of June 30, 2019, $18.8 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 2.31 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program. Refer to Note 9 – 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, 2018	3,822,133		$	10.76
Granted	2,217,794		7.98
Vested	(2,261,323	)	11.05
Forfeited	(178,985	)	9.23
Unvested balance at June 30, 2019	3,599,619		$	8.94

Performance Share Units

The payouts for performance share units are dependent upon the Company's total shareholder return compared to a group of its peers over three years. The awards are denominated in share units and have historically been paid in cash. The Company has the option to settle earned awards in cash or shares of common stock under the Company's LTIP; however, as of June 30, 2019, 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 Company paid $11.4 million and $2.0 million for vested performance share units during the six months ended June 30, 2019 and 2018, respectively. The weighted-average grant date fair value of the performance share units granted during the six months ended June 30, 2019 and 2018 was $7.93 and $9.55 per share, respectively. As of June 30, 2019, $7.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.33 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program. Refer to Note 9 – 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, 2018	1,559,312		$	11.47
Granted	589,412		7.93
Vested and paid	(1,117,848	)	10.73
Unvested balance at June 30, 2019	1,030,876		$	9.63

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Restricted Share Units

Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over three years and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately paid in cash. They are classified as liabilities in "Other long-term liabilities" on the 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 $7.93 and $9.55 per share for the six months ended June 30, 2019 and 2018, respectively. As of June 30, 2019, $0.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.64 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program. Refer to Note 9 – Restructuring for additional information.

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

	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2018	42,675		$	10.47
Granted	37,224		7.93
Vested and paid	(36,392	)	10.67
Unvested balance at June 30, 2019	43,507		$	8.16

Note 13 – Employee Benefits

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 six months ended June 30, 2019, the Company made contributions of $5.0 million to the Pension Plan and does not expect to make any additional contributions during the remainder of 2019. 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 six months ended June 30, 2019, the Company made contributions of $0.2 million to the SERP and expects to contribute an additional $0.3 million to the SERP during the remainder of 2019. 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 six months ended June 30, 2019, the Company made contributions of $0.1 million to the Medical Plan and expects to contribute $0.2 million to the Medical Plan during the remainder of 2019. 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 implementation of its strategic initiatives may trigger curtailments related to the Pension Plan, SERP and/or Medical Plan upon the closing of any transaction. Refer to Note 9 – Restructuring for more information. During the six months ended June 30, 2019, the Company recognized a $0.4 million pension curtailment gain related to strategic initiatives, of which $0.5 million of curtailment gain was related to the Haynesville Divestiture and included in "Interest and other income (expense)" and "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations, and $0.1 million of curtailment loss was related to corporate restructuring activities and included as "Interest and other income (expense)" on the Condensed Consolidated Statements of Operations.

27

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						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Pension Plan and SERP benefits	(in millions)
Service cost	$	—		$	0.2		$	0.1		$	0.4
Interest cost	1.2			1.1			2.4			2.2
Expected return on plan assets	(1.4		)	(1.5		)	(2.9		)	(2.9		)
Amortization of prior service costs(1)	0.1			0.2			0.2			0.4
Amortization of actuarial losses(1)	—			0.3			0.1			0.6
Curtailment (gain) loss(2)	0.1			—			0.4			—
Periodic expense	$	—		$	0.3		$	0.3		$	0.7
Medical Plan benefits
Interest cost	$	0.1		$	0.1		$	0.1		$	0.1
Amortization of prior service costs(1)	—			—			—			(0.1		)
Curtailment (gain) loss(2)	—			—			(0.8		)	—
Periodic expense	$	0.1		$	0.1		$	(0.7	)	$	—

____________________________

⁽¹⁾  Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income (loss) 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. The net curtailment gain between the SERP and Medical Plan of $0.4 million is related to the Haynesville Divestiture and corporate restructuring activities. Of the $0.4 million curtailment gain recognized, $0.2 million was recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)" and $0.2 million was recognized on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs" for the six months ended June 30, 2019.

Employee Investment Plan

QEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (the 401(k) Plan). The 401(k) Plan allows eligible employees to make investments, including purchasing shares of QEP common stock, through payroll deduction at the current fair market value on the transaction date. Both employees and QEP make contributions to the 401(k) Plan. The Company may contribute a discretionary portion beyond the Company's matching contribution to employees not in the Pension Plan or SERP. During the six months ended June 30, 2019, the Company made contributions of $2.6 million to the 401(k) Plan and expects to contribute an additional $1.8 million to the 401(k) Plan during the remainder of 2019. The Company recognizes expense equal to its yearly contributions. Due to the Company's strategic initiatives, the amount to be contributed to the 401(k) Plan may change. Refer to Note 9 – Restructuring for more information.

As a result of freezing benefits under the Pension Plan, the 401(k) Plan and a nonqualified, unfunded deferred compensation plan (the Wrap Plan) were amended to allow the Company to make discretionary contributions (Company Transition Credits) to eligible participants. Eligible participants are certain employees who were active participants in the Pension Plan on December 31, 2015. During the six months ended June 30, 2019, the Company did not make a discretionary contribution to active participants of the Pension Plan but expects to contribute $0.1 million to eligible participants during the fourth quarter of 2019.

28

Note 14 – Subsequent Event

Subsequent to June 30, 2019, QEP's Board of Directors completed its comprehensive review of strategic alternatives and determined that the best alternative for QEP's shareholders is to move forward as an independent company. The Company is not able to reasonably estimate the future costs to be incurred in connection with the review of strategic alternatives.

On August 6, 2019, QEP's Board of Directors approved the reinstatement of a quarterly cash dividend of $0.02 per share of common stock, payable on September 10, 2019 to shareholders of record on August 20, 2019.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

The following information updates the discussion of QEP's financial condition provided in its Annual Report on Form 10-K for the year ended December 31, 2018 (2018 Form 10-K) and analyzes the changes in the results of operations between the three and six months ended June 30, 2019 and 2018. For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the "Glossary of Terms" provided in the 2018 Form 10-K.

OVERVIEW

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 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".

In February 2019, QEP's Board of Directors commenced a comprehensive review of strategic alternatives to maximize shareholder value, which included the evaluation of a merger, sale of the Company or other transaction involving the Company's assets. In August 2019, QEP's Board of Directors completed their comprehensive review of strategic alternatives and determined that the best alternative for QEP's shareholders is to move forward as an independent company.

QEP's strategy will be a continued focus on high-return investments in its business with disciplined production growth. QEP is committed to strengthening its balance sheet, reducing leverage and returning capital to shareholders. QEP plans to fulfill this commitment by continuing to reassess its organizational needs and reducing its general and administrative expense to ensure its cost structure is competitive with industry peers and lowering drilling, completion and facility costs. All of this is underpinned by improved performance and deliverability of our high-quality, oil weighted asset base.

As a part of the 2018 and 2019 strategic initiatives, QEP has incurred or expects to incur additional costs associated with contractual termination benefits, including severance, accelerated vesting of share-based compensation and other expenses. Refer to Note 3 – Acquisitions and Divestitures and Note 9 – Restructuring in Part 1, Item I of this Quarterly Report on Form 10-Q for more information. The Company incurred $26.3 million of general and administrative restructuring costs related to organizational changes implemented during the first half of 2019.

Acquisitions and Divestitures

While we believe our inventory of identified drilling locations provides a solid base for growth in production and reserves, we will continue to evaluate and acquire properties in our operating areas to add additional development opportunities and facilitate the drilling of long lateral wells.

Acquisitions

During the six months ended June 30, 2019, QEP acquired various oil and gas properties, which primarily included proved acreage in the Permian Basin for an aggregate purchase price of $1.8 million, subject to post-closing purchase price adjustments.

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During the six months ended June 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 $45.1 million, subject to post-closing purchase price adjustments. Of the $45.1 million, $37.5 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 (2017 Permian Basin Acquisition) on substantially the same terms and conditions as the 2017 Permian Basin Acquisition in the fourth quarter of 2017.

Divestitures

In January 2019, QEP closed the sale of its assets in Haynesville/Cotton Valley (Haynesville Divestiture) and in July 2019 reached final settlement on asserted title defects. The purchase price, after adjustments, is $634.2 million. QEP received net cash proceeds of $627.1 million during the six months ended June 30, 2019. Additionally, a total pre-tax loss on sale of $3.7 million was recognized. Refer to Note 3 – Acquisitions and Divestitures in Part 1, Item I of this Quarterly Report on Form 10-Q for more information.

In addition to the Haynesville Divestiture, during the six months ended June 30, 2019, QEP received net cash proceeds of $39.6 million and recorded a net pre-tax gain on sale of $5.3 million related to the divestiture of properties outside our main operating areas.

During the six months ended June 30, 2018, QEP recorded a pre-tax loss of $1.9 million related to estimated restructuring costs associated with the Uinta Basin Divestiture (refer to Note 9 – Restructuring for more information), partially offset by a pre-tax gain of $0.7 million related to the divestiture of properties outside our main operating areas in the Uinta Basin, Pinedale and the Other Northern area, and the sale of an underground storage facility, in which QEP received aggregate net cash proceeds of $48.8 million. In addition, QEP recorded a pre-tax gain of $0.8 million related to the sale of QEP's assets in Pinedale (the Pinedale Divestiture).

Financial and Operating Highlights

During the three months ended June 30, 2019, QEP:

• Generated net income of $48.8 million, or $0.20 per diluted share;

• Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $166.5 million;

• Increased oil and condensate production in the Permian Basin by 2% to 3.3 MMbbls compared to the second quarter 2018;

• Reduced capital expenditures by $249.1 million compared to the second quarter 2018; and

• Reduced general and administrative expenses by 44% compared to the second quarter 2018.

During the six months ended June 30, 2019, QEP:

• Generated a net loss of $67.9 million, or $0.29 per diluted share;

• Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $286.3 million;

• Closed the Haynesville Divestiture for a total estimated purchase price of $634.2 million;

• Increased oil and condensate production in the Permian Basin by 15% to 6.2 MMbbls compared to the first half of 2018;

• Reduced capital expenditures by $490.8 million compared to the first half of 2018; and

• Reduced general and administrative expenses by 18% compared to the first half of 2018.

Outlook

QEP's strategy will be a continued focus on high-return investments in our business with disciplined production growth. QEP is committed to strengthening our balance sheet, reducing leverage and returning capital to shareholders. We plan to fulfill this commitment by continuing to reassess our organizational needs and reducing our general and administrative expense to ensure our cost structure is competitive with industry peers and lowering drilling, completion and facility costs. All of this is underpinned by improved performance and deliverability of our high-quality, oil weighted asset base.

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Based on current commodity prices, we expect to be able to fund our planned capital program for 2019 with cash flow from operating activities, cash on hand and borrowings under our credit facility. Our total capital expenditures (excluding property acquisitions) for 2019 are expected to be approximately $590.0 million, a decrease of approximately 50% from 2018 capital expenditures. We continuously evaluate our level of drilling and completion activity in light of drilling results, commodity prices and changes in our operating and development costs and will adjust our capital investment program based on such evaluations. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures.

Factors Affecting Results of Operations

Shareholder Activism

Elliott Management Corporation (Elliott), is a beneficial holder of approximately 4.9% of our common stock (based on Elliott's Form 13F-HR filed on May 15, 2019). Elliott has actively engaged in discussions with us regarding certain aspects of our business and operations. In addition, on January 7, 2019, Elliott made a proposal to our Board of Directors to acquire all of our outstanding shares of common stock. As a result of that proposal, our Board of Directors engaged in a comprehensive review of strategic alternatives and concluded that the best alternative for QEP's shareholders was to move forward as an independent company. Our business and/or operations could be adversely affected by any future actions of activist shareholders. Responding to actions by activist shareholders could be costly and time-consuming, disrupting our operations and diverting the attention of our management and employees. Activities of activist shareholders could interfere with our ability to execute our strategic plan or realize short- or long-term value from our assets.

Supply, Demand, Market Risk and their Impact on Oil Prices

Oil prices are affected by many factors outside of our control, including changes in supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. In recent years, oil prices have been affected by supply growth, particularly in the U.S., driven by advances in drilling and completion technologies, and fluctuations in demand driven by a variety of factors.

Changes in the market prices for oil directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling and completion activity and related capital expenditures, its proved undeveloped (PUD) reserves conversion rate, liquidity, rate of growth, costs of goods and services required to drill, complete and operate wells, and the carrying value of its oil and gas properties. Historically, field-level prices received for QEP's oil production have been volatile. During the past five years, the posted price for WTI crude oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $106.06 per barrel in July 2014. If oil prices decline to early 2016 levels or further, our operations, financial condition and level of expenditures for the development of our oil reserves may be materially and adversely affected.

Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the global economy, including Europe and China's economic outlook; the Organization of Petroleum Exporting Countries (OPEC) countries' oil production and policies regarding production quotas; political unrest and global economic issues; slowing growth in certain emerging market economies; actions taken by the United States Congress and the president of the United States; the U.S. federal budget deficit; changes in regulatory oversight policy; commodity price volatility; tariffs on goods we use in our operations or on the products we sell; the impact of a potential increase in interest rates; volatility in various global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on oil, gas and NGL supply, demand and prices and the Company's ability to continue its planned drilling programs and could materially impact the Company's financial position, results of operations and cash flow from operations. Disruption to the global oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oil prices.

Due to continued global economic uncertainty and the corresponding volatility of commodity prices, QEP continues to focus on maintaining a sufficient liquidity position to ensure financial flexibility. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter 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. At June 30, 2019, QEP forecasted the midpoint of its 2019 annual production to be approximately 30.5 MMboe and had approximately 67% of its forecasted oil and condensate production covered with fixed price swaps. See Part 1, Item 3 – "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk Management" for further details on QEP's commodity derivatives transactions.

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Potential for Future Asset Impairments

The carrying values of the Company's properties are sensitive to declines in oil, gas and NGL prices as well as increases in various development and operating costs and expenses and, therefore, are at risk of impairment. The Company uses a cash flow model to assess its proved oil and gas properties and operating lease right-of-use assets for impairment. The cash flow model includes numerous assumptions, including estimates of future oil, gas and NGL production, estimates of future prices for production that are based on the price forecast that management uses to make investment decisions, including estimates of basis differentials, future operating costs, transportation expenses, production taxes, and development costs that management believes are consistent with its price forecast, and discount rates. Management also considers a number of other factors, including the forward curve for future oil and gas prices, and developments in regional transportation infrastructure when developing its estimate of future prices for production. All inputs for the cash flow model are evaluated at each date of estimate.

We base our fair value estimates on projected financial information that we believe to be reasonably likely to occur. An assessment of the sensitivity of our capitalized costs to changes in the assumptions in our cash flow calculations is not practicable, given the numerous assumptions (e.g., future oil, gas and NGL prices; production and reserves; pace and timing of development drilling plans; timing of capital expenditures; operating costs; drilling and development costs; and inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced oil, gas and NGL prices on future undiscounted cash flows would likely be offset by lower drilling and development costs and lower operating costs. The signing of a purchase and sale agreement could also cause the Company to recognize an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value.

During the six months ended June 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease.

During the six months ended June 30, 2018, QEP recorded an impairment charge of $404.4 million, of which $402.8 million of proved and unproved properties impairment was triggered by the Uinta Basin Divestiture and $1.6 million was related to expiring leaseholds on unproved properties and impairment of proved properties related to a divestiture in the Other Northern area.

We could be at risk for proved and unproved property and operating lease right-of-use asset impairments if forward oil prices decline from June 30, 2019 levels, we experience negative changes in estimated reserve quantities or from our strategic initiative results. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, the additional risk-adjusted value of probable and possible reserves associated with the properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.

Tax Legislation

The Tax Legislation enacted in December 2017 reduced our federal corporate tax rate from 35% to 21%. In addition, the Tax Legislation eliminated Alternative Minimum Tax (AMT) and QEP has the ability to offset its regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior years. The Company currently anticipates it will realize approximately $148.4 million in AMT credit refunds and overpayments. The Company expects to receive the $148.4 million over the next four years, including $75.0 million in 2019. The amount expected to be refunded in 2019 is included in "Income tax receivable" with the remaining $73.4 million included in "Deferred income taxes" on the Condensed Consolidated Balance Sheet as of June 30, 2019.

Multi-Well Pad Drilling and Completion

To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling, where practical. For example, in the Permian Basin, QEP utilizes "tank-style" development, in which we simultaneously develop multiple subsurface targets by drilling and completing all wells in a given "tank" before any individual well is turned to production. We believe this approach maximizes the economic recovery of oil through the simultaneous development of multiple subsurface targets, while improving capital efficiency though shared surface facilities, which we believe will reduce per-unit operating costs and result in expanded operating margins and improve our returns on invested capital. In certain of our producing areas, wells drilled on a pad are not completed and brought into production until all wells on the pad are drilled and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the completion of wells and the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells may impact the timing of planned conversion of PUD reserves to proved developed reserves.

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Uncertainties Related to Claims

QEP is currently subject to claims that could adversely impact QEP's liquidity, operating results and capital expenditures for a particular reporting period, including, but not limited to those described in Note 11 – Commitments and Contingencies, in Item 1 of Part I of this Quarterly Report on Form 10-Q. Given the uncertainties involved in these matters, QEP is unable to predict the ultimate outcomes.

Critical Accounting Estimates

QEP's significant accounting policies are described in Item 7 of Part II of its 2018 Form 10-K. The Company's Condensed Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of the Company's Condensed Consolidated Financial Statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP's accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, impairment of long-lived assets, asset retirement obligations, revenue recognition, litigation and other contingencies, derivative contracts, pension and other postretirement benefits, share-based compensation, income taxes and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.

Drilling, Completion and Production Activities

The following table presents operated and non-operated wells in the process of being drilled or waiting on completion as of June 30, 2019:

		Operated				Non-operated
	Drilling	Drilling		Waiting on completion		Drilling		Waiting on completion
	Rigs	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin(1)	1	2	2.0	5	4.4	3	0.1	12	1.7
Other Northern	—	—	—	—	—	—	—	—	—
Southern Region
Permian Basin(2)	2	5	5.0	44	44.0	—	—	—	—
Other Southern	—	—	—	—	—	—	—	—	—

____________________________

⁽¹⁾  The 2 gross operated drilling wells in the Williston Basin represent wells in which intermediate casing had been set as of June 30, 2019.

⁽²⁾  The 5 gross operated drilling wells in the Permian Basin represent wells for which surface casing had been set as of June 30, 2019.

Each gross well completed in more than one producing zone is counted as a single well. Delays and well shut-ins resulting from multi-well pad drilling have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells could impact planned conversion of PUD reserves to proved developed reserves. QEP had 49 gross operated wells waiting on completion as of June 30, 2019.

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The following table presents the number of operated and non-operated wells completed and turned to sales (put on production) for the three and six months ended June 30, 2019:

	Operated Put on Production				Non-operated Put on Production
	Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended
	June 30, 2019		June 30, 2019		June 30, 2019		June 30, 2019
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	—	—	—	—	5	0.1	5	0.1
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Permian Basin	23	23.0	35	34.9	5	0.4	5	0.4
Other Southern	—	—	—	—	—	—	—	—

The following table presents the number of operated wells in the process of being drilled or waiting on completion at June 30, 2019 and operated wells completed and turned to sales (put on production) for the six months ended June 30, 2019:

	Permian Basin		Williston Basin
	As of June 30, 2019
	Gross	Net	Gross	Net
Well Progress
Drilling	5	5.0	2	2.0
At total depth - under drilling rig	6	6.0	—	—
Waiting to be completed	22	22.0	5	4.4
Undergoing completion	4	4.0	—	—
Completed, awaiting production	12	12.0	—	—
Waiting on completion	44	44.0	5	4.4
Put on production	35	34.9	—	—

RESULTS OF OPERATIONS

Net Income

QEP generated net income during the second quarter of 2019 of $48.8 million or $0.20 per diluted share, compared to a net loss of $336.0 million or $1.42 per diluted share, in the second quarter of 2018. QEP generated more income in the second quarter of 2019 than in 2018 primarily due to $403.7 million impairment expense recorded in the second quarter of 2018.

During the first half of 2019, QEP generated a net loss during the first half of 2019 of $67.9 million or $0.29 per diluted share, compared to net loss of $389.6 million or $1.63 per diluted share, in the first half of 2018. QEP generated more income in the first half of 2019 than in 2018 primarily due to $403.7 million impairment expense recorded the in first half of 2018.

See below for additional discussion regarding the components of net income (loss) for each of the periods presented.

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Adjusted EBITDA (Non-GAAP)

Management defines Adjusted EBITDA (a non-GAAP measure) as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment and certain other items. Management uses Adjusted EBITDA to evaluate QEP's financial performance and trends, make operating decisions and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP's performance from period to period. QEP's Adjusted EBITDA may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.

Below is a reconciliation of net income (loss) (the most comparable GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Net income (loss)	$	48.8		$	(336.0	)	$	(67.9	)	$	(389.6	)
Interest expense	33.2			38.2			67.2			73.2
Interest and other (income) expense	(0.9		)	3.1			(3.7		)	3.8
Income tax provision (benefit)	29.7			(106.2		)	(82.3		)	(120.1		)
Depreciation, depletion and amortization	128.0			242.2			251.3			438.7
Unrealized (gains) losses on derivative contracts	(54.5		)	33.6			121.3			43.6
Exploration expenses	—			0.1			—			0.1
Net (gain) loss from asset sales, inclusive of restructuring costs	(17.8		)	3.9			(4.6		)	0.4
Impairment	—			403.7			5.0			404.4
Adjusted EBITDA	$	166.5		$	282.6		$	286.3		$	454.5

In the second quarter of 2019, Adjusted EBITDA decreased to $166.5 million compared to $282.6 million in the second quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, lower equivalent production in the Williston Basin and an 11% decrease in average field-level oil prices, partially offset by a 13% increase in equivalent production in the Permian Basin, a $29.5 million decrease in realized derivative losses and $24.3 million decrease in general and administrative expenses.

In the first half of 2019, Adjusted EBITDA decreased to $286.3 million compared to $454.5 million in the first half of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, lower equivalent production in the Williston Basin and a 15% decrease in average field-level oil prices, partially offset by a 27% increase in equivalent production in the Permian Basin, a $66.8 million decrease in realized derivative losses and $21.1 million decrease in general and administrative expenses.

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Revenue

The following table presents our revenues disaggregated by revenue source.

	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2019		2018		Change			2019		2018		Change
	(in millions)
Oil and condensate, gas and NGL sales, as presented	$	294.6	$	520.3	$	(225.7	)	$	570.2	$	930.1	$	(359.9	)
Transportation and processing costs included in revenue(1)	12.7		12.4		0.3			26.5		25.1		1.4
Oil and condensate, gas and NGL sales, as adjusted(2)	307.3		$	532.7	$	(225.4	)	$	596.7	$	955.2	$	(358.5	)
Oil and condensate sales	$	285.7	$	408.5	$	(122.8	)	$	535.2	$	709.2	$	(174.0	)
Gas sales	7.3		97.8		(90.5		)	30.3		199.8		(169.5		)
NGL sales	14.3		26.4		(12.1		)	31.2		46.2		(15.0		)
Oil and condensate, gas and NGL sales, as adjusted(2)	$	307.3	532.7		$	(225.4	)	$	596.7	$	955.2	$	(358.5	)

 ____________________________

⁽¹⁾  Transportation and processing costs are deducted from revenue and are a portion of total transportation and processing costs incurred. Refer to the Operating Expenses section below for a reconciliation of total transportation and processing costs.

⁽²⁾  Oil and condensate, gas and NGL sales (the most comparable GAAP measure) as presented on the Condensed Consolidated Statements of Operations is reconciled to Oil and condensate, gas and NGL sales, as adjusted (a non-GAAP measure). Management excludes costs deducted from revenue to reflect total revenue associated with its production prior to deducting any expenses. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total revenue generated from its wells for the period. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial measure prepared in accordance with GAAP. Refer to Note 2 – Revenue in Part 1, Item I of this Quarterly Report on Form 10-Q.

Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP's adjusted production-related revenue categories for the three and six months ended June 30, 2019, compared to the three and six months ended June 30, 2018:

	Oil and condensate			Gas			NGL			Total
	(in millions)
Oil and condensate, gas and NGL sales, as adjusted
Three months ended June 30, 2018	$	408.5		$	97.8		$	26.4		$	532.7
Changes associated with volumes(1)	(88.0		)	(79.4		)	0.7			(166.7		)
Changes associated with prices(2)	(34.8		)	(11.1		)	(12.8		)	(58.7		)
Three months ended June 30, 2019	$	285.7		$	7.3		$	14.3		$	307.3
Oil and condensate, gas and NGL sales, as adjusted
Six months ended June 30, 2018	$	709.2		$	199.8		$	46.2		$	955.2
Changes associated with volumes(1)	(80.4		)	(155.1		)	7.0			(228.5		)
Changes associated with prices(2)	(93.6		)	(14.4		)	(22.0		)	(130.0		)
Six months ended June 30, 2019	$	535.2		$	30.3		$	31.2		$	596.7

 ____________________________

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⁽¹⁾  The revenue variance attributed to the change in volume is calculated by multiplying the change in volume from the three and six months ended June 30, 2019, as compared to the three and six months ended June 30, 2018, by the average field-level price for the three and six months ended June 30, 2018.

⁽²⁾  The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level price from the three and six months ended June 30, 2019, as compared to the three and six months ended June 30, 2018, by the respective volumes for the three and six months ended June 30, 2019. Pricing changes are driven by changes in commodity average field-level prices, excluding the impact from commodity derivatives.

Production and Pricing

	Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change
Total production volumes (Mboe)
Northern Region
Williston Basin	2,962.4			4,459.7			(1,497.3		)	6,339.4			8,189.4			(1,850.0		)
Uinta Basin	—			821.7			(821.7		)	—			1,626.2			(1,626.2		)
Other Northern	21.0			42.8			(21.8		)	45.7			148.3			(102.6		)
Southern Region
Permian Basin	4,552.4			4,016.2			536.2			8,634.7			6,799.1			1,835.6
Haynesville/Cotton Valley	(6.3		)	4,761.3			(4,767.6		)	310.9			9,051.8			(8,740.9		)
Other Southern	5.2			4.4			0.8			10.3			15.9			(5.6		)
Total production	7,534.7			14,106.1			(6,571.4		)	15,341.0			25,830.7			(10,489.7		)
Total equivalent prices (per Boe)
Average field-level equivalent price	$	40.77		$	37.77		$	3.00		$	38.89		$	36.98		$	1.91
Commodity derivative impact	(2.13		)	(3.23		)	1.10			(1.43		)	(3.45		)	2.02
Net realized equivalent price	$	38.64		$	34.54		$	4.10		$	37.46		$	33.53		$	3.93

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Oil and Condensate Volumes and Prices

	Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change
Oil and condensate production volumes (Mbbl)
Northern Region
Williston Basin	1,861.4			3,166.8			(1,305.4		)	4,019.4			5,779.0			(1,759.6		)
Uinta Basin	—			168.6			(168.6		)	—			320.3			(320.3		)
Other Northern	13.0			19.2			(6.2		)	24.0			57.0			(33.0		)
Southern Region
Permian Basin	3,273.9			3,207.2			66.7			6,188.4			5,366.3			822.1
Haynesville/Cotton Valley	—			4.5			(4.5		)	(0.4		)	10.3			(10.7		)
Other Southern	2.0			1.3			0.7			2.5			8.7			(6.2		)
Total production	5,150.3			6,567.6			(1,417.3		)	10,233.9			11,541.6			(1,307.7		)
Average field-level oil prices (per bbl)
Northern Region	$	57.60		$	64.99		$	(7.39	)	$	54.00		$	63.14		$	(9.14	)
Southern Region	$	54.24		$	59.30		$	(5.06	)	$	51.18		$	59.51		$	(8.33	)
Average field-level price	$	55.46		$	62.21		$	(6.75	)	$	52.30		$	61.45		$	(9.15	)
Commodity derivative impact	(3.11		)	(7.91		)	4.80			(1.85		)	(8.34		)	6.49
Net realized price	$	52.35		$	54.30		$	(1.95	)	$	50.45		$	53.11		$	(2.66	)

Oil and condensate revenues decreased $122.8 million, or 30%, in the second quarter of 2019 compared to the second quarter of 2018, due to lower oil and condensate production volumes and lower average field-level prices. The 22% decrease in production volumes was primarily driven by a decrease in production in the Williston Basin due to the lack of new well completions in 2019 and the Uinta Basin Divestiture, partially offset by an increase in production in the Permian Basin due to continued drilling and completion activity. Average field-level oil prices decreased 11% in the second quarter of 2019 compared to the second quarter of 2018 primarily driven by a decrease in average NYMEX-WTI oil prices for the comparable periods, partially offset by a $1.46 per bbl, or 25%, decrease in the basis differential relative to the average NYMEX-WTI oil price in the second quarter of 2019 compared to the second quarter of 2018.

Oil and condensate revenues decreased $174.0 million, or 25%, in the first half of 2019 compared to the first half of 2018, due to lower average field-level prices and lower oil and condensate production volumes. Average field-level oil prices decreased 15% in the first half of 2019 compared to the first half of 2018 primarily driven by a decrease in average NYMEX-WTI oil prices for the comparable periods and a $1.01 per bbl, or 25%, increase in the basis differential relative to the average NYMEX-WTI oil price in the first half of 2019 compared to the first half of 2018. The 11% decrease in production volumes was driven by a decrease in production in the Williston Basin due to the lack of new well completions in 2019 and the Uinta Basin Divestiture, partially offset by an increase in production in the Permian Basin due to continued drilling and completion activity.

38

Gas Volumes and Prices

	Three Months Ended June 30,								Six Months Ended June 30,
	2019			2018		Change			2019			2018		Change
Gas production volumes (Bcf)
Northern Region
Williston Basin	3.5			3.8		(0.3		)	7.3			7.2		0.1
Uinta Basin	—			3.7		(3.7		)	—			7.4		(7.4		)
Other Northern	—			0.1		(0.1		)	0.1			0.5		(0.4		)
Southern Region
Permian Basin	3.7			2.1		1.6			7.1			4.0		3.1
Haynesville/Cotton Valley	—			28.5		(28.5		)	1.9			54.2		(52.3		)
Other Southern	—			0.1		(0.1		)	—			0.1		(0.1		)
Total production	7.2			38.3		(31.1		)	16.4			73.4		(57.0		)
Average field-level gas prices (per Mcf)
Northern Region	$	2.15		$	2.17	$	(0.02	)	$	2.72		$	2.48	$	0.24
Southern Region	$	(0.06	)	$	2.65	$	(2.71	)	$	1.12		$	2.78	$	(1.66	)
Average field-level price	$	1.01		$	2.55	$	(1.54	)	$	1.84		$	2.72	$	(0.88	)
Commodity derivative impact	—			0.17		(0.17		)	(0.18		)	0.10		(0.28		)
Net realized price	$	1.01		$	2.72	$	(1.71	)	$	1.66		$	2.82	$	(1.16	)

Gas revenues decreased $90.5 million, or 93%, in the second quarter of 2019 compared to the second quarter of 2018, due to lower gas production volumes and lower average field-level prices. Production volumes decreased 81% in the second quarter of 2019 compared to the second quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Average field-level gas prices decreased 60% in the second quarter of 2019 compared to the second quarter of 2018, primarily driven by a decrease in average NYMEX-HH gas spot prices and regional basis differentials, particularly in the Permian Basin, for the comparable periods.

Gas revenues decreased $169.5 million, or 85%, in the first half of 2019 compared to the first half of 2018, due to lower gas production volumes and lower average field-level prices. Production volumes decreased 78% in the first half of 2019 compared to the first half of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, partially offset by an increase in production in the Permian Basin due to continued drilling and completion activity. Average field-level gas prices decreased 32% in the first half of 2019 compared to the first half of 2018, primarily driven by a decrease in average NYMEX-HH gas spot prices and regional basis differentials for the comparable periods.

39

NGL Volumes and Prices

	Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Change			2019		2018		Change
NGL production volumes (Mbbl)
Northern Region
Williston Basin	526.6		666.7		(140.1		)	1,105.4		1,218.1		(112.7		)
Uinta Basin	—		34.9		(34.9		)	—		71.2		(71.2		)
Other Northern	0.7		2.4		(1.7		)	0.4		5.7		(5.3		)
Southern Region
Permian Basin	658.6		448.4		210.2			1,258.5		761.3		497.2
Haynesville/Cotton Valley	—		0.2		(0.2		)	—		0.3		(0.3		)
Other Southern	0.1		0.2		(0.1		)	0.5		0.6		(0.1		)
Total production	1,186.0		1,152.8		33.2			2,364.8		2,057.2		307.6
Average field-level NGL prices (per bbl)
Northern Region	$	10.96	$	23.44	$	(12.48	)	$	11.91	$	23.05	$	(11.14	)
Southern Region	$	12.94	$	21.91	$	(8.97	)	$	14.30	$	21.49	$	(7.19	)
Average field-level price	$	12.06	$	22.84	$	(10.78	)	$	13.18	$	22.47	$	(9.29	)
Commodity derivative impact	—		—		—			—		—		—
Net realized price	$	12.06	$	22.84	$	(10.78	)	$	13.18	$	22.47	$	(9.29	)

NGL revenues decreased $12.1 million, or 46%, during the second quarter of 2019 compared to the second quarter of 2018, due to lower average field-level prices, partially offset by higher NGL production volumes. The 47% decrease in NGL prices during the second quarter of 2019 compared to the second quarter of 2018 was primarily driven by a decrease in propane, ethane and other NGL component prices. The decrease in price was partially offset by a 3% increase in NGL production volumes primarily driven by continued drilling and completion activity and higher gas capture rates as a result of the completion of our midstream infrastructure in the Permian Basin, partially offset by production decreases in the Williston Basin due to the lack of new well completions in 2019 and the Uinta Basin Divestiture.

NGL revenues decreased $15.0 million, or 32%, during the first half of 2019 compared to the first half of 2018, due to lower average field-level prices, partially offset by higher NGL production volumes. The 41% decrease in NGL prices during the first half of 2019 compared to the first half of 2018 was primarily driven by a decrease in propane, ethane and other NGL component prices. The decrease in price was partially offset by a 15% increase in NGL production volumes primarily driven by continued drilling and completion activity and higher gas capture rates as a result of the completion of our midstream infrastructure in the Permian Basin, partially offset by production decreases in the Williston Basin due to the lack of new well completions in 2019 and the Uinta Basin Divestiture.

40

Resale Margin and Storage Activity

QEP purchases and resells oil and gas primarily to mitigate credit risk related to third party purchasers, to fulfill volume commitments when our production does not fulfill contractual commitments and to capture additional margin from subsequent sales of third party purchases. With the Pinedale and Uinta Basin divestitures in 2018 and the Haynesville Divestiture (which included our firm transportation agreements) in the first quarter of 2019, purchase and resale of gas will be minimal going forward. The following table is a summary of QEP's financial results from its resale activities.

	Three Months Ended June 30,								Six Months Ended June 30,
	2019		2018			Change			2019			2018			Change
	(in millions)
Purchased oil and gas sales	$	—	$	9.1		$	(9.1	)	$	1.3		$	23.2		$	(21.9	)
Purchased oil and gas expense	—		(9.8		)	9.8			(1.4		)	(25.3		)	23.9
Realized gains (losses) on gas storage derivative contracts	—		0.1			(0.1		)	—			0.3			(0.3		)
Resale margin	$	—	$	(0.6	)	$	0.6		$	(0.1	)	$	(1.8	)	$	1.7

Purchased oil and gas sales and expense were lower in the second quarter of 2019 compared to the second quarter of 2018, primarily due to the fulfillment of a gas sales agreement related to Pinedale that was retained and not part of the Pinedale Divestiture, and fulfillment of our firm volume commitments in Haynesville/Cotton Valley and our underground storage facility, which were divested in January 2019 and May 2018, respectively.

Purchased oil and gas sales and expense were lower in the first half of 2019 compared to the first half of 2018, primarily due to the fulfillment of a gas sales agreement related to Pinedale that was retained and not part of the Pinedale Divestiture, and fulfillment of our firm volume commitments in Haynesville/Cotton Valley and our underground storage facility, which were divested in January 2019 and May 2018, respectively.

41

Operating Expenses

The following table presents QEP production costs and production costs on a per unit of production basis:

	Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Change			2019		2018		Change
	(in millions)
Lease operating expense	$	45.7	$	66.5	$	(20.8	)	$	97.2	$	139.0	$	(41.8	)
Adjusted transportation and processing costs(1)	22.6		43.6		(21.0		)	47.3		90.3		(43.0		)
Production and property taxes	23.6		37.6		(14.0		)	47.6		66.5		(18.9		)
Total production costs	$	91.9	$	147.7	$	(55.8	)	$	192.1	$	295.8	$	(103.7	)
	(per Boe)
Lease operating expense	$	6.06	$	4.71	$	1.35		$	6.34	$	5.38	$	0.96
Adjusted transportation and processing costs(1)	3.00		3.09		(0.09		)	3.09		3.49		(0.40		)
Production and property taxes	3.13		2.66		0.47			3.10		2.57		0.53
Total production costs	$	12.19	$	10.46	$	1.73		$	12.53	$	11.44	$	1.09

 ____________________________

⁽¹⁾  Below are reconciliations of transportation and processing costs (the most comparable GAAP measure) as presented on the Condensed Consolidated Statements of Operations and on a unit of production basis to adjusted transportation and processing costs. Adjusted transportation and processing costs includes transportation and processing costs that are reflected as part of "Oil and condensate, gas and NGL sales" on the Condensed Consolidated Statements of Operations. Management adds these costs together to reflect the total operating costs associated with its production. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total production costs required to operate the wells for the period. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial measure prepared in accordance with GAAP. Refer to Note 2 – Revenue in Part 1, Item I of this Quarterly Report on Form 10-Q.

	Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Change			2019		2018		Change
	(in millions)
Transportation and processing costs, as presented	$	9.9	$	31.2	$	(21.3	)	$	20.8	$	65.2	$	(44.4	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	12.7		12.4		0.3			26.5		25.1		1.4
Adjusted transportation and processing costs	$	22.6	$	43.6	$	(21.0	)	$	47.3	$	90.3	$	(43.0	)
	(per Boe)
Transportation and processing costs, as presented	$	1.31	$	2.21	$	(0.90	)	$	1.36	$	2.52	$	(1.16	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	1.69		0.88		0.81			1.73		0.97		0.76
Adjusted transportation and processing costs	$	3.00	$	3.09	$	(0.09	)	$	3.09	$	3.49	$	(0.40	)

Lease operating expense (LOE). QEP's LOE decreased $20.8 million, or 31%, in the second quarter of 2019 compared to the second quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE decreased $5.8 million, driven by a decrease in maintenance and repair expenses, labor and water disposal in the Williston Basin.

42

During the second quarter of 2019, LOE increased $1.35 per Boe, or 29%, compared to the second quarter of 2018, but was flat excluding the loss of lower LOE production due to the Haynesville/Cotton Valley and Uinta Basin divestitures. The flat per BOE rate was related to lower cost production from the recent horizontal well completions in the Permian Basin offset by decreased production in the Williston Basin.

QEP's LOE decreased $41.8 million, or 30%, in the first half of 2019 compared to the first half of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE decreased $9.6 million, driven by a decrease in workovers and maintenance and repair expenses in the Williston Basin.

During the first half of 2019, LOE increased $0.96 per Boe, or 18%, compared to the first half of 2018, but was down 8% excluding the loss of lower LOE production due to the Haynesville/Cotton Valley and Uinta Basin divestitures. The 8% per BOE decrease was related to lower cost production from the recent horizontal well completions in the Permian Basin, partially offset by decreased production in the Williston Basin.

Adjusted transportation and processing costs (non-GAAP). Adjusted transportation and processing costs decreased $21.0 million, or 48%, in the second quarter of 2019 compared to the second quarter of 2018. The decrease in expense was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, adjusted transportation and processing costs decreased $1.7 million, primarily due to decreased production in the Williston Basin, partially offset by increased production in the Permian Basin.

During the second quarter of 2019, adjusted transportation and processing costs decreased $0.09 per Boe, or 3%, during the second quarter of 2019 compared to the second quarter of 2018. The decrease was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, which had higher adjusted transportation and processing costs per Boe. Excluding the Haynesville/Cotton Valley and Uinta Basin divestitures, adjusted transportation and processing costs per Boe were up 5% due to increased gas and NGL production, which has higher adjusted transportation and processing costs per Boe.

Adjusted transportation and processing costs decreased $43.0 million, or 48%, in the first half of 2019 compared to the first half of 2018. The decrease in expense was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, adjusted transportation and processing costs decreased $1.0 million, primarily due to decreased production in the Williston Basin, partially offset by increased production in the Permian Basin.

During the first half of 2019, adjusted transportation and processing costs decreased $0.40 per Boe, or 11%, during the first half of 2019 compared to the first half of 2018. The decrease was primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, which had higher adjusted transportation and processing costs per Boe. Excluding the Haynesville/Cotton Valley and Uinta Basin divestitures, adjusted transportation and processing costs per Boe were down 2% due to increased production in the Permian Basin, which has lower adjusted transportation and processing costs per Boe.

Production and property taxes. In most states in which QEP operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production and property taxes decreased $14.0 million, or 37%, in the second quarter of 2019 compared to the second quarter of 2018, primarily due to decreased revenues in the Williston Basin as well as the Haynesville/Cotton Valley and Uinta Basin divestitures.

During the second quarter of 2019, production and property taxes increased $0.47 per Boe, or 18%, compared to the second quarter of 2018, but decreased 16% excluding the Haynesville/Cotton Valley and Uinta Basin divestitures. The 16% decrease was due to a decrease in average field-level equivalent prices in the Permian and Williston basins, partially offset by higher ad valorem charges per Boe in the Permian Basin.

Production and property taxes decreased $18.9 million, or 28%, in the first half of 2019 compared to the first half of 2018, primarily due to decreased revenues in the Williston Basin as well as the Haynesville/Cotton Valley and Uinta Basin divestitures.

During the first half of 2019, production and property taxes increased $0.53 per Boe, or 21%, compared to the first half of 2018, but decreased 14% excluding the Haynesville/Cotton Valley and Uinta Basin divestitures. The 14% decrease was due to a decrease in average field-level equivalent prices in the Permian and Williston basins, partially offset by higher ad valorem charges per Boe in the Permian Basin.

43

Depreciation, depletion and amortization (DD&A). DD&A expense decreased $114.2 million in the second quarter of 2019 compared to the second quarter of 2018, primarily in the Williston Basin due to a lower rate and decreased production, as well as the Haynesville/Cotton Valley and Uinta Basin divestitures. The decreased DD&A rate in the Williston Basin was driven by a 2018 impairment. This decrease was partially offset by increased DD&A in the Permian Basin due to increased volumes and a slightly higher DD&A rate.

DD&A expense decreased $187.4 million in the first half of 2019 compared to the first half of 2018, primarily in the Williston Basin due to a lower DD&A rate and decreased production, as well as the Haynesville/Cotton Valley and Uinta Basin divestitures. The decreased DD&A rate in the Williston Basin was driven by a 2018 impairment. This decrease was partially offset by increased DD&A in the Permian Basin due to increased volumes and a slightly higher DD&A rate.

Impairment expense. During the second quarter of 2019, there were no impairment charges. During the second quarter of 2018, QEP recorded impairment charges of $403.7 million, which were primarily due to the impairment of proved and unproved properties related to the Uinta Basin Divestiture.

During the first half of 2019, QEP recorded impairment charges of $5.0 million, which related to impairment of an office building operating lease. During the first half of 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment was triggered by the Uinta Basin Divestiture and $1.6 million was related to expiring leaseholds on unproved properties and impairment of proved properties related to a divestiture in the Other Northern area.

General and administrative (G&A) expense. During the second quarter of 2019, G&A expense decreased $24.3 million, or 44%, compared to the second quarter of 2018. During the second quarter of 2019 and 2018, QEP incurred $7.2 million and $13.0 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $6.0 million and $9.5 million, respectively, related to restructuring costs (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). Excluding these costs, G&A expense decreased by $18.7 million, primarily due to $19.1 million lower labor, benefits and other associated costs due to the reduction in our workforce, partially offset by a $2.3 million decrease in overhead recoveries, primarily associated with our Haynesville/Cotton Valley and Uinta Basin divestitures.

During the first half of 2019, G&A expense decreased $21.1 million, or 18%, compared to the first half of 2018. During the first half of 2019 and 2018, QEP incurred $33.2 million and $22.5 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $26.3 million and $17.4 million, respectively, related to restructuring costs (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). Excluding these costs, G&A expense decreased by $31.9 million, primarily due to $29.1 million lower labor, benefits and other associated costs due to the reduction in our workforce and $4.6 million in lower legal and outside service costs, partially offset by a $5.0 million decrease in overhead recoveries, primarily associated with our Haynesville/Cotton Valley and Uinta Basin divestitures.

Net gain (loss) from asset sales, inclusive of restructuring costs. During the second quarter of 2019, QEP recognized a gain on the sale of assets of $17.8 million, of which $14.3 million related to the Haynesville Divestiture. During the second quarter of 2018, QEP recognized a loss on the sale of assets of $3.9 million primarily related to a pre-tax loss of $1.9 million related to estimated restructuring costs associated with the Uinta Basin Divestiture (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for more information). In addition, QEP recognized a pre-tax loss of $2.0 million related to the divestiture of properties outside our main operating areas in the Uinta Basin and the Other Northern area, and an underground gas storage facility.

During the first half of 2019, QEP recognized a gain on the sale of assets of $4.6 million primarily related to the $5.5 million gain from the divestiture of other properties, partially offset by a net pre-tax loss on sale of $0.7 million related to our Haynesville Divestiture, which included $4.3 million of restructuring costs (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for more information). During the first half of 2018, QEP recognized a loss on the sale of assets of $0.4 million primarily comprised of $1.9 million of estimated restructuring costs associated with the Uinta Basin Divestiture (refer to Note 9 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for more information) partially offset by a net pre-tax gain on sale of assets of $1.5 million related to the divestiture of properties outside our main operating areas in the Uinta Basin, Pinedale and the Other Northern area, and an underground gas storage facility.

44

Non-operating Expenses

Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative contracts are comprised of both realized and unrealized gains and losses on QEP's commodity derivative contracts, which are marked-to-market each quarter. During the second quarter of 2019, gains on commodity derivative contracts were $38.5 million, of which $54.5 million were unrealized gains and $16.0 million were realized losses on settled derivative contracts. During the second quarter of 2018, losses on commodity derivative contracts were $79.1 million, of which $45.5 million were realized losses and $33.6 million were unrealized losses.

During the first half of 2019, losses on commodity derivative contracts were $143.2 million, of which $123.1 million were unrealized losses, $21.9 million were realized losses on settled derivative contracts, and $1.8 million were unrealized gains related to the Haynesville Divestiture (refer to Note 7 – Derivative Contracts, in Item I of Part I of the Quarterly Report on Form 10-Q for more information). During the first half of 2018, losses on commodity derivative contracts were $132.3 million, of which $88.7 million were realized losses and $43.6 million were unrealized losses.

Interest expense. Interest expense decreased $5.0 million, or 13%, during the second quarter of 2019 compared to the second quarter of 2018. The decrease during the second quarter of 2019 was primarily related to decreased borrowings under the credit facility.

Interest expense decreased $6.0 million, or 8%, during the first half of 2019 compared to the first half of 2018. The decrease during the first half of 2019 was primarily related to decreased borrowings under the credit facility.

Income tax (provision) benefit. Income tax expense increased $135.9 million during the second quarter of 2019 compared to the second quarter of 2018. The increase in expense was the result of net income during the second quarter of 2019 compared to a net loss during the second quarter of 2018. QEP’s effective federal and state income tax rate of 37.8% during the second quarter of 2019 compared to a rate of 24.0% during the second quarter of 2018 is primarily driven by the impact of non-deductible executive compensation during the second quarter of 2019 compared to the second quarter of 2018.

Income tax benefit decreased $37.8 million during the first half of 2019 compared to the first half of 2018. QEP's income tax benefit during the first half of 2019 was impacted by a higher combined effective federal and state income tax rate of 54.8% during the first half of 2019 compared to a rate of 23.6% during the first half of 2018. The increase in effective income tax rate was primarily driven by the re-measurement of QEP's deferred tax assets and liabilities at a lower blended state tax rate due to exiting the state of Louisiana as a result of the Haynesville Divestiture during the first half of 2019.

LIQUIDITY AND CAPITAL RESOURCES

QEP strives to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility and fund its development projects, operations, capital expenditures, debt maturities, quarterly dividends and costs related to its strategic initiatives. The Company utilizes derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. QEP generally funds its operations and planned capital expenditures with cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility. QEP also periodically accesses debt and equity markets and sells properties to enhance its liquidity. The Company expects that cash flows from its operating activities, cash on hand and borrowings under its revolving credit facility will be sufficient to fund its operations, capital expenditures, debt maturities and quarterly dividends during the next 12 months and the foreseeable future.

During the six months ended June 30, 2019, QEP closed the Haynesville Divestiture for net cash proceeds of $627.1 million, subject to post closing purchase price adjustments. QEP used the proceeds to repay the outstanding balance on its revolving credit facility and for general corporate purposes. In July 2019, QEP reached final settlement on asserted title defects and received an additional $9.5 million.

As of June 30, 2019, the Company had $97.1 million in cash and cash equivalents, no borrowings under its revolving credit facility and $2.9 million in letters of credit outstanding. The Company estimates that as of June 30, 2019, it could incur additional indebtedness of approximately $551.1 million and be in compliance with the covenants contained in its revolving credit facility. To the extent actual operating results, realized commodity prices or uses of cash differ from the Company's assumptions, QEP's ability to incur additional indebtedness and liquidity could be adversely affected.

45

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 governing QEP's revolving credit facility 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 3.75 times consolidated EBITDA (as defined in the credit agreement), and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.40 times through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. As of June 30, 2019 and December 31, 2018, QEP was in compliance with the covenants under the credit agreement.

During the six months ended June 30, 2019, QEP's weighted-average interest rate on borrowings from its credit facility was 4.73%. As of June 30, 2019, QEP had no borrowings outstanding and $2.9 million in letters of credit outstanding under the credit facility. As of December 31, 2018, QEP had $430.0 million of borrowings outstanding and $0.3 million in letters of credit outstanding under the credit facility. As of July 19, 2019, QEP had no borrowings outstanding and had $2.9 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.

Senior Notes

The Company's senior notes outstanding as of June 30, 2019, totaled $2,099.3 million principal amount and are comprised of five issuances as follows:

• $51.7 million 6.80% Senior Notes due March 2020;

• $397.6 million 6.875% Senior Notes due March 2021;

• $500.0 million 5.375% Senior Notes due October 2022;

• $650.0 million 5.25% Senior Notes due May 2023; and

• $500.0 million 5.625% Senior Notes due March 2026.

Cash Flow from Operating Activities

Cash flows from operating activities are primarily affected by oil and condensate, gas and NGL production volumes and commodity prices (including the effects of settlements of the Company's derivative contracts) and by changes in working capital. QEP typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and condensate production for the next 12 to 24 months.

Net cash provided by (used in) operating activities is presented below:

	Six Months Ended June 30,
	2019			2018			Change
	(in millions)
Net income (loss)	$	(67.9	)	$	(389.6	)	$	321.7
Non-cash adjustments to net income (loss)	296.5			785.1			(488.6		)
Changes in operating assets and liabilities	(32.9		)	(18.6		)	(14.3		)
Net cash provided by (used in) operating activities	$	195.7		$	376.9		$	(181.2	)

Net cash provided by operating activities was $195.7 million during the first half of 2019, which included $67.9 million of net loss, $296.5 million of non-cash adjustments to the net loss and $32.9 million in changes in operating assets and liabilities. Non-cash adjustments to the net loss of $296.5 million primarily included DD&A expense of $251.3 million, $121.3 million of unrealized losses on derivative contracts and $11.2 million of non-cash share-based compensation expense, partially offset by $87.7 million of deferred income taxes benefit and net gain from assets sales, inclusive of restructuring costs, of $4.6 million.

The decrease in changes in operating assets and liabilities of $32.9 million primarily resulted from decreases in accounts payable and accrued expenses of $54.0 million, other long-term liabilities of $11.8 million and accrued production and property taxes of $8.0 million, partially offset by a decrease in accounts receivable of $21.2 million, a decrease in inventory of $9.0 million, an increase in accrued income taxes of $5.1 million and a decrease in prepaid expenses of $4.0 million.

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Net cash provided by operating activities was $376.9 million during the first half of 2018, which included $389.6 million of net loss, $785.1 million of non-cash adjustments to the net loss and $18.6 million in changes in operating assets and liabilities. Non-cash adjustments to the net loss of $785.1 million primarily included DD&A expense of $438.7 million, $404.4 million of impairment expense, $43.6 million of unrealized losses on derivative contracts and $16.3 million of non-cash share-based compensation expense, partially offset by $120.5 million of deferred income tax benefit.

The decrease in changes in operating assets and liabilities of $18.6 million primarily resulted from an increase in accounts receivable of $32.6 million and a decrease in other long-term liabilities of $2.4 million, partially offset by an increase in interest payable of $6.7 million and an increase in accounts payable and accrued expenses of $3.2 million.

Cash Flow from Investing Activities

A comparison of capital expenditures for the first half of 2019 and 2018, are presented in the table below:

	Six Months Ended June 30,
	2019			2018			Change
	(in millions)
Property acquisitions	$	1.8		$	45.1		$	(43.3	)
Property, plant and equipment capital expenditures	337.1			784.5			(447.4		)
Total accrued capital expenditures	338.9			829.6			(490.7		)
Change in accruals and other non-cash adjustments	(20.3		)	(20.2		)	(0.1		)
Total cash capital expenditures	$	318.6		$	809.4		$	(490.8	)

In the first half of 2019, on an accrual basis, the Company invested $337.1 million on property, plant and equipment capital expenditures (which excludes property acquisitions), a decrease of $447.4 million compared to the first half of 2018. In the first half of 2019, QEP's primary capital expenditures included $307.0 million in the Permian Basin (including midstream infrastructure of $32.9 million, primarily related to oil and gas gathering and water handling) and $31.0 million in the Williston Basin.

In the first half of 2018, on an accrual basis, the Company invested $784.5 million on property, plant and equipment capital expenditures (which excludes property acquisitions). QEP's significant capital expenditures included $498.9 million in the Permian Basin (including midstream infrastructure of $38.3 million, primarily related to fresh water supply, produced water gathering, salt water disposal and oil and gas gathering), $157.8 million in the Williston Basin, $120.6 million in Haynesville/Cotton Valley (including midstream infrastructure of $7.5 million, primarily related to gas gathering) and $4.5 million in the Uinta Basin. In addition, in the first half of 2018, QEP acquired various oil and gas properties, primarily proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $45.1 million, of which $37.5 million was related to the 2017 Permian Basin Acquisition.

The mid-point of our 2019 forecasted capital expenditures (excluding property acquisitions) is $590.0 million. QEP intends to fund capital expenditures (excluding property acquisitions) with cash flow from operating activities, cash on hand and borrowings under the credit facility. The aggregate levels of capital expenditures for 2019 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, oil, gas and NGL prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management's business assessments as to where QEP's capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP's estimates.

Cash Flow from Financing Activities

In the first half of 2019, net cash used in financing activities was $445.6 million compared to net cash provided by financing activities of $386.4 million in the first half of 2018. During the first half of 2019, QEP made repayments on its credit facility of $486.0 million and had borrowings from the credit facility of $56.0 million. In addition, QEP had treasury stock repurchases of $6.3 million related to the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants. During the first half of 2019, QEP had a decrease in checks outstanding in excess of cash balances of $9.3 million.

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During the first half of 2018, QEP had borrowings from its credit facility of $2,029.5 million and repayments on its credit facility of $1,543.5 million. In addition, QEP used $58.4 million of cash to repurchase common stock under the Company's share repurchase program and had treasury stock repurchases of $5.9 million related to the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants. QEP also had a decrease in checks outstanding in excess of cash balances of $35.5 million.

As of June 30, 2019, long-term debt consisted of $2,079.8 million, of which $2,099.3 million is senior notes and $19.5 million of net original issue discount and unamortized debt issuance costs.

Off-Balance Sheet Arrangements

QEP may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. At June 30, 2019, the Company's material off-balance sheet arrangements included drilling, gathering, processing and firm transportation arrangements and undrawn letters of credit. There are no other off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on QEP's financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. For more information regarding off-balance sheet arrangements, we refer you to "Contractual Cash Obligations and Other Commitments" in our 2018 Annual Report on Form 10-K.

Contractual Cash Obligations and Other Commitments

We have various contractual obligations in the normal course of our operations and financing activities. The close of the Haynesville Divestiture resulted in a $195.4 million reduction in contractual cash obligations and other commitments subsequent to December 31, 2018, primarily related to firm transportation agreements and asset retirement obligations. There have been no other material changes to our contractual obligations from those disclosed in our 2018 Annual Report on Form 10-K.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP's primary market risks arise from changes in the market price for oil, gas and NGL and volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. In addition, additional non-cash impairment expense of the Company's oil and gas properties may be required if future oil and gas commodity prices experience a significant decline. Furthermore, the Company's revolving credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. To partially manage the Company's exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price and basis swaps and collars to manage commodity price risk and periodically enters into interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP uses commodity derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price and basis swaps and collars. The volume of commodity derivative instruments utilized by the Company may vary from year to year based on QEP's forecasted production. The Company's current derivative instruments do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of June 30, 2019, QEP held commodity price derivative contracts, excluding basis swaps, totaling 14.6 million barrels of oil and no commodity price gas derivatives. As of December 31, 2018, QEP held commodity price derivative contracts, excluding basis swaps, totaling 13.9 million barrels of oil and 43.8 million MMBtu of gas.

The following tables present QEP's volumes and average prices for its derivative positions as of July 19, 2019. Refer to Note 7 – Derivative Contracts in Part 1, Item 1 of this Quarterly Report on Form 10-Q for open derivative positions as of June 30, 2019.

Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	6.6	$	55.24
2019	ICE Brent	0.9	$	66.73
2019	Argus WTI Houston	0.2	$	65.70
2020	NYMEX WTI	7.5	$	59.70
2020	Argus WTI Midland	0.7	$	60.00

Production Commodity Derivative Basis Swaps
Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2019	NYMEX WTI	Argus WTI Midland	3.3	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.9	$	3.69
2020	NYMEX WTI	Argus WTI Midland	4.4	$	(0.02	)
2020 (January - June)	NYMEX WTI	Argus WTI Houston	0.4	$	3.75

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Changes in the fair value of derivative contracts from December 31, 2018 to June 30, 2019, are presented below:

	Commodity derivative contracts
	(in millions)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2018	$	122.5
Contracts settled	21.9
Change in oil prices on futures markets	300.5
Contracts added	(445.5		)
Net fair value of oil derivative contracts outstanding at June 30, 2019	$	(0.6	)

The following table shows the sensitivity of the fair value of oil derivative contracts to changes in the market price of oil and basis differentials:

	June 30, 2019
	(in millions)
Net fair value – asset (liability)	$	(0.6	)
Fair value if market prices of oil and basis differentials decline by 10%	$	(0.5	)
Fair value if market prices of oil and basis differentials increase by 10%	$	(0.7	)

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $0.1 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $0.1 million as of June 30, 2019. However, a gain or loss eventually would be offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company's commodity derivative transactions, refer to Note 7 – Derivative Contracts in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Interest Rate Risk Management

The Company's revolving credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. At June 30, 2019, the Company had no borrowings outstanding under its revolving credit facility. If interest rates were to increase or decrease 10% during the six months ended June 30, 2019, at our average level of borrowing for those same periods, the Company's interest expense would increase or decrease by less than $0.1 million for the six months ended June 30, 2019, or less than 1% of total interest expense.

The remaining $2,099.3 million of the Company's debt is senior notes with fixed interest rates; therefore, it is not affected by interest rate movements. For additional information regarding the Company's debt instruments, refer to Note 10 – Debt, in Item I of Part I of this Quarterly Report on Form 10-Q.

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Forward-Looking Statements

The quarterly report contains information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. We use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:

• our comprehensive review of strategic alternatives to maximize shareholder value, resulting in our decision to move forward as an independent company;

• our strategy to continue to focus on high-return investments in our business with disciplined production growth;

• our commitment to strengthening our balance sheet, reducing leverage and returning capital to shareholders;

• improved performance and deliverability of our asset base;

• plans to reduce general and administrative expense significantly;

• timing of the implementation of organizational changes;

• expected costs associated with contractual termination benefits, including severance and accelerated vesting of share-based compensations, as part of the strategic initiatives;

• plans to reduce operating and drilling, completion and facility costs and managing liquidity;

• plans to grow oil and condensate production;

• drilling and completion plans and strategies;

• adding additional acreage in our operating areas;

• adequacy of procedures implemented to protect against credit-related losses;

• expectations and assumptions regarding oil, gas and NGL prices, including volatility and effects on our business;

• our ability to meet delivery and sales commitments;

• impact of potential activist shareholders to our operations, personnel retention, strategies and costs;

• the unfunded status of our pension plan;

• estimates of future liability for deficiency charges in connection with the divestiture of our assets in Pinedale;

• the conditions impacting the timing and amount of share repurchases under our share repurchase program;

• the adjustments made to GAAP measures to arrive at non-GAAP measures and the usefulness of non-GAAP financial measures;

• solid base for growth in production and reserves provided by our inventory of drilling locations;

• adjustments to our capital investment program based on a variety of factors; including an evaluation of drilling and completion activities and drilling results;

• amount and allocation of forecasted capital expenditures (excluding property acquisitions) and plans and sources for funding operations and capital investments;

• impact of lower or higher commodity prices and interest rates;

• potential for asset impairments and factors impacting impairment amounts;

• fair value estimates and related assumptions and assessment of the sensitivity of changes in assumptions and critical accounting estimates, including estimated asset retirement obligations;

• critical accounting estimates, including assets retirement obligations;

• impact of global geopolitical and macroeconomic events and monitoring of such events;

• plans regarding derivative contracts, including the volumes utilized, and the anticipated benefits derived there from;

• outcome and impact of various claims;

• expected cost savings and other efficiencies from multi-well pad drilling, including "tank-style" development;

• delays in completion of wells, well shut-ins and volatility to operating results caused by multi-well pad drilling, including the effect of such delays on quarterly operating results and planned conversion of PUD reserves;

• maintaining a sufficient liquidity position to ensure financial flexibility, withstand commodity price volatility, and fund our development projects, operations, capital expenditures and costs related to strategic initiatives;

• estimates of the amount of additional indebtedness we may incur under our revolving credit facility;

• factors impacting ability to incur additional indebtedness;

• off-balance sheet arrangements;

• redemption of senior notes;

• assumptions regarding share-based compensation;

• settlement of performance share units and restricted share units in cash;

• AMT credits amount and timing; and

• our plans regarding contributions to the nonqualified retirement plan (SERP), medical plan and 401(k) plan.

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Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:

• the risk factors discussed in Item 1A of Part I of the 2018 Form 10-K and Item 1A of Part II of this Quarterly Report on Form 10-Q;

• any potential impact from the announcement that the Board of Directors of the Company completed its comprehensive review of strategic alternatives and is moving forward as an independent company;

• changes in oil, gas and NGL prices;

• global geopolitical and macroeconomic factors;

• general economic conditions, including the performance of financial markets and interest rates;

• the risks and liabilities associated with acquired assets;

• asset impairments;

• liquidity constraints, including those resulting from the cost and availability of debt and equity financing;

• drilling and completion strategies, methods and results;

• assumptions around well density/spacing and recoverable reserves per well prove to be inaccurate;

• changes in estimated reserve quantities;

• changes in management's assessments as to where QEP's capital can be most profitably deployed;

• shortages and costs of oilfield equipment, services and personnel;

• changes in development plans;

• lack of available pipeline, processing and refining capacity;

• processing volumes and pipeline throughput;

• risks associated with hydraulic fracturing;

• the outcome of contingencies such as legal proceedings;

• delays in obtaining permits and governmental approvals;

• operating risks such as unexpected drilling conditions and risks inherent in the production of oil and gas;

• weather conditions;

• changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning: the environment, climate change, greenhouse gas or other emissions, renewable energy mandates, natural resources, fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;

• derivative activities;

• potential losses or earnings reductions from our commodity price risk management programs;

• volatility in the commodity-futures market;

• failure of internal controls and procedures;

• failure of our information technology infrastructure or applications to prevent a cyberattack;

• elimination of federal income tax deductions for oil and gas exploration and development costs;

• production, severance and property taxation rates;

• the amount of AMT credit refunds realized;

• tariffs on products we use in our operations on products we sell;

• discount rates;

• regulatory approvals and compliance with contractual obligations;

• actions of, or inaction by federal, state, local or tribal governments, foreign countries and the Organization of Petroleum Exporting Countries;

• lack of, or disruptions in, adequate and reliable transportation for our production;

• competitive conditions;

• production and sales volumes;

• actions of operators on properties in which we own an interest but do not operate;

• estimates of oil and gas reserve quantities;

• reservoir performance;

• operating costs;

• inflation;

• capital costs;

• creditworthiness and performance of the Company's counterparties, including financial institutions, operating partners and other parties;

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• volatility in the securities, capital and credit markets;

• actions by credit rating agencies and their impact on the Company;

• changes in guidance issued related to tax reform legislation;

• actions of activist shareholders; and

• other factors, most of which are beyond the Company's control.

QEP undertakes no obligation to publicly correct or update the forward-looking statements in this Quarterly Report on

Form 10-Q, in other documents, or on the Company's website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(b) under the Securities Exchange Act of 1934, as amended), as of June 30, 2019. Based on such evaluation, such officers have concluded that, as of June 30, 2019, the Company's disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission's rules and forms and that information required to be disclosed in the Company's reports filed or submitted under the Exchange Act is accumulated and communicated to the Company's management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting (as defined by Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended June 30, 2019, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. Item 103 of the SEC's Regulation S-K requires disclosure of material pending legal proceedings, other than ordinary routine litigation incidental to the business, to which QEP or any of its subsidiaries is a party or of which any of their property is the subject. Item 103 also requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that the Company reasonably believes could exceed $100,000. The matter below is disclosed pursuant to that second requirement. Refer to Note 11 – Commitments and Contingencies in Item I of Part I of this Quarterly Report on Form 10-Q for additional information regarding our legal proceedings.

Environmental Protection Agency (EPA) Request for Information - As previously disclosed, in July 2015, QEP received an information request from the EPA pursuant to Section 114(a) of the Clean Air Act. The information request sought facts and data about certain tank batteries in QEP's Williston Basin operations. QEP timely responded to the information request, and has been in discussions with the EPA regarding this matter. In June, 2019, QEP and the EPA entered into a Consent Agreement under which QEP agreed to pay an immaterial monetary penalty and adopt an enhanced inspection, monitoring and repair program.

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ITEM 1A. RISK FACTORS

Risk factors relating to the Company are set forth in its 2018 Form 10-K. There have been no material changes to such risk factors since filing the 2018 Form 10-K, except for the risk factor below. The risks described below and in the 2018 Form 10‑K are not the only risks facing QEP. Additional risks and uncertainties not currently known to QEP or that the Company currently deems to be immaterial also may materially adversely affect its business, financial condition, or future results.

Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of QEP’s current or future debt obligations, including QEP’s revolving credit facility. Regulators and law enforcement agencies in the United Kingdom and elsewhere are conducting civil and criminal investigations into whether the banks that contributed to the British Bankers Association (BBA) in connection with the calculation of daily LIBOR may have been under-reporting or otherwise manipulating or attempting to manipulate LIBOR. A number of BBA member banks have entered into settlements with their regulators and law enforcement agencies with respect to this alleged manipulation of LIBOR. Actions by the BBA or any other administrator of LIBOR, regulators or law enforcement agencies may result in changes to the manner in which LIBOR is determined, the phasing out of LIBOR or the establishment of alternative reference rates. For example, in July 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. As a result, LIBOR may be discontinued by 2021. Furthermore, in the United States, efforts to identify a set of alternative U.S. dollar reference interest rates that could replace LIBOR include proposals by the Alternative Reference Rates Committee of the Federal Reserve Board and the Federal Reserve Bank of New York. At this time, it is not possible to predict whether any such changes will occur, whether LIBOR will be phased out or any such alternative reference rates or other reforms to LIBOR will be enacted in the United Kingdom, the United States or elsewhere or the effect that any such changes, phase out, alternative reference rates or other reforms, if they occur, would have on the amount of interest paid on, or the market value of, QEP’s current or future debt obligations, including QEP's revolving credit facility. Uncertainty as to the nature of such potential changes, phase out, alternative reference rates or other reforms may materially adversely affect the terms of QEP's revolving credit facility. Reform of, or the replacement or phasing out of, LIBOR and proposed regulation of LIBOR and other "benchmarks" may materially adversely affect the market value of, the applicable interest rate on and the amount of interest paid on QEP’s current or future debt obligations, including QEP's revolving credit facility.

Our business could be negatively affected as a result of actions of activist shareholders, and such activism could impact the strategic direction of QEP and the trading value of our securities. Elliott Management Corporation (Elliott), a beneficial holder of approximately 4.9% of our common stock (based on Elliott's Form 13F-HR filed on May 15, 2019), made a proposal to our Board on January 7, 2019, to acquire all shares of our common stock. As a result of that proposal, our Board of Directors engaged in a comprehensive review of strategic alternatives and concluded that the best alternative for QEP's shareholders was to move forward as an independent company. Activities of activist shareholders could adversely affect our business and/or operations because:

• responding to actions by activist shareholders could be costly and time-consuming, disrupting our operations and diverting the attention of our management and employees; and

• such activities could interfere with our ability to execute our strategic plan or realize short- or long-term value from our assets.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On February 28, 2018, QEP announced the authorization by its Board of Directors to repurchase up to $1.25 billion of the Company's outstanding shares of common stock (the February 2018 $1.25 billion Repurchase Program). The timing and amount of any QEP share repurchases will be subject to available liquidity and market conditions. The share repurchase program does not obligate QEP to acquire any specific number of shares and may be discontinued at any time.

During the three months ended June 30, 2019, no shares were repurchased under the previously announced plan. The following repurchases of QEP shares were made by QEP in association with vested restricted share awards withheld for taxes and pursuant to the Company's share repurchase authorization.

Period	Total shares purchased(1)	Weighted-average price paid per share		Total shares purchased as part of publicly announced plans or programs	Remaining dollar amount that may be purchased under the plans or programs
					(in millions)
April 1, 2019 - April 30, 2019	48,090	$	8.05	—	$	1,191.6
May 1, 2019 - May 31, 2019	11,248	$	7.44	—	$	1,191.6
June 1, 2019 - June 30, 2019	6,997	$	6.01	—	$	1,191.6
Total	66,335			—

 ____________________________

⁽¹⁾  During the three months ended June 30, 2019, QEP purchased 66,335 shares from employees in connection with the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Amended and Restated Executive Severance Compensation Plan - CIC

On August 5, 2019, the Compensation Committee of the Company’s Board of Directors approved an amendment and restatement, effective August 7, 2019, of the Company’s Executive Severance Compensation - CIC (CIC Plan), to, among other things, clarify the manner in which severance calculations will be made for certain executives. The CIC Plan provides severance compensation and other benefits to eligible executive officers upon a termination of their employment without cause or a resignation of their employment for good reason, in either case within three years following a change in control. Payments and benefits upon such a qualifying termination generally consist of a payment measured based on a multiple of annual base salary and average annual incentive awards (depending on seniority), a pro-rated annual incentive award payment for the year of termination, a payment in respect of certain enhanced retirement benefits and continued participation (without cost) in health and welfare benefit programs for either two or three years (depending on level of position). Payments are generally made in a lump sum shortly following termination (except the pro-rated annual incentive award payment is paid following the end of the year in which the termination occurs), subject to any legally required delay, and may be reduced in certain circumstances on account of Section 280G of the Internal Revenue Code (Code). No Code Section 280G gross ups are provided.

A copy of the CIC Plan is filed with this Form 10-Q and attached hereto as Exhibit 10.2 and incorporated by reference herein. The foregoing description of the CIC Plan is qualified in its entirety by reference to the full text of the CIC Plan.

Letter Agreement

On August 6, 2019, QEP entered into an agreement (Agreement) with Elliott Management Corporation, a Delaware corporation (Elliott).

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Under the terms of the Agreement, the Company agreed to issue a press release announcing, among other things, Elliott’s support of QEP and its strategy to move forward as an independent company.

The Agreement also provides that Elliott and the Company will cooperate with each other to select two individuals (New Directors) to be appointed to the Company’s board of directors (Board) as soon as reasonably practical, but in any event within 75 days of signing the Agreement. The New Directors will qualify as independent under the rules of the New York Stock Exchange, will have technical and operating oil and gas experience and will not be affiliated with Elliott. QEP also agreed to include the New Directors in the slate of directors to be proposed for election by the Board in QEP’s proxy statement (2020 Proxy Statement) for the 2020 annual meeting (2020 Annual Meeting). Elliott and the Company further agreed that, following the appointment of the New Directors, the Board will form a five-person Operations Committee comprised of the chief executive officer, the New Directors and two existing members of the Board. The purpose of the Operations Committee will be to identify best operating practices in the areas of the Company’s operations and to work with management to focus on continuous operational improvement and excellence.

The Agreement also provides that at the 2020 Annual Meeting, Elliott will, so long as the Company’s nominees for the Board include the New Directors, vote or cause to be voted any shares of common stock of the Company that it or certain of its affiliates have the right to vote, as of the record date, in favor of the election of directors nominated by the Company and in accordance with the recommendations of the Board on the other proposals in the Proxy Statement not related to an extraordinary transaction.

Elliott further agreed that, subject to certain exceptions, until the earlier of (i) June 30, 2020 and (ii) the second business day after the completion of the 2020 Annual Meeting, not to, among other things and subject to certain exceptions: (a) make any "solicitation" of proxies (as such terms are used in the proxy rules of the Securities and Exchange Commission), (b) form, join or act in concert with any "group" as defined in Section 13(d)(3) of the United States Securities Exchange Act of 1934 (the Exchange Act), other than solely with affiliates of Elliott with respect to voting securities now or hereafter held by them, (c) acquire, offer or seek to acquire any voting securities of the Company that would result in Elliott having a net long position of, or voting rights with respect to, more than 9.9% of the voting securities of the Company, (d) effect or seek to effect, whether alone or in concert with others, any extraordinary transaction involving the Company, (e) enter into any voting trust or similar arrangement, (f) seek to (i) elect or appoint to, or have representation on, the Board or (ii) remove any member of the Board, (g) make or be the proponent of any shareholder proposal (pursuant to Rule 14a-8 under the Exchange Act or otherwise) or (h) enter into any discussions, negotiations, agreements or understandings with any third party with respect to the foregoing.

A copy of the Agreement is filed with this Form 10-Q and attached hereto as Exhibit 10.3 and incorporated by reference herein. The foregoing description of the Agreement is qualified in its entirety by reference to the full text of the Agreement.

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ITEM 6. EXHIBITS

The following exhibits are being filed as part of this report:

Exhibit No.	Description of Exhibit
3.1	Amended and Restated Certificate of Incorporation dated May 15, 2018 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 17, 2018).
3.2	Amended and Restated Bylaws, as amended and restated on May 14, 2019 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 17, 2019).
10.1*+	Form of Deferred Share Award Agreement for shares of common stock granted to non-employee directors under the 2018 Long-Term Incentive Plan and for deferral of receipt of such shares in accordance with the terms of the Director Deferred Compensation Plan.
10.2*+	Executive Severance Compensation Plan – CIC, as Amended and Restated Effective as of August 7, 2019.
10.3*	Letter Agreement, dated August 6, 2019, by and between QEP Resources, Inc. and Elliott Management Corporation.
31.1*	Certification signed by Timothy J. Cutt, QEP Resources, Inc.'s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification signed by Richard J. Doleshek, QEP Resources, Inc.'s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification signed by Timothy J. Cutt and Richard J. Doleshek, QEP Resources, Inc.'s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*	XBRL Schema Document.
101.CAL*	XBRL Calculation Linkbase Document.
101.LAB*	XBRL Label Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.
101.DEF*	XBRL Definition Linkbase Document.

____________________________

+ Indicates a management contract or compensatory plan or arrangement.

* Filed herewith.

** Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	QEP RESOURCES, INC.
	(Registrant)
August 7, 2019	/s/ Timothy J. Cutt
	Timothy J. Cutt,
	President and Chief Executive Officer
August 7, 2019	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

58

EX-10.1

QEP RESOURCES, INC.

2018 LONG-TERM INCENTIVE PLAN

DEFERRED SHARE AWARD AGREEMENT

THIS DEFERRED SHARE AWARD AGREEMENT (the “Agreement”) is made as of _______________________ (the “Effective Date”), between QEP Resources, Inc., a Delaware corporation (the “Company”), and ________________ (“Grantee”). Terms not defined herein shall have the meanings ascribed to them in the QEP Resources, Inc. 2018 Long-Term Incentive Plan, as it may be amended from time to time (the “Plan”).

1.Grant of Deferred Shares. Subject to the terms and conditions of this Agreement, the Plan and the QEP Resources, Inc. Deferred Compensation Plan for Directors (the “Deferral Plan”), for good and valuable consideration, on the Effective Date, the Company hereby grants to Grantee the right to receive ________ shares of the Company’s Common Stock, $.01 par value (the “Deferred Shares”). The Grantee has previously elected to defer receipt of the Deferred Shares in accordance with the terms of the Deferral Plan. For the avoidance of doubt, the Deferred Shares shall constitute “Phantom Stock” pursuant to the terms of the Deferral Plan and shall become a part of the Grantee’s Equity Compensation Sub-Account pursuant to Section 5.3 of the Deferral Plan This Agreement is intended to constitute a “Phantom Stock Agreement” for purposes of the Deferral Plan.

2.    Vesting; Lapse of Restrictions. Except as provided otherwise in this Agreement, the Deferred Shares shall vest and become non-forfeitable, subject to the terms of the Deferral Plan, on March 5 of the year following the date of grant. If the Vesting Date falls on a day when the New York Stock Exchange (NYSE) is closed, the Vesting Date will occur on the next day that the NYSE is open. In the event that the Vesting Date falls on a day when trading in the Common Stock has been suspended, the Vesting Date will occur on the next full day after trading resumes.

3.     Payment. Except as otherwise provided herein or under the Deferral Plan, all amounts attributable to vested Deferred Shares shall be paid or distributed to the Grantee in accordance with the terms of the deferral election previously made by the Grantee with respect to the Deferred Shares under the Deferral Plan, and otherwise in accordance with the terms of the Deferral Plan.

4.Termination of Service; Forfeiture of Deferred Shares.

(a) Death, Disability, Retirement or Failure to be Renominated. If Grantee

ceases to be a member of the Board on account of death, Disability, mandatory retirement at age 75, or failure to be renominated for any reason (including at Grantee’s or the Company’s request) other than failure to adequately perform his or her duties as a member of the Board, the Deferred Shares, to the extent not yet vested, shall vest in full and shall become non-forfeitable, subject to the terms of the Deferral Plan.

(b) Other Terminations. Except as provided in Section 4(a) above or in

Section 5 below, if Grantee’s directorship with the Company terminates for any reason, Grantee shall forfeit all Deferred Shares (and any earnings and dividends attributable thereto) that are

1

not yet vested at the time of such termination in accordance with Section 5.3(a)(ii) of the Deferral Plan.

5.Change in Control. Upon a Change in Control, the Deferred Shares shall become 100% vested and all amounts attributable to the Deferred Shares shall be paid or distributed to the Grantee in accordance with Section 6.2 of the Deferral Plan.

6.No Transfer. The Deferred Shares are subject to Section 11.3 of the Deferral Plan and may not be anticipated, assigned (either at law or in equity), alienated, or be subject to attachment, garnishment, levy, execution or other legal or equitable process, except as otherwise permitted under the Deferral Plan.

7.    No Rights as a Stockholder. Unless and until any actual shares of Common Stock are distributed to the Grantee pursuant to the terms of this Agreement and the Deferral Plan, the Grantee shall have no voting or other rights as a stockholder of the Company with respect to the Deferred Shares.

8.Adjustments.

(a) Adjustment by Merger, Stock Split, Stock Dividend, Etc. Subject to the terms of the Deferral Plan, if the Common Stock, as presently constituted, shall be changed into or exchanged for a different number or kind of shares of stock or other securities of the Company or of another corporation (whether by reason of merger, consolidation, recapitalization, reclassification, stock split, spinoff, combination of shares or otherwise), or if the number of such shares of stock shall be increased through the payment of a stock dividend, then there shall be substituted for or added to each Deferred Share, the number and kind of shares of stock or other securities into which each outstanding share of Common Stock shall be so changed or for which each such share shall be exchanged or to which each such share shall be entitled, as the case may be.

(b) Other Distributions and Changes in the Stock. Subject to the terms of the Deferral Plan, in the event there shall be any other change affecting the number or kind of the outstanding shares of the Common Stock, or any stock or other securities into which the stock shall have been changed or for which it shall have been exchanged, then if the Committee shall, in its sole discretion, determine that the change equitably requires an adjustment in the Deferred Shares, an adjustment shall be made in accordance with such determination.

(c) General Adjustment Rules. All adjustments relating to stock or securities of the Company shall be made by the Committee, whose determination in that respect shall be final, binding and conclusive. Fractional shares resulting from any adjustment to the Deferred Shares pursuant to this Section 8 may be settled as the Committee shall determine, subject to the terms of the Deferral Plan. Notice of any adjustment shall be given to Grantee.

(d) Reservation of Rights. The issuance of Deferred Shares shall not affect in any way the right or power of the Company to make adjustments, reclassifications, reorganizations or changes of its capital or business structure, to merge, to consolidate, to dissolve, to liquidate or to sell or transfer all or any part of its business or assets.

2

9.Notices. Any notice required or permitted to be given under this Agreement shall be in writing and shall be given by hand delivery or by first class registered or certified mail, postage prepaid, addressed, if to the Company, to its Corporate Secretary, and if to Grantee, to his or her address now on file with the Company, or to such other address as either may designate in writing. Any notice shall be deemed to be duly given as of the date delivered in the case of personal delivery, or as of the second day after enclosed in a properly sealed envelope and deposited, postage prepaid, in a United States post office, in the case of mailed notice.

10. Amendment. Except as provided herein, this Agreement may not be amended or otherwise modified unless evidenced in writing and signed by the Company and Grantee, and as approved by the Committee. Notwithstanding any provision in this Agreement to the contrary, including Section 11, an amendment to the Plan that would materially and adversely affect Grantee’s rights with respect to the award of Deferred Shares granted hereunder will not be effective with respect to such award.

11.Relationship to Plan and Deferral Plan. This Agreement shall not alter the terms of the Plan or the Deferral Plan. If there is a conflict between the terms of the Plan or the Deferral Plan and the terms of this Agreement, the terms of the Plan or the Deferral Plan, as applicable, shall prevail.

12.Construction; Severability. The section headings contained herein are for reference purposes only and shall not in any way affect the meaning or interpretation of this Agreement. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, and each other provision of this Agreement shall be severable and enforceable to the extent permitted by law.

13.Waiver. Any provision contained in this Agreement may be waived, either generally or in any particular instance, by the Committee appointed under the Plan, but only to the extent permitted under the Plan and the Deferral Plan.

14.Entire Agreement; Binding Effect. Once accepted, this Agreement, the terms and conditions of the Plan, and the award of Deferred Shares set forth herein, constitute the entire agreement between Grantee and the Company governing such award of Deferred Shares, and shall be binding upon and inure to the benefit of the Company and to Grantee and to the Company’s and Grantee’s respective heirs, executors, administrators, legal representatives, successors and assigns.

15.No Rights to Continued Service as a Director. Nothing contained in this Agreement shall be construed as giving Grantee any right to be retained as a member of the Board and this Agreement is limited solely to governing the rights and obligations of Grantee with respect to the Deferred Shares.

16.Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, without regard to the choice of law principles thereof.

3

IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written.

GRANTEE QEP RESOURCES, INC.

[NAME]

by
	[NAME]
	[TITLE]

4

EX-10.2

QEP RESOURCES, INC.

EXECUTIVE SEVERANCE COMPENSATION PLAN – CIC

As Amended and Restated Effective as of August 7, 2019

ARTICLE I.

INTRODUCTION AND ESTABLISHMENT OF PLAN

The Board of Directors of QEP Resources, Inc. recognizes that, as is the case with many publicly held corporations, the possibility of a Change in Control exists. This possibility, and the uncertainty it creates with executives, may be detrimental to the Company and its shareholders if executives are distracted and/or leave the Company.

The Board considers the avoidance of such loss and distraction to be essential to protecting and enhancing the best interests of the Company and its shareholders. The Board also believes that when a Change in Control is perceived as imminent, or is occurring, the Board should be able to receive and rely on disinterested service from executive employees regarding the best interests of the Company and its shareholders without concern that the executive employees might be distracted or concerned by their personal uncertainties and risks created by the perception of an imminent or occurring Change in Control.

In addition, the Board believes that it is consistent with the Company’s employment practices and policies and in the best interests of the Company and its shareholders to compensate its executive employees whose employment terminates in connection with or following a Change in Control.

Accordingly, the Board has determined that appropriate steps should be taken to assure the Company and its Affiliates of the executive employees’ continued employment and attention and dedication to duty, and to seek to ensure the availability of their continued service, notwithstanding the possibility, threat or occurrence of a Change in Control.

In order to fulfill the above purposes, the Board hereby adopts this QEP Resources, Inc. Executive Severance Compensation Plan - CIC, as amended and restated (the “Plan”) effective as of August 7, 2019 (the “Effective Date”).

ARTICLE II.

DEFINITIONS

As used herein, the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.

(a)Affiliate. Any entity that is treated as the same employer as the Company under Sections 414(b), (c), (m), or (o) of the Code, any entity required to be aggregated with the Company pursuant to regulations adopted under Section 409A of the Code, or any entity otherwise designated as an Affiliate by the Company.

(b)Annual Cash Incentive Plan. Any annual incentive plan, program or arrangement offered by an Employer pursuant to which a Participant is eligible to receive a cash award, subject in whole or in part to the achievement of performance goals over a period of no more than one year, including without limitation the QEP Resources, Inc. Cash Incentive Plan.

(c)Annual Base Salary. A Participant’s gross annual base salary in effect immediately prior to a Change in Control.

(d)Average Annual Incentive Amount. The average of the annual incentive awards a Participant actually received under the Annual Cash Incentive Plans for the last three completed years for which awards under the Annual Cash Incentive Plans have been determined (or such lesser number of years as the Participant has been employed

by the Company and eligible to receive awards under the Annual Cash Incentive Plans), provided, however, that (i) if a Participant's award under the Annual Cash Incentive Plan for an applicable year was pro-rated based on a partial year of service, the annualized (i.e., non-prorated) amount of such award shall not be used in calculating the Average Annual Incentive Amount, and (ii) if a Participant has not previously received any award under the Annual Cash Incentive Plans, the "Average Annual Incentive Amount" shall be the Participant's target annual incentive award amount.

(e)Board. The Board of Directors of the Company.

(f)Cause. Cause means the Participant’s: (i) willful and continued failure to perform substantially the Participant’s duties with an Employer (other than any such failure resulting from incapacity due to physical or mental illness), following written demand for substantial performance delivered to the Participant by the Board or the Chief Executive Officer of the Company; or (ii) willful engagement in conduct that is materially injurious to an Employer. For purposes of this definition, no act or failure to act on the part of the Participant shall be considered “willful” unless it is done, or omitted to be done, by the Participant without reasonable belief that the Participant’s action or omission was in the best interests of the Participant’s Employer. The Company, acting through the Board, must notify the Participant in writing that the Participant’s employment is being terminated for “Cause”. The notice shall include a list of the factual findings used to sustain the judgment that the Participant’s employment is being terminated for “Cause”.

(g)Change in Control. A Change in Control of the Company shall be deemed to have occurred if (i) any individual, entity, or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934 (the “Exchange Act”)) other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, is or becomes the beneficial owner (as such term is used in Rule 13d-3 under the Exchange Act) of securities of the Company representing 30 percent or more of the combined voting power of the Company; or (ii) the following individuals cease for any reason to constitute a majority of the number of directors then serving: individuals who, as of the Effective Date, constitute the Company’s Board of Directors and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation, relating to the election of directors of the Company) whose appointment or election by the Board or nomination for election by the Company’s stockholders was approved or recommended by a vote of at least two-thirds of the directors then still in office who either were directors on the Effective Date, or whose appointment, election or nomination for election was previously so approved or recommended; or (iii) there is consummated a merger or consolidation of the Company or any direct or indirect subsidiary of the Company with any corporation, other than a merger or consolidation that would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least 60 percent of the combined voting power of the securities of the Company or such surviving entity or its parent outstanding immediately after such merger or consolidation, or a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no person is or becomes the beneficial owner, directly or indirectly, of securities of the Company representing 30 percent or more of the combined voting power of the Company’s then outstanding securities; or (iv) the Company’s stockholders approve a plan of complete liquidation or dissolution of the Company or there is consummated the sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition by the Company of all or substantially all of the Company’s assets to an entity, at least 60 percent of the combined voting power of the voting securities of which are owned by the stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale. In addition, if a Change in Control constitutes a payment event with respect to any payment under the Plan which provides for the deferral of compensation and is subject to Section 409A of the Code, the transaction or event described in clauses (i), (ii), (iii) and (iv) with respect to such payment must also constitute a “change in control event,” as defined in Treasury Regulation Section 1.409A-3(i)(5) before any such payment can be made.

(h)Code. The Internal Revenue Code of 1986, as amended from time to time.

(i)Company. QEP Resources, Inc. and any successor to such entity.

(j)Compensation. For purposes of the Plan, “Compensation” means (i) with respect to any Participant who participates in the Retirement Plan, such Participant’s remuneration taken into account for purposes of calculating the retirement benefit thereunder, and, (ii) with respect to any Participant who participates in the SERP, such Participant’s remuneration taken into account for purposes of calculating the retirement benefit thereunder.

(k)Date of Termination. The date on which a Participant ceases to be an Employee of an Employer as a result of a Separation from Service.

(l)Disability. A condition resulting in the Participant’s receipt of payments for disability under the QEP Resources, Inc. Long-term Disability Plan or any plan providing similar long-term disability benefits sponsored by the Company or an Affiliate.

(m)Eligible Employee. Any officer of any Employer.

(n)Employer. With respect to any Participant, the Company and any Affiliate that participates in the Plan pursuant to Article VIII hereof which employs the Participant.

(o)ERISA. The Employee Retirement Income Security Act of 1974, as amended from time to time.

(p)Good Reason. Good Reason means any of the following events or conditions that occur without the Participant’s written consent, and that remain in effect after notice has been provided by the Participant to the Company of such event or condition and the expiration of a 30 day cure period: (i) a material diminution in the Participant’s Annual Base Salary, target incentive opportunity under any Annual Cash Incentive Plan or long-term incentive award opportunity under any Long-Term Incentive Plan or Stock Incentive Plan; (ii) a material diminution in the Participant’s authority, duties, or responsibilities; (iii) a material diminution in the authority, duties, or responsibilities of the supervisor to whom the Participant is required to report, including a requirement that a Participant report to a corporate officer or employee instead of reporting directly to the Board; (iv) a material diminution in the budget over which the Participant retains authority; (v) a material change in the geographic location at which the Participant performs services; or (vi) any other action or inaction that constitutes a material breach by an Employer of the Participant’s employment agreement (if any). The Participant’s notification to the Company must be in writing and must occur within a reasonable period of time, not to exceed 90 days, following the initial existence of the relevant event or condition.

(q)Long-Term Incentive Plan. Any long-term incentive plan, program or arrangement offered by an Employer pursuant to which a Participant is eligible to receive an award, subject in whole or in part to the achievement of performance goals over a period of more than one year, including without limitation the QEP Resources, Inc. Cash Incentive Plan.

(r)Participant. An individual who is designated as such pursuant to Section 3.1.

(s)Performance Share Units. Performance share units granted under a Long-Term Incentive Plan which settle in cash and/or shares of the Company’s common stock, and any similar award granted under a Stock Incentive Plan which settles, or may settle, wholly or partially in shares of the Company’s common stock, in each case based on the achievement of performance goals over a period of more than one year.

(t)Plan Administrator. The Compensation Committee of the Board.

(u)Retirement Plan. The QEP Resources, Inc. Retirement Plan, as amended or restated from time to time, or any successor plan.

(v)Separation Benefits. The payments and benefits described in Article V that are provided to Participants under the Plan pursuant to Section 4.1.

(w)Separation from Service. A Participant’s termination or deemed termination from employment with the Employer. For purposes of determining whether a Separation from Service has occurred, the employment relationship is treated as continuing intact while the Participant is on military leave, sick leave or other bona fide leave of absence if the period of such leave does not exceed six months, or if longer, so long as the Participant retains a right to reemployment with his Employer under an applicable statute or by contract. For this purpose, a leave of absence constitutes a bona fide leave of absence only if there is a reasonable expectation that the Participant will return to perform services for the Employer. If the period of leave exceeds six months and the Participant does not retain a right to reemployment under an applicable statute or by contract, the employment relationship will be deemed to terminate on the first date immediately following such six-month period. For purposes of the Plan, a Separation from Service occurs at the date as of which the facts and circumstances indicate either that, after such date: (i) the Participant and Employer reasonably anticipate the Participant will perform no further services for the Company or an Affiliate (whether as an employee or an independent contractor), or (ii) that the level of bona fide services the Participant will perform for the Company or any Affiliate (whether as an employee or independent contractor) will permanently decrease to no more than 20 percent of the average level of bona fide services performed over the immediately preceding 36-month period or, if the Participant has been providing services to the Company or an Affiliate for less than 36 months, the full period over which the Participant has rendered services, whether as an employee or independent contractor. The determination of whether a Separation from Service has occurred shall be governed by the provisions of Treasury Regulation Section 1.409A-1, as amended, taking into account the objective facts and circumstances with respect to the level of bona fide services performed by the Participant after a certain date.

(x)SERP. The QEP Resources, Inc. Supplemental Executive Retirement Plan, as amended or restated from time to time, or any successor plan.

(y)Stock Incentive Plan. Any incentive plan offered by the Company pursuant to which upon or following vesting or exercise, as applicable, a Participant is entitled to receive shares of the Company’s common stock, including without limitation the QEP Resources, Inc. 2010 Long-Term Stock Incentive Plan and the QEP Resources, Inc. 2018 Long-Term Incentive Plan.

(z)Tier 1 Participant. A Participant who is the Chief Executive Officer or any other person so designated by the Board.

(aa)Tier 2 Participant. Each Participant who is not a Tier 1 Participant.

(bb)    Year. The calendar year or other applicable performance period under any Annual Cash Incentive Plan.

ARTICLE III.

ELIGIBILITY

3.1    Participation. The Board shall, in its sole discretion, select from the group of Eligible Employees those individuals who may participate in the Plan. Any Eligible Employee selected for participation shall become a Participant upon written notification by the Board (or its designee) to such Eligible Employee of his or her participation in the Plan.

3.2    Termination of Participation. Prior to the time that the Board knows or should know that a Change in Control is under consideration, is being negotiated or is otherwise contemplated, a Participant shall continue to participate in the Plan at the sole discretion of the Board, which may terminate the individual’s participation in the Plan for any reason. In the event that a Participant ceases to be an Eligible Employee (other than by virtue of an action by the Employer which constitutes Good Reason) and is not entitled to a Separation Benefit as of the date

such Participant ceases to be an Eligible Employee (including by virtue thereof), such Participant shall cease to be a Participant in the Plan on such date. Notwithstanding anything to the contrary in the Plan, a Participant entitled to Separation Benefits under the Plan shall remain a Participant in the Plan until the full Separation Benefits and any other amounts payable under the Plan have been paid or provided.

ARTICLE IV.

ENTITLEMENT TO BENEFITS

4.1    Separations from Service That Give Rise to Separation Benefits Under The Plan. A Participant shall be entitled to Separation Benefits if, upon a Change in Control or within the three years thereafter, the Participant incurs a Separation from Service from an Employer that is (a) initiated by the Participant’s Employer for any reason other than Cause or Disability (it being understood that in the event of a termination due to Disability, the Participant shall continue to have any all rights that may be available under any applicable equity or incentive plan document or any award agreement thereunder or any other agreement with the Company or any of its affiliates) or (b) initiated by the Participant for Good Reason within 60 days following the expiration of the cure period afforded the Company to rectify the condition giving rise to Good Reason.

4.2    Non-Competition and Other Restrictive Covenants. The Company may seek to condition some or all of the Separation Benefits of any Participant on the execution of a non-competition, non-solicitation and/or other restrictive covenant agreement to be entered into between the Company and the Participant prior to or contemporaneously with the transaction or event resulting in a Change in Control.

ARTICLE V.

SEPARATION BENEFITS

5.1    Separation Benefits; General. If a Participant’s employment is terminated in circumstances entitling the participant to Separation Benefits pursuant to Section 4.1, the Company shall provide to such Participant the cash payment set forth in Section 5.2 below, the bonus set forth in Section 5.3 below, the enhanced retirement benefits set forth in Section 5.4 below and the continued welfare benefits as set forth in Section 5.5 below.

5.2    Cash Severance. Each Participant entitled to Separation Benefits shall receive cash severance equal to the aggregate of the following amounts:

(a)    For a Tier 1 Participant, an amount equal to three times the Participant’s Annual Base Salary plus three-times the Participant’s Average Annual Incentive Amount; and

(b)    For a Tier 2 Participant, an amount equal to two times the Participant’s Annual Base Salary plus two-times the Participant’s Average Annual Incentive Amount.

All cash payments required by this Section 5.2 shall be paid within 10 calendar days of the Participant’s Date of Termination; subject, however, to any payment delay required by Section 5.7(b).

5.3    Incentive Amount. Each Participant entitled to Separation Benefits shall receive the incentive the Participant would have received in respect of the Year in which the Change in Control occurs (or, if applicable, a subsequent Year in which the Date of Termination occurs) under the applicable Annual Cash Incentive Plan had the Change in Control not occurred, based on the level of satisfaction of the performance goals that is achieved for such Year without application of any discretion to reduce the earned amount of the incentive (provided, that to the extent such incentive (or any portion thereof) is not based on non-discretionary and measurable performance goals (or such goals have not yet been established as of the date of the Change in Control) or any such performance goals are not susceptible of being measured after the occurrence of the Change in Control, then the incentive or applicable portion thereof shall be deemed earned at the target level), multiplied by (A) the number of full months of Participant’s continuous service with the Employer during such Year (with each month for which at least one day has elapsed counting as a full month), divided by (B) the number of full months in such Year. In addition, if the Date of Termination

occurs after the end of a Year but before the Participant’s incentive under the applicable Annual Cash Incentive Plan in respect of such Year has been paid, the Participant shall be eligible to receive such incentive, without proration or application of discretion to reduce the amount of such incentive.

The payment required by the first sentence of this Section 5.3 shall be paid in a lump sum within 60 days following the end of the year in which the Date of Termination occurs; subject, however, to any payment delay required by Section 5.7(b).

5.4    Enhanced Retirement Benefits. Each Participant entitled to Separation Benefits shall receive an enhanced retirement benefit under the Retirement Plan and/or the SERP, to the extent that the Participant is a participant in such plan(s) as of the Date of Termination, as follows:

(a)    Vested Participants. Participants who have an accrued vested benefit under either the Retirement Plan or both the Retirement Plan and the SERP as of the Date of Termination shall be entitled to an enhanced retirement benefit under the Plan in an amount equal to the excess of (i) the benefit the Participant would have accrued under the Retirement Plan and the SERP (if participating) as of the Date of Termination calculated as if (A) the Participant had been credited with two additional years of benefit service under the Retirement Plan and the SERP (if participating) as of the Date of Termination, and (B) the Participant’s Compensation under the Retirement Plan and the SERP (if participating) for each additional year of such service had been equal to the Participant’s Compensation for the last full Year prior to the Date of Termination, over (ii) the actual benefit accrued under the Retirement Plan and the SERP (if participating) as of the Date of Termination.

(b)    Payment of Enhanced Retirement Benefits. Any enhanced retirement benefit to which a Participant may be entitled under paragraph (a) above shall be paid in a single lump sum within 30 calendar days of the Date of Termination; subject, however, to any payment delay required by Section 5.7(b). The lump-sum payment shall be equal to (i) the present value of the applicable enhanced retirement benefit on the Date of Termination, calculated using the applicable mortality tables then being used by the Company for financial reporting purposes and an interest rate equal to 80 percent of the average of the IRS 30-year Treasury Securities Rates for the six-month period preceding the participant’s Date of Termination, plus (ii) interest on such amount, credited monthly from the Date of Termination through the date of payment (taking into account any delay required by Section 5.7(b)), using the appropriate 30-year Treasury bond rate quoted in the Wall Street Journal on the first business day of each month. The appropriate 30-year Treasury bond shall be the bond that has the closest maturity date (by month) preceding the month in which interest is to be credited.

(c)    Ineligible to Participate in Retirement Plan. In no event shall a Participant be entitled to any benefit under this Section 5.4 if he or she is not a participant in the Retirement Plan and/or the SERP as of the Date of Termination.

5.5    Continued Welfare Benefits. For a period of three years in the case of a Tier 1 Participant, and two years in the case of a Tier 2 Participant, following the Participant’s Date of Termination, the Participant and his or her family shall be provided without cost medical, dental, vision, accidental death and dismemberment, and life insurance benefits that are the same as, or substantially similar to, the benefits that would have been provided by the Company, an Affiliate or any successor during such period had the Participant’s employment not been terminated. Some or all of the benefits required by this Section may be provided through the payment or reimbursement of premiums incurred for similar coverage procured by the Company, an Affiliate or any successor on the Participant’s behalf or by the Participant, through the payment of COBRA premiums, or pursuant to the terms and conditions of the Company’s retiree health insurance program, if applicable, in each case as determined by the Company in its sole discretion and subject to Sections 5.7 and 11.8 below.

5.6    Other Benefits Payable. To the extent not theretofore paid or provided, the Company shall timely pay or provide (or cause to be paid or provided) to a Participant entitled to Separation Benefits, any other amounts or benefits required to be paid or provided to the Participant or which the Participant is eligible to receive under any plan, program, policy or practice or contract or agreement of an Employer. Notwithstanding the foregoing, if a

Participant is entitled to Separation Benefits under the Plan, the Participant shall not also be entitled to severance benefits under any employment agreement or other severance pay plan or policy of the Company. Thus, by way of example and not by way of limitation, benefits earned under the Retirement Plan, the SERP, and the QEP Resources, Inc. Deferred Compensation Wrap Plan, in each case as amended from time to time, or any successor plans, shall be unaffected by a Participant’s receipt of Separation Benefits, and shall continue to be payable solely in accordance with the relevant terms of those plans, but any severance benefits to which a Participant otherwise may be entitled under an employment agreement or severance plan, if any, shall not apply if the Participant is entitled to receive Separation Benefits under the Plan.

5.7    Code Section 409A; Specified Employees.

(a)    Subject to Section 5.7(b), to the extent permitted under Code Section 409A, any separate payment or benefit under the Plan or otherwise shall not be deemed “nonqualified deferred compensation” subject to Code Section 409A, to the extent provided in the exceptions in Treasury Regulation Section 1.409A-1(b)(4), Section 1.409A-1(b)(9) or any other applicable exception or provision of Code Section 409A.

(b)    Notwithstanding anything to the contrary in the Plan, no compensation or benefits shall be paid to a Participant during the six-month period following his or her Date of Termination to the extent that the Company determines that the Participant is a “specified employee” as of the Date of Termination and that paying such amounts at the time or times indicated in the Plan would result in tax penalties to the Participant under Code Section 409A. If the payment of any such amounts is delayed as a result of the previous sentence, then on the first business day following the end of such six-month period (or such earlier date upon which such amount can be paid under Code Section 409A without being subject to tax penalties, including as a result of the Participant’s death), the Company shall pay to the Participant a lump- sum amount equal to the cumulative amount that would have otherwise been payable to the Participant during such six-month period.

(c)    To the extent that Section 5.5 requires the Company, partially or wholly, to subsidize any continuation of health insurance benefits following the Participant’s Date of Termination:

(i)If such continued health insurance benefits are to be provided through third-party insurance maintained by the Company under the Company’s benefit plans in a manner that causes such health insurance benefits to be exempt from the application of Code Section 409A under Treasury Regulation Section 1.409A-1(a)(5), the Company shall pay or reimburse such premiums in accordance with the terms of the Plan, subject to Section 5.7(d); provided, however, that if, during the period of health insurance benefits continuation coverage (the “Health Benefits Continuation Period”), any plan pursuant to which such health insurance benefits are provided is not, or ceases prior to the expiration of the Health Benefits Continuation Period to be, exempt from the application of Code Section 409A under Treasury Regulation Section 1.409A-1(a)(5), then an amount equal to each remaining premium payments shall thereafter be paid to the Participant as currently taxable compensation in substantially equal monthly installments over the remainder of the Health Benefits Continuation Period, accompanied by any additional amounts necessary to offset the taxable nature of such benefit to the extent such amounts are either exempt from or compliant with the requirements of Code Section 409A; or

(ii)If such continued health insurance benefits are to be provided in whole or in part through a self-funded plan maintained by the Company, the benefits of which are not fully-insured by a third-party insurer:

(A)To the greatest extent applicable, such health insurance benefits shall be construed to satisfy the exemption from Code Section 409A pursuant to Treasury Regulation Section 1.409A-1(b)(9)(v)(B), and

(B)To the extent such health insurance benefits do not satisfy such exemption and/or they do extend beyond the continuation period under COBRA, determined as of the Participant’s Date of Termination, the Company shall reimburse the premiums relating to such health insurance benefits in accordance with Section 5.7(d).

(d)    To the extent that any payments or reimbursements provided to the Participant under the Plan are deemed to constitute compensation to the Participant, such amounts shall be paid or reimbursed reasonably promptly, but not later than December 31 of the year following the year in which the associated expense was incurred. The amount of any expense reimbursements that constitute compensation in one year shall not affect the amount of expense reimbursements constituting compensation that are eligible for reimbursement in any subsequent year, and the Participant’s right to such reimbursement of any such expenses shall not be subject to liquidation or exchange for any other benefit.

ARTICLE VI.

EQUITY INCENTIVE BENEFITS

The treatment of all of a Participant’s stock options, stock appreciation rights, restricted stock awards, restricted stock units, and other equity incentive awards (including any Performance Share Units and deferred shares) granted pursuant to a Stock Incentive Plan or Long-Term Incentive Plan shall be governed by the applicable Stock Incentive Plan or Long-Term Incentive Plan documents and any award agreement between a Participant and the Company evidencing the grant of such equity incentive award.

ARTICLE VII.

SPECIAL TAX PROVISIONS

7.1    Participant Choice. Except as set forth below, in the event it shall be determined that any payment or distribution by an Employer to or for the benefit of a Participant pursuant to the terms of the Plan (a “ Payment”) would be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties would be incurred by the Participant with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the “Excise Tax”), then the Participant shall be entitled to elect either to (a) receive the full amount of the Payment and be solely responsible for the payment of any Excise Tax due on such payment, or (b) have the payments, distributions or benefits owing to the Participant under the Plan “capped” or limited to the maximum dollar amount that can be paid from the Plan without the Participant’s incurring Excise Tax (the “Capped Amount”).

7.2    Determination of Capped Amount. Subject to the provisions of Section 7.3, all determinations required to be made under this Article VII, including computation of the Capped Amount, and the assumptions to be utilized in arriving at such determination, shall be made by a nationally recognized certified public accounting firm or other third party expert designated by the Company (the “Accounting Firm”) which shall provide detailed supporting calculations both to the Company and the Participant within 15 business days after the receipt of notice from the Participant that amounts payable to the Participant could constitute a Payment, or such earlier time as is requested by the Company. In the event that the Accounting Firm is serving as accountant or auditor for the individual, entity or group effecting the Change in Control, the Company shall appoint another nationally recognized accounting firm or other third party expert to make the determinations required hereunder (which firm shall then be referred to as the Accounting Firm hereunder). All fees and expenses of the Accounting Firm shall be borne solely by the Company. Subject to the provisions of Section 7.3 hereof, any determination by the Accounting Firm shall be binding upon the Company and the Participant.

7.3    Overpayment/Underpayment. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the determination by the Accounting Firm pursuant to Section 7.2, it is possible that amounts will have been paid or distributed by the Company to or for the benefit of the Participant pursuant to Section 7.2 that should not have been so paid or distributed (each, an “Overpayment”) or that additional amounts which will have not been paid or distributed by the Company to or for the benefit of the Participant pursuant to Section 7.2 could have been so paid or distributed (each, an “Underpayment”), in each case, consistent with the calculation of the Capped Amount pursuant to Section 7.2. In the event that the Accounting Firm, based upon the assertion of a deficiency by the Internal Revenue Service against either the Company or the Participant which the Accounting Firm believes has a high probability of success determines that an Overpayment has been made, any such Overpayment paid or

distributed by the Company to or for the benefit of the Participant shall be repaid by the Participant to the Company together with interest at the applicable federal rate provided for in Section 7872(f)(2) of the Code; provided, however, that no such repayment shall be required if and to the extent such deemed repayment would not either reduce the amount on which the Participant is subject to tax under Section 1 and Section 4999 of the Code or generate a refund of such taxes. In the event that the Accounting Firm, based upon controlling precedent or substantial authority, determines that an Underpayment has occurred, any such Underpayment shall be promptly paid by the Company to or for the benefit of the Participant together with interest at the applicable federal rate provided for in Section 7872(f)(2) of the Code.

7.4    Tax Proceedings. In the event that (i) the Participant elects to receive the Capped Amount pursuant to Section 7.1 and/or otherwise timely files all of the Participant’s tax returns (and timely pays all applicable taxes pursuant to such returns) in a manner consistent with the determinations of the Accounting Firm, and (ii) a deficiency is later asserted by the Internal Revenue Service due to an alleged Overpayment or otherwise in relation to the application of Section 4999 of the Code, the Company shall indemnify and hold the Participant harmless for any costs, expenses, interest, penalties, taxes, attorneys’ fees or other amounts (the “Indemnified Amounts”) incurred or imposed in connection with any tax contest, audit or litigation of such deficiency; provided, however, that in no event shall the Indemnified Amounts include any portion of the Capped Amount itself or any Excise Tax thereon. Any Indemnified Amounts will be paid directly by the Company or advanced to the Participant by the end of the Participant’s taxable year following the taxable year in which the taxes that are the subject of the tax contest, audit or litigation are remitted to the taxing authority, or where as a result of such tax contest, audit or litigation no taxes are remitted, the end of the Participant’s taxable year following the taxable year in which the audit is completed or there is a final and non-appealable settlement or other resolution of the contest or litigation.

7.5    Withholding. All payments to the Participant in accordance with the provisions of the Plan shall be subject to applicable withholding of local, state, Federal and foreign taxes, as determined in the sole discretion of the Company.

ARTICLE VIII.

PARTICIPATING EMPLOYERS

Any Affiliate of the Company may become a participating Employer in the Plan following approval by the Company. The provisions of the Plan shall be fully applicable to the Employees of any such Affiliate who are Participants pursuant to Section 3.1.

ARTICLE IX.

SUCCESSOR TO COMPANY

The Plan shall bind any successor of the Company, its assets or its businesses (whether direct or indirect, by purchase, merger, consolidation, separation or otherwise), in the same manner and to the same extent that the Company would be obligated under the Plan if no succession had taken place.

In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by the Plan, the Company shall require such successor expressly and unconditionally to assume and agree to perform the Company’s obligations under the Plan, in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place. In the event of a Change in Control in which the successor fails to expressly and unconditionally assume and agree to perform the Company’s obligations under the Plan, each Participant in the Plan immediately prior to such Change in Control shall be deemed to have incurred a qualifying Separation from Service under Section 4.1 and shall be entitled to payment of the cash equivalent of all Separation Benefits set forth in Article V as if the day prior to the date of such Change in Control were the Participant’s Date of Termination, in the form of a single lump sum within 60 days following the Change in Control.

The term “Company,” as used in the Plan, shall mean the Company as hereinbefore defined and any successor or assignee to the business or assets which by reason hereof becomes bound by the Plan.

ARTICLE .

DURATION, AMENDMENT AND TERMINATION

10.1    Duration. If a Change in Control has not occurred, the Plan shall continue indefinitely unless and until terminated by the Board pursuant to Section 10.2, below. If a Change in Control occurs while the Plan is in effect, the Plan shall continue in full force and effect for three years following such Change in Control, and shall then automatically terminate; provided, however, that all Participants who become entitled to Separation Benefits hereunder prior to termination of the Plan shall continue to receive such Separation Benefits notwithstanding any termination of the Plan.

10.2    Amendment or Termination. The Board may amend or terminate the Plan for any reason prior to a Change in Control except that the Plan shall not be terminated or amended to reduce any benefits provided under the Plan at a time when the Board knows or should know that a Change in Control is under consideration, is being negotiated or is otherwise contemplated. In the event of a Change in Control, the Plan shall automatically terminate as set forth in Section 10.1 but may not be amended or prematurely terminated.

10.3    Procedure for Extension, Amendment or Termination. Any amendment or termination of the Plan by the Board in accordance with the foregoing shall be made by action of the Board in accordance with the Company’s charter and by-laws and applicable law.

ARTICLE XI.

MISCELLANEOUS

11.1    Full Settlement. The Company’s obligation to make the payments provided for under the Plan and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against a Participant or others outside of the Plan. In no event shall a Participant be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to the Participant under any of the provisions of the Plan and such amounts shall not be reduced whether or not the Participant obtains other employment.

11.2    Employment Status. This Plan does not constitute a contract of employment or impose on the Participant or the Participant’s Employer any obligation for the Participant to remain an Employee or change the status of the Participant’s employment or the policies of the Participant’s Employer regarding termination of employment.

11.3    Confidential Information. No Participant shall disclose or divulge to any other person or entity, directly or indirectly, any secret or confidential information, knowledge or data relating to the Company or its Affiliates, or their respective businesses, including but not limited to, (a) practices, policies and/or procedures; (b) trade secrets; (c) customer names; (d) information regarding existing or prospective future business, planning or development; (e) contracts or proposed contracts; (f) financial information; (g) staffing or personnel utilization; (h) salary or wage levels; (i) privileged communications; and (j) other information deemed confidential or proprietary not listed herein which shall have been obtained by the Participant during the Participant’s employment by the Participant’s Employer and which shall not be or become public knowledge (other than by acts by the Participant or representatives of the Participant in violation of the Plan) (the “Confidential Information”). During and after termination of a Participant’s employment with the Company or other Employer, the Participant shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any Confidential Information to anyone other than the Company or its Affiliates. Notwithstanding the foregoing, the use or communication of mental impressions of Confidential Information in a manner that does not directly or indirectly identify the Company and its Affiliates and would not be reasonably expected to materially adversely affect the business of the Company and its Affiliates shall not be a violation of this Section 11.3.

11.4    Applicability of ERISA. The Plan is not intended to be an “employee benefit plan,” as defined in Section 3(3) of ERISA, and therefore is intended to not be subject to ERISA. However, if (and only if) the Plan is

determined to be such an “employee benefit plan” and therefore subject to ERISA, (i) it is intended to be a plan which is unfunded and maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees, (ii) the Company shall be the named fiduciary of the Plan, and (iii) Section 11.6 of the Plan shall apply.

11.5    Administration. The Plan Administrator shall have full and complete discretionary authority to administer, construe, and interpret the Plan, to decide all questions of eligibility, to determine the amount, manner and time of payment, and to make all other determinations deemed necessary or advisable for the Plan. The Plan Administrator shall review and determine all claims for benefits under the Plan. Notwithstanding the foregoing, the Plan Administrator may delegate its authority and responsibilities under the Plan to any officer of the Company; provided that no officer to whom any such authority or responsibilities is delegated may make any determination under the Plan which affects his or her eligibility for Separation Benefits or the amount thereof.

11.6    Claim Procedure.

(a)    Filing a Claim. All claims and inquiries concerning benefits under the Plan must be submitted to the Plan Administrator in writing. The claimant may submit written comments, documents, records or any other information relating to the claim. Furthermore, the claimant shall be provided, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claim for benefits. If an Employee or former Employee makes a written request alleging a right to receive benefits under the Plan or alleging a right to receive an adjustment in benefits being paid under the Plan, the Company shall treat it as a claim for benefits.

(b)    Review of Claims; Claims Denial. The Plan Administrator shall initially deny or approve all claims for benefits under the Plan. If any claim for benefits is denied in whole or in part, the Plan Administrator shall notify the claimant in writing of such denial and shall advise the claimant of his right to a review thereof. Such written notice shall set forth, in a manner calculated to be understood by the claimant, specific reasons for such denial, specific references to the Plan provisions on which such denial is based, a description of any information or material necessary for the claimant to perfect his claim, an explanation of why such material is necessary and an explanation of the Plan’s review procedure, and the time limits applicable to such procedures. Furthermore, the notification shall include a statement of the claimant’s right to bring a civil action under Section 502(a) of ERISA following an adverse benefit determination on review. Such written notice shall be given to the claimant within a reasonable period of time, which normally shall not exceed 90 days, after the claim is received by the Plan Administrator.

(c)    Appeals. Any claimant or his duly authorized representative, whose claim for benefits is denied in whole or in part, may appeal such denial by submitting to the Plan Administrator a request for a review of the claim within 60 days after receiving written notice of such denial from the Plan Administrator. The Plan Administrator shall give the claimant upon request, and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claim of the claimant, in preparing his request for review. The request for review must be in writing. The request for review shall set forth all of the grounds upon which it is based, all facts in support thereof, and any other matters which the claimant deems pertinent. The Plan Administrator may require the claimant to submit such additional facts, documents, or other materials as the Plan Administrator may deem necessary or appropriate in making its review.

(d)    Review of Appeals. The Plan Administrator shall act upon each request for review within 60 days after receipt thereof. The review on appeal shall consider all comments, documents, records and other information submitted by the claimant relating to the claim without regard to whether this information was submitted or considered in the initial benefit determination.

(e)    Decision on Appeals. The Plan Administrator shall give written notice of its decision to the claimant. If the Plan Administrator confirms the denial of the application for benefits in whole or in part, such notice shall set forth, in a manner calculated to be understood by the claimant, the specific reasons for such denial, and specific references to the Plan provisions on which the decision is based. The notice shall also contain a statement that the

claimant is entitled to receive upon request, and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claimant’s claim for benefits. Information is relevant to a claim if it was relied upon in making the benefit determination or was submitted, considered or generated in the course of making the benefit determination, whether it was relied upon or not. The notice shall also contain a statement of the claimant’s right to bring an action under ERISA Section 502(a). If the Plan Administrator has not rendered a decision on a request for review within 60 days after receipt of the request for review, the claimant’s claim shall be deemed to have been approved. The Plan Administrator’s decision shall be final and not subject to further review within the Company. There are no voluntary appeals procedures after appellate review by the Plan Administrator.

(f)    Determination of Time Periods. If the day on which any of the foregoing time periods is to end is a Saturday, Sunday or holiday recognized by the Company, the period shall extend until the next following business day.

11.7    Attorneys’ Fees. In the event of any legal proceeding brought by the Participant to enforce any of the Participant’s rights under the Plan, the Company shall be responsible to pay or reimburse the Participant for all reasonable attorney’s fees and costs incurred by the Participant in connection with such proceeding; provided, that the Participant prevails on at least one material claim in such proceeding. If fees and costs are required to be reimbursed under this provision, such reimbursement shall occur no later than March 15 of the calendar year next following the calendar year in which the obligation to reimburse such fees and costs was determined.

11.8    Unfunded Plan Status. All payments pursuant to the Plan shall be made from the general funds of the Company and no special or separate fund shall be established or other segregation of assets made to assure payment. No Participant or other person shall have under any circumstances any interest in any particular property or assets of the Company as a result of participating in the Plan. Notwithstanding the foregoing, the Company may (but shall not be obligated to) create one or more grantor trusts, the assets of which are subject to the claims of the Company’s creditors, to assist it in accumulating funds to pay its obligations under the Plan.

11.9    Code Section 409A Savings Clause. The payments and benefits provided hereunder are intended to be exempt from or compliant with the requirements of Code Section 409A. Notwithstanding any provision of the Plan to the contrary, in the event that the Company reasonably determines that any payments or benefits hereunder are not either exempt from or compliant with the requirements of Code Section 409A, the Company shall have the right to adopt such amendments to the Plan or adopt such other policies and procedures (including amendments, policies and procedures with retroactive effect), or take any other actions, that are necessary or appropriate (i) to preserve the intended tax treatment of the payments and benefits provided hereunder, to preserve the economic benefits with respect to such payments and benefits, and/or (ii) to exempt such payments and benefits from Code Section 409A or to comply with the requirements of Code Section 409A and thereby avoid the application of penalty taxes thereunder; provided, however, that this Section 11.9 does not, and shall not be construed so as to, create any obligation on the part of the Company to adopt any such amendments, policies or procedures or to take any other such actions or to indemnify any Participant for any failure to do so.

11.10    Validity and Severability. The invalidity or unenforceability of any provision of the Plan shall not affect the validity or enforceability of any other provision of the Plan, which shall remain in full force and effect, and any prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

11.11    Governing Law. The validity, interpretation, construction and performance of the Plan shall in all respects be governed by the laws of Colorado without reference to principles of conflict of law, except to the extent pre-empted by Federal law.

I hereby certify that this QEP Resources, Inc. Executive Severance Compensation Plan - CIC was duly adopted by the Board of Directors of QEP Resources, Inc. on August 5, 2019.

Executed on this 5th day of August, 2019.

By: /s/ Timothy J. Cutt

Name: Timothy J. Cutt

Title: President & CEO

EX-10.3

QEP RESOURCES, INC.

1050 17th Street

Denver, CO 80265

August 6, 2019

Elliott Management Corporation

40 West 57th Street

New York, NY 10019-4001

Attention: Andrew Taylor

Ladies and Gentlemen:

This letter (this “Agreement”) constitutes the agreement between Elliott Management Corporation (“Elliott”) and QEP Resources, Inc. (the “Company”). Each of Elliott and the Company is individually a “Party” and collectively they are the “Parties.” Capitalized terms used and not otherwise defined have the meanings ascribed to them in paragraph 6 of this Agreement.

1.    Promptly following the execution and delivery of this Agreement (but in any event no later than August 7, 2019), the Company shall issue a press release in the form attached to this Agreement as Exhibit A (the “Company Press Release”) and each Party shall not, and shall cause its Affiliates and its and their respective principals, directors, members, general partners, officers, employees and agents and representatives acting on their behalf not to, make any statement inconsistent with the Company Press Release in connection with the announcement of this Agreement. The Company Press Release shall include a statement by Elliott with respect to Elliott’s support of the Company and its ongoing strategy. Elliott shall not, and shall cause its other Restricted Persons (as defined below) not to, issue any press release in connection with the execution of this Agreement. Additionally, promptly following the execution and delivery of this Agreement (but in any event no later than 9:00 a.m. Eastern Time on August 7, 2019), the Company shall file a Current Report on Form 8-K (the “Company 8-K”) and/or a Quarterly Report on Form 10-Q (the “Company 10-Q”), which shall report the entry into this Agreement. Each of the Form 8-K and Form 10-Q shall be consistent with the Company Press Release and the terms of this Agreement.

2.    (a) Elliott and the Company will cooperate with each other to select two mutually accepted individuals to be appointed to the Company’s Board of Directors (the “Board”) as soon as reasonably practical. The two individuals appointed to the Board (the “New Directors”) pursuant to this paragraph 2(a),will qualify as independent directors under the rules of the New York Stock Exchange, will have technical and operating oil and gas experience as reasonably determined by the Nominating and Governance Committee of the Board, and will not be a principal, director, general partner, officer, employee, agent, representative or affiliate of Elliott or an investor in any funds managed by Elliott (each a “qualified candidate”). The Company and Elliott will develop a joint list of up to six qualified candidates (with each Party proposing up to three qualified candidates) for appointment as a New Director (the “Candidate List”) and will each use all reasonable efforts to agree on two mutually acceptable individuals from the Candidate List to be appointed as New Directors. If Elliott and the Company cannot agree on two mutually acceptable qualified candidates from the Candidate List to be appointed as New Directors within 60 days of the date of this Agreement, each Party will designate one qualified candidate to be appointed as a New Director, subject to the consent of the other Party, which consent cannot be unreasonably withheld, conditioned or delayed. The Nominating and Governance Committee of the Board will recommend to the Board, and the Board will appoint the New Directors to the Board, in each case promptly (and no later than eight business days) after the New Directors are agreed upon in accordance with the process set forth in this paragraph 2(a). The Parties will use all reasonable efforts to identify and appoint the New Directors to the Board no later than 75 days after the date of this Agreement. The New Directors will be included in the slate of directors proposed by the Board in the Company’s Proxy Statement for the 2020 Annual Meeting.

(b) Promptly following the appointment of the New Directors, the Board will form a five-person Operations Committee of the Board, chaired by the chief executive officer of the Company (the “CEO”), comprised of the CEO, the New Directors and two of the incumbent directors of the Board (the “Operations Committee”). The purpose of the Operations Committee is to identify best operating practices in the areas of the Company’s operations and to work with management to focus on continuous operational improvement and excellence. The Operations Committee will be provided with the technical resources and authority reasonably necessary for the Operations Committee to discharge its purpose, including to retain and terminate its own independent technical consultants, advisors and experts to the extent that the Operations Committee so determines.

(c) At least until the expiration of the Restricted Period (as defined below), the Board will take all actions necessary to (i) cause the Operations Committee to remain in place, (ii) maintain the size of the Operations Committee at five members and not remove any New Director from the Operations Committee, and (iii) simultaneous with the appointment of any Replacement New Director (as defined below) to the Board pursuant to paragraph 2(d), appoint such Replacement New Director to the Operations Committee to replace the applicable prior New Director. Additionally, the Company agrees that the size of the Board shall be no greater than 10 at any time prior to the expiration of the Restricted Period.

(d) If any New Director (or any Replacement New Director) is unable or unwilling to serve as a director, resigns as a director, is removed as a director or ceases to be a director for any other reason prior to the expiration of the Restricted Period, Elliott and the Company will cooperate with each other to select a mutually acceptable qualified candidate to be appointed to the Board as a substitute New Director (a “Replacement New Director”) as promptly as practicable. Effective upon the appointment of a Replacement New Director to the Board, such Replacement New Director will be considered a New Director for all purposes of this Agreement.

3.    In connection with the 2020 Annual Meeting (and any adjournments or postponements), the Company shall (a) recommend that the Company’s stockholders vote in favor of the election of each of the New Directors, (b) use its reasonable best efforts (which shall include the solicitation of proxies) to cause the election of the New Directors (it being understood that such efforts shall not be less than the efforts used by the Company to cause the election of any other director nominee nominated by the Company), and (c) cause all Company common stock represented by proxies granted to it (or any of its officers, directors or representatives) to be voted in favor of each of the New Directors. In connection with the 2020 Annual Meeting (and any adjournments or postponements), so long as the Company’s nominees for the Board include the New Directors, Elliott shall cause to be present for quorum purposes and vote or cause to be voted any Company common stock that Elliott or its controlling or controlled Affiliates has the right to vote on the record date for the 2020 Annual Meeting and is beneficially owned by Elliott or its controlling or controlled Affiliates in favor of (i) the election of directors nominated by the Board, and (ii) otherwise in accordance with the Board’s recommendation on any other proposals not related to an Extraordinary Transaction (as defined below).

4.    From the date of this Agreement until the Expiration Date or until such earlier time as the restrictions in this paragraph 4 terminate as provided herein (such period, the “Restricted Period”), Elliott shall not, and shall cause its Affiliates and its and their respective principals, directors, general partners, officers, employees, and agents and representatives acting on their behalf (collectively, “Restricted Persons”) not to, directly or indirectly, absent prior express written invitation or authorization by the Board:

(a) engage in any “solicitation” (as such term is used in the proxy rules of the SEC) of proxies or consents with respect to the election or removal of directors of the Company or any of its subsidiaries or any other matter or proposal relating to the Company or any of its subsidiaries or become a “participant” (as such term is used in the proxy rules of the SEC) in any such solicitation of proxies or consents;

(b) knowingly encourage or advise any Person or knowingly assist any Person in encouraging or advising any other Person (i) with respect to the giving or withholding of any proxy or consent relating to, or other authority to vote, any Voting Securities, or (ii) in conducting any type of referendum relating to the Company or any of its subsidiaries (other than such encouragement or advice that is consistent with management’s recommendation in connection with a particular matter);

(c) form, join or act in concert with any “group” as defined pursuant to Section 13(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), with respect to any Voting Securities, other than solely with Affiliates of Elliott with respect to Voting Securities now or hereafter owned by them;

(d) acquire, or offer, seek or agree to acquire, by purchase or otherwise, or direct any Third Party in the acquisition of, any Voting Securities of the Company, or engage in any swap or hedging transactions or other derivative agreements of any nature with respect to Voting Securities, in each case, if such acquisition, offer, agreement or transaction would result in Elliott having a Net Long Position of, or voting rights (or the right to acquire voting rights) with respect to, more than 9.9% of the Voting Securities of the Company;

(e) sell, offer or agree to sell, all or substantially all, directly or indirectly, through swap or hedging transactions or otherwise, voting rights decoupled from the underlying common stock of the Company held by Elliott to any Third Party;

(f) make or in any way participate, either alone or in concert with others, directly or indirectly, in any tender offer, exchange offer, merger, consolidation, acquisition, business combination, purchase of a division, purchase of all or substantially all of the assets, recapitalization, restructuring, liquidation, dissolution or similar extraordinary transaction involving the Company or any of its subsidiaries or its or their respective securities or assets (each, an “Extraordinary Transaction”) (it being understood that the foregoing shall not restrict the Restricted Persons from tendering shares, receiving payment for shares or otherwise participating in any Extraordinary Transaction initiated by a Third Party on the same basis as other stockholders of the Company or any of its subsidiaries, or from participating in any Extraordinary Transaction that has been approved by the Board or the board of any subsidiary of the Company); or make, directly or indirectly, any proposal, either alone or in concert with others, to the Company or any of its subsidiaries or the Board or the board of any subsidiary of the Company that would reasonably be expected to require the Company or Elliott to make a public announcement regarding any of the types of matters set forth above in this clause (f);

(g) enter into a voting trust, arrangement or agreement with respect to any Voting Securities, or subject any Voting Securities to any voting trust, arrangement or agreement other than (i) this Agreement, (ii) solely with Affiliates of Elliott, or (iii) granting proxies in solicitations approved by the Board or the board of any subsidiary of the Company;

(h) (i) seek, alone or in concert with others, election or appointment to, or representation on, the Board or the board of any subsidiary of the Company or nominate or propose the nomination of, or recommend the nomination of, any candidate to the Board or any such other board, (ii) seek, alone or in concert with others, the removal of any member of the Board or any such other board, or (iii) conduct a referendum of stockholders of the Company or any of its subsidiaries; provided that nothing in this Agreement shall prevent Elliott or its Affiliates from taking actions confidentially in furtherance of identifying director candidates in accordance with paragraph 2 of this Agreement or in connection with the 2021 Annual Meeting so long as such actions do not create a public disclosure obligation for Elliott or the Company and are undertaken on a confidential basis and in accordance in all material respects with Elliott’s normal practices in the circumstances;

(i) make or be the proponent of any stockholder proposal (pursuant to Rule 14a-8 under the Exchange Act or otherwise) relating to the Company or any of its subsidiaries;

(j) make any request for stock list materials or other books and records of the Company or any of its subsidiaries under Section 220 of the General Corporation Law of the State of Delaware or other statutory or regulatory provisions providing for shareholder access to books and records;

(k) except as set forth in this Agreement, make any public proposal with respect to (i) any change in the number or term of directors or the filling of any vacancies on the Board or the board of any subsidiary of the Company, (ii) any material change in the capitalization or dividend policy of the Company or any of its subsidiaries, (iii) any other material change in management, business or corporate structure of the Company or any of its subsidiaries, or in the ability of the Company to engage in a future change of control transaction, (iv) any waiver, amendment or modification to the certificate of incorporation or bylaws (“Governing Documents”) of the Company or any of its subsidiaries, (v) causing a class of securities of the Company or any of its subsidiaries to be delisted from, or to cease to be authorized to be quoted on, any securities exchange or (vi) causing a class of equity securities of the Company or any of its subsidiaries to become eligible for termination of registration pursuant to Section 12(g)(4) of the Exchange Act;

(l) institute, solicit, assist or join any litigation, arbitration or other proceeding against or involving the Company or any of its subsidiaries or any of its or their respective current or former directors or officers (including derivative actions) in order to effect or take any of the actions expressly prohibited by this paragraph 4; provided, however, that for the avoidance of doubt, the foregoing shall not prevent any Restricted Person from (i) instituting litigation to enforce the provisions of this Agreement, (ii) making counterclaims with respect to any proceeding initiated by, or on behalf of, the Company against a Restricted Person, (iii) bringing bona fide commercial disputes that do not relate to the subject matter of this Agreement, or (iv) exercising statutory appraisal rights; provided, further, that the foregoing shall also not prevent the Restricted Persons from responding to or complying with a validly issued legal process;

(m) enter into any negotiations, agreements or understandings with any Third Party to take any action that Elliott is prohibited from taking pursuant to this paragraph 4;

(n) publicly disclose any intention, plan or arrangement inconsistent with any provision of this paragraph 4; or

(o) make any request or submit any proposal to amend or waive the terms of this Agreement, in each case which would reasonably be expected to result in a public announcement of such request or proposal;

provided that (A) the restrictions in this paragraph 4 shall terminate automatically upon the earliest of: (i) as a nonexclusive remedy for any such breach, five (5) business days after written notice is delivered to the Company by Elliott following a material breach of this Agreement by the Company (including without limitation its failure to appoint a New Director or a Replacement New Director in accordance with paragraph 2) if such breach has not been cured within such notice period; provided further, that Elliott is not in material breach of this Agreement at the time such notice is given; (ii) the announcement by the Company that it (x) has entered into a definitive agreement, or (y) is negotiating with any Third Party regarding a commercially reasonable offer (which it intends to pursue in good faith to enter into an Extraordinary Transaction), in each case with respect to any Extraordinary Transaction that would result in the acquisition by any Person of more than 50% of the Voting Securities of the Company; (iii) the commencement of any tender or exchange offer (by any Person other than Elliott or its Affiliates) which, if consummated, would constitute an Extraordinary Transaction that would result in the acquisition by any Person of more than 50% of the Voting Securities, where the Company files with the SEC a Schedule 14D-9 (or any amendment thereto) that does not recommend that its stockholders reject such tender or exchange offer (provided that nothing herein shall prevent the Company from issuing a “stop, look and listen” communication pursuant to Rule 14d-9(f) promulgated under the Exchange Act in response to the commencement of any tender or exchange offer); (iv) the public announcement by the Company that it is exploring or may explore strategic alternatives for an Extraordinary Transaction, including by conducting a strategic review process or similar evaluation; (v) such time as the Company files with the SEC or delivers to its stockholders any preliminary proxy statement, definitive proxy statement or other proxy materials in connection with the 2020 Annual Meeting that does not nominate and/or recommend the election of the New Directors or otherwise is inconsistent with the terms of this Agreement; (vi) the adoption by the Board of any amendment to the Company’s Governing Documents, each as in effect on the date hereof, that would reasonably be expected to impair the ability of a stockholder to submit nominations of individuals for election to the Board or stockholder proposals in connection with any Annual Meeting after the 2020 Annual Meeting; and (vii) the adoption of any shareholder rights plan (unless such rights plan has a trigger in excess of 10% of the common stock of the Company outstanding and is adopted (x) in response to an accumulation by a Third Party, or (y) in response to an unsolicited proposal for an Extraordinary Transaction); and (B) nothing in this paragraph 4 or paragraph 5 shall prevent Elliott from making (i) any public or private statement or announcement with respect to any Extraordinary Transaction that is publicly announced by the Company or a Third Party, or (ii) any factual statement made to comply with any subpoena or other legal process or respond to a request for information from any governmental authority with jurisdiction over Elliott from whom information is sought (so long as such process or request did not arise as a result of discretionary acts by Elliott or any of its Affiliates). Notwithstanding the foregoing, nothing in this Agreement shall restrict the ability of the Restricted Persons to grant any liens or encumbrances on any claims or interests in favor of a bank or broker-dealer or prime broker holding such claims or interests in custody or prime brokerage in the ordinary course of business, which lien or encumbrance is released upon the transfer of such claims or interests in accordance with the terms of the custody or prime brokerage agreement(s), as applicable.

5.    During the Restricted Period, each of the Company and Elliott shall refrain from making, and shall cause their respective Affiliates and its and their respective principals, directors, members, general partners, officers, employees and agents and representatives acting on their behalf not to make or cause to be made any statement or announcement, including in any document or report filed with or furnished to the SEC or through the press, media, analysts or other Persons, that constitutes an ad hominem attack on, or otherwise disparages, defames, slanders, impugns or is reasonably likely to damage the reputation of, (a) in the case of statements or announcements by any of Elliott, the Company or any of its Affiliates, subsidiaries or advisors, or any of its or their respective current or former officers, directors or employees, and (b) in the case of statements or announcements by the Company, Elliott and Elliott’s advisors, their respective employees or any individual who has served as an employee of Elliott and Elliott’s advisors. The foregoing shall not (i) restrict the ability of any Person to comply with any subpoena or other legal process or respond to a request for information from any governmental authority with jurisdiction over the Person from whom information is sought or (ii) apply to any private communications between Elliott, its Affiliates and its and their respective principals, directors, members, general partners, officers, employees or agents or representatives acting on their behalf, on the one hand, and the Company or any of its subsidiaries, directors, officers, employees or agents or representatives acting on their behalf, on the other hand.

6.    As used in this Agreement, the term (a) “Affiliate” shall have the meaning set forth in Rule 12b-2 promulgated under the Exchange Act and shall include Persons who become Affiliates of any Person subsequent to the date of this Agreement; provided that “Affiliates” of a Person shall not include any entity, solely by reason of the fact that one or more of such Person’s employees or principals serves as a member of its board of directors or similar governing body, unless such Person otherwise controls such entity (as the term “control” is defined in Rule 12b-2 promulgated by the SEC under the Exchange Act); provided further that with respect to Elliott “Affiliates” shall not include any portfolio operating company of Elliott or its Affiliates; (b) “Annual Meeting” shall mean the annual meeting of stockholders of the Company, and any reference

to an Annual Meeting preceded by a calendar year (e.g., “2020”) shall mean the Annual Meeting to occur during such calendar year; (c) “beneficially own”, “beneficially owned” and “beneficial ownership” shall have the meaning set forth in Rules 13d-3 and 13d-5(b)(l) promulgated under the Exchange Act; (d) “business day” shall mean any day other than a Saturday, Sunday or a day on which the Federal Reserve Bank of New York is closed; (e) “controlled,” “controlling” and “controlled by” shall have the meanings set forth in Rule 12b-2 promulgated under the Exchange Act; (f) “Expiration Date” shall mean the earlier of (i) June 30, 2020, and (ii) the second business day after the completion of the 2020 Annual Meeting (including any postponement or adjournment thereof); (g) “Net Long Position” shall mean, with respect to any Person, such Person’s net long position, as defined in Rule 14e-4 under the Exchange Act, mutatis mutandis, in respect of the Company’s common stock; provided that, for the avoidance of doubt, “Net Long Position” will not include any shares as to which such Person does not have the right to vote or direct the vote or as to which such Person has entered into a derivative contract or other agreement, arrangement or understanding that hedges or transfers, in whole or in part, any of the economic consequences of ownership of such shares; (h) “Person” shall be interpreted broadly to include, among others, any individual, general or limited partnership, corporation, limited liability or unlimited liability company, joint venture, estate, trust, group, association or other entity of any kind or structure; (i) “SEC” means the United States Securities and Exchange Commission; (j) “Third Party” shall mean any Person that is not a Party or an Affiliate thereof, a member of the Board, a director or officer of the Company, or legal counsel to any Party; and (k) “Voting Securities” shall mean the shares of common stock of the Company and any other securities thereof entitled to vote in the election of directors, or securities convertible into, or exercisable or exchangeable for, such shares or other securities, whether or not subject to the passage of time or other contingencies; provided that “Voting Securities” shall not include any securities contained in any index, exchange traded fund, benchmark or other industry-related basket of at least ten securities.

7.    Elliott represents, warrants and agrees that (a) this Agreement has been duly authorized, executed and delivered by it and is a valid and binding obligation of Elliott, enforceable against it in accordance with its terms; (b) as of the date of this Agreement, Elliott beneficially owns an aggregate of 11,700,000 shares of Voting Securities of the Company, of which 11,700,000 are shares of common stock of the Company; and (c) this Agreement does not violate any law, any order of any court or other agency of government, or Elliott’s organizational documents, each as in effect on the date of this Agreement.

8.    The Company represents and warrants that (a) this Agreement has been duly authorized, executed and delivered by it and is a valid and binding obligation of the Company, enforceable against the Company in accordance with its terms; (b) this Agreement does not require the approval of the stockholders of the Company; and (c) this Agreement does not violate any law, any order of any court or other agency of government, or the Company’s Governing Documents, each as in effect on the date of this Agreement.

9.    Each Party acknowledges that (i) the other Party would be irreparably injured by a breach of this agreement and (ii) monetary remedies may be inadequate to protect a party against any actual or threatened breach or continuation of any breach of this agreement. Without prejudice to any other rights and remedies otherwise available to a Party under this agreement, (a) each Party shall be entitled to seek equitable relief by way of injunction or otherwise to prevent breaches or threatened breaches of any of the provisions of this Agreement, without proof of actual damages; (b) the breaching Party shall not plead in defense thereto that there would be an adequate remedy at law; and (c) the breaching Party agrees to waive any applicable right or requirement that a bond be posted by the non-breaching Party. Such remedies shall not be the exclusive remedies for a breach of this Agreement, but shall be in addition to all other remedies available at law or in equity. This Agreement is solely for the benefit of the Parties and shall not be enforceable by any other Person.

10.    This Agreement constitutes the only agreement between Elliott and the Company with respect to the subject matter hereof and supersedes all prior agreements, understandings, negotiations and discussions, whether oral or written. This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns. No Party may assign or otherwise transfer either this Agreement or any of its rights, interests, or obligations under this Agreement without the prior written approval of the other Party. Any purported transfer requiring consent without such consent shall be void. No amendment, modification, supplement or waiver of any provision of this Agreement shall be effective unless it is in writing and signed by the Party affected thereby, and then only in the specific instance and for the specific purpose stated therein. Any waiver by any Party of a breach of any provision of this Agreement shall not operate as or be construed to be a waiver of any other breach of such provision or of any breach of any other provision of this Agreement. The failure of a Party to insist upon strict adherence to any term of this Agreement on one or more occasions shall not be considered a waiver or deprive that Party of the right thereafter to insist upon strict adherence to that term or any other term of this Agreement. If any provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement shall remain in full force and effect. Any provision of this Agreement held invalid or unenforceable only in part or degree shall remain in full force and effect to the extent not held invalid or unenforceable. The Parties further agree to replace such invalid or unenforceable provision of this Agreement with a valid and enforceable provision that will achieve, to the extent possible, the purposes of such invalid or unenforceable provision. All attorneys’ fees,

costs and expenses incurred in connection with this Agreement and all matters related hereto will be paid by the Party incurring such fees, costs or expenses. Each of the parties acknowledges that it has been represented by counsel of its choice throughout all negotiations that have preceded the execution of this Agreement, and that it has executed this Agreement with the advice of such counsel. Each Party and its counsel cooperated and participated in the drafting and preparation of this Agreement, and any and all drafts relating thereto exchanged among the Parties shall be deemed the work product of all of the Parties and may not be construed against any Party by reason of its drafting or preparation. Accordingly, any rule of law or any legal decision that would require interpretation of any ambiguities in this Agreement against any Party that drafted or prepared it is of no application and is expressly waived by each of the Parties, and any controversy over interpretations of this Agreement shall be decided without regard to events of drafting or preparation.

11.    This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware without giving effect to the choice of law principles of such state. Each Party irrevocably and unconditionally consents to the exclusive institution and resolution of any action, suit or proceeding of any kind or nature with respect to or arising out of this Agreement brought by any Party in the Chancery Court of the State of Delaware and the appellate courts thereof. Each Party irrevocably and unconditionally waives any objection to the laying of venue of any action, suit or proceeding arising out of this agreement in such court, and further irrevocably and unconditionally waives and agrees not to plead or claim in any such court that any such action, suit or proceeding brought in any such court has been brought in an inconvenient forum. The Parties agree that a final judgment in any such dispute shall be conclusive and may be enforced in other jurisdictions by suits on the judgment or in any other manner provided by law. The Parties agree that mailing of process or other papers in connection with any such action or proceeding in the manner provided in paragraph 12 or in such other manner as may be permitted by applicable law, shall be valid and sufficient service thereof. Each of the Parties, after consulting or having had the opportunity to consult with counsel, knowingly, voluntarily and intentionally waives any right that such Party may have to a trial by jury in any litigation based upon or arising out of this Agreement or any related instrument or agreement, or any of the transactions contemplated thereby, or any course of conduct, dealing, statements (whether oral or written), or actions of any of them. No Party shall seek to consolidate, by counterclaim or otherwise, any action in which a jury trial has been waived with any other action in which a jury trial cannot be or has not been waived.

12.    All notices, consents, requests, instructions, approvals and other communications provided for in this Agreement, and all legal process in regard hereto, shall be in writing and shall be deemed validly given, made or served when delivered in person, by electronic mail, by overnight courier or two (2) business days after being sent by registered or certified mail (postage prepaid, return receipt requested) as follows:

If to the Company to:

QEP Resources, Inc.

1050 17th Street

Denver, CO 80265

Attention: Christopher K. Woosley, Esq.

Email: chris.woosley@qepres.com

with a copy (which shall not constitute notice) to:

Wachtell, Lipton, Rosen & Katz

51 West 52^nd Street

New York, NY 10019-6119

Attention: David A. Katz, Esq.

Email: dakatz@wlrk.com

and

Latham & Watkins LLP

811 Main Street

Suite 3700

Houston, TX 77002

Attention: Michael E. Dillard, Esq.

Email: Michael.Dillard@lw.com

If to Elliott:

Elliott Management Corporation

40 West 57 Street

New York, NY 10019-4001

Attention: Andrew Taylor

Email: ataylor@elliottmgmt.com

with a copy (which shall not constitute notice) to:

Olshan Frome Wolosky LLP

1325 Avenue of the Americas

New York, NY 10019

Attention: Steve Wolosky, Esq. and Andrew Freedman, Esq.

Email: swolosky@olshanlaw.com and afreedman@olshanlaw.com

At any time, any Party may, by notice given in accordance with this paragraph 12 to the other Party, provide updated information for notices hereunder

13.    This Agreement may be executed in two counterparts, each of which shall be deemed to be an original, but all of which shall constitute the same agreement and shall become a binding agreement when a counterpart has been signed by each party and delivered to the other party, thereby constituting the entire agreement among the parties pertaining to the subject matter hereof. Signatures of the parties transmitted by facsimile, PDF, jpeg, .gif, .bmp or other electronic file shall be deemed to be their original signatures for all purposes and the exchange of copies of this Agreement and of signature pages by facsimile transmission, PDF or other electronic file shall constitute effective execution and delivery of this Agreement as to the parties.

[Signature page follows]

Please confirm your agreement with the foregoing by signing and returning this agreement to the undersigned, whereupon this Agreement shall become a binding agreement between Elliott and the Company.

Very truly yours,

QEP RESOURCES, INC.

By:    /s/ Timothy J. Cutt

Name:     Timothy J. Cutt

Title:     President & CEO

Accepted and agreed

as of the date first written above:

Elliott Management Corporation

By:    /s/ Elliott Greenberg

Name:     Elliott Greenberg

Title:     Vice President

EXHIBIT A

[Final Version of Press Release]

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Timothy J. Cutt, certify that:

1. I have reviewed this Form 10-Q of QEP Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

August 7, 2019

/s/ Timothy J. Cutt

Timothy J. Cutt

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard J. Doleshek, certify that:

1. I have reviewed this Form 10-Q of QEP Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

August 7, 2019

/s/ Richard J. Doleshek

Richard J. Doleshek

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of QEP Resources, Inc. (the Company) on Form 10-Q for the period ended June 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the Report), Timothy J. Cutt, President and Chief Executive Officer of the Company, and Richard J. Doleshek, Executive Vice President and Chief Financial Officer, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	QEP RESOURCES, INC.
August 7, 2019
	/s/ Timothy J. Cutt
	Timothy J. Cutt
	President and Chief Executive Officer
August 7, 2019
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2019 shares
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	001-34778
Entity Registrant Name	QEP RESOURCES, INC.
Entity Incorporation, State or Country Code	DE
Entity Central Index Key	0001108827
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Tax Identification Number	87-0287750
Entity Address, Address Line One	1050 17th Street, Suite 800
Entity Address, City or Town	Denver
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80265
City Area Code	303
Local Phone Number	672-6900
Title of 12(b) Security	Common stock, $0.01 par value
Trading Symbol	QEP
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	237,912,768

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenues [Abstract]
Revenues	$ 296.2	$ 532.4	$ 576.8	$ 961.3
Operating Expenses [Abstract]
General and administrative	31.5	55.8	94.8	115.9
Production and property taxes	23.6	37.6	47.6	66.5
Depreciation, depletion and amortization	128.0	242.2	251.3	438.7
Exploration expenses	0.0	0.1	0.0	0.1
Impairment	0.0	403.7	5.0	404.4
Total Operating Expenses	241.7	850.3	524.9	1,261.3
Net gain (loss) from asset sales, inclusive of restructuring costs	17.8	(3.9)	4.6	(0.4)
OPERATING INCOME (LOSS)	72.3	(321.8)	56.5	(300.4)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	38.5	(79.1)	(143.2)	(132.3)
Interest and other income (expense)	0.9	(3.1)	3.7	(3.8)
Interest expense	(33.2)	(38.2)	(67.2)	(73.2)
INCOME (LOSS) BEFORE INCOME TAXES	78.5	(442.2)	(150.2)	(509.7)
Income tax (provision) benefit	(29.7)	106.2	82.3	120.1
Net income (loss)	$ 48.8	$ (336.0)	$ (67.9)	$ (389.6)
Earnings Per Share [Abstract]
Basic	$ 0.20	$ (1.42)	$ (0.29)	$ (1.63)
Diluted	$ 0.20	$ (1.42)	$ (0.29)	$ (1.63)
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Used in basic calculation	238.0	237.0	237.5	238.9
Used in diluted calculation	238.0	237.0	237.5	238.9
Oil and Gas, Exploration and Production [Member]
Revenues [Abstract]
Revenues	$ 294.6	$ 520.3	$ 570.2	$ 930.1
Product and Service, Other [Member]
Revenues [Abstract]
Revenues	1.6	3.0	5.3	8.0
Oil and Gas, Purchased [Member]
Revenues [Abstract]
Revenues	0.0	9.1	1.3	23.2
Operating Expenses [Abstract]
Operating Costs and Expenses	0.0	9.8	1.4	25.3
Lease Operating Expense [Member]
Operating Expenses [Abstract]
Operating Costs and Expenses	45.7	66.5	97.2	139.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Operating Expenses [Abstract]
Operating Costs and Expenses	9.9	31.2	20.8	65.2
Gathering and other expense [Member]
Operating Expenses [Abstract]
Operating Costs and Expenses	$ 3.0	$ 3.4	$ 6.8	$ 6.2

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2019		Jun. 30, 2018		Jun. 30, 2019		Jun. 30, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 48.8		$ (336.0)		$ (67.9)		$ (389.6)
Fair value of plan assets adjustment(1)	0.0		0.0		0.0		0.3	[1]
Pension and other postretirement plans adjustments:
Amortization of prior service costs(2)	0.0		0.1	[2]	0.1		0.2	[2]
Amortization of actuarial losses(3)	0.0		0.2	[3]	0.1		0.4	[3]
Curtailment Gain (Loss), after Tax(4)	0.1	[4]	0.0		(0.3)	[4]	0.0
Other comprehensive income (loss)	0.1		0.3		(0.1)		0.9
Comprehensive income (loss)	$ 48.9		$ (335.7)		$ (68.0)		$ (388.7)

[1] Adjustment recorded during the six months ended June 30, 2018, related to a change in the fair value of plan assets as of December 31, 2017.

[2] Presented net of income tax expense of $0.1 million and $0.1 million for the three and six months ended June 30, 2018, respectively.

[3] Presented net of income tax expense of $0.1 million and $0.2 million for the three and six months ended June 30, 2018, respectively.

[4] Presented net of income tax expense of $0.1 million for the six months ended June 30, 2019, respectively.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019		Jun. 30, 2018
Amortization of prior service cost, tax expense	[1]		$ 0.1			$ 0.1
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss, income tax expense		$ 0.0	0.1	$ 0.0		0.2	[2]
Net curtailment (gain) loss, tax		$ 0.0	$ 0.0	$ (0.1)	[3]	$ 0.0

[1] Presented net of income tax expense of $0.1 million and $0.1 million for the three and six months ended June 30, 2018, respectively.

[2] Presented net of income tax expense of $0.1 million and $0.2 million for the three and six months ended June 30, 2018, respectively.

[3] Presented net of income tax expense of $0.1 million for the six months ended June 30, 2019, respectively.

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 97.1	$ 0.0
Accounts receivable, net	93.5	104.3
Income tax receivable	70.8	75.9
Fair value of derivative contracts	2.7	87.5
Prepaid expenses	7.1	12.7
Other current assets	0.2	0.2
Total Current Assets	271.4	280.6
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,316.0	9,096.9
Unproved properties	706.6	705.5
Gathering and other	169.1	167.7
Materials and supplies	20.9	29.9
Total Property, Plant and Equipment	10,212.6	10,000.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,050.9	4,882.4
Gathering and other	58.4	58.1
Total Accumulated Depreciation, Depletion and Amortization	5,109.3	4,940.5
Net Property, Plant and Equipment	5,103.3	5,059.5
Fair value of derivative contracts	15.2	35.4
Operating lease right-of-use assets, net	60.2	0.0
Other noncurrent assets	54.2	49.6
Noncurrent assets held for sale	0.0	692.7
TOTAL ASSETS	5,504.3	6,117.8
Current Liabilities
Checks outstanding in excess of cash balances	5.3	14.6
Accounts payable and accrued expenses	227.9	258.1
Production and property taxes	15.9	24.1
Current portion of long term debt	51.7	0.0
Interest payable	32.5	32.4
Fair value of derivative contracts	17.6	0.0
Current operating lease lease liabilities	18.8	0.0
Asset retirement obligations	6.8	5.1
Total Current Liabilities	376.5	334.3
Long-term debt	2,028.1	2,507.1
Deferred income taxes	181.4	269.2
Asset retirement obligations	94.6	96.9
Fair value of derivative contracts	0.9	0.7
Operating lease liabilities	47.9	0.0
Other long-term liabilities	85.6	97.4
Other long-term liabilities held for sale	0.0	61.3
Commitments and contingencies (Note 11)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 242.0 million and 239.8 million shares issued, respectively	2.4	2.4
Treasury stock – 4.1 million and 3.1 million shares, respectively	(53.6)	(45.6)
Additional paid-in capital	1,446.3	1,431.9
Retained earnings	1,308.6	1,376.5
Accumulated other comprehensive income (loss)	(14.4)	(14.3)
Total Common Shareholders' Equity	2,689.3	2,750.9
TOTAL LIABILITIES AND EQUITY	$ 5,504.3	$ 6,117.8

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares shares in Millions	Jun. 30, 2019	Dec. 31, 2018
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)	242.0	239.8
Treasury stock (in shares)	4.1	3.1

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) Statement - USD ($) shares in Millions, $ in Millions	Total	Common Stock, Value [Member]	Stockholders' Equity, Total	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		$ 2.4		$ (34.2)	$ 1,398.2	$ 2,442.6	$ (11.1)	$ 3,797.9
Net income (loss)	$ (389.6)
Net income (loss), Shares		0.0		0.0
Net income (loss)	(389.6)	$ 0.0		$ 0.0	0.0	(389.6)	0.0	(389.6)
Common stock repurchased and retired, Shares		(6.2)		0.0
Common stock repurchased and retired	58.4	$ (0.1)	$ (58.4)	$ 0.0	0.0	(58.3)	0.0
Share-based compensation, Shares		2.9
Share-based compensation		$ 0.1
Stock Issued During Period, Shares, Treasury Stock Reissued				(0.7)
Share-based compensation				$ (7.0)	17.5	0.0	0.0	10.6
Stock Issued During Period, Shares, Employee Benefit Plan		0.0		0.0
Change in pension and postretirement liability, net of tax		$ 0.0		$ 0.0	0.0	0.0	0.9	0.9
Common Stock, Shares		240.3
Treasury Stock, Shares				(2.6)
Stockholders' Equity		$ 2.4		$ (39.5)	1,408.0	2,336.3	(10.5)	3,696.7
Net income (loss), Shares		0.0		0.0
Net income (loss)	$ (336.0)	$ 0.0		$ 0.0	0.0	(336.0)	0.0	(336.0)
Common stock repurchased and retired, Shares		(0.6)		0.0
Common stock repurchased and retired		$ 0.0	$ (5.6)	$ 0.0	0.0	(5.6)	0.0
Share-based compensation, Shares		0.0
Share-based compensation		$ 0.0
Stock Issued During Period, Shares, Treasury Stock Reissued				(0.1)
Share-based compensation				$ (1.7)	7.7	0.0	0.0	6.0
Stock Issued During Period, Shares, Employee Benefit Plan		0.0		0.0
Change in pension and postretirement liability, net of tax		$ 0.0		$ 0.0	0.0	0.0	0.3	0.3
Common Stock, Shares		239.7
Treasury Stock, Shares				(2.7)
Stockholders' Equity		$ 2.4		$ (41.2)	1,415.7	1,994.7	(10.2)	3,361.4
Common Stock, Shares		239.8
Treasury Stock, Shares	(3.1)			(3.1)
Stockholders' Equity	$ 2,750.9	$ 2.4		$ (45.6)	1,431.9	1,376.5	(14.3)	2,750.9
Net income (loss), Shares		0.0		0.0
Net income (loss)	(67.9)	$ 0.0		$ 0.0	0.0	(67.9)	0.0	(67.9)
Common stock repurchased and retired	0.0
Share-based compensation, Shares		2.2
Share-based compensation		$ 0.0
Stock Issued During Period, Shares, Treasury Stock Reissued				(1.0)
Share-based compensation				$ (8.0)	14.4	0.0	0.0	6.4
Stock Issued During Period, Shares, Employee Benefit Plan		0.0		0.0
Change in pension and postretirement liability, net of tax		$ 0.0		$ 0.0	0.0	0.0	(0.1)	(0.1)
Common Stock, Shares		242.0
Treasury Stock, Shares				(3.9)
Stockholders' Equity		$ 2.4		$ (51.8)	1,440.2	1,259.8	(14.5)	2,636.1
Net income (loss), Shares		0.0		0.0
Net income (loss)	$ 48.8	$ 0.0		$ 0.0	0.0	48.8	0.0	48.8
Share-based compensation, Shares		0.0
Share-based compensation		$ 0.0
Stock Issued During Period, Shares, Treasury Stock Reissued				(0.2)
Share-based compensation				$ (1.8)	6.1	0.0	0.0	4.3
Stock Issued During Period, Shares, Employee Benefit Plan		0.0		0.0
Change in pension and postretirement liability, net of tax		$ 0.0		$ 0.0	0.0	0.0	0.1	0.1
Common Stock, Shares		242.0
Treasury Stock, Shares	(4.1)			(4.1)
Stockholders' Equity	$ 2,689.3	$ 2.4		$ (53.6)	$ 1,446.3	$ 1,308.6	$ (14.4)	$ 2,689.3

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
OPERATING ACTIVITIES
Net income (loss)	$ (67.9)	$ (389.6)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	251.3	438.7
Deferred income taxes (benefit)	(87.7)	(120.5)
Impairment	5.0	404.4
Non-cash share-based compensation	11.2	16.3
Amortization of debt issuance costs and discounts	2.7	2.6
Net (gain) loss from asset sales, inclusive of restructuring costs	(4.6)	0.4
Unrealized (gains) losses on marketable securities	(2.7)	(0.4)
Unrealized (gains) losses on derivative contracts	121.3	43.6
Changes in operating assets and liabilities	(32.9)	(18.6)
Net Cash Provided by (Used in) Operating Activities	195.7	376.9
INVESTING ACTIVITIES
Property acquisitions	(1.8)	(45.1)
Property, plant and equipment, including exploratory well expense	(316.8)	(764.3)
Proceeds from disposition of assets	666.7	48.8
Net Cash Provided by (Used in) Investing Activities	348.1	(760.6)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(9.3)	(35.5)
Proceeds from credit facility	56.0	2,029.5
Repayments of credit facility	(486.0)	(1,543.5)
Common stock repurchased and retired	0.0	(58.4)
Treasury stock repurchases	(6.3)	(5.9)
Other capital contributions	0.0	0.2
Net Cash Provided by (Used in) Financing Activities	(445.6)	386.4
Change in cash, cash equivalents and restricted cash(1)	98.2	2.7
Beginning cash, cash equivalents and restricted cash(1)	28.1	23.4
Ending cash, cash equivalents and restricted cash(1)	126.3	26.1
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	63.3	63.5
Cash paid for income taxes, net	1.5	0.2
Cash Paid for Amounts Included in the Measurement of Lease Liabilities	13.1	0.0
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	9.8	0.0
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$ 20.3	$ 20.2

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Basis of Presentation

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation [Text Block]

Nature of Business

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

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, 2018.

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 six months ended June 30, 2019, are not necessarily indicative of the results that may be expected for the year ending December 31, 2019.

Reclassifications

Certain prior period balances on the Condensed Consolidated Statements of Cash Flows have been reclassified 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 six months ended June 30, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.

During the six months ended June 30, 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment was triggered due to the signing of a purchase and sale agreement for the divestiture of the Uinta Basin assets. 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.

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:

	June 30,
	2019		2018
	(in millions)
Cash and cash equivalents	$	97.1	$	—
Restricted cash(1)	29.2		26.1
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	126.3	$	26.1

_______________________

⁽¹⁾ As of June 30, 2019 and 2018, the restricted cash balance is cash held in an escrow account related to a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Condensed Consolidated Balance Sheets.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance. The Company adopted ASU 2016-02 on January 1, 2019 using the modified retrospective approach and elected to not adjust periods prior to January 1, 2019. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed the carry forward of the historical lease classification, including accounting treatment for land easements. This standard does not apply to QEP's leases that provide the right to explore for minerals, oil or natural gas resources. The adoption of this guidance resulted in the recognition of net operating lease right-of-use assets and operating lease liabilities on QEP's Condensed Consolidated Balance Sheets. These leases primarily relate to office buildings, compressors and generators. This guidance did not have a significant impact on the Condensed Consolidated Statement of Operations or the Condensed Consolidated Statement of Cash Flows. Refer to Note 8 – Leases for more information.

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Revenue Revenue

6 Months Ended

Jun. 30, 2019

Revenue Recognition [Abstract]

Revenue

Revenue Recognition

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

QEP's oil is typically sold at specific delivery points under contract terms that are common in the industry. QEP's gas and NGL are also sold under contract types that are common in the industry; however, under these contracts, the gas and its components, including NGL, may be sold to a single purchaser or the residue gas and NGL may be sold to separate purchasers. Regardless of the contract type, the terms of these contracts compensate QEP for the value of the residue gas and NGL constituent components at market prices for each product. QEP also purchases and resells oil and gas primarily to mitigate credit risk related to third party purchasers, to fulfill volume commitments when production does not fulfill contractual commitments and to capture additional margin from subsequent sales of third party purchases. QEP recognizes revenue from these resale activities in the period that the performance obligations are satisfied.

The following tables present QEP's revenues that are disaggregated by revenue source and by geographic area. Transportation and processing costs in the following table are not all of the transportation and processing costs that QEP 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 June 30, 2019
Northern Region
Williston Basin	$	107.5	$	7.5		$	5.8	$	(8.9	)	$	111.9
Other Northern	0.5		0.1			—		—			0.6
Southern Region
Permian Basin	177.6		(0.6		)	8.5		(3.8		)	181.7
Other Southern	0.1		0.3			—		—			0.4
Total oil and condensate, gas and NGL sales	$	285.7	$	7.3		$	14.3	$	(12.7	)	$	294.6
	Three Months Ended June 30, 2018
Northern Region
Williston Basin	$	207.6	$	8.4		$	14.7	$	(10.7	)	$	220.0
Uinta Basin	9.5		7.9			1.7		—			19.1
Other Northern	0.9		0.2			0.1		—			1.2
Southern Region
Permian Basin	190.3		3.2			9.9		(1.7		)	201.7
Haynesville/Cotton Valley	0.2		77.9			—		—			78.1
Other Southern	—		0.2			—		—			0.2
Total oil and condensate, gas and NGL sales	$	408.5	$	97.8		$	26.4	$	(12.4	)	$	520.3

	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)
	Six Months Ended June 30, 2019
Northern Region
Williston Basin	$	217.4		$	20.0	$	13.2		$	(19.0	)	$	231.6
Other Northern	0.9			0.3		—			—			1.2
Southern Region
Permian Basin	316.8			4.0		18.0			(7.5		)	331.3
Other Southern	0.1			6.0		—			—			6.1
Total oil and condensate, gas and NGL sales	$	535.2		$	30.3	$	31.2		$	(26.5	)	$	570.2
	Six Months Ended June 30, 2018
Northern Region
Williston Basin	$	368.1		$	18.2	$	26.5		$	(20.6	)	$	392.2
Uinta Basin	17.9			18.0		3.4			—			39.3
Other Northern	2.8			1.2		(0.1		)	—			3.9
Southern Region
Permian Basin	320.1			7.8		16.4			(4.5		)	339.8
Haynesville/Cotton Valley	0.6			154.3		—			—			154.9
Other Southern	(0.3		)	0.3		—			—			—
Total oil and condensate, gas and NGL sales	$	709.2		$	199.8	$	46.2		$	(25.1	)	$	930.1

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Acquisitions & Divestitures

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Acquisitions & Divestitures [Text Block]

Acquisitions

During the six months ended June 30, 2019, QEP acquired various oil and gas properties, which primarily included proved leasehold acreage in the Permian Basin for an aggregate purchase price of $1.8 million, subject to post-closing purchase price adjustments.

During the six months ended June 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 $45.1 million. Of the $45.1 million, $37.5 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.

Divestitures

In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial 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. The Company subsequently closed the sale of its Uinta Basin assets in the third quarter of 2018 and the sale of the Haynesville/Cotton Valley assets in the first quarter of 2019. In November 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a purchase and sale agreement for its assets in the Williston Basin, however, in February 2019, the Company agreed with the buyer to terminate the purchase and sale agreement.

Haynesville/Cotton Valley Divestiture

In January 2019, QEP closed the sale of its assets in Haynesville/Cotton Valley (Haynesville Divestiture), and in July 2019 QEP reached final settlement on asserted title defects. The purchase price, after adjustments, is $634.2 million. QEP received net cash proceeds of $627.1 million during the six months ended June 30, 2019, and, as of June 30, 2019, recorded a $9.5 million receivable and a $2.4 million payable which were included in "Accounts receivable, net" and "Accounts payable and accrued expenses", respectively. The total pre-tax loss on sale was $3.7 million, of which $0.7 million was recognized during the six months ended June 30, 2019, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. Included in the $0.7 million pre-tax loss on sale is $1.4 million of restructuring costs related to the Haynesville Divestiture. Refer to Note 9 – Restructuring for more information. As of December 31, 2018, it was deemed unlikely that there will be any significant changes to the Haynesville Divestiture. Accordingly, the assets and liabilities associated with the Haynesville Divestiture were classified as noncurrent assets and liabilities held for sale, on the Condensed Consolidated Balance Sheets.

During the six months ended June 30, 2019, QEP accounted for revenues and expenses related to Haynesville/Cotton Valley, including the pre-tax loss on sale of $0.7 million, as income from continuing operations on the Condensed Consolidated Statements of Operations because the Haynesville Divestiture did not cause a strategic shift for the Company and therefore did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. During the three months ended June 30, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $14.4 million, which includes a pre-tax gain on sale of $14.3 million. During the six months ended June 30, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $3.3 million, which includes the pre-tax loss on sale of $0.7 million. For the three and six months ended June 30, 2018, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $7.4 million and $19.7 million, respectively.

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

	December 31, 2018(1)
	(in millions)
Assets
Current assets, total	$	1.2
Net Property, Plant and Equipment	683.7
Other noncurrent assets	7.8
Noncurrent assets held for sale	$	692.7
Liabilities
Current liabilities, total	$	3.4
Asset retirement obligations, current	0.7
Asset retirement obligations, long-term	56.9
Other long-term liabilities	0.3
Other long-term liabilities held for sale	$	61.3

____________________________

⁽¹⁾  The Haynesville Divestiture closed in January 2019, therefore there are no assets and liabilities held for sale as of June 30, 2019.

Uinta Basin Divestiture

In September 2018, QEP sold its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of $153.0 million (Uinta Basin Divestiture). During the three and six months ended June 30, 2019, QEP recorded a pre-tax loss on sale of $0.3 million and $0.2 million, respectively, due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs". For the three and six months ended June 30, 2018, QEP recorded a net loss before income taxes related to the divested Uinta Basin assets of $409.9 million and $414.9 million, respectively. The net loss before income taxes 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.

Pinedale Divestiture

In September 2017, QEP sold its Pinedale assets (Pinedale Divestiture) for net cash proceeds (after purchase price adjustments) of $718.2 million. During the six months ended June 30, 2018, QEP recorded a pre-tax gain on sale of $0.8 million, due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs".

QEP agreed to reimburse the buyer of its Pinedale assets for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. As of June 30, 2019, the remaining liability associated with estimated future payments for this commitment was $2.0 million and is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses".

Other Divestitures

During the six months ended June 30, 2019, QEP received net cash proceeds of $39.7 million and recorded a net pre-tax gain on sale of $5.5 million related to the divestiture of properties outside its main operating areas.

During the six months ended June 30, 2018, QEP received net cash proceeds of $48.8 million and recorded a pre-tax gain on sale of $0.7 million, primarily related to the divestiture of properties outside its main operating areas in the Uinta Basin, Pinedale and Other Northern area, and the sale of an underground gas storage facility.

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

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Earnings Per Share

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

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

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. During the three and six months ended June 30, 2019 there were no anti-dilutive shares. During the three and six months ended June 30, 2018, 0.1 million shares were not included in diluted common shares outstanding as they were anti-dilutive to QEP's net loss.

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	238.0	237.0	237.5	238.9
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—	—
Average diluted common shares outstanding	238.0	237.0	237.5	238.9

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2019

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.

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

	Asset Retirement Obligations
	June 30,		December 31,
	2019		2018
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.8	$	5.1
Long-term:
Asset retirement obligations	94.6		96.9
Other long-term liabilities held for sale	—		57.6
Total ARO Liability	$	101.4	$	159.6

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 January 1, 2019	$	159.6
Accretion	3.1
Additions	0.4
Revisions	(0.3		)
Liabilities related to assets sold(1)	(60.7		)
Liabilities settled	(0.7		)
ARO liability at June 30, 2019	$	101.4

_______________________

⁽¹⁾ 

Liabilities related to assets sold during the six months ended June 30, 2019, includes $57.6 million related to the Haynesville Divestiture (refer to Note 3 – Acquisitions and Divestitures for more information).

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Fair Value Measurements

6 Months Ended

Jun. 30, 2019

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

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

The fair value of financial assets and liabilities at June 30, 2019 and December 31, 2018, 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
	(in millions)
Financial Assets	June 30, 2019
Fair value of derivative contracts – short-term	$	—	$	2.7	$	—	$	—		$	2.7
Fair value of derivative contracts – long-term	—		15.2		—		—			15.2
Total financial assets	$	—	$	17.9	$	—	$	—		$	17.9
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	17.6	$	—	$	—		$	17.6
Fair value of derivative contracts – long-term	—		0.9		—		—			0.9
Total financial liabilities	$	—	$	18.5	$	—	$	—		$	18.5
	December 31, 2018
Financial Assets
Fair value of derivative contracts – short-term(2)	$	—	$	88.2	$	—	$	(0.4	)	$	87.8
Fair value of derivative contracts – long-term	—		35.4		—		—			35.4
Total financial assets	$	—	$	123.6	$	—	$	(0.4	)	$	123.2
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	0.4	$	—	$	(0.4	)	$	—
Fair value of derivative contracts – long-term	—		0.7		—		—			0.7
Total financial liabilities	$	—	$	1.1	$	—	$	(0.4	)	$	0.7

_______________________

⁽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.

⁽²⁾  Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of

December 31, 2018 on the Condensed Consolidated Balance Sheets related to the Haynesville Divestiture.

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

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	June 30, 2019				December 31, 2018
Financial Assets	(in millions)
Cash and cash equivalents	$	97.1	$	97.1	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	5.3	$	5.3	$	14.6	$	14.6
Total debt outstanding	$	2,079.8	$	2,042.5	$	2,507.1	$	2,350.5

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 carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.

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

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and 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 and operating lease right-of-use assets for potential impairment when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. The fair value of property is measured utilizing the income approach and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. If a range is estimated for the amount of future cash flows, the fair value of property is measured utilizing a probability-weighted approach in which the likelihood of possible outcomes is taken into consideration. Given the unobservable nature of the inputs, fair value calculations associated with long-term operating lease right-of-use assets and proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. During the six months ended June 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease. During the six months ended June 30, 2018, the Company recorded impairments on certain proved oil and gas properties of $397.6 million.

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, and future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. Refer to Note 3 – Acquisitions and Divestitures for more information on the fair value of acquired properties.

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Derivative Contracts

6 Months Ended

Jun. 30, 2019

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, during the time that QEP owned gas storage facilities or had contracts for gas storage capacity, QEP 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 basis swaps to achieve a fixed-price swap for a portion of its oil sales at prices that reference specific regional index prices.

QEP does not currently have any commodity derivative instruments 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 June 30, 2019:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	6.6	$	55.24
2019	ICE Brent	0.9	$	66.73
2019	Argus WTI Houston	0.2	$	65.70
2020	NYMEX WTI	6.2	$	60.07
2020	Argus WTI Midland	0.7	$	60.00

QEP uses oil basis swaps, combined with NYMEX WTI fixed-price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil basis swaps as of June 30, 2019:

Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2019	NYMEX WTI	Argus WTI Midland	3.3	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.9	$	3.69
2020	NYMEX WTI	Argus WTI Midland	4.4	$	(0.02	)
2020 (January - June)	NYMEX WTI	Argus WTI Houston	0.4	$	3.75

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	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
Current:		(in millions)
Commodity(1)	Fair value of derivative contracts	$	2.7	$	88.2	$	17.6	$	0.4
Long-term:
Commodity	Fair value of derivative contracts	15.2		35.4		0.9		0.7
Total derivative instruments		$	17.9	$	123.6	$	18.5	$	1.1

_______________________

⁽¹⁾  Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 on the Condensed Consolidated Balance Sheet related to the Haynesville Divestiture.

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						Six Months Ended
Derivative contracts	June 30,						June 30,
	2019			2018			2019			2018
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(16.0	)	$	(52.0	)	$	(19.0	)	$	(96.3	)
Gas derivative contracts	—			6.4			(2.9		)	7.3
Gas Storage
Gas derivative contracts	—			0.1			—			0.3
Realized gains (losses) on commodity derivative contracts	(16.0		)	(45.5		)	(21.9		)	(88.7		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	54.5			(20.6		)	(122.8		)	(27.5		)
Gas derivative contracts	—			(13.0		)	(0.3		)	(15.8		)
Gas Storage
Gas derivative contracts	—			—			—			(0.3		)
Unrealized gains (losses) on commodity derivative contracts	54.5			(33.6		)	(123.1		)	(43.6		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	38.5		$	(79.1	)	$	(145.0	)	$	(132.3	)
Derivatives associated with Haynesville Divestiture
Unrealized gains (losses) on commodity derivative contracts
Production
Gas derivative contracts	—			—			1.8			—
Unrealized gains (losses) on commodity derivative contracts related to divestitures(1)	$	—		$	—		$	1.8		$	—
Total realized and unrealized gains (losses) on commodity derivative contracts	$	38.5		$	(79.1	)	$	(143.2	)	$	(132.3	)

_______________________

⁽¹⁾ 

During the three and six months ended June 30, 2019, the unrealized gains (losses) on commodity derivative contracts related to the Haynesville Divestiture were comprised of derivatives included as part of the Haynesville/Cotton Valley purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in January 2019. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Haynesville Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

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Leases (Notes)

6 Months Ended

Jun. 30, 2019

Operating Leased Assets [Line Items]

Leases of Lessee Disclosure [Text Block]

Adoption of ASC Topic 842, Leases

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

In accordance with the adoption of ASC Topic 842, QEP now records a net operating lease right-of-use (ROU) asset and operating lease liability on the Condensed Consolidated Balance Sheets for all operating leases with a contract term in excess of 12 months. Prior to the adoption of ASC Topic 842, these same leases were treated as operating leases under ASC Topic 840 and therefore were not recorded on the December 31, 2018 Consolidated Balance Sheets. There was no impact to retained earnings and no significant impact on the Condensed Consolidated Statement of Operations or the Condensed Consolidated Statement of Cash Flows as a result of adopting ASC Topic 842.

Lease Recognition

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

QEP determines if an arrangement is a lease at inception of the contract and records the resulting operating lease asset on the Condensed Consolidated Balance Sheets as “Operating lease right-of-use assets, net” with offsetting liabilities recorded as “Current operating lease liabilities” and “Operating lease liabilities.” QEP recognizes a lease in the financial statements when the arrangement either explicitly or implicitly involves property, plant, or equipment (PP&E), the contract terms are dependent on the use of the PP&E, and QEP has the ability or right to operate the PP&E or to direct others to operate the PP&E and receive the majority of the economic benefits of the assets. As of June 30, 2019, QEP does not have any financing leases.

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

	Three Months Ended		Six Months Ended
	June 30, 2019(1)		June 30, 2019(1)
Lease Cost included in the Condensed Consolidated Balance Sheets	(in millions)
Property, Plant and Equipment acquisitions(2)	$	4.1	$	8.8
	Three Months Ended		Six Months Ended
	June 30, 2019(1)		June 30, 2019(1)
Lease Cost included in the Condensed Consolidated Statement of Operations	(in millions)
Lease operating expense	$	3.0	$	6.1
Gathering and other expense	2.3		3.8
General and administrative	1.6		3.2
Total lease cost	$	11.0	$	21.9

 ____________________________

⁽¹⁾  Prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective method for the new lease recognition rule. Refer to Note 1 – Basis of Presentation for additional information.

⁽²⁾  Represents short-term lease capital expenditures related to drilling rigs for the three and six months ended June 30, 2019. These costs are capitalized as a part of "Proved properties" on the Condensed Consolidated Balance Sheets.

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

	Three Months Ended		Six Months Ended
	June 30, 2019(1)		June 30, 2019(1)
Weighted-average remaining lease term (years)	3.6		3.6
Weighted-average discount rate	7.7	%	7.7	%

 ____________________________

⁽¹⁾  Prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective method for the new lease recognition rule. Refer to Note 1 – Basis of Presentation for additional information.

Refer to Note 11 – Commitments and Contingencies for a reconciliation of our minimum future lease payments to the Condensed Consolidated Balance Sheets.

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Restructuring Costs

6 Months Ended

Jun. 30, 2019

Restructuring [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

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

Restructuring costs recognized 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)"
	Three Months Ended June 30, 2019
	(in millions)
Termination benefits	$	(0.1	)	$	(0.1	)	$	—		$	—
Office lease termination costs	—			—			—			—
Accelerated share-based compensation(1)	1.3			1.3			—			—
Retention expense (including share-based compensation)	4.8			4.8			—			—
Pension and Medical Plan curtailment	0.1			—			—			0.1
Total restructuring costs	$	6.1		$	6.0		$	—		$	0.1
	Six Months Ended June 30, 2019
Termination benefits	$	6.7		$	6.6		$	0.1		$	—
Office lease termination costs	0.6			0.6			—			—
Accelerated share-based compensation(1)	9.7			8.2			1.5			—
Retention expense (including share-based compensation)	10.9			10.9			—			—
Pension and Medical Plan curtailment	(0.4		)	—			(0.2		)	(0.2		)
Total restructuring costs	$	27.5		$	26.3		$	1.4		$	(0.2	)
	Three Months Ended June 30, 2018
Termination benefits	$	3.6		$	1.7		$	1.9		—
Office lease termination costs	0.3			0.3			—			—
Accelerated share-based compensation	1.2			1.2			—			—
Retention expense (including share-based compensation)	6.3			6.3			—			—
Total restructuring costs	$	11.4		$	9.5		$	1.9		$	—
	Six Months Ended June 30, 2018
Termination benefits	$	7.0		$	5.1		$	1.9		—
Office lease termination costs	0.3			0.3			—			—
Accelerated share-based compensation	4.0			4.0			—			—
Retention expense (including share-based compensation)	8.0			8.0			—			—
Total restructuring costs	$	19.3		$	17.4		$	1.9		$	—

 ____________________________

⁽¹⁾  Accelerated share-based compensation represents the additional expense or loss recognized in the Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2019. Total accelerated share based compensation was $2.8 million and $21.7 million for the three and six months ended June 30, 2019, respectively, and was determined based on the contractual vesting date, with $1.3 million and $9.7 million recognized during the three and six months ended June 30, 2019, respectively, as shown above, and the remaining amount recognized in prior periods.

	Costs recognized from inception to June 30, 2019(1)			Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	38.9		$	—	(2)
Office lease termination costs	1.6			—		(2)
Accelerated share-based compensation	21.0			—		(2)
Retention expense (including share-based compensation)	29.7			10.1
Pension and Medical Plan curtailment	(0.2		)	—		(2)
Total restructuring costs	$	91.0		$	10.1

 ____________________________

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

⁽²⁾  Due to the nature of the strategic initiatives, as of June 30, 2019, the Company is not able to reasonably estimate the total cost to be incurred in connection with these restructurings.

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, 2018	$	19.5		$	—		$	—		$	10.8		$	—		$	30.3
Costs incurred and charged to expense	6.7			0.6			9.7			10.9			(0.4		)	27.5
Costs paid or otherwise settled	(23.9		)	(0.6		)	(9.7		)	(15.9		)	0.4			(49.7		)
Balance at June 30, 2019	$	2.3		$	—		$	—		$	5.8		$	—		$	8.1

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Debt

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Debt [Text Block]

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

	June 30, 2019			December 31, 2018
	(in millions)
Revolving Credit Facility due 2022	$	—		$	430.0
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	(19.5		)	(22.2		)
Total principal amount of debt (including current portion)	2,079.8			2,507.1
Less: current portion of long-term debt	(51.7		)	—
Total long-term debt outstanding	$	2,028.1		$	2,507.1

Of the total debt outstanding on June 30, 2019, 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 governing QEP's revolving credit facility 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 3.75 times consolidated EBITDA (as defined in the credit agreement) and (iii) a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.40 times through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. At June 30, 2019 and December 31, 2018, QEP was in compliance with the covenants under the credit agreement.

During the six months ended June 30, 2019, QEP's weighted-average interest rate on borrowings from its credit facility was 4.73%. As of June 30, 2019, QEP had no borrowings outstanding and $2.9 million in letters of credit outstanding under the credit facility. As of December 31, 2018, QEP had $430.0 million of borrowings outstanding and $0.3 million in letters of credit outstanding under the credit facility.

Senior Notes

At June 30, 2019, the Company had $2,099.3 million in principal amount of senior notes outstanding with maturities ranging from March 1, 2020 to March 1, 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 QEP's 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.

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Commitment and Contingencies

6 Months Ended

Jun. 30, 2019

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 and the ongoing discovery and/or development of information important to the matter.

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

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

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

Commitments

QEP has entered into contractual lease arrangements to rent office space, compressors, generators, drilling rigs and other equipment from third-party lessors. On January 1, 2019, QEP adopted ASC Topic 842, Leases, using the modified retrospective approach. Refer to Note 8 – Leases for additional information.

As of June 30, 2019, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC 842 are as follows:

Year	Amount
	(in millions)
2019	$	12.4
2020	$	21.1
2021	$	19.4
2022	$	14.9
2023	$	9.4
After 2023	$	0.5
Less: Interest(1)	$	(11.0	)
Present value of lease liabilities(2)	$	66.7

 ____________________________

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

⁽²⁾  Of the total present value of lease liabilities, $18.8 million was recorded in "Current operating lease liabilities" and $47.9 million was recorded in "Operating lease liabilities" on the Condensed Consolidated Balance Sheets.

As of December 31, 2018, minimum future contractual payments for long-term operating leases under the scope of ASC 840 are as follows:

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

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Share-Based Compensation

6 Months Ended

Jun. 30, 2019

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 has issued stock options, restricted share awards, and restricted share units under its LTSIP or 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 were under the LTSIP and 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 8.3 million shares available for future grants under the LTIP at June 30, 2019.

Share-based compensation expense is generally recognized within "General and administrative" expense on the Condensed Consolidated Statements of Operations and is summarized in the table below. During the three and six months ended June 30, 2019, the Company recorded an additional $1.3 million and $9.7 million, respectively, of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program, of which $1.5 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statement of Operations during the six months ended June 30, 2019 and the remaining $1.3 million and $8.2 million, respectively, is included in the table below. During the three and six months ended June 30, 2018, the Company recorded an additional $1.2 million and $4.0 million, respectively of share-based compensation expense, related to the acceleration of vesting that occurred as part of the restructuring program, all of which is included in the table below. Refer to Note 9 – Restructuring for additional information.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(in millions)
Stock options	$	—	$	0.2	$	0.3	$	0.7
Restricted share awards	4.8		6.8		10.9		15.6
Performance share units	0.3		5.1		5.5		7.0
Restricted share units	0.1		0.1		0.2		0.1
Total share-based compensation expense	$	5.2	$	12.2	$	16.9	$	23.4

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 option 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 three years from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company recognizes forfeitures of stock options as they occur. During the six months ended June 30, 2019, 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, 2018	2,098,933		$	22.27
Cancelled	(283,029	)	30.90
Outstanding at June 30, 2019	1,815,904		$	20.93	2.80	$	—
Options Exercisable at June 30, 2019	1,761,139		$	21.08	2.74	$	—
Unvested Options at June 30, 2019	54,765		$	15.92	4.69	$	—

During the six months ended June 30, 2019 there were no exercises of stock options. As of June 30, 2019, $0.1 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 0.78 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program. Refer to Note 9 – Restructuring for additional information.

Restricted Share Awards

Restricted share award grants typically vest in equal installments over three years from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company recognizes restricted share forfeitures as they occur. The total fair value of restricted share awards that vested during the six months ended June 30, 2019 and 2018 was $25.0 million and $24.6 million, respectively. The weighted-average grant date fair value of restricted share awards was $7.98 per share and $9.55 per share for the six months ended June 30, 2019 and 2018, respectively. As of June 30, 2019, $18.8 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 2.31 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program. Refer to Note 9 – 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, 2018	3,822,133		$	10.76
Granted	2,217,794		7.98
Vested	(2,261,323	)	11.05
Forfeited	(178,985	)	9.23
Unvested balance at June 30, 2019	3,599,619		$	8.94

Performance Share Units

The payouts for performance share units are dependent upon the Company's total shareholder return compared to a group of its peers over three years. The awards are denominated in share units and have historically been paid in cash. The Company has the option to settle earned awards in cash or shares of common stock under the Company's LTIP; however, as of June 30, 2019, 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 Company paid $11.4 million and $2.0 million for vested performance share units during the six months ended June 30, 2019 and 2018, respectively. The weighted-average grant date fair value of the performance share units granted during the six months ended June 30, 2019 and 2018 was $7.93 and $9.55 per share, respectively. As of June 30, 2019, $7.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.33 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program. Refer to Note 9 – 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, 2018	1,559,312		$	11.47
Granted	589,412		7.93
Vested and paid	(1,117,848	)	10.73
Unvested balance at June 30, 2019	1,030,876		$	9.63

Restricted Share Units

Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over three years and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately paid in cash. They are classified as liabilities in "Other long-term liabilities" on the 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 $7.93 and $9.55 per share for the six months ended June 30, 2019 and 2018, respectively. As of June 30, 2019, $0.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.64 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program. Refer to Note 9 – Restructuring for additional information.

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

	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2018	42,675		$	10.47
Granted	37,224		7.93
Vested and paid	(36,392	)	10.67
Unvested balance at June 30, 2019	43,507		$	8.16

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Employee Benefits

6 Months Ended

Jun. 30, 2019

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 six months ended June 30, 2019, the Company made contributions of $5.0 million to the Pension Plan and does not expect to make any additional contributions during the remainder of 2019. 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 six months ended June 30, 2019, the Company made contributions of $0.2 million to the SERP and expects to contribute an additional $0.3 million to the SERP during the remainder of 2019. 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 six months ended June 30, 2019, the Company made contributions of $0.1 million to the Medical Plan and expects to contribute $0.2 million to the Medical Plan during the remainder of 2019. 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 implementation of its strategic initiatives may trigger curtailments related to the Pension Plan, SERP and/or Medical Plan upon the closing of any transaction. Refer to Note 9 – Restructuring for more information. During the six months ended June 30, 2019, the Company recognized a $0.4 million pension curtailment gain related to strategic initiatives, of which $0.5 million of curtailment gain was related to the Haynesville Divestiture and included in "Interest and other income (expense)" and "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations, and $0.1 million of curtailment loss was related to corporate restructuring activities and included as "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						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Pension Plan and SERP benefits	(in millions)
Service cost	$	—		$	0.2		$	0.1		$	0.4
Interest cost	1.2			1.1			2.4			2.2
Expected return on plan assets	(1.4		)	(1.5		)	(2.9		)	(2.9		)
Amortization of prior service costs(1)	0.1			0.2			0.2			0.4
Amortization of actuarial losses(1)	—			0.3			0.1			0.6
Curtailment (gain) loss(2)	0.1			—			0.4			—
Periodic expense	$	—		$	0.3		$	0.3		$	0.7
Medical Plan benefits
Interest cost	$	0.1		$	0.1		$	0.1		$	0.1
Amortization of prior service costs(1)	—			—			—			(0.1		)
Curtailment (gain) loss(2)	—			—			(0.8		)	—
Periodic expense	$	0.1		$	0.1		$	(0.7	)	$	—

____________________________

⁽¹⁾  Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income (loss) 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. The net curtailment gain between the SERP and Medical Plan of $0.4 million is related to the Haynesville Divestiture and corporate restructuring activities. Of the $0.4 million curtailment gain recognized, $0.2 million was recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)" and $0.2 million was recognized on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs" for the six months ended June 30, 2019.

Employee Investment Plan

QEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (the 401(k) Plan). The 401(k) Plan allows eligible employees to make investments, including purchasing shares of QEP common stock, through payroll deduction at the current fair market value on the transaction date. Both employees and QEP make contributions to the 401(k) Plan. The Company may contribute a discretionary portion beyond the Company's matching contribution to employees not in the Pension Plan or SERP. During the six months ended June 30, 2019, the Company made contributions of $2.6 million to the 401(k) Plan and expects to contribute an additional $1.8 million to the 401(k) Plan during the remainder of 2019. The Company recognizes expense equal to its yearly contributions. Due to the Company's strategic initiatives, the amount to be contributed to the 401(k) Plan may change. Refer to Note 9 – Restructuring for more information.

As a result of freezing benefits under the Pension Plan, the 401(k) Plan and a nonqualified, unfunded deferred compensation plan (the Wrap Plan) were amended to allow the Company to make discretionary contributions (Company Transition Credits) to eligible participants. Eligible participants are certain employees who were active participants in the Pension Plan on December 31, 2015. During the six months ended June 30, 2019, the Company did not make a discretionary contribution to active participants of the Pension Plan but expects to contribute $0.1 million to eligible participants during the fourth quarter of 2019.

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Subsequent Event (Notes)

6 Months Ended

Jun. 30, 2019

Subsequent Event [Line Items]

Subsequent Events [Text Block]

Subsequent to June 30, 2019, QEP's Board of Directors completed its comprehensive review of strategic alternatives and determined that the best alternative for QEP's shareholders is to move forward as an independent company. The Company is not able to reasonably estimate the future costs to be incurred in connection with the review of strategic alternatives.

On August 6, 2019, QEP's Board of Directors approved the reinstatement of a quarterly cash dividend of $0.02 per share of common stock, payable on September 10, 2019 to shareholders of record on August 20, 2019.

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Basis of Presentation Restricted Cash (Tables)

6 Months Ended

Jun. 30, 2019

Restricted Cash [Abstract]

Restrictions on Cash and Cash Equivalents [Table Text Block]

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

	June 30,
	2019		2018
	(in millions)
Cash and cash equivalents	$	97.1	$	—
Restricted cash(1)	29.2		26.1
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	126.3	$	26.1

_______________________

⁽¹⁾ As of June 30, 2019 and 2018, the restricted cash balance is cash held in an escrow account related to a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet

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Revenue (Tables)

6 Months Ended

Jun. 30, 2019

Revenue Recognition [Abstract]

Revenue Recognition [Table Text Block]

The following tables present QEP's revenues that are disaggregated by revenue source and by geographic area. Transportation and processing costs in the following table are not all of the transportation and processing costs that QEP 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 June 30, 2019
Northern Region
Williston Basin	$	107.5	$	7.5		$	5.8	$	(8.9	)	$	111.9
Other Northern	0.5		0.1			—		—			0.6
Southern Region
Permian Basin	177.6		(0.6		)	8.5		(3.8		)	181.7
Other Southern	0.1		0.3			—		—			0.4
Total oil and condensate, gas and NGL sales	$	285.7	$	7.3		$	14.3	$	(12.7	)	$	294.6
	Three Months Ended June 30, 2018
Northern Region
Williston Basin	$	207.6	$	8.4		$	14.7	$	(10.7	)	$	220.0
Uinta Basin	9.5		7.9			1.7		—			19.1
Other Northern	0.9		0.2			0.1		—			1.2
Southern Region
Permian Basin	190.3		3.2			9.9		(1.7		)	201.7
Haynesville/Cotton Valley	0.2		77.9			—		—			78.1
Other Southern	—		0.2			—		—			0.2
Total oil and condensate, gas and NGL sales	$	408.5	$	97.8		$	26.4	$	(12.4	)	$	520.3

	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)
	Six Months Ended June 30, 2019
Northern Region
Williston Basin	$	217.4		$	20.0	$	13.2		$	(19.0	)	$	231.6
Other Northern	0.9			0.3		—			—			1.2
Southern Region
Permian Basin	316.8			4.0		18.0			(7.5		)	331.3
Other Southern	0.1			6.0		—			—			6.1
Total oil and condensate, gas and NGL sales	$	535.2		$	30.3	$	31.2		$	(26.5	)	$	570.2
	Six Months Ended June 30, 2018
Northern Region
Williston Basin	$	368.1		$	18.2	$	26.5		$	(20.6	)	$	392.2
Uinta Basin	17.9			18.0		3.4			—			39.3
Other Northern	2.8			1.2		(0.1		)	—			3.9
Southern Region
Permian Basin	320.1			7.8		16.4			(4.5		)	339.8
Haynesville/Cotton Valley	0.6			154.3		—			—			154.9
Other Southern	(0.3		)	0.3		—			—			—
Total oil and condensate, gas and NGL sales	$	709.2		$	199.8	$	46.2		$	(25.1	)	$	930.1

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Acquisitions & Divestitures Schedule of Assets and Liabilities Held for Sale (Tables)

12 Months Ended

Dec. 31, 2018

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

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

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

	December 31, 2018(1)
	(in millions)
Assets
Current assets, total	$	1.2
Net Property, Plant and Equipment	683.7
Other noncurrent assets	7.8
Noncurrent assets held for sale	$	692.7
Liabilities
Current liabilities, total	$	3.4
Asset retirement obligations, current	0.7
Asset retirement obligations, long-term	56.9
Other long-term liabilities	0.3
Other long-term liabilities held for sale	$	61.3

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2019

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		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	238.0	237.0	237.5	238.9
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—	—
Average diluted common shares outstanding	238.0	237.0	237.5	238.9

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

	Asset Retirement Obligations
	June 30,		December 31,
	2019		2018
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.8	$	5.1
Long-term:
Asset retirement obligations	94.6		96.9
Other long-term liabilities held for sale	—		57.6
Total ARO Liability	$	101.4	$	159.6

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

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

	Asset Retirement Obligations
	(in millions)
ARO liability at January 1, 2019	$	159.6
Accretion	3.1
Additions	0.4
Revisions	(0.3		)
Liabilities related to assets sold(1)	(60.7		)
Liabilities settled	(0.7		)
ARO liability at June 30, 2019	$	101.4

_______________________

⁽¹⁾ 

Liabilities related to assets sold during the six months ended June 30, 2019, includes $57.6 million related to the Haynesville Divestiture (refer to Note 3 – Acquisitions and Divestitures for more information).

^[1]

[1] ⁽¹⁾  Liabilities related to assets sold during the six months ended June 30, 2019, includes $57.6 million related to the Haynesville Divestiture (refer to Note 3 – Acquisitions and Divestitures for more information).

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2019

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 June 30, 2019 and December 31, 2018, 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
	(in millions)
Financial Assets	June 30, 2019
Fair value of derivative contracts – short-term	$	—	$	2.7	$	—	$	—		$	2.7
Fair value of derivative contracts – long-term	—		15.2		—		—			15.2
Total financial assets	$	—	$	17.9	$	—	$	—		$	17.9
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	17.6	$	—	$	—		$	17.6
Fair value of derivative contracts – long-term	—		0.9		—		—			0.9
Total financial liabilities	$	—	$	18.5	$	—	$	—		$	18.5
	December 31, 2018
Financial Assets
Fair value of derivative contracts – short-term(2)	$	—	$	88.2	$	—	$	(0.4	)	$	87.8
Fair value of derivative contracts – long-term	—		35.4		—		—			35.4
Total financial assets	$	—	$	123.6	$	—	$	(0.4	)	$	123.2
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	0.4	$	—	$	(0.4	)	$	—
Fair value of derivative contracts – long-term	—		0.7		—		—			0.7
Total financial liabilities	$	—	$	1.1	$	—	$	(0.4	)	$	0.7

_______________________

⁽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]

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
	June 30, 2019				December 31, 2018
Financial Assets	(in millions)
Cash and cash equivalents	$	97.1	$	97.1	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	5.3	$	5.3	$	14.6	$	14.6
Total debt outstanding	$	2,079.8	$	2,042.5	$	2,507.1	$	2,350.5

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Derivative Contracts (Tables)

6 Months Ended

Jun. 30, 2019

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 June 30, 2019:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	6.6	$	55.24
2019	ICE Brent	0.9	$	66.73
2019	Argus WTI Houston	0.2	$	65.70
2020	NYMEX WTI	6.2	$	60.07
2020	Argus WTI Midland	0.7	$	60.00

QEP uses oil basis swaps, combined with NYMEX WTI fixed-price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil basis swaps as of June 30, 2019:

Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2019	NYMEX WTI	Argus WTI Midland	3.3	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.9	$	3.69
2020	NYMEX WTI	Argus WTI Midland	4.4	$	(0.02	)
2020 (January - June)	NYMEX WTI	Argus WTI Houston	0.4	$	3.75

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

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	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
Current:		(in millions)
Commodity(1)	Fair value of derivative contracts	$	2.7	$	88.2	$	17.6	$	0.4
Long-term:
Commodity	Fair value of derivative contracts	15.2		35.4		0.9		0.7
Total derivative instruments		$	17.9	$	123.6	$	18.5	$	1.1

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

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						Six Months Ended
Derivative contracts	June 30,						June 30,
	2019			2018			2019			2018
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(16.0	)	$	(52.0	)	$	(19.0	)	$	(96.3	)
Gas derivative contracts	—			6.4			(2.9		)	7.3
Gas Storage
Gas derivative contracts	—			0.1			—			0.3
Realized gains (losses) on commodity derivative contracts	(16.0		)	(45.5		)	(21.9		)	(88.7		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	54.5			(20.6		)	(122.8		)	(27.5		)
Gas derivative contracts	—			(13.0		)	(0.3		)	(15.8		)
Gas Storage
Gas derivative contracts	—			—			—			(0.3		)
Unrealized gains (losses) on commodity derivative contracts	54.5			(33.6		)	(123.1		)	(43.6		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	38.5		$	(79.1	)	$	(145.0	)	$	(132.3	)
Derivatives associated with Haynesville Divestiture
Unrealized gains (losses) on commodity derivative contracts
Production
Gas derivative contracts	—			—			1.8			—
Unrealized gains (losses) on commodity derivative contracts related to divestitures(1)	$	—		$	—		$	1.8		$	—
Total realized and unrealized gains (losses) on commodity derivative contracts	$	38.5		$	(79.1	)	$	(143.2	)	$	(132.3	)

_______________________

⁽¹⁾ 

During the three and six months ended June 30, 2019, the unrealized gains (losses) on commodity derivative contracts related to the Haynesville Divestiture were comprised of derivatives included as part of the Haynesville/Cotton Valley purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in January 2019. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Haynesville Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

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Leases (Tables)

6 Months Ended

Jun. 30, 2019

Lessee, Lease, Description [Line Items]

Lease, Cost [Table Text Block]

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

	Three Months Ended		Six Months Ended
	June 30, 2019(1)		June 30, 2019(1)
Lease Cost included in the Condensed Consolidated Balance Sheets	(in millions)
Property, Plant and Equipment acquisitions(2)	$	4.1	$	8.8
	Three Months Ended		Six Months Ended
	June 30, 2019(1)		June 30, 2019(1)
Lease Cost included in the Condensed Consolidated Statement of Operations	(in millions)
Lease operating expense	$	3.0	$	6.1
Gathering and other expense	2.3		3.8
General and administrative	1.6		3.2
Total lease cost	$	11.0	$	21.9

 ____________________________

⁽¹⁾  Prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective method for the new lease recognition rule. Refer to Note 1 – Basis of Presentation for additional information.

⁽²⁾  Represents short-term lease capital expenditures related to drilling rigs for the three and six months ended June 30, 2019. These costs are capitalized as a part of "Proved properties" on the Condensed Consolidated Balance Sheets.

Lessee, Operating Leases [Text Block]

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

	Three Months Ended		Six Months Ended
	June 30, 2019(1)		June 30, 2019(1)
Weighted-average remaining lease term (years)	3.6		3.6
Weighted-average discount rate	7.7	%	7.7	%

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Restructuring Costs Restructuring Costs (Tables)

6 Months Ended

Jun. 30, 2019

Restructuring and Related Activities [Abstract]

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

Restructuring costs recognized 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)"
	Three Months Ended June 30, 2019
	(in millions)
Termination benefits	$	(0.1	)	$	(0.1	)	$	—		$	—
Office lease termination costs	—			—			—			—
Accelerated share-based compensation(1)	1.3			1.3			—			—
Retention expense (including share-based compensation)	4.8			4.8			—			—
Pension and Medical Plan curtailment	0.1			—			—			0.1
Total restructuring costs	$	6.1		$	6.0		$	—		$	0.1
	Six Months Ended June 30, 2019
Termination benefits	$	6.7		$	6.6		$	0.1		$	—
Office lease termination costs	0.6			0.6			—			—
Accelerated share-based compensation(1)	9.7			8.2			1.5			—
Retention expense (including share-based compensation)	10.9			10.9			—			—
Pension and Medical Plan curtailment	(0.4		)	—			(0.2		)	(0.2		)
Total restructuring costs	$	27.5		$	26.3		$	1.4		$	(0.2	)
	Three Months Ended June 30, 2018
Termination benefits	$	3.6		$	1.7		$	1.9		—
Office lease termination costs	0.3			0.3			—			—
Accelerated share-based compensation	1.2			1.2			—			—
Retention expense (including share-based compensation)	6.3			6.3			—			—
Total restructuring costs	$	11.4		$	9.5		$	1.9		$	—
	Six Months Ended June 30, 2018
Termination benefits	$	7.0		$	5.1		$	1.9		—
Office lease termination costs	0.3			0.3			—			—
Accelerated share-based compensation	4.0			4.0			—			—
Retention expense (including share-based compensation)	8.0			8.0			—			—
Total restructuring costs	$	19.3		$	17.4		$	1.9		$	—

Restructuring Costs [Table Text Block]

	Costs recognized from inception to June 30, 2019(1)			Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	38.9		$	—	(2)
Office lease termination costs	1.6			—		(2)
Accelerated share-based compensation	21.0			—		(2)
Retention expense (including share-based compensation)	29.7			10.1
Pension and Medical Plan curtailment	(0.2		)	—		(2)
Total restructuring costs	$	91.0		$	10.1

 ____________________________

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

⁽²⁾  Due to the nature of the strategic initiatives, as of June 30, 2019, the Company is not able to reasonably estimate the total cost to be incurred in connection with these restructurings.

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, 2018	$	19.5		$	—		$	—		$	10.8		$	—		$	30.3
Costs incurred and charged to expense	6.7			0.6			9.7			10.9			(0.4		)	27.5
Costs paid or otherwise settled	(23.9		)	(0.6		)	(9.7		)	(15.9		)	0.4			(49.7		)
Balance at June 30, 2019	$	2.3		$	—		$	—		$	5.8		$	—		$	8.1

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Debt (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Debt Outstanding [Table Text Block]

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

	June 30, 2019			December 31, 2018
	(in millions)
Revolving Credit Facility due 2022	$	—		$	430.0
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	(19.5		)	(22.2		)
Total principal amount of debt (including current portion)	2,079.8			2,507.1
Less: current portion of long-term debt	(51.7		)	—
Total long-term debt outstanding	$	2,028.1		$	2,507.1

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Commitments and Contingencies Minimum Lease Payments (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Schedule of Future Minimum Rental Payments Including Imputed Interest [Table Text Block]

As of June 30, 2019, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC 842 are as follows:

Year	Amount
	(in millions)
2019	$	12.4
2020	$	21.1
2021	$	19.4
2022	$	14.9
2023	$	9.4
After 2023	$	0.5
Less: Interest(1)	$	(11.0	)
Present value of lease liabilities(2)	$	66.7

 ____________________________

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

⁽²⁾ 

Of the total present value of lease liabilities, $18.8 million was recorded in "Current operating lease liabilities" and $47.9 million was recorded in "Operating lease liabilities" on the Condensed Consolidated Balance Sheets.

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

As of December 31, 2018, minimum future contractual payments for long-term operating leases under the scope of ASC 840 are as follows:

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

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Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2019

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

Share-based Compensation Expense [Table Text Block]

Share-based compensation expense is generally recognized within "General and administrative" expense on the Condensed Consolidated Statements of Operations and is summarized in the table below. During the three and six months ended June 30, 2019, the Company recorded an additional $1.3 million and $9.7 million, respectively, of share-based compensation expense related to the acceleration of vesting that occurred as part of the restructuring program, of which $1.5 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statement of Operations during the six months ended June 30, 2019 and the remaining $1.3 million and $8.2 million, respectively, is included in the table below. During the three and six months ended June 30, 2018, the Company recorded an additional $1.2 million and $4.0 million, respectively of share-based compensation expense, related to the acceleration of vesting that occurred as part of the restructuring program, all of which is included in the table below. Refer to Note 9 – Restructuring for additional information.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(in millions)
Stock options	$	—	$	0.2	$	0.3	$	0.7
Restricted share awards	4.8		6.8		10.9		15.6
Performance share units	0.3		5.1		5.5		7.0
Restricted share units	0.1		0.1		0.2		0.1
Total share-based compensation expense	$	5.2	$	12.2	$	16.9	$	23.4

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, 2018	2,098,933		$	22.27
Cancelled	(283,029	)	30.90
Outstanding at June 30, 2019	1,815,904		$	20.93	2.80	$	—
Options Exercisable at June 30, 2019	1,761,139		$	21.08	2.74	$	—
Unvested Options at June 30, 2019	54,765		$	15.92	4.69	$	—

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, 2018	3,822,133		$	10.76
Granted	2,217,794		7.98
Vested	(2,261,323	)	11.05
Forfeited	(178,985	)	9.23
Unvested balance at June 30, 2019	3,599,619		$	8.94

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

	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2018	42,675		$	10.47
Granted	37,224		7.93
Vested and paid	(36,392	)	10.67
Unvested balance at June 30, 2019	43,507		$	8.16

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, 2018	1,559,312		$	11.47
Granted	589,412		7.93
Vested and paid	(1,117,848	)	10.73
Unvested balance at June 30, 2019	1,030,876		$	9.63

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Employee Benefits (Tables)

6 Months Ended

Jun. 30, 2019

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						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Pension Plan and SERP benefits	(in millions)
Service cost	$	—		$	0.2		$	0.1		$	0.4
Interest cost	1.2			1.1			2.4			2.2
Expected return on plan assets	(1.4		)	(1.5		)	(2.9		)	(2.9		)
Amortization of prior service costs(1)	0.1			0.2			0.2			0.4
Amortization of actuarial losses(1)	—			0.3			0.1			0.6
Curtailment (gain) loss(2)	0.1			—			0.4			—
Periodic expense	$	—		$	0.3		$	0.3		$	0.7
Medical Plan benefits
Interest cost	$	0.1		$	0.1		$	0.1		$	0.1
Amortization of prior service costs(1)	—			—			—			(0.1		)
Curtailment (gain) loss(2)	—			—			(0.8		)	—
Periodic expense	$	0.1		$	0.1		$	(0.7	)	$	—

____________________________

⁽¹⁾  Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income (loss) 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. The net curtailment gain between the SERP and Medical Plan of $0.4 million is related to the Haynesville Divestiture and corporate restructuring activities. Of the $0.4 million curtailment gain recognized, $0.2 million was recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)" and $0.2 million was recognized on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs" for the six months ended June 30, 2019.

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Basis of Presentation ImpaIrment of Long Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 0.0	$ 403.7	$ 5.0	$ 404.4
Impairment of Leasehold				1.6
Uinta Basin Divestiture [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment				$ 402.8

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Basis of Presentation Restricted Cash (Details) - USD ($) $ in Millions		Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2017
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents		$ 97.1	$ 0.0	$ 0.0
Restricted cash(1)	[1]	29.2		26.1
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows		$ 126.3	$ 28.1	$ 26.1	$ 23.4

[1] As of June 30, 2019 and 2018, the restricted cash balance is cash held in an escrow account related to a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Condensed Consolidated Balance Sheets.

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Revenue Disaggregated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenue from Contract with Customer, Including Assessed Tax	$ 296.2	$ 532.4	$ 576.8	$ 961.3
Oil and Condensate [Member] | As reported [Member] | Williston Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax	107.5	207.6	217.4	368.1
Oil and Condensate [Member] | As reported [Member] | Uinta Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax		9.5		17.9
Oil and Condensate [Member] | As reported [Member] | Other Northern [Member]
Revenue from Contract with Customer, Including Assessed Tax	0.5	0.9	0.9	2.8
Oil and Condensate [Member] | As reported [Member] | Permian Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax	177.6	190.3	316.8	320.1
Oil and Condensate [Member] | As reported [Member] | Haynesville/Cotton Valley [Member]
Revenue from Contract with Customer, Including Assessed Tax		0.2		0.6
Oil and Condensate [Member] | As reported [Member] | Other Southern [Member]
Revenue from Contract with Customer, Including Assessed Tax	0.1	0.0	0.1	(0.3)
Oil and Condensate [Member] | As reported [Member] | Total [Member]
Revenue from Contract with Customer, Including Assessed Tax	285.7	408.5	535.2	709.2
Natural Gas [Member] | As reported [Member] | Williston Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax	7.5	8.4	20.0	18.2
Natural Gas [Member] | As reported [Member] | Uinta Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax		7.9		18.0
Natural Gas [Member] | As reported [Member] | Other Northern [Member]
Revenue from Contract with Customer, Including Assessed Tax	0.1	0.2	0.3	1.2
Natural Gas [Member] | As reported [Member] | Permian Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax	(0.6)	3.2	4.0	7.8
Natural Gas [Member] | As reported [Member] | Haynesville/Cotton Valley [Member]
Revenue from Contract with Customer, Including Assessed Tax		77.9		154.3
Natural Gas [Member] | As reported [Member] | Other Southern [Member]
Revenue from Contract with Customer, Including Assessed Tax	0.3	0.2	6.0	0.3
Natural Gas [Member] | As reported [Member] | Total [Member]
Revenue from Contract with Customer, Including Assessed Tax	7.3	97.8	30.3	199.8
Natural Gas, Midstream [Member] | As reported [Member] | Williston Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax	5.8	14.7	13.2	26.5
Natural Gas, Midstream [Member] | As reported [Member] | Uinta Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax		1.7		3.4
Natural Gas, Midstream [Member] | As reported [Member] | Other Northern [Member]
Revenue from Contract with Customer, Including Assessed Tax	0.0	0.1	0.0	(0.1)
Natural Gas, Midstream [Member] | As reported [Member] | Permian Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax	8.5	9.9	18.0	16.4
Natural Gas, Midstream [Member] | As reported [Member] | Haynesville/Cotton Valley [Member]
Revenue from Contract with Customer, Including Assessed Tax		0.0		0.0
Natural Gas, Midstream [Member] | As reported [Member] | Other Southern [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0	0.0	0.0
Natural Gas, Midstream [Member] | As reported [Member] | Total [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	14.3	26.4	31.2	46.2
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | As reported [Member] | Williston Basin [Member]
Cost of Goods and Services Sold	(8.9)	(10.7)	(19.0)	(20.6)
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | As reported [Member] | Uinta Basin [Member]
Cost of Goods and Services Sold		0.0		0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | As reported [Member] | Other Northern [Member]
Cost of Goods and Services Sold	0.0	0.0	0.0	0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | As reported [Member] | Permian Basin [Member]
Cost of Goods and Services Sold	(3.8)	(1.7)	(7.5)	(4.5)
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | As reported [Member] | Haynesville/Cotton Valley [Member]
Cost of Goods and Services Sold		0.0		0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | As reported [Member] | Other Southern [Member]
Cost of Goods and Services Sold	0.0	0.0	0.0	0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | As reported [Member] | Total [Member]
Cost of Goods and Services Sold	(12.7)	(12.4)	(26.5)	(25.1)
Oil and Gas, Exploration and Production [Member]
Revenue from Contract with Customer, Including Assessed Tax	294.6	520.3	570.2	930.1
Oil and Gas, Exploration and Production [Member] | As reported [Member] | Williston Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax	111.9	220.0	231.6	392.2
Oil and Gas, Exploration and Production [Member] | As reported [Member] | Uinta Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax		19.1		39.3
Oil and Gas, Exploration and Production [Member] | As reported [Member] | Other Northern [Member]
Revenue from Contract with Customer, Including Assessed Tax	0.6	1.2	1.2	3.9
Oil and Gas, Exploration and Production [Member] | As reported [Member] | Permian Basin [Member]
Revenue from Contract with Customer, Including Assessed Tax	181.7	201.7	331.3	339.8
Oil and Gas, Exploration and Production [Member] | As reported [Member] | Haynesville/Cotton Valley [Member]
Revenue from Contract with Customer, Including Assessed Tax		78.1		154.9
Oil and Gas, Exploration and Production [Member] | As reported [Member] | Other Southern [Member]
Revenue from Contract with Customer, Including Assessed Tax	0.4	0.2	6.1	0.0
Oil and Gas, Exploration and Production [Member] | As reported [Member] | Total [Member]
Revenue from Contract with Customer, Including Assessed Tax	$ 294.6	$ 520.3	$ 570.2	$ 930.1

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Acquisitions & Divestitures Acquisitions (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 666.7	$ 48.8
Payments to acquire oil and gas property	$ 1.8	45.1
Permian Basin [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property		$ 37.5

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Acquisitions & Divestitures Uinta Basin (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended		9 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Sep. 30, 2018	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			$ 666.7	$ 48.8
Noncurrent assets held for sale	$ 0.0		0.0			$ 692.7
Gain (Loss) on Disposition of Oil and Gas Property	17.8	$ (3.9)	4.6	(0.4)
Impairment	0.0	403.7	5.0	404.4
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				402.8
Uinta Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Results of Operations, Loss before Income Taxes	$ 0.3	$ 409.9	$ 0.2	$ 414.9

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Acquisitions & Divestitures Pinedale Divestiture (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2017
Divestitures [Line Items]
Proceeds from disposition of assets			$ 666.7	$ 48.8
Net gain (loss) from asset sales, inclusive of restructuring costs	$ 17.8	$ (3.9)	4.6	(0.4)
Income (loss) before income taxes	78.5	$ (442.2)	(150.2)	$ (509.7)
Pinedale Divestiture [Member]
Divestitures [Line Items]
Proceeds from disposition of assets					$ 718.2
Net gain (loss) from asset sales, inclusive of restructuring costs			0.8
Minimum volume commitment			45.0
Minimum volume commitment remaining	$ 2.0		$ 2.0

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Acquisitions & Divestitures Other Divestitures (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Divestitures [Line Items]
Proceeds from disposition of assets			$ 666.7	$ 48.8
Net gain (loss) from asset sales, inclusive of restructuring costs	$ 17.8	$ (3.9)	4.6	(0.4)
Non-core properties Divestitures [Member]
Divestitures [Line Items]
Proceeds from disposition of assets			39.7	48.8
Net gain (loss) from asset sales, inclusive of restructuring costs			$ 5.5	$ 0.7

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Acquisitions & Divestitures Haynesville Divestiture (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Business Acquisition [Line Items]
Noncurrent assets held for sale	$ 0.0	$ 692.7		$ 0.0
Payments to acquire oil and gas property				1.8	$ 45.1
Proceeds from Sale of Oil and Gas Property and Equipment				666.7	48.8
Gain (Loss) on Disposition of Oil and Gas Property	17.8		$ (3.9)	4.6	(0.4)
Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property		634.2
Proceeds from Sale of Oil and Gas Property and Equipment				627.1
Gain (Loss) on Disposition of Oil and Gas Property	14.3	3.0		0.7
Results of Operations, Loss before Income Taxes	$ 14.4		$ 7.4	3.3	$ 19.7
Restructuring Charges				(1.4)
Property, Plant and Equipment [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Noncurrent assets held for sale		683.7
Other Noncurrent Assets [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Noncurrent assets held for sale		7.8
Noncurrent Assets Held for Sale [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Noncurrent assets held for sale		692.7
Other Current Liabilities [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Noncurrent assets held for sale		3.4
Asset Retirement Obligations, Current [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Noncurrent assets held for sale		0.7
Asset Retirement Obligations, Long Term [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Noncurrent assets held for sale		56.9
Derivative Financial Instruments, Liabilities [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Noncurrent assets held for sale		0.3
Other Noncurrent Liabilities [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Noncurrent assets held for sale		61.3
Other Current Assets [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Noncurrent assets held for sale		$ 1.2
Total incurred to date [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Oil and Gas Property				(3.7)
Accounts Receivable [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				9.5
Accounts Payable [Member] | Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				$ (2.4)

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Earnings Per Share Components of Basic and Diluted Shares Used In EPS Calculation (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	0.0	0.1	0.0	0.1
Weighted-average basic common shares outstanding	238.0	237.0	237.5	238.9
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	0.0	0.0	0.0	0.0
Average diluted common shares outstanding	238.0	237.0	237.5	238.9

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Earnings Per Share Earnings per share (non-printing) (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share [Abstract]
Anti-dilutive shares	0.0	0.1	0.0	0.1

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Asset Retirement Obligations Consolidated Balance Sheet Line Items of ARO Liability (Details) - USD ($) $ in Millions	Jun. 30, 2019	Jan. 01, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, current liability	$ 6.8		$ 5.1
Asset retirement obligations	94.6		96.9
Other long-term liabilities held for sale	0.0		57.6
Total ARO Liability	$ 101.4	$ 159.6	$ 159.6

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Asset Retirement Obligations Asset Retirement Obligations ARO Rollforward (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Divestitures [Line Items]
ARO liability at January 1, 2019	$ 159.6
Accretion	3.1
Additions	0.4
Revisions	(0.3)
Liabilities related to assets sold(1)	(60.7)
Liabilities settled	(0.7)
ARO Liability at June 30, 2019	101.4
Haynesville Divestiture [Member]
Divestitures [Line Items]
Liabilities related to assets sold(1)	$ 57.6

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Fair Value Measurements Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions		Jun. 30, 2019	Dec. 31, 2018
Financial Assets
Derivative Asset, Netting Adjustments	[1]	$ 0.0	$ (0.4)
Derivative Asset, Net		17.9	123.2
Financial liabilities
Derivative Liability, Netting Adjustments	[1]	0.0	(0.4)
Derivative Liability, Net		18.5	0.7
Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Fair Value, Inputs, Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		17.9	123.6
Financial liabilities
Derivative Liability, Fair Value, Gross		18.5	1.1
Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Noncurrent Assets Held for Sale [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			0.3
Long-term [Member]
Financial Assets
Derivative Asset, Netting Adjustments	[1]	0.0	0.0
Derivative Asset, Net		15.2	35.4
Financial liabilities
Derivative Liability, Netting Adjustments	[1]	0.0	0.0
Derivative Liability, Net		0.9	0.7
Long-term [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Long-term [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		15.2	35.4
Financial liabilities
Derivative Liability, Fair Value, Gross		0.9	0.7
Long-term [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Short-term [Member]
Financial Assets
Derivative Asset, Netting Adjustments	[1]	0.0	(0.4)
Derivative Asset, Net		2.7	87.8
Financial liabilities
Derivative Liability, Netting Adjustments	[1]	0.0	(0.4)
Derivative Liability, Net		17.6	0.0
Short-term [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Short-term [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		2.7	88.2
Financial liabilities
Derivative Liability, Fair Value, Gross		17.6	0.4
Short-term [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		$ 0.0	$ 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.

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Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 97.1	$ 0.0	$ 0.0
Checks outstanding in excess of cash balances	5.3	14.6
Debt, Long-term and Short-term, Combined Amount	2,079.8	2,507.1
Long-term debt	2,028.1	2,507.1
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	97.1	0.0
Checks outstanding in excess of cash balances	5.3	14.6
Long-term debt, fair value	$ 2,042.5	$ 2,350.5

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Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment	$ 0.0	$ 403.7	$ 5.0	$ 404.4
Proved Property [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Oil and Gas Properties			$ 5.0	$ 397.6

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Derivative Contracts (Narrative) (Details)	6 Months Ended
	Jun. 30, 2019
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%

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Derivative Contracts Schedule Of Commodity Derivative Contracts (Details) MMBTU in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) MMBTU $ / MMBTU	Dec. 31, 2018 USD ($)
Oil Swaps [Member] | Year 2019 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	6.6
Average Swap Price per Unit | $	$ 55.24
Oil Swaps [Member] | Year 2019 [Member] | Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	0.7
Average Swap Price per Unit | $	$ 60.00
Oil Swaps [Member] | Year 2019 [Member] | ICE Brent [Member]
Derivative [Line Items]
Derivative Volumes	0.9
Average Swap Price per Unit | $	$ 66.73
Oil Swaps [Member] | Year 2019 [Member] | Argus WTI Houston [Member]
Derivative [Line Items]
Derivative Volumes	0.2
Average Swap Price per Unit | $	$ 65.70
Oil Swaps [Member] | Year 2020 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	6.2
Average Swap Price per Unit | $	$ 60.07
Oil Basis Swaps [Member] | Year 2019 [Member] | NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	3.3
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	0.9
Weighted-Average Differential | $ / MMBTU	3.69
Oil Basis Swaps [Member] | Year 2020 [Member] | NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	4.4
Weighted-Average Differential | $ / MMBTU	(0.02)
Oil Basis Swaps [Member] | Year 2020 [Member] | NYMEX WTI less Argus WTI Houston [Member]
Derivative [Line Items]
Derivative Volumes	0.4
Weighted-Average Differential | $ / MMBTU	3.75
Fair Value, Inputs, Level 2 [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross | $	$ 17,900,000	$ 123,600,000
Fair Value, Inputs, Level 2 [Member] | Noncurrent Assets Held for Sale [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross | $		$ 300,000

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Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Inputs, Level 2 [Member] - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	$ 17.9	$ 123.6
Derivative Liability, Fair Value, Gross	18.5	1.1
Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	2.7	88.2
Derivative Liability, Fair Value, Gross	17.6	0.4
Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	15.2	35.4
Derivative Liability, Fair Value, Gross	0.9	0.7
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	17.9	123.6
Derivative Liability, Fair Value, Gross	18.5	1.1
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	2.7	88.2
Derivative Liability, Fair Value, Gross	17.6	0.4
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	15.2	35.4
Derivative Liability, Fair Value, Gross	$ 0.9	$ 0.7

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Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	$ (16.0)	$ (45.5)	$ (21.9)	$ (88.7)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	38.5	(79.1)	(143.2)	(132.3)
Oil derivative contracts [Member] | Production [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	(16.0)	(52.0)	(19.0)	(96.3)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	54.5	(20.6)	(122.8)	(27.5)
Gas derivative contracts [Member] | Production [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	6.4	(2.9)	7.3
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	(13.0)	(0.3)	(15.8)
Gas derivative contracts [Member] | Storage [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.1	0.0	0.3
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.0	0.0	(0.3)
Total [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	54.5	(33.6)	(123.1)	(43.6)
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	38.5	(79.1)	(145.0)	(132.3)
Uinta Basin Divestiture [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0		1.8
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		$ 1.8
Pinedale Divestiture [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		0.0		0.0
Pinedale 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

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Leases (Details) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)
Lessor, Lease, Description [Line Items]
Lease, Cost	$ 11.0	$ 21.9
Operating Lease, Weighted Average Remaining Lease Term	3 years 7 months 6 days	3 years 7 months 6 days
Operating Lease, Weighted Average Discount Rate, Percent	7.70%	7.70%
Property, Plant and Equipment [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	$ 4.1	$ 8.8
Lease Operating Expense [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	3.0	6.1
Gathering and other expense [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	2.3	3.8
General and Administrative Expense [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	$ 1.6	$ 3.2

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Restructuring Costs Restructuring Expense Table (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Other Nonoperating Income (Expense) [Member]
Total restructuring costs	$ 0.1		$ (0.2)
Other Expense [Member]
Total restructuring costs		$ 0.0		$ 0.0
Termination Benefits [Member]
Costs recognized period from inception to June 30, 2019(1)	38.9		38.9
Total remaining costs expected to be incurred			0.0
Office lease Termination Costs [Member]
Costs recognized period from inception to June 30, 2019(1)	1.6		1.6
Total remaining costs expected to be incurred			0.0
Accelerated Share Based Compensation [Member]
Costs recognized period from inception to June 30, 2019(1)	21.0		21.0
Total remaining costs expected to be incurred			0.0
Retention Expense [Member]
Costs recognized period from inception to June 30, 2019(1)	29.7		29.7
Total remaining costs expected to be incurred			10.1
Pension curtailment [Member]
Costs recognized period from inception to June 30, 2019(1)	(0.2)		(0.2)
Total remaining costs expected to be incurred			0.0
Total [Member]
Termination benefits	(0.1)	3.6	6.7	7.0
Office lease termination costs	0.0	0.3	0.6	0.3
Accelerated share-based compensation(1)	1.3	1.2	9.7	4.0
Retention expense (including share-based compensation)	4.8	6.3	10.9	8.0
Pension and Medical Plan curtailment	0.1		(0.4)
Total restructuring costs	6.1	11.4	27.5	19.3
Costs recognized period from inception to June 30, 2019(1)	91.0		91.0
Total remaining costs expected to be incurred			10.1
General and Administrative Expense [Member]
Termination benefits	(0.1)	1.7	6.6	5.1
Office lease termination costs	0.0	0.3	0.6	0.3
Accelerated share-based compensation(1)	1.3	1.2	8.2	4.0
Retention expense (including share-based compensation)	4.8	6.3	10.9	8.0
Pension and Medical Plan curtailment	0.0		0.0
Total restructuring costs	6.0	9.5	26.3	17.4
Net gain (loss) from asset sales [Member]
Termination benefits	0.0	1.9	0.1	1.9
Office lease termination costs	0.0	0.0	0.0	0.0
Accelerated share-based compensation(1)	0.0	0.0	1.5	0.0
Retention expense (including share-based compensation)	0.0	0.0	0.0	0.0
Pension and Medical Plan curtailment	0.0		(0.2)
Total restructuring costs	0.0	1.9	1.4	1.9
Interest and other income (expense) [Member]
Termination benefits	0.0	0.0	0.0	0.0
Office lease termination costs	0.0	0.0	0.0	0.0
Accelerated share-based compensation(1)	0.0	0.0	0.0	0.0
Retention expense (including share-based compensation)	0.0	$ 0.0	0.0	$ 0.0
Pension and Medical Plan curtailment	0.1		(0.2)
Net gain (loss) from asset sales [Member] | Total [Member]
Pension and Medical Plan curtailment			(0.5)
Total incurred to date [Member]
Accelerated share-based compensation(1)	$ 2.8		$ 21.7

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Restructuring Costs Restructuring Liability (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	$ 2.3	$ 19.5
Costs incurred and charged to expense	6.7
Costs paid or otherwise settled	(23.9)
Office lease Termination Costs [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	0.0	0.0
Costs incurred and charged to expense	0.6
Costs paid or otherwise settled	(0.6)
Accelerated Share Based Compensation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	0.0	0.0
Costs incurred and charged to expense	9.7
Costs paid or otherwise settled	(9.7)
Retention Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	5.8	10.8
Costs incurred and charged to expense	10.9
Costs paid or otherwise settled	(15.9)
Pension curtailment [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	0.0	0.0
Costs incurred and charged to expense	(0.4)
Costs paid or otherwise settled	0.4
Total [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	8.1	$ 30.3
Costs incurred and charged to expense	27.5
Costs paid or otherwise settled	$ (49.7)

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Debt (Narrative) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Debt Maturity Period	5 years
Long-term Debt, Weighted Average Interest Rate, at Point in Time	4.73%
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	$ 0.0	$ 430.0
Maturity date of long-term debt	Sep. 01, 2022
Borrowing capacity	$ 1,250.0
Letters of credit outstanding	2.9	0.3
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

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Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Less unamortized discount	$ (19.5)	$ (22.2)
Debt, Long-term and Short-term, Combined Amount	2,079.8	2,507.1
Long-term debt	2,028.1	2,507.1
Total long-term debt outstanding	2,028.1	2,507.1
Less: current portion of long-term debt	(51.7)	0.0
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	0.0	430.0
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

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Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 12.4	$ 17.4
Operating Leases, Future Minimum Payments, Due in Two Years	21.1	13.8
Operating Leases, Future Minimum Payments, Due in Three Years	19.4	9.1
Operating Leases, Future Minimum Payments, Due in Four Years	14.9	7.4
Operating Leases, Future Minimum Payments, Due in Five Years	9.4	4.5
Operating Leases, Future Minimum Payments, Due Thereafter	$ 0.5	$ 0.0

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Commitments and Contingencies Minimum Lease Payments Under ASC 842 (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Current operating lease lease liabilities	$ 18.8	$ 0.0
Operating lease liabilities	47.9	0.0
Operating Leases, Future Minimum Payments Due, Next Twelve Months	12.4	17.4
Operating Leases, Future Minimum Payments, Due in Two Years	21.1	13.8
Operating Leases, Future Minimum Payments, Due in Three Years	19.4	9.1
Operating Leases, Future Minimum Payments, Due in Four Years	14.9	7.4
Operating Leases, Future Minimum Payments, Due in Five Years	9.4	4.5
Operating Leases, Future Minimum Payments, Due Thereafter	0.5	$ 0.0
Lease operating expense	(11.0)
Operating Lease, Liability	$ 66.7

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Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
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	8.3
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$ 0.1
Weighted average vesting period	9 months 10 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Restricted Share Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 7.98	$ 9.55
Unrecognized compensation costs	$ 18.8
Weighted average vesting period	2 years 3 months 21 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Total fair value of stock that vested during the period	$ 25.0	$ 24.6
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 11.4	$ 2.0
Weighted average grant date fair value, grants	$ 7.93	$ 9.55
Unrecognized compensation costs	$ 7.2
Weighted average vesting period	2 years 3 months 29 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Restricted Share Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 7.93	$ 9.55
Unrecognized compensation costs	$ 0.2
Weighted average vesting period	1 year 7 months 20 days

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Share-Based Compensation Share-based compensation expense (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	$ 5.2	$ 12.2	$ 16.9	$ 23.4
Stock Options [Member]
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	0.0	0.2	0.3	0.7
Performance Share Units [Member]
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	0.3	5.1	5.5	7.0
Restricted Shares [Member]
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	4.8	6.8	10.9	15.6
Restricted Share Units (RSUs) [Member]
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	0.1	0.1	0.2	0.1
Net gain (loss) from asset sales [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	0.0	0.0	1.5	0.0
General and Administrative Expense [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	1.3	1.2	8.2	4.0
Total [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	$ 1.3	$ 1.2	$ 9.7	$ 4.0

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Share-Based Compensation Schedule Of Stock Option Transactions (Details) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding at beginning of period | shares	2,098,933
Options canceled | shares	(283,029)
Outstanding at end of period | shares	1,815,904
Options exercisable, shares | shares	1,761,139
Unvested options, shares | shares	54,765
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted average exercise price, beginning of year | $ / shares	$ 22.27
Weighted average exercise price, canceled in period | $ / shares	30.90
Weighted average exercise price, end of year | $ / shares	20.93
Options exercisable, weighted average exercise price | $ / shares	21.08
Unvested options, weighted average exercise price | $ / shares	$ 15.92
Weighted average remaining contractual term, options outstanding	2 years 9 months 18 days
Weighted average remaining contractual term, options exercisable	2 years 8 months 26 days
Weighted average remaining contractual term, options unvested	4 years 8 months 8 days
Aggregate intrinsic value, options outstanding | $	$ 0.0
Aggregate intrinsic value, options exercisable | $	0.0
Aggregate intrinsic value, options unvested | $	$ 0.0
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years

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Share-Based Compensation Schedule of Restricted Share Awards Transactions (Details) - Restricted Share Awards [Member] - $ / shares	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	3,822,133
Shares granted	2,217,794
Shares vested	(2,261,323)
Shares forfeited	(178,985)
Unvested balance at end of period	3,599,619
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	$ 10.76
Weighted average grant date fair value, grants	7.98	$ 9.55
Weighted average grant date fair value, vested	11.05
Weighted average grant date fair value, forfeited	9.23
Weighted average grant date fair value, end of period	$ 8.94

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Share-Based Compensation Schedule Of Performance Share Unit Transactions (Details) - Performance Share Units [Member] - USD ($) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 11.4	$ 2.0
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	1,559,312
Shares granted	589,412
Shares vested	(1,117,848)
Unvested balance at end of period	1,030,876
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	$ 11.47
Weighted average grant date fair value, grants	7.93	$ 9.55
Weighted average grant date fair value, vested	10.73
Weighted average grant date fair value, end of period	$ 9.63

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Share-Based Compensation Schedule of Restricted Share Unit Transactions (Details) - Restricted Share Units (RSUs) [Member] - $ / shares	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Unvested balance at beginning of period	42,675
Shares granted	37,224
Shares vested and paid	(36,392)
Unvested balance at end of period	43,507
Weighted average grant date fair value, beginning of period	$ 10.47
Weighted average grant date fair value, grants	7.93	$ 9.55
Weighted average grant date fair value, vested	10.67
Weighted average grant date fair value, end of period	$ 8.16

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Employee Benefits (Narrative) (Details) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer		$ 5.0
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer		0.2
Estimated Future Employer Contributions in Current Fiscal Year	$ 0.3	0.3
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer		0.1
Estimated Future Employer Contributions in Current Fiscal Year	0.2	0.2
401(k) Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer		2.6
Estimated Future Employer Contributions in Current Fiscal Year	1.8	1.8
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	0.1	0.1
Total [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Medical Plan curtailment	0.1	(0.4)
Interest and other income (expense) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Medical Plan curtailment	0.1	(0.2)
Net gain (loss) from asset sales [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Medical Plan curtailment	$ 0.0	(0.2)
Restructuring Charges [Member] | Total [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Medical Plan curtailment		0.1
Net gain (loss) from asset sales [Member] | Total [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Medical Plan curtailment		$ (0.5)

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Employee Benefits Schedule of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Pension Plan and SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost		$ 0.0	$ 0.2	$ 0.1	$ 0.4
Interest cost		1.2	1.1	2.4	2.2
Expected return on plan assets		(1.4)	(1.5)	(2.9)	(2.9)
Amortization of prior service costs(1)	[1]	0.1	0.2	0.2	0.4
Amortization of actuarial losses(1)	[1]	0.0	0.3	0.1	0.6
Curtailment (gain) loss(2)	[2]	0.1	0.0	0.4	0.0
Periodic expense		0.0	0.3	0.3	0.7
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Interest cost		0.1	0.1	0.1	0.1
Amortization of prior service costs(1)	[1]	0.0	0.0	0.0	(0.1)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Curtailment	[2]	0.0	0.0	(0.8)	0.0
Periodic expense		$ 0.1	$ 0.1	$ (0.7)	$ 0.0

[1] Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income (loss) 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. The net curtailment gain between the SERP and Medical Plan of $0.4 million is related to the Haynesville Divestiture and corporate restructuring activities. Of the $0.4 million curtailment gain recognized, $0.2 million was recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)" and $0.2 million was recognized on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs" for the six months ended June 30, 2019.

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Subsequent Event (Details)	6 Months Ended
	Jun. 30, 2019 $ / shares
Subsequent Event [Line Items]
Dividends, Cash	$ 0.02