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 September 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 September 30, 2019, there were 237,791,780 shares of the registrant's common stock, $0.01 par value, outstanding. 

QEP Resources, Inc.

Form 10-Q for the Quarter Ended September 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 NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018	3
		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT SEPTEMBER 30, 2019 AND DECEMBER 31, 2018	4
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF EQUITY FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018	5
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 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	30
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	50
	ITEM 4.	CONTROLS AND PROCEDURES	54
PART II. OTHER INFORMATION			54
	ITEM 1.	LEGAL PROCEEDINGS	54
	ITEM 1A.	RISK FACTORS	55
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	56
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	56
	ITEM 4.	MINE SAFETY DISCLOSURES	56
	ITEM 5.	OTHER INFORMATION	56
	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						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	305.6		$	544.0		$	875.8		$	1,474.1
Other revenues	1.8			3.8			7.1			11.8
Purchased oil and gas sales	0.1			13.0			1.4			36.2
Total Revenues	307.5			560.8			884.3			1,522.1
OPERATING EXPENSES
Purchased oil and gas expense	0.1			13.3			1.5			38.6
Lease operating expense	38.3			64.6			135.5			203.6
Transportation and processing costs	18.0			28.0			38.8			93.2
Gathering and other expense	3.1			4.6			9.9			10.8
General and administrative	29.6			48.3			124.4			164.2
Production and property taxes	20.0			37.4			67.6			103.9
Depreciation, depletion and amortization	144.2			234.9			395.5			673.6
Exploration expenses	—			—			—			0.1
Impairment	—			—			5.0			404.4
Total Operating Expenses	253.3			431.1			778.2			1,692.4
Net gain (loss) from asset sales, inclusive of restructuring costs	(2.1		)	27.1			2.5			26.7
OPERATING INCOME (LOSS)	52.1			156.8			108.6			(143.6		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	87.4			(108.0		)	(55.8		)	(240.3		)
Interest and other income (expense)	0.9			(0.3		)	4.6			(4.1		)
Interest expense	(32.8		)	(38.7		)	(100.0		)	(111.9		)
INCOME (LOSS) BEFORE INCOME TAXES	107.6			9.8			(42.6		)	(499.9		)
Income tax (provision) benefit	(26.6		)	(2.5		)	55.7			117.6
NET INCOME (LOSS)	$	81.0		$	7.3		$	13.1		$	(382.3	)
Earnings (loss) per common share
Basic	$	0.34		$	0.03		$	0.06		$	(1.60	)
Diluted	$	0.34		$	0.03		$	0.06		$	(1.60	)
Weighted-average common shares outstanding
Used in basic calculation	237.9			236.9			237.7			238.3
Used in diluted calculation	237.9			237.0			237.7			238.3

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

2

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019			2018
	(in millions)
Net income (loss)	$	81.0	$	7.3	$	13.1		$	(382.3	)
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		0.2		0.2			0.4
Amortization of actuarial losses(3)	—		0.1		0.1			0.5
Net curtailment(4)	—		—		(0.3		)	—
Other comprehensive income (loss)	0.1		0.3		—			1.2
Comprehensive income (loss)	$	81.1	$	7.6	$	13.1		$	(381.1	)

____________________________

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

⁽²⁾  Presented net of income tax expense of $0.1 million for the nine months ended September 30, 2018.

⁽³⁾  Presented net of income tax benefit of $0.1 million and expense of $0.1 million for the three and nine months ended September 30, 2018, respectively.

⁽⁴⁾  Presented net of income tax benefit of $0.1 million for the nine months ended September 30, 2019.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2019			December 31, 2018
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	92.4		$	—
Accounts receivable, net	104.3			104.3
Income tax receivable	75.5			75.9
Fair value of derivative contracts	69.8			87.5
Prepaid expenses and other current assets	8.1			12.9
Total Current Assets	350.1			280.6
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,416.9			9,096.9
Unproved properties	698.3			705.5
Gathering and other	162.7			167.7
Materials and supplies	19.3			29.9
Total Property, Plant and Equipment	10,297.2			10,000.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,153.3			4,882.4
Gathering and other	58.5			58.1
Total Accumulated Depreciation, Depletion and Amortization	5,211.8			4,940.5
Net Property, Plant and Equipment	5,085.4			5,059.5
Fair value of derivative contracts	23.2			35.4
Operating lease right-of-use assets, net	57.4			—
Other noncurrent assets	54.5			49.6
Noncurrent assets held for sale	—			692.7
TOTAL ASSETS	$	5,570.6		$	6,117.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	0.7		$	14.6
Accounts payable and accrued expenses	206.2			258.1
Production and property taxes	17.7			24.1
Current portion of long term debt	51.7			—
Interest payable	33.0			32.4
Fair value of derivative contracts	0.8			—
Current operating lease liabilities	18.4			—
Asset retirement obligations	6.7			5.1
Total Current Liabilities	335.2			334.3
Long-term debt	2,029.4			2,507.1
Deferred income taxes	208.0			269.2
Asset retirement obligations	95.5			96.9
Fair value of derivative contracts	0.4			0.7
Operating lease liabilities	45.3			—
Other long-term liabilities	86.8			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; 242.1 million and 239.8 million shares issued, respectively	2.4			2.4
Treasury stock – 4.3 million and 3.1 million shares, respectively	(54.8		)	(45.6		)
Additional paid-in capital	1,451.9			1,431.9
Retained earnings	1,384.8			1,376.5
Accumulated other comprehensive income (loss)	(14.3		)	(14.3		)
Total Common Shareholders' Equity	2,770.0			2,750.9
TOTAL LIABILITIES AND EQUITY	$	5,570.6		$	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 June 30, 2019	242.0	$	2.4	(4.1	)	$	(53.6	)	$	1,446.3	$	1,308.6		$	(14.4	)	$	2,689.3
Net income (loss)	—	—		—		—			—		81.0			—			81.0
Cash dividends declared, $0.02 per share	—	—		—		—			—		(4.8		)	—			(4.8		)
Share-based compensation	0.1	—		(0.2	)	(1.2		)	5.6		—			—			4.4
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—			0.1			0.1
Balance at September 30, 2019	242.1	$	2.4	(4.3	)	$	(54.8	)	$	1,451.9	$	1,384.8		$	(14.3	)	$	2,770.0

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)	—	—		—		—			—		13.1			—			13.1
Cash dividends declared, $0.02 per share	—	—		—		—			—		(4.8		)	—			(4.8		)
Share-based compensation	2.3	—		(1.2	)	(9.2		)	20.0		—			—			10.8
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—			—			—
Balance at September 30, 2019	242.1	$	2.4	(4.3	)	$	(54.8	)	$	1,451.9	$	1,384.8		$	(14.3	)	$	2,770.0

Balance at June 30, 2018	239.7	$	2.4	(2.7	)	$	(41.2	)	$	1,415.7	$	1,994.7	$	(10.2	)	$	3,361.4
Net income (loss)	—	—		—		—			—		7.3		—			7.3
Common stock repurchased and retired	—	—		—		—			—		—		—			—
Share-based compensation	0.1	—		(0.3	)	(3.0		)	8.9		—		—			5.9
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—		0.3			0.3
Balance at September 30, 2018	239.8	$	2.4	(3.0	)	$	(44.2	)	$	1,424.6	$	2,002.0	$	(9.9	)	$	3,374.9

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)	—		—			—		—			—		(382.3		)	—			(382.3		)
Common stock repurchased and retired	(6.2	)	(0.1		)	—		—			—		(58.3		)	—			(58.4		)
Share-based compensation	3.0		0.1			(1.0	)	(10.0		)	26.4		—			—			16.5
Change in pension and postretirement liability, net of tax	—		—			—		—			—		—			1.2			1.2
Balance at September 30, 2018	239.8		$	2.4		(3.0	)	$	(44.2	)	$	1,424.6	$	2,002.0		$	(9.9	)	$	3,374.9

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

5

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2019			2018
OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	13.1		$	(382.3	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	395.5			673.6
Deferred income taxes (benefit)	(61.2		)	(119.6		)
Impairment	5.0			404.4
Non-cash share-based compensation	16.2			24.0
Amortization of debt issuance costs and discounts	4.0			4.0
Net (gain) loss from asset sales, inclusive of restructuring costs	(2.5		)	(26.7		)
Unrealized (gains) losses on marketable securities	(2.8		)	(1.1		)
Unrealized (gains) losses on derivative contracts	29.0			113.2
Changes in operating assets and liabilities	(54.3		)	(14.6		)
Net Cash Provided by (Used in) Operating Activities	342.0			674.9
INVESTING ACTIVITIES
Property acquisitions	(3.6		)	(48.3		)
Property, plant and equipment, including exploratory well expense	(465.2		)	(1,032.1		)
Proceeds from disposition of assets	676.5			217.5
Net Cash Provided by (Used in) Investing Activities	207.7			(862.9		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(13.9		)	(28.7		)
Long-term debt issuance costs paid	—			(0.1		)
Proceeds from credit facility	56.0			2,616.0
Repayments of credit facility	(486.0		)	(2,329.5		)
Common stock repurchased and retired	—			(58.4		)
Treasury stock repurchases	(7.0		)	(7.8		)
Dividends paid	(4.8		)	—
Other capital contributions	—			0.3
Net Cash Provided by (Used in) Financing Activities	(455.7		)	191.8
Change in cash, cash equivalents and restricted cash(1)	94.0			3.8
Beginning cash, cash equivalents and restricted cash(1)	28.1			23.4
Ending cash, cash equivalents and restricted cash(1)	$	122.1		$	27.2
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	94.1		$	100.2
Cash paid for income taxes, net	$	5.0		$	0.3
Cash paid for amounts included in the measurement of lease liabilities	$	14.5		$	—
Non-cash Operating Activities:
Right-of-use assets obtained in exchange for operating lease obligations	$	11.1		$	—
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$	0.8		$	(43.9	)

____________________________

⁽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 nine months ended September 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 nine months ended September 30, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.

During the nine months ended September 30, 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment 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 primarily consist 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:

	September 30,
	2019		2018
	(in millions)
Cash and cash equivalents	$	92.4	$	—
Restricted cash(1)	29.7		27.2
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	122.1	$	27.2

_______________________

⁽¹⁾ As of September 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.

8

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, Revenue Recognition.

	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Three Months Ended September 30, 2019
Northern Region
Williston Basin	$	88.9	$	5.5	$	2.4	$	(7.0	)	$	89.8
Other Northern	—		0.1		0.1		—			0.2
Southern Region
Permian Basin	209.9		3.4		9.4		(7.2		)	215.5
Other Southern	—		0.1		—		—			0.1
Total oil and condensate, gas and NGL sales	$	298.8	$	9.1	$	11.9	$	(14.2	)	$	305.6
	Three Months Ended September 30, 2018
Northern Region
Williston Basin	$	203.4	$	12.0	$	19.2	$	(12.3	)	$	222.3
Uinta Basin	7.3		6.8		1.4		—			15.5
Other Northern	1.1		0.5		0.1		—			1.7
Southern Region
Permian Basin	204.0		5.4		21.3		(3.5		)	227.2
Haynesville/Cotton Valley	0.2		76.9		—		—			77.1
Other Southern	0.1		0.1		—		—			0.2
Total oil and condensate, gas and NGL sales	$	416.1	$	101.7	$	42.0	$	(15.8	)	$	544.0

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)
	Nine Months Ended September 30, 2019
Northern Region
Williston Basin	$	306.3		$	25.5	$	15.6	$	(26.0	)	$	321.4
Other Northern	0.9			0.4		0.1		—			1.4
Southern Region
Permian Basin	526.7			7.4		27.4		(14.7		)	546.8
Other Southern	0.1			6.1		—		—			6.2
Total oil and condensate, gas and NGL sales	$	834.0		$	39.4	$	43.1	$	(40.7	)	$	875.8
	Nine Months Ended September 30, 2018
Northern Region
Williston Basin	$	571.5		$	30.2	$	45.7	$	(32.9	)	$	614.5
Uinta Basin	25.2			24.8		4.8		—			54.8
Other Northern	3.9			1.7		—		—			5.6
Southern Region
Permian Basin	524.1			13.2		37.7		(8.0		)	567.0
Haynesville/Cotton Valley	0.8			231.2		—		—			232.0
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,125.3		$	301.5	$	88.2	$	(40.9	)	$	1,474.1

10

Note 3 – Acquisitions and Divestitures

Acquisitions

During the nine months ended September 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 $3.6 million, subject to post-closing purchase price adjustments.

During the nine months ended September 30, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $48.3 million. Of the $48.3 million, $37.6 million was related to acquisitions from various entities that owned additional oil and gas interests in certain properties included in the 2017 acquisition of oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) on substantially the same terms and conditions as the 2017 Permian Basin Acquisition.

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. QEP received net cash proceeds of $633.9 million during the nine months ended September 30, 2019. The total pre-tax loss on sale was $4.0 million, of which $1.0 million was recognized during the nine months ended September 30, 2019, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. Included in the $1.0 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, and therefore 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 nine months ended September 30, 2019, QEP accounted for revenues and expenses related to Haynesville/Cotton Valley, including the pre-tax loss on sale of $1.0 million, as income from continuing operations on the 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 September 30, 2019, QEP recorded a net loss before income taxes related to the divested Haynesville/Cotton Valley properties of $0.2 million, which includes a pre-tax loss on sale of $0.3 million. During the nine months ended September 30, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $3.1 million, which includes the pre-tax loss on sale of $1.0 million. For the three and nine months ended September 30, 2018, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $18.0 million and $37.7 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 September 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 nine months ended September 30, 2019, QEP recorded a pre-tax loss on sale of $0.2 million due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs". For the three and nine months ended September 30, 2018, QEP recorded a net loss before income taxes related to the divested Uinta Basin assets of $4.4 million and $419.3 million, respectively, which both include a pre-tax loss on sale of $12.4 million. 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.

Other Divestitures

During the nine months ended September 30, 2019, QEP received net cash proceeds of $42.7 million and recorded a net pre-tax gain on sale of $3.7 million, primarily related to the divestiture of properties outside its main operating areas and the sale of corporate equipment.

During the nine months ended September 30, 2018, QEP received net cash proceeds of $64.5 million and recorded a pre-tax gain on sale of $39.1 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.

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.

12

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 nine months ended September 30, 2019 and 2018 there were no anti-dilutive shares.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019	2018	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	237.9	236.9	237.7	238.3
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	0.1	—	—
Average diluted common shares outstanding	237.9	237.0	237.7	238.3

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
	September 30,		December 31,
	2019		2018
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.7	$	5.1
Long-term:
Asset retirement obligations	95.5		96.9
Other long-term liabilities held for sale	—		57.6
Total ARO Liability	$	102.2	$	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	4.1
Additions	0.8
Revisions	(0.3		)
Liabilities related to assets sold(1)	(60.7		)
Liabilities settled	(1.3		)
ARO liability at September 30, 2019	$	102.2

_______________________

⁽¹⁾  Liabilities related to assets sold during the nine months ended September 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 September 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	September 30, 2019
Fair value of derivative contracts – short-term	$	—	$	69.8	$	—	$	—		$	69.8
Fair value of derivative contracts – long-term	—		23.2		—		—			23.2
Total financial assets	$	—	$	93.0	$	—	$	—		$	93.0
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	0.8	$	—	$	—		$	0.8
Fair value of derivative contracts – long-term	—		0.4		—		—			0.4
Total financial liabilities	$	—	$	1.2	$	—	$	—		$	1.2
	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
	September 30, 2019				December 31, 2018
Financial Assets	(in millions)
Cash and cash equivalents	$	92.4	$	92.4	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	0.7	$	0.7	$	14.6	$	14.6
Total debt outstanding	$	2,081.1	$	1,959.1	$	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 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 nine months ended September 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease. During the nine months ended September 30, 2018, the Company recorded impairments on certain proved oil and gas properties, primarily in the Uinta Basin, of $397.6 million, resulting in a reduction of the associated carrying amount to fair value.

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, basis 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. QEP has also entered into oil price derivative swaps that use Intercontinental Exchange, Inc. (ICE) Brent or regional price indices as the reference price. 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 September 30, 2019:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	3.6	$	55.44
2019	ICE Brent	0.5	$	66.73
2019	Argus WTI Midland	0.2	$	54.60
2019	Argus WTI Houston	0.1	$	65.70
2020	NYMEX WTI	11.3	$	58.29
2020	Argus WTI Midland	1.5	$	57.30
2020 (January - June)	Argus WTI Houston	1.0	$	60.06

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

Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2019	NYMEX WTI	Argus WTI Midland	1.7	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.5	$	3.69
2020	NYMEX WTI	Argus WTI Midland	6.2	$	0.13
2020 (January - June)	NYMEX WTI	Argus WTI Houston	0.4	$	3.75

17

QEP Derivative Financial Statement Presentation

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

		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	September 30, 2019		December 31, 2018		September 30, 2019		December 31, 2018
Current:		(in millions)
Commodity(1)	Fair value of derivative contracts	$	69.8	$	88.2	$	0.8	$	0.4
Long-term:
Commodity	Fair value of derivative contracts	23.2		35.4		0.4		0.7
Total derivative instruments		$	93.0	$	123.6	$	1.2	$	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.

18

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

	Three Months Ended						Nine Months Ended
Derivative contracts	September 30,						September 30,
	2019			2018(2)			2019(1)			2018(2)
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(4.9	)	$	(41.7	)	$	(23.9	)	$	(138.0	)
Gas derivative contracts	—			3.3			(2.9		)	10.6
Gas Storage
Gas derivative contracts	—			—			—			0.3
Realized gains (losses) on commodity derivative contracts	(4.9		)	(38.4		)	(26.8		)	(127.1		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	92.3			(60.6		)	(30.5		)	(88.1		)
Gas derivative contracts	—			(3.1		)	(0.3		)	(18.9		)
Gas Storage
Gas derivative contracts	—			—			—			(0.3		)
Unrealized gains (losses) on commodity derivative contracts	92.3			(63.7		)	(30.8		)	(107.3		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	87.4		$	(102.1	)	$	(57.6	)	$	(234.4	)
Derivatives associated with divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	—		$	(2.7	)	$	—		$	(2.7	)
Gas derivative contracts	—			—			1.8			—
NGL derivative contracts	—			(3.2		)	—			(3.2		)
Unrealized gains (losses) on commodity derivative contracts related to divestitures	$	—		$	(5.9	)	$	1.8		$	(5.9	)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	87.4		$	(108.0	)	$	(55.8	)	$	(240.3	)

_______________________

⁽¹⁾  During the nine months ended September 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.

⁽²⁾  During the three and nine months ended September 30, 2018, the unrealized gains (losses) on commodity derivative contracts related to the Uinta Basin Divestiture were comprised of derivatives included as a part of the Uinta Basin purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2018. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Uinta Basin Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

19

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.

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 September 30, 2019, QEP does not have any financing leases.

20

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		Nine Months Ended
	September 30, 2019(1)		September 30, 2019(1)
Lease Cost included in the Condensed Consolidated Balance Sheets	(in millions)
Property, Plant and Equipment acquisitions(2)	$	2.5	$	11.3
	Three Months Ended		Nine Months Ended
	September 30, 2019(1)		September 30, 2019(1)
Lease Cost included in the Condensed Consolidated Statement of Operations	(in millions)
Lease operating expense	$	2.9	$	9.0
Gathering and other expense	2.0		5.8
General and administrative	1.3		4.5
Total lease cost	$	8.7	$	30.6

 ____________________________

⁽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 nine months ended September 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:

	September 30, 2019(1)
Weighted-average remaining lease term (years)	3.4
Weighted-average discount rate	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 September 30, 2019
	(in millions)
Termination benefits	$	4.3		$	4.3	$	—		$	—
Accelerated share-based compensation(1)	1.6			1.6		—			—
Retention expense (including share-based compensation)	4.5			4.5		—			—
Total restructuring costs	$	10.4		$	10.4	$	—		$	—
	Nine Months Ended September 30, 2019
Termination benefits	$	11.0		$	10.9	$	0.1		$	—
Office lease termination costs	0.6			0.6		—			—
Accelerated share-based compensation(1)	11.3			9.8		1.5			—
Retention expense (including share-based compensation)	15.4			15.4		—			—
Pension and Medical Plan curtailment	(0.4		)	—		(0.2		)	(0.2		)
Total restructuring costs	$	37.9		$	36.7	$	1.4		$	(0.2	)
	Three Months Ended September 30, 2018
Termination benefits	$	6.7		$	5.3	$	1.4		—
Office lease termination costs	0.7			0.7		—			—
Accelerated share-based compensation	3.2			1.0		2.2			—
Retention expense (including share-based compensation)	5.8			5.8		—			—
Pension and Medical Plan curtailment	0.3			—		—			0.3
Total restructuring costs	$	16.7		$	12.8	$	3.6		$	0.3
	Nine Months Ended September 30, 2018
Termination benefits	$	13.7		$	10.4	$	3.3		—
Office lease termination costs	1.0			1.0		—			—
Accelerated share-based compensation	7.2			5.0		2.2			—
Retention expense (including share-based compensation)	13.8			13.8		—			—
Pension and Medical Plan curtailment	0.3			—		—			0.3
Total restructuring costs	$	36.0		$	30.2	$	5.5		$	0.3

 ____________________________

⁽¹⁾  Accelerated share-based compensation represents the additional expense or loss recognized in the Condensed Consolidated Statement of Operations for the three and nine months ended September 30, 2019. Total accelerated share based compensation was $3.5 million and $25.2 million for the three and nine months ended September 30, 2019, respectively, and was determined based on the contractual vesting date, with $1.6 million and $11.3 million recognized during the three and nine months ended September 30, 2019, respectively, as shown above, and the remaining amount recognized in prior periods.

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	Costs recognized from inception through September 30, 2019(1)			Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	43.2		$	—	(2)
Office lease termination costs	1.6			—		(2)
Accelerated share-based compensation	22.6			—		(2)
Retention expense (including share-based compensation)	34.2			5.0
Pension and Medical Plan curtailment	(0.2		)	—		(2)
Total restructuring costs	$	101.4		$	5.0

 ____________________________

⁽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 September 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	11.0			0.6			11.3			15.4			(0.4		)	37.9
Costs paid or otherwise settled	(28.3		)	(0.6		)	(11.3		)	(23.6		)	0.4			(63.4		)
Balance at September 30, 2019	$	2.2		$	—		$	—		$	2.6		$	—		$	4.8

Note 10 – Debt

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

	September 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	(18.2		)	(22.2		)
Total principal amount of debt (including current portion)	2,081.1			2,507.1
Less: current portion of long-term debt	(51.7		)	—
Total long-term debt outstanding	$	2,029.4		$	2,507.1

Of the total debt outstanding on September 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 unsecured 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 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 September 30, 2019 and December 31, 2018, QEP was in compliance with the covenants under the credit agreement.

During the nine months ended September 30, 2019, QEP's weighted-average interest rate on borrowings from its credit facility was 4.73%. As of September 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 September 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.  

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

In many cases, the Company is unable to make an estimate of the range of reasonably possible loss related to its contingencies. To the extent that the Company can reasonably estimate losses for contingencies where the risk of material loss (in excess of

24

accruals, if any) is reasonably possible, the Company estimates such losses to be in a range of zero to approximately $10.0 million, in the aggregate.

Commitments

QEP has 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 September 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	$	6.2
2020	$	21.7
2021	$	19.9
2022	$	15.4
2023	$	9.8
After 2023	$	0.7
Less: Interest(1)	$	(10.0	)
Present value of lease liabilities(2)	$	63.7

 ____________________________

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

⁽²⁾  Of the total present value of lease liabilities, $18.4 million was recorded in "Current operating lease liabilities" and $45.3 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 September 30, 2019.

25

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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019(1)			2018(2)			2019(1)		2018(2)
	(in millions)
Stock options	$	—		$	0.2		$	0.3	$	0.9
Restricted share awards	5.0			5.3			15.9		20.9
Performance share units	(0.9		)	(2.9		)	4.6		4.1
Restricted share units	—			0.1			0.2		0.2
Total share-based compensation expense	$	4.1		$	2.7		$	21.0	$	26.1

 ________________________

⁽¹⁾  During the three and nine months ended September 30, 2019, the Company recorded an additional $1.6 million and $11.3 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 nine months ended September 30, 2019 and the remaining $1.6 million and $9.8 million, respectively, is included in the table above. Refer to Note 9 – Restructuring for additional information.

⁽²⁾  During the three and nine months ended September 30, 2018, the Company recorded an additional $3.2 million and $7.2 million, respectively of share-based compensation expense, related to the acceleration of vesting that occurred as part of the restructuring program, of which $2.2 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statement of Operations during the three and nine months ended September 30, 2018 and the remaining $1.0 million and $5.0 million, respectively, is included in the table above. Refer to Note 9 – Restructuring for additional information.

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 nine months ended September 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	(292,921	)	30.82
Outstanding at September 30, 2019	1,806,012		$	20.88	2.56	$	—
Options Exercisable at September 30, 2019	1,761,836		$	21.00	2.52	$	—
Unvested Options at September 30, 2019	44,176		$	16.32	4.41	$	—

During the nine months ended September 30, 2019 there were no exercises of stock options. As of September 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 0.54 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 nine months ended September 30, 2019 and 2018 was $29.6 million and $30.7 million, respectively. The weighted-average grant date fair value of restricted share awards was $7.79 per share and $9.56 per share for the nine months ended September 30, 2019 and 2018, respectively. As of September 30, 2019, $13.8 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 2.15 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	2,330,254		7.79
Vested	(2,780,285	)	10.66
Forfeited	(239,489	)	9.15
Unvested balance at September 30, 2019	3,132,613		$	8.76

Performance Share Units

The payouts associated with 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 September 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 $12.1 million and $2.0 million for vested performance share units during the nine months ended September 30, 2019 and 2018, respectively. The weighted-average grant date fair value of the performance share units granted during the nine months ended September 30, 2019 and 2018 was $7.93 and $9.55 per share, respectively. As of September 30, 2019, $2.6 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 2.16 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	614,633		7.93
Vested and paid	(1,206,165	)	10.68
Unvested balance at September 30, 2019	967,780		$	9.50

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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 $7.90 and $9.55 per share for the nine months ended September 30, 2019 and 2018, respectively. As of September 30, 2019, $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.22 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	37,498		7.90
Vested and paid	(47,807	)	10.04
Unvested balance at September 30, 2019	32,366		$	8.13

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 nine months ended September 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 participants do not earn additional defined benefits for future services.

The SERP is a nonqualified retirement plan that is unfunded and provides postretirement benefits to certain QEP employees. During the nine months ended September 30, 2019, the Company made contributions of $0.4 million to the SERP and expects to contribute an additional $0.1 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 nine months ended September 30, 2019, the Company made contributions of $0.2 million to the Medical Plan and does not expect to make additional contributions 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.

During the nine months ended September 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. Refer to Note 9 – Restructuring for more information.

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.1		$	0.2		$	0.2		$	0.6
Interest cost	1.2			1.2			3.6			3.4
Expected return on plan assets	(1.5		)	(1.4		)	(4.4		)	(4.3		)
Amortization of prior service costs(1)	—			0.2			0.2			0.6
Amortization of actuarial losses(1)	—			—			0.1			0.6
Curtailment (gain) loss(2)	—			0.3			0.4			0.3
Periodic expense	$	(0.2	)	$	0.5		$	0.1		$	1.2
Medical Plan benefits
Interest cost	$	—		$	—		$	0.1		$	0.1
Amortization of prior service costs(1)	—			(0.1		)	—			(0.2		)
Curtailment (gain) loss(2)	—			—			(0.8		)	—
Periodic expense	$	—		$	(0.1	)	$	(0.7	)	$	(0.1	)

____________________________

⁽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 nine months ended September 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 nine months ended September 30, 2019, the Company made contributions of $3.2 million to the 401(k) Plan and expects to contribute an additional $0.8 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 nine months ended September 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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Note 14 – Subsequent Event

On October 23, 2019, the Company issued a notice to holders of its outstanding 6.80% Senior Notes due March 1, 2020, of the Company’s intent to redeem all of the outstanding notes on November 22, 2019. The Company expects that the redemption will decrease the "Current portion of long term debt" on the Condensed Consolidated Balance Sheets by $51.7 million and expects to incur a loss on early extinguishment of debt of approximately $0.7 million in connection with the redemption of the Senior Notes.

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 nine months ended September 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 was to move forward as an independent company.

QEP's strategy incorporates 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, while continuing to lower its lease operating expense and drilling, completion and facility costs. All of this is underpinned by the 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. During the first three quarters of 2019, the Company incurred $36.7 million of general and administrative restructuring costs related to organizational changes and additional legal and outside professional costs of $6.5 million associated with the evaluation of strategic alternatives.

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.

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Acquisitions

During the nine months ended September 30, 2019, QEP acquired various oil and gas properties, which primarily included proved acreage in the Permian Basin for an aggregate purchase price of $3.6 million, subject to post-closing purchase price adjustments.

During the nine months ended September 30, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $48.3 million. Of the $48.3 million, $37.6 million was related to acquisitions from various entities that owned additional oil and gas interests in certain properties included in the 2017 acquisition of oil and gas properties in the Permian Basin (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. QEP received net cash proceeds of $633.9 million during the nine months ended September 30, 2019. Additionally, a total pre-tax loss on sale of $4.0 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 nine months ended September 30, 2019, QEP received net cash proceeds of $42.6 million and recorded a net pre-tax gain on sale of $3.5 million, primarily related to the divestiture of properties outside our main operating areas, partially offset by the sale of the corporate aircraft.

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 nine months ended September 30, 2019, QEP recorded a pre-tax loss on sale of $0.2 million due to post-closing purchase price adjustments, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs". Refer to Note 1 – Basis of Presentation and 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 Uinta Basin Divestiture, during the nine months ended September 30, 2018, QEP recorded net cash proceeds of $64.5 million which resulted in a net pre-tax gain on sale of $39.1 million related to the divestiture of properties outside our main operating areas.

Financial and Operating Highlights

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

• Generated net income of $81.0 million, or $0.34 per diluted share;

• Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $193.5 million;

• Reported record oil and condensate production of 4.0 MMbbls in the Permian Basin, an increase of 12% compared to the third quarter 2018;

• Reduced capital expenditures by $120.8 million compared to the third quarter 2018

• Reinstated a quarterly cash dividend of $0.02 per share of common stock, which was paid in September 2019; and

• Reduced general and administrative expenses by 39% compared to the third quarter 2018.

During the nine months ended September 30, 2019, QEP:

• Generated net income of $13.1 million, or $0.06 per diluted share;

• Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $479.8 million;

• Closed the Haynesville Divestiture for a total purchase price of $633.9 million;

• Increased oil and condensate production in the Permian Basin by 14% to 10.1 MMbbls compared to the first three quarters of 2018;

• Reduced capital expenditures by $611.6 million compared to the first three quarters of 2018; and

• Reduced general and administrative expenses by 24% compared to the first three quarters of 2018.

Outlook

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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, if needed, borrowings under our credit facility. Our total capital expenditures (excluding property acquisitions) for 2019 are expected to be approximately $574.5 million, a decrease of approximately 51% 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 August 14, 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, and the Company entered into an agreement with affiliates of Elliott. 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 $91.02 per barrel in October 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 September 30, 2019, QEP forecasted the midpoint of its 2019 annual production to be approximately 32.3 MMboe and had approximately 68% 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 nine months ended September 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease.

During the nine months ended September 30, 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment 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 September 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.

Income Tax

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 allows the Company 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. The Company expects to receive the $148.4 million over the next four years, including $74.2 million in 2019. The amount expected to be refunded in 2019 is included in "Income tax receivable" with the remaining $74.2 million included in "Deferred income taxes" on the Condensed Consolidated Balance Sheet as of September 30, 2019.

As of September 30, 2019, QEP had $19.0 million in uncertain tax positions related to asset sales that occurred in 2014, which were recorded within "Other long-term liabilities" on the Condensed Consolidated Balance Sheet. The uncertain tax position was recognized as income tax expense during the year ended December 31, 2014, with an additional income tax expense recognized during 2017 as a result of the Tax Legislation changes. The statute of limitations related to the uncertain tax position expires in the fourth quarter of 2019, and upon expiration, the Company expects to recognize a $19.0 million tax benefit as well as record a $3.6 million reduction in "Interest expense" and a $2.8 million reduction in "General and administrative" expense on the Consolidated Statements of Operations related to accrued interest and penalties that were previously recorded in prior periods.

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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. Because 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, 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.

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 September 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	—	—	—	4	3.4	—	—	12	0.8
Southern Region
Permian Basin(1)	2	7	7.0	31	31.0	—	—	—	—

____________________________

⁽¹⁾  Five of the seven gross operated drilling wells in the Permian Basin represent wells for which surface casing had been set as of September 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 35 gross operated wells waiting on completion as of September 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 nine months ended September 30, 2019:

	Operated Put on Production				Non-operated Put on Production
	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
	September 30, 2019		September 30, 2019		September 30, 2019		September 30, 2019
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	3	3.0	3	3.0	3	1.0	8	1.1
Southern Region
Permian Basin	24	24.0	59	58.9	—	—	5	0.4

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

	Permian Basin		Williston Basin
	As of September 30, 2019
	Gross	Net	Gross	Net
Well Progress
Drilling	7	7.0	—	—
At total depth - under drilling rig	6	6.0	—	—
Waiting to be completed	25	25.0	—	—
Completed, awaiting production	—	—	4	3.4
Waiting on completion	31	31.0	4	3.4
Put on production	59	58.9	3	3.0

RESULTS OF OPERATIONS

Net Income

QEP generated net income during the third quarter of 2019 of $81.0 million or $0.34 per diluted share, compared to a net income of $7.3 million or $0.03 per diluted share, in the third quarter of 2018. QEP's increase in net income in the third quarter of 2019 compared to 2018 was primarily due to an $87.4 million gain on realized and unrealized derivative contracts in the third quarter of 2019.

During the first three quarters of 2019, QEP generated net income of $13.1 million or $0.06 per diluted share, compared to net loss of $382.3 million or $1.60 per diluted share, in the first three quarters of 2018. QEP generated more income in the first three quarters of 2019 than in 2018 primarily due to $404.4 million impairment expense and a $240.3 million loss on realized and unrealized derivative contracts recorded in the first three quarters 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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in millions)
Net income (loss)	$	81.0		$	7.3		$	13.1		$	(382.3	)
Interest expense	32.8			38.7			100.0			111.9
Interest and other (income) expense	(0.9		)	0.3			(4.6		)	4.1
Income tax provision (benefit)	26.6			2.5			(55.7		)	(117.6		)
Depreciation, depletion and amortization	144.2			234.9			395.5			673.6
Unrealized (gains) losses on derivative contracts	(92.3		)	69.6			29.0			113.2
Exploration expenses	—			—			—			0.1
Net (gain) loss from asset sales, inclusive of restructuring costs	2.1			(27.1		)	(2.5		)	(26.7		)
Impairment	—			—			5.0			404.4
Adjusted EBITDA	$	193.5		$	326.2		$	479.8		$	780.7

In the third quarter of 2019, Adjusted EBITDA decreased to $193.5 million compared to $326.2 million in the third quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures, lower equivalent production in the Williston Basin and an 16% decrease in average field-level oil prices, partially offset by an 18% increase in equivalent production in the Permian Basin, a $33.5 million decrease in realized derivative losses and $18.7 million decrease in general and administrative expenses.

In the first three quarters of 2019, Adjusted EBITDA decreased to $479.8 million compared to $780.7 million in the first three quarters 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 23% increase in equivalent production in the Permian Basin, a $100.3 million decrease in realized derivative losses and $39.8 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							Nine Months Ended
	September 30,							September 30,
	2019		2018		Change			2019		2018		Change
	(in millions)
Oil and condensate, gas and NGL sales, as presented	$	305.6	$	544.0	$	(238.4	)	$	875.8	$	1,474.1	$	(598.3	)
Transportation and processing costs included in revenue(1)	14.2		15.8		(1.6		)	40.7		40.9		(0.2		)
Oil and condensate, gas and NGL sales, as adjusted(2)	319.8		$	559.8	$	(240.0	)	$	916.5	$	1,515.0	$	(598.5	)
Oil and condensate sales	$	298.8	$	416.1	$	(117.3	)	$	834.0	$	1,125.3	$	(291.3	)
Gas sales	9.1		101.7		(92.6		)	39.4		301.5		(262.1		)
NGL sales	11.9		42.0		(30.1		)	43.1		88.2		(45.1		)
Oil and condensate, gas and NGL sales, as adjusted(2)	$	319.8	559.8		$	(240.0	)	$	916.5	$	1,515.0	$	(598.5	)

 ____________________________

⁽¹⁾  Depending on the terms of the contract, a portion of the total transportation and processing costs incurred by the Company are deducted from revenue. 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 nine months ended September 30, 2019, compared to the three and nine months ended September 30, 2018:

	Oil and condensate			Gas			NGL			Total
	(in millions)
Oil and condensate, gas and NGL sales, as adjusted
Three months ended September 30, 2018	$	416.1		$	101.7		$	42.0		$	559.8
Changes associated with volumes(1)	(60.9		)	(80.0		)	(1.0		)	(141.9		)
Changes associated with prices(2)	(56.4		)	(12.6		)	(29.1		)	(98.1		)
Three months ended September 30, 2019	$	298.8		$	9.1		$	11.9		$	319.8
Oil and condensate, gas and NGL sales, as adjusted
Nine months ended September 30, 2018	$	1,125.3		$	301.5		$	88.2		$	1,515.0
Changes associated with volumes(1)	(141.0		)	(235.0		)	7.0			(369.0		)
Changes associated with prices(2)	(150.3		)	(27.1		)	(52.1		)	(229.5		)
Nine months ended September 30, 2019	$	834.0		$	39.4		$	43.1		$	916.5

 ____________________________

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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 nine months ended September 30, 2019, as compared to the three and nine months ended September 30, 2018, by the average field-level price for the three and nine months ended September 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 nine months ended September 30, 2019, as compared to the three and nine months ended September 30, 2018, by the respective volumes for the three and nine months ended September 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 September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Total production volumes (Mboe)
Northern Region
Williston Basin	2,722.5			4,381.1			(1,658.6		)	9,061.9			12,570.5			(3,508.6		)
Uinta Basin	—			606.0			(606.0		)	—			2,232.2			(2,232.2		)
Other Northern	19.4			63.1			(43.7		)	65.1			211.4			(146.3		)
Southern Region
Permian Basin	5,658.5			4,792.5			866.0			14,293.2			11,591.6			2,701.6
Haynesville/Cotton Valley	(0.4		)	4,552.8			(4,553.2		)	310.5			13,604.6			(13,294.1		)
Other Southern	4.0			4.5			(0.5		)	14.3			20.4			(6.1		)
Total production	8,404.0			14,400.0			(5,996.0		)	23,745.0			40,230.7			(16,485.7		)
Total equivalent prices (per Boe)
Average field-level equivalent price	$	38.06		$	38.87		$	(0.81	)	$	38.60		$	37.66		$	0.94
Commodity derivative impact	(0.59		)	(2.66		)	2.07			(1.13		)	(3.16		)	2.03
Net realized equivalent price	$	37.47		$	36.21		$	1.26		$	37.47		$	34.50		$	2.97

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Oil and Condensate Volumes and Prices

	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Oil and condensate production volumes (Mbbl)
Northern Region
Williston Basin	1,700.3			2,968.6			(1,268.3		)	5,719.7			8,747.6			(3,027.9		)
Uinta Basin	—			124.7			(124.7		)	—			445.0			(445.0		)
Other Northern	12.1			19.8			(7.7		)	36.1			76.8			(40.7		)
Southern Region
Permian Basin	3,956.5			3,525.7			430.8			10,144.9			8,892.0			1,252.9
Haynesville/Cotton Valley	—			1.9			(1.9		)	—			12.2			(12.2		)
Other Southern	1.6			(0.2		)	1.8			3.7			8.5			(4.8		)
Total production	5,670.5			6,640.5			(970.0		)	15,904.4			18,182.1			(2,277.7		)
Average field-level oil prices (per bbl)
Northern Region	$	51.92		$	68.06		$	(16.14	)	$	53.38		$	64.80		$	(11.42	)
Southern Region	$	53.03		$	57.88		$	(4.85	)	$	51.91		$	58.87		$	(6.96	)
Average field-level price	$	52.70		$	62.65		$	(9.95	)	$	52.44		$	61.89		$	(9.45	)
Commodity derivative impact	(0.87		)	(6.27		)	5.40			(1.50		)	(7.59		)	6.09
Net realized price	$	51.83		$	56.38		$	(4.55	)	$	50.94		$	54.30		$	(3.36	)

Oil and condensate revenues decreased $117.3 million, or 28%, in the third quarter of 2019 compared to the third quarter of 2018, due to lower average field-level prices and lower aggregate oil and condensate production volumes. Average field-level oil prices decreased 16% in the third quarter of 2019 compared to the third quarter of 2018 primarily driven by a decrease in average NYMEX-WTI oil prices for the comparable periods, partially offset by a $3.40 per bbl, or 48%, decrease in the basis differential relative to the average NYMEX-WTI oil price in the third quarter of 2019 compared to the third quarter of 2018. The 15% decrease in production volumes was primarily driven by a decrease in production in the Williston Basin due to a reduced level of activity in the third quarter of 2019 and the Uinta Basin Divestiture, partially offset by an increase in production in the Permian Basin due to continued drilling and completion activity.

Oil and condensate revenues decreased $291.3 million, or 26%, in the first three quarters of 2019 compared to the first three quarters of 2018, due to lower average field-level prices and lower aggregate oil and condensate production volumes. Average field-level oil prices decreased 15% in the first three quarters of 2019 compared to the first three quarters of 2018 primarily driven by a decrease in average NYMEX-WTI oil prices for the comparable periods, partially offset by a $0.46 per bbl, or 9%, decrease in the basis differential relative to the average NYMEX-WTI oil price in the first three quarters of 2019 compared to the first three quarters of 2018. The 13% decrease in production volumes was driven by a decrease in production in the Williston Basin due to a reduced level of activity 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.

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Gas Volumes and Prices

	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2019			2018		Change
Gas production volumes (Bcf)
Northern Region
Williston Basin	3.3		4.4		(1.1		)	10.6			11.6		(1.0		)
Uinta Basin	—		2.7		(2.7		)	—			10.1		(10.1		)
Other Northern	—		0.3		(0.3		)	0.1			0.8		(0.7		)
Southern Region
Permian Basin	4.8		3.3		1.5			11.9			7.3		4.6
Haynesville/Cotton Valley	—		27.4		(27.4		)	1.9			81.6		(79.7		)
Other Southern	0.1		—		0.1			0.1			0.1		—
Total production	8.2		38.1		(29.9		)	24.6			111.5		(86.9		)
Average field-level gas prices (per Mcf)
Northern Region	$	1.72	$	2.59	$	(0.87	)	$	2.41		$	2.52	$	(0.11	)
Southern Region	$	0.71	$	2.69	$	(1.98	)	$	0.98		$	2.75	$	(1.77	)
Average field-level price	$	1.13	$	2.67	$	(1.54	)	$	1.61		$	2.71	$	(1.10	)
Commodity derivative impact	—		0.09		(0.09		)	(0.12		)	0.10		(0.22		)
Net realized price	$	1.13	$	2.76	$	(1.63	)	$	1.49		$	2.81	$	(1.32	)

Gas revenues decreased $92.6 million, or 91%, in the third quarter of 2019 compared to the third quarter of 2018, due to lower gas production volumes and lower average field-level prices. Production volumes decreased 78% in the third quarter of 2019 compared to the third quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Average field-level gas prices decreased 58% in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by a decrease in average NYMEX-HH gas spot prices and regional basis differentials in the Permian and Williston basins for the comparable periods.

Gas revenues decreased $262.1 million, or 87%, in the first three quarters of 2019 compared to the first three quarters of 2018, due to lower gas production volumes and lower average field-level prices. Production volumes decreased 78% in the first three quarters of 2019 compared to the first three quarters 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 41% in the first three quarters of 2019 compared to the first three quarters of 2018, primarily driven by a decrease in average NYMEX-HH gas spot prices and regional basis differentials for the comparable periods.

40

NGL Volumes and Prices

	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2019		2018		Change
NGL production volumes (Mbbl)
Northern Region
Williston Basin	472.1		667.6		(195.5		)	1,577.5		1,885.7		(308.2		)
Uinta Basin	—		25.7		(25.7		)	—		96.9		(96.9		)
Other Northern	0.7		3.7		(3.0		)	1.1		9.4		(8.3		)
Southern Region
Permian Basin	909.9		717.9		192.0			2,168.4		1,479.2		689.2
Haynesville/Cotton Valley	—		0.1		(0.1		)	—		0.4		(0.4		)
Other Southern	0.3		0.3		—			0.8		0.9		(0.1		)
Total production	1,383.0		1,415.3		(32.3		)	3,747.8		3,472.5		275.3
Average field-level NGL prices (per bbl)
Northern Region	$	5.26	$	29.55	$	(24.29	)	$	9.92	$	25.32	$	(15.40	)
Southern Region	$	10.38	$	29.74	$	(19.36	)	$	12.65	$	25.49	$	(12.84	)
Average field-level price	$	8.63	$	29.65	$	(21.02	)	$	11.50	$	25.39	$	(13.89	)
Commodity derivative impact	—		—		—			—		—		—
Net realized price	$	8.63	$	29.65	$	(21.02	)	$	11.50	$	25.39	$	(13.89	)

NGL revenues decreased $30.1 million, or 72%, during the third quarter of 2019 compared to the third quarter of 2018, due to lower average field-level prices and lower NGL production volumes. The 71% decrease in NGL prices during the third quarter of 2019 compared to the third quarter of 2018 was primarily driven by a decrease in propane, ethane and other NGL component prices. The 2% decrease in NGL production volumes was primarily driven by production decreases in the Williston Basin due to a reduced level of activity in 2019 and the Uinta Basin Divestiture, partially offset by continued drilling and completion activity in the Permian Basin.

NGL revenues decreased $45.1 million, or 51%, during the first three quarters of 2019 compared to the first three quarters of 2018, due to lower average field-level prices, partially offset by higher NGL production volumes. The 55% decrease in NGL prices during the first three quarters of 2019 compared to the first three quarters of 2018 was primarily driven by a decrease in propane, ethane and other NGL component prices. The decrease in price was partially offset by an 8% 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 a reduced level of activity in 2019 and the Uinta Basin Divestiture.

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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, purchases and resale of gas are minimal going forward. The following table is a summary of QEP's financial results from its resale activities.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
	(in millions)
Purchased oil and gas sales	$	0.1		$	13.0		$	(12.9	)	$	1.4		$	36.2		$	(34.8	)
Purchased oil and gas expense	(0.1		)	(13.3		)	13.2			(1.5		)	(38.6		)	37.1
Realized gains (losses) on gas storage derivative contracts	—			—			—			—			0.3			(0.3		)
Resale margin	$	—		$	(0.3	)	$	0.3		$	(0.1	)	$	(2.1	)	$	2.0

Purchased oil and gas sales and expense were lower in the third quarter of 2019 compared to the third 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, which were divested in January 2019.

Purchased oil and gas sales and expense were lower in the first three quarters of 2019 compared to the first three quarters 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, which were divested in January 2019.

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Operating Expenses

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2019		2018		Change
	(in millions)
Lease operating expense	$	38.3	$	64.6	$	(26.3	)	$	135.5	$	203.6	$	(68.1	)
Adjusted transportation and processing costs(1)	32.2		43.8		(11.6		)	79.5		134.1		(54.6		)
Production and property taxes	20.0		37.4		(17.4		)	67.6		103.9		(36.3		)
Total production costs	$	90.5	$	145.8	$	(55.3	)	$	282.6	$	441.6	$	(159.0	)
	(per Boe)
Lease operating expense	$	4.56	$	4.49	$	0.07		$	5.71	$	5.06	$	0.65
Adjusted transportation and processing costs(1)	3.83		3.04		0.79			3.34		3.34		—
Production and property taxes	2.38		2.60		(0.22		)	2.85		2.58		0.27
Total production costs	$	10.77	$	10.13	$	0.64		$	11.90	$	10.98	$	0.92

 ____________________________

⁽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 September 30,							Nine Months Ended September 30,
	2019		2018		Change			2019		2018		Change
	(in millions)
Transportation and processing costs, as presented	$	18.0	$	28.0	$	(10.0	)	$	38.8	$	93.2	$	(54.4	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	14.2		15.8		(1.6		)	40.7		40.9		(0.2		)
Adjusted transportation and processing costs	$	32.2	$	43.8	$	(11.6	)	$	79.5	$	134.1	$	(54.6	)
	(per Boe)
Transportation and processing costs, as presented	$	2.14	$	1.94	$	0.20		$	1.63	$	2.32	$	(0.69	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	1.69		1.10		0.59			1.71		1.02		0.69
Adjusted transportation and processing costs	$	3.83	$	3.04	$	0.79		$	3.34	$	3.34	$	—

Lease operating expense (LOE). QEP's LOE decreased $26.3 million, or 41%, in the third quarter of 2019 compared to the third quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE decreased $14.1 million, driven by a decrease in maintenance and repair expenses, labor and water disposal in the Permian and Williston basins as a result of continuing efforts to reduce operating expenses.

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During the third quarter of 2019, LOE increased $0.07 per Boe, or 2%, compared to the third quarter of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE per Boe decreased by 20% compared to the third quarter of 2018. The 20% decrease per BOE rate 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.

QEP's LOE decreased $68.1 million, or 33%, in the first three quarters of 2019 compared to the first three quarters of 2018, primarily due to the Haynesville/Cotton Valley and Uinta Basin divestitures. Excluding those divestitures, LOE decreased $23.7 million, driven by a decrease in workovers, maintenance and repair expenses and water disposal in the Permian and Williston basins as a result of continuing efforts to reduce operating expenses.

During the first three quarters of 2019, LOE increased $0.65 per Boe, or 13%, compared to the first three quarters of 2018, but was down 11% excluding the loss of lower LOE production due to the Haynesville/Cotton Valley and Uinta Basin divestitures. The 11% 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 $11.6 million, or 26%, in the third quarter of 2019 compared to the third 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 increased $5.2 million, primarily due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations as well as increased production in the Permian Basin, partially offset by decreased production in the Williston Basin.

During the third quarter of 2019, adjusted transportation and processing costs increased $0.79 per Boe, or 26%, compared to the third quarter of 2018. The increase was primarily due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations, partially offset by the Haynesville/Cotton Valley and Uinta Basin divestitures, which had higher adjusted transportation and processing costs per Boe.

Adjusted transportation and processing costs decreased $54.6 million, or 41%, in the first three quarters of 2019 compared to the first three quarters 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 increased $2.5 million, primarily due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations and increased production in the Permian Basin, partially offset by decreased production in the Williston Basin.

During the first three quarters of 2019, adjusted transportation and processing costs remained flat per Boe compared to the first three quarters of 2018. The flat rate per Boe 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 7% due to the recognition of $7.7 million of firm transportation expense related to future obligations in an area in which the Company no longer has production operations.

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 $17.4 million, or 47%, in the third quarter of 2019 compared to the third 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 third quarter of 2019, production and property taxes decreased $0.22 per Boe, or 8%, compared to the third quarter of 2018, but decreased 35% excluding the Haynesville/Cotton Valley and Uinta Basin divestitures. The 35% decrease was primarily due to a decrease in average field-level equivalent prices in the Permian and Williston basins.

Production and property taxes decreased $36.3 million, or 35%, in the first three quarters of 2019 compared to the first three quarters 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 three quarters of 2019, production and property taxes increased $0.27 per Boe, or 10%, compared to the first three quarters of 2018, but decreased 21% excluding the Haynesville/Cotton Valley and Uinta Basin divestitures. The 21% 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.

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Depreciation, depletion and amortization (DD&A). DD&A expense decreased $90.7 million in the third quarter of 2019 compared to the third quarter of 2018, primarily in the Williston Basin due to decreased production and a lower rate, 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 $278.1 million in the first three quarters of 2019 compared to the first three quarters 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 third quarter of 2019 and 2018, there were no impairment charges.

During the first three quarters of 2019, QEP recorded impairment charges of $5.0 million, which related to impairment of an office building operating lease. During the first three quarters 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 third quarter of 2019, G&A expense decreased $18.7 million, or 39%, compared to the third quarter of 2018. During the third quarter of 2019 and 2018, QEP incurred $10.0 million and $14.2 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $10.4 million and $12.8 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 $14.4 million, or 42%, primarily due to $12.7 million lower labor, benefits and other associated costs due to the reduction in our workforce and $3.2 million in lower legal and outside service costs, partially offset by a $2.2 million decrease in overhead recoveries, primarily associated with our Haynesville/Cotton Valley and Uinta Basin divestitures.

During the first three quarters of 2019, G&A expense decreased $39.8 million, or 24%, compared to the first three quarters of 2018. During the first three quarters of 2019 and 2018, QEP incurred $43.2 million and $36.7 million, respectively, in costs associated with the implementation of our strategic initiatives, of which $36.7 million and $30.2 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 $46.3 million, or 36%, primarily due to $41.8 million lower labor, benefits and other associated costs as of a result of the reduction in our workforce and $7.7 million in lower legal and outside service costs, partially offset by a $7.2 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 third quarter of 2019, QEP recognized a loss on the sale of assets of $2.1 million, primarily related to a $2.7 million loss on the sale of the corporate aircraft, partially offset by a $0.9 million gain related to the divestiture of properties outside our main operating areas. During the third quarter of 2018, QEP recognized a gain on the sale of assets of $27.1 million primarily related to a net pre-tax gain on sale of $39.1 million related to the divestiture of properties outside our main operating areas and an additional pre-tax gain on sale of $0.4 million related to the sale of our Pinedale assets, partially offset by a pre-tax loss of $12.4 million related to the Uinta Basin Divestiture (refer to the Impairment expense discussion above for impairment charges related to the Uinta Basin Divestiture), which included $3.6 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 three quarters of 2019, QEP recognized a gain on the sale of assets of $2.5 million primarily related to the $3.5 million net gain from the divestiture of properties, partially offset by the loss on the sale of the corporate aircraft and a net pre-tax loss on sale of $1.0 million related to our Haynesville Divestiture, which included $1.4 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 three quarters of 2018, QEP recognized a gain on the sale of assets of $26.7 million related to the divestiture of properties outside our main operating area and an additional pre-tax gain on sale of $1.2 million related to the sale of our Pinedale assets, partially offset by a pre-tax loss of $12.4 million related to the Uinta Basin Divestiture (refer to the Impairment expense discussion above for impairment charges related to the Uinta Basin Divestiture), which included $5.5 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).

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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 third quarter of 2019, gains on commodity derivative contracts were $87.4 million, of which $92.3 million were unrealized gains and $4.9 million were realized losses on settled derivative contracts. During the third quarter of 2018, losses on commodity derivative contracts were $108.0 million, of which $63.7 million were unrealized losses, $38.4 million were realized losses on derivative contracts related to production contracts and $5.9 million were unrealized losses related to the Uinta Basin 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 three quarters of 2019, losses on commodity derivative contracts were $55.8 million, of which $30.8 million were unrealized losses, $26.8 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 three quarters of 2018, losses on commodity derivative contracts were $240.3 million, of which $127.1 million were realized losses on derivative contracts related to production and storage contracts, $107.3 million were unrealized losses and $5.9 million were unrealized losses related to the Uinta Basin Divestiture (refer to Note 7 – Derivative Contracts, in Item I of Part I of the Quarterly Report on Form 10-Q for more information).

Interest expense. Interest expense decreased $5.9 million, or 15%, during the third quarter of 2019 compared to the third quarter of 2018. The decrease during the third quarter of 2019 was primarily related to decreased borrowings under the credit facility.

Interest expense decreased $11.9 million, or 11%, during the first three quarters of 2019 compared to the first three quarters of 2018. The decrease during the first three quarters of 2019 was primarily related to decreased borrowings under the credit facility.

Income tax (provision) benefit. Income tax expense increased $24.1 million during the third quarter of 2019 compared to the third quarter of 2018. The increase in expense was the result of higher pre-tax income during the third quarter of 2019 compared to 2018. QEP’s effective federal and state income tax rate of 24.7% during the third quarter of 2019 compared to a rate of 25.5% during the third quarter of 2018 is primarily driven by the impact of discrete items recognized during the third quarter of 2018.

Income tax benefit decreased $61.9 million during the first three quarters of 2019 compared to the first three quarters of 2018. QEP's income tax benefit during the first three quarters of 2019 was impacted by a higher combined effective federal and state income tax rate of 130.8% during 2019 compared to a rate of 23.5% during the first three quarters 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 three quarters 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, interest expense and quarterly dividends. 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, interest expense, debt maturities and quarterly dividends during the next 12 months and the foreseeable future. In August 2019, QEP's Board of Directors approved the reinstatement of a quarterly cash dividend of $0.02 per share of common stock. The third quarter 2019 dividend of $4.8 million was paid in September 2019.

During the nine months ended September 30, 2019, QEP closed the Haynesville Divestiture for net cash proceeds of $633.9 million. QEP used the proceeds to repay the outstanding balance on its revolving credit facility and for general corporate purposes.

As of September 30, 2019, the Company had $92.4 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 September 30, 2019, it could

46

incur additional indebtedness of $307.9 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.

Credit Facility

QEP's unsecured 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 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 September 30, 2019 and December 31, 2018, QEP was in compliance with the covenants under the credit agreement.

During the nine months ended September 30, 2019, QEP's weighted-average interest rate on borrowings from its credit facility was 4.73%. As of September 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 October 18, 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 September 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.

On October 23, 2019, the Company issued a notice to holders of its outstanding 6.80% Senior Notes due March 1, 2020, of the Company’s intent to redeem all of the outstanding notes on November 22, 2019. The Company expects that the redemption will decrease the "Current portion of long term debt" on the Condensed Consolidated Balance Sheets by $51.7 million and expects to incur a loss on early extinguishment of debt of approximately $0.7 million in connection with the redemption of the Senior Notes.

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:

	Nine Months Ended September 30,
	2019			2018			Change
	(in millions)
Net income (loss)	$	13.1		$	(382.3	)	$	395.4
Non-cash adjustments to net income (loss)	383.2			1,071.8			(688.6		)
Changes in operating assets and liabilities	(54.3		)	(14.6		)	(39.7		)
Net cash provided by (used in) operating activities	$	342.0		$	674.9		$	(332.9	)

47

Net cash provided by operating activities was $342.0 million during the first three quarters of 2019, which included $13.1 million of net income, $383.2 million of non-cash adjustments to net income and $54.3 million in changes in operating assets and liabilities. Non-cash adjustments to net income of $383.2 million primarily included DD&A expense of $395.5 million, $29.0 million of unrealized losses on derivative contracts and $16.2 million of non-cash share-based compensation expense, partially offset by $61.2 million of deferred income taxes benefit.

The decrease in changes in operating assets and liabilities of $54.3 million primarily resulted from decreases in accounts payable and accrued expenses of $55.2 million, other long-term liabilities of $9.8 million and accrued production and property taxes of $6.3 million, partially offset by a decrease in inventory of $10.6 million, decrease in prepaid expenses and other current assets of $2.7 million and an increase in operating leases of $2.7 million.

Net cash provided by operating activities was $674.9 million during the first three quarters of 2018, which included $382.3 million of net loss, $1,071.8 million of non-cash adjustments to the net loss and $14.6 million in changes in operating assets and liabilities. Non-cash adjustments to the net loss of $1,071.8 million primarily included DD&A expense of $673.6 million, $404.4 million of impairment expense, $113.2 million of unrealized losses on derivative contracts and $24.0 million of non-cash share-based compensation expense, partially offset by $119.6 million of deferred income tax benefit.

The decrease in changes in operating assets and liabilities of $14.6 million primarily resulted from an increase in accounts receivable of $49.8 million, partially offset by an increase in accounts payable and accrued expenses of $11.8 million and a decrease in other assets of $18.8 million.

Cash Flow from Investing Activities

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

	Nine Months Ended September 30,
	2019			2018		Change
	(in millions)
Property acquisitions	$	3.6		$	48.3	$	(44.7	)
Property, plant and equipment capital expenditures	466.0			988.2		(522.2		)
Total accrued capital expenditures	469.6			1,036.5		(566.9		)
Change in accruals and other non-cash adjustments	(0.8		)	43.9		(44.7		)
Total cash capital expenditures	$	468.8		$	1,080.4	$	(611.6	)

In the first three quarters of 2019, on an accrual basis, the Company invested $466.0 million on property, plant and equipment capital expenditures (which excludes property acquisitions), a decrease of $522.2 million compared to the first three quarters of 2018. In the first three quarters of 2019, QEP's primary capital expenditures included $396.5 million in the Permian Basin (including midstream infrastructure of $38.9 million, primarily related to oil and gas gathering and water handling) and $70.3 million in the Williston Basin.

In the first three quarters of 2018, on an accrual basis, the Company invested $988.2 million on property, plant and equipment capital expenditures (which excludes property acquisitions). QEP's significant capital expenditures included $689.7 million in the Permian Basin (including midstream infrastructure of $58.0 million, primarily related to oil and gas gathering and water handling), $165.1 million in the Williston Basin, $124.7 million in Haynesville/Cotton Valley (including midstream infrastructure of $7.5 million, primarily related to gas gathering) and $5.1 million in the Uinta Basin. In addition, in the first three quarters 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 $48.3 million, of which $37.6 million was related to the 2017 Permian Basin Acquisition.

The mid-point of our 2019 forecasted capital expenditures (excluding property acquisitions) is $574.5 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.

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Cash Flow from Financing Activities

In the first three quarters of 2019, net cash used in financing activities was $455.7 million compared to net cash provided by financing activities of $191.8 million in the first three quarters of 2018. During the first three quarters of 2019, QEP made repayments on its credit facility of $486.0 million, had borrowings from the credit facility of $56.0 million and paid a quarterly dividend payment of $4.8 million. In addition, QEP had treasury stock repurchases of $7.0 million related to the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants. During the first three quarters of 2019, QEP had a decrease in checks outstanding in excess of cash balances of $13.9 million.

During the first three quarters of 2018, QEP had borrowings from its credit facility of $2,616.0 million and repayments on its credit facility of $2,329.5 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 $7.8 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 $28.7 million.

As of September 30, 2019, the total principal amount of long-term debt was $2,081.1 million, of which $2,099.3 million was senior notes and $18.2 million was 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 September 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 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 September 30, 2019, QEP held commodity price derivative contracts, excluding basis swaps, totaling 18.2 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 October 18, 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 September 30, 2019.

Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	3.6	$	55.44
2019	ICE Brent	0.5	$	66.73
2019	Argus WTI Midland	0.2	$	54.60
2019	Argus WTI Houston	0.1	$	65.70
2020	NYMEX WTI	11.3	$	58.29
2020	Argus WTI Midland	1.5	$	57.30
2020 (January - June)	Argus WTI Houston	1.0	$	60.06

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	1.7	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.5	$	3.69
2020	NYMEX WTI	Argus WTI Midland	6.6	$	0.17
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 September 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	26.8
Change in oil prices on futures markets	(125.5		)
Contracts added	68.0
Net fair value of oil derivative contracts outstanding at September 30, 2019	$	91.8

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:

	September 30, 2019
	(in millions)
Net fair value – asset (liability)	$	91.8
Fair value if market prices of oil and basis differentials decline by 10%	$	82.6
Fair value if market prices of oil and basis differentials increase by 10%	$	100.9

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $9.1 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $9.2 million as of September 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 September 30, 2019, the Company had no borrowings outstanding under its revolving credit facility. If interest rates were to increase or decrease 10% during the nine months ended September 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 nine months ended September 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;

• 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, debt maturities, interest expense and dividends;

• 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;

• expiration of statute of limitations related to uncertain tax position and associated recognition of tax benefit and reduction in interest and general and administrative expenses;

• 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;

53

• 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 September 30, 2019. Based on such evaluation, such officers have concluded that, as of September 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 September 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. 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.

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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 factors 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 August 14, 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 September 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)
July 1, 2019 - July 31, 2019	6,170	$	5.36	—	1,191.6
August 1, 2019 - August 31, 2019	35,261	$	3.53	—	1,191.6
September 1, 2019 - September 30, 2019	131,522	$	4.06	—	1,191.6
Total	172,953			—

 ____________________________

⁽¹⁾  During the three months ended September 30, 2019, QEP purchased 172,953 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

None.

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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 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on August 7, 2019).
10.2+	Executive Severance Compensation Plan – CIC, as Amended and Restated Effective as of August 7, 2019 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on August 7, 2019).
10.3	Letter Agreement, dated August 6, 2019, by and between QEP Resources, Inc. and Elliott Management Corporation (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on August 7, 2019).
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.

57

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)
October 23, 2019	/s/ Timothy J. Cutt
	Timothy J. Cutt,
	President and Chief Executive Officer
October 23, 2019	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

58

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.

October 23, 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.

October 23, 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 September 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.
October 23, 2019
	/s/ Timothy J. Cutt
	Timothy J. Cutt
	President and Chief Executive Officer
October 23, 2019
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer

XML

Share-Based Compensation

9 Months Ended

Sep. 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 September 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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019(1)			2018(2)			2019(1)		2018(2)
	(in millions)
Stock options	$	—		$	0.2		$	0.3	$	0.9
Restricted share awards	5.0			5.3			15.9		20.9
Performance share units	(0.9		)	(2.9		)	4.6		4.1
Restricted share units	—			0.1			0.2		0.2
Total share-based compensation expense	$	4.1		$	2.7		$	21.0	$	26.1

 ________________________

⁽¹⁾  During the three and nine months ended September 30, 2019, the Company recorded an additional $1.6 million and $11.3 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 nine months ended September 30, 2019 and the remaining $1.6 million and $9.8 million, respectively, is included in the table above. Refer to Note 9 – Restructuring for additional information.

⁽²⁾  During the three and nine months ended September 30, 2018, the Company recorded an additional $3.2 million and $7.2 million, respectively of share-based compensation expense, related to the acceleration of vesting that occurred as part of the restructuring program, of which $2.2 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statement of Operations during the three and nine months ended September 30, 2018 and the remaining $1.0 million and $5.0 million, respectively, is included in the table above. Refer to Note 9 – Restructuring for additional information.

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 nine months ended September 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	(292,921	)	30.82
Outstanding at September 30, 2019	1,806,012		$	20.88	2.56	$	—
Options Exercisable at September 30, 2019	1,761,836		$	21.00	2.52	$	—
Unvested Options at September 30, 2019	44,176		$	16.32	4.41	$	—

During the nine months ended September 30, 2019 there were no exercises of stock options. As of September 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 0.54 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 nine months ended September 30, 2019 and 2018 was $29.6 million and $30.7 million, respectively. The weighted-average grant date fair value of restricted share awards was $7.79 per share and $9.56 per share for the nine months ended September 30, 2019 and 2018, respectively. As of September 30, 2019, $13.8 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 2.15 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	2,330,254		7.79
Vested	(2,780,285	)	10.66
Forfeited	(239,489	)	9.15
Unvested balance at September 30, 2019	3,132,613		$	8.76

Performance Share Units

The payouts associated with 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 September 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 $12.1 million and $2.0 million for vested performance share units during the nine months ended September 30, 2019 and 2018, respectively. The weighted-average grant date fair value of the performance share units granted during the nine months ended September 30, 2019 and 2018 was $7.93 and $9.55 per share, respectively. As of September 30, 2019, $2.6 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 2.16 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	614,633		7.93
Vested and paid	(1,206,165	)	10.68
Unvested balance at September 30, 2019	967,780		$	9.50

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 $7.90 and $9.55 per share for the nine months ended September 30, 2019 and 2018, respectively. As of September 30, 2019, $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.22 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	37,498		7.90
Vested and paid	(47,807	)	10.04
Unvested balance at September 30, 2019	32,366		$	8.13

XML

Revenue (Tables)

9 Months Ended

Sep. 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, Revenue Recognition.

	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Three Months Ended September 30, 2019
Northern Region
Williston Basin	$	88.9	$	5.5	$	2.4	$	(7.0	)	$	89.8
Other Northern	—		0.1		0.1		—			0.2
Southern Region
Permian Basin	209.9		3.4		9.4		(7.2		)	215.5
Other Southern	—		0.1		—		—			0.1
Total oil and condensate, gas and NGL sales	$	298.8	$	9.1	$	11.9	$	(14.2	)	$	305.6
	Three Months Ended September 30, 2018
Northern Region
Williston Basin	$	203.4	$	12.0	$	19.2	$	(12.3	)	$	222.3
Uinta Basin	7.3		6.8		1.4		—			15.5
Other Northern	1.1		0.5		0.1		—			1.7
Southern Region
Permian Basin	204.0		5.4		21.3		(3.5		)	227.2
Haynesville/Cotton Valley	0.2		76.9		—		—			77.1
Other Southern	0.1		0.1		—		—			0.2
Total oil and condensate, gas and NGL sales	$	416.1	$	101.7	$	42.0	$	(15.8	)	$	544.0

	Oil and condensate sales			Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Nine Months Ended September 30, 2019
Northern Region
Williston Basin	$	306.3		$	25.5	$	15.6	$	(26.0	)	$	321.4
Other Northern	0.9			0.4		0.1		—			1.4
Southern Region
Permian Basin	526.7			7.4		27.4		(14.7		)	546.8
Other Southern	0.1			6.1		—		—			6.2
Total oil and condensate, gas and NGL sales	$	834.0		$	39.4	$	43.1	$	(40.7	)	$	875.8
	Nine Months Ended September 30, 2018
Northern Region
Williston Basin	$	571.5		$	30.2	$	45.7	$	(32.9	)	$	614.5
Uinta Basin	25.2			24.8		4.8		—			54.8
Other Northern	3.9			1.7		—		—			5.6
Southern Region
Permian Basin	524.1			13.2		37.7		(8.0		)	567.0
Haynesville/Cotton Valley	0.8			231.2		—		—			232.0
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,125.3		$	301.5	$	88.2	$	(40.9	)	$	1,474.1

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 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 September 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	September 30, 2019
Fair value of derivative contracts – short-term	$	—	$	69.8	$	—	$	—		$	69.8
Fair value of derivative contracts – long-term	—		23.2		—		—			23.2
Total financial assets	$	—	$	93.0	$	—	$	—		$	93.0
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	0.8	$	—	$	—		$	0.8
Fair value of derivative contracts – long-term	—		0.4		—		—			0.4
Total financial liabilities	$	—	$	1.2	$	—	$	—		$	1.2
	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
	September 30, 2019				December 31, 2018
Financial Assets	(in millions)
Cash and cash equivalents	$	92.4	$	92.4	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	0.7	$	0.7	$	14.6	$	14.6
Total debt outstanding	$	2,081.1	$	1,959.1	$	2,507.1	$	2,350.5

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018		Sep. 30, 2019		Sep. 30, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 81.0	$ 7.3		$ 13.1		$ (382.3)
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)	0.1	0.2	[2]	0.2		0.4	[2]
Amortization of actuarial losses(3)	0.0	0.1	[3]	0.1		0.5	[3]
Curtailment Gain (Loss), after Tax(4)		0.0		(0.3)	[4]	0.0
Other comprehensive income (loss)	0.1	0.3		0.0		1.2
Comprehensive income (loss)	81.1	7.6		13.1		(381.1)
Amortization of prior service cost, income tax expense	$ 0.0	$ 0.0	[2]	$ 0.0		$ 0.1	[2]

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

[2] Presented net of income tax expense of $0.1 million for the nine months ended September 30, 2018.

[3] Presented net of income tax benefit of $0.1 million and expense of $0.1 million for the three and nine months ended September 30, 2018, respectively.

[4] Presented net of income tax benefit of $0.1 million for the nine months ended September 30, 2019

XML

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) Statement - USD ($) shares in Millions, $ in Millions	Total	Common Stock, Value [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Other Comprehensive Income (Loss) [Member]	Total [Member]
Common Stock, Shares		243.0
Treasury Stock, Shares			(2.0)
Stockholders' Equity		$ 2.4	$ (34.2)	$ 1,398.2	$ 2,442.6	$ (11.1)	$ 3,797.9
Net income (loss), Shares		0.0	0.0
Net income (loss)	$ (382.3)	$ 0.0	$ 0.0	0.0	(382.3)	0.0	(382.3)
Common stock repurchased and retired, Shares		(6.2)	0.0
Common stock repurchased and retired		$ (0.1)	$ 0.0	0.0	(58.3)	0.0	(58.4)
Share-based compensation, Shares		3.0
Share-based compensation		$ 0.1
Stock Issued During Period, Shares, Treasury Stock Reissued			(1.0)
Share-based compensation			$ (10.0)	26.4	0.0	0.0	16.5
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	1.2	1.2
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
Net income (loss), Shares		0.0	0.0
Net income (loss)	7.3	$ 0.0	$ 0.0	0.0	7.3	0.0	7.3
Common stock repurchased and retired, Shares		0.0	0.0
Common stock repurchased and retired	$ 0.0	$ 0.0	$ 0.0	0.0	0.0	0.0
Share-based compensation, Shares		0.1
Share-based compensation		$ 0.0
Stock Issued During Period, Shares, Treasury Stock Reissued			(0.3)
Share-based compensation			$ (3.0)	8.9	0.0	0.0	5.9
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		239.8
Treasury Stock, Shares			(3.0)
Stockholders' Equity		$ 2.4	$ (44.2)	1,424.6	2,002.0	(9.9)	3,374.9
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)	13.1	$ 0.0	$ 0.0	0.0	13.1	0.0	13.1
Cash dividends declared, $0.02 per share					(4.8)		(4.8)
Share-based compensation, Shares		2.3
Share-based compensation		$ 0.0
Stock Issued During Period, Shares, Treasury Stock Reissued			(1.2)
Share-based compensation			$ (9.2)	20.0	0.0	0.0	10.8
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	0.0	0.0
Common Stock, Shares		242.0
Treasury Stock, Shares			(4.1)
Stockholders' Equity		$ 2.4	$ (53.6)	1,446.3	1,308.6	(14.4)	2,689.3
Net income (loss), Shares		0.0	0.0
Net income (loss)	$ 81.0	$ 0.0	$ 0.0	0.0	81.0	0.0	81.0
Cash dividends declared, $0.02 per share					(4.8)		(4.8)
Share-based compensation, Shares		0.1
Share-based compensation		$ 0.0
Stock Issued During Period, Shares, Treasury Stock Reissued			(0.2)
Share-based compensation			$ (1.2)	5.6	0.0	0.0	4.4
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		242.1
Treasury Stock, Shares	(4.3)		(4.3)
Stockholders' Equity	$ 2,770.0	$ 2.4	$ (54.8)	$ 1,451.9	$ 1,384.8	$ (14.3)	$ 2,770.0

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Share-Based Compensation Schedule Of Stock Option Transactions (Details) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 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	(292,921)
Outstanding at end of period | shares	1,806,012
Options exercisable, shares | shares	1,761,836
Unvested options, shares | shares	44,176
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	30.82
Weighted average exercise price, end of year | $ / shares	20.88
Options exercisable, weighted average exercise price | $ / shares	21.00
Unvested options, weighted average exercise price | $ / shares	$ 16.32
Weighted average remaining contractual term, options outstanding	2 years 6 months 21 days
Weighted average remaining contractual term, options exercisable	2 years 6 months 7 days
Weighted average remaining contractual term, options unvested	4 years 4 months 28 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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Employee Benefits (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
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		0.4
Estimated Future Employer Contributions in Current Fiscal Year		0.1
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer		0.2
401(k) Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer		3.2
Estimated Future Employer Contributions in Current Fiscal Year		0.8
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
Total [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Medical Plan curtailment	$ 0.3	(0.4)	$ 0.3
Interest and other income (expense) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Medical Plan curtailment	0.3	(0.2)	0.3
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)	$ 0.0
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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Derivative Contracts (Narrative) (Details)	9 Months Ended
	Sep. 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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Asset Retirement Obligations Asset Retirement Obligations ARO Rollforward (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Divestitures [Line Items]
ARO liability at January 1, 2019	$ 159.6
Accretion	4.1
Additions	0.8
Revisions	(0.3)
Liabilities related to assets sold(1)	(60.7)
Liabilities settled	(1.3)
ARO Liability at September 30, 2019	102.2
Haynesville Divestiture [Member]
Divestitures [Line Items]
Liabilities related to assets sold(1)	$ (57.6)

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Acquisitions & Divestitures Uinta Basin (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	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			$ 676.5	$ 217.5
Noncurrent assets held for sale	$ 0.0		0.0		$ 692.7
Gain (Loss) on Disposition of Oil and Gas Property	(2.1)	$ 27.1	2.5	26.7
Impairment	$ 0.0	0.0	5.0	404.4
Uinta Basin [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
Gain (Loss) on Disposition of Oil and Gas Property				(12.4)
Results of Operations, Loss before Income Taxes		$ 4.4	$ 0.2	419.3
Impairment				$ 402.8

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Derivative Contracts Schedule Of Commodity Derivative Contracts (Details) MMBTU in Millions	9 Months Ended
	Sep. 30, 2019 USD ($) MMBTU $ / MMBTU	Dec. 31, 2018 USD ($)
Oil Swaps [Member] | Year 2019 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	3.6
Average Swap Price per Unit | $	$ 55.44
Oil Swaps [Member] | Year 2019 [Member] | Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	0.2
Average Swap Price per Unit | $	$ 54.60
Oil Swaps [Member] | Year 2019 [Member] | ICE Brent [Member]
Derivative [Line Items]
Derivative Volumes	0.5
Average Swap Price per Unit | $	$ 66.73
Oil Swaps [Member] | Year 2019 [Member] | Argus WTI Houston [Member]
Derivative [Line Items]
Derivative Volumes	0.1
Average Swap Price per Unit | $	$ 65.70
Oil Swaps [Member] | Year 2020 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	11.3
Average Swap Price per Unit | $	$ 58.29
Oil Swaps [Member] | Year 2020 [Member] | Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	1.5
Average Swap Price per Unit | $	$ 57.30
Oil Swaps [Member] | Year 2020 [Member] | Argus WTI Houston [Member]
Derivative [Line Items]
Derivative Volumes	1.0
Average Swap Price per Unit | $	$ 60.06
Oil Basis Swaps [Member] | Year 2019 [Member] | NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	1.7
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	0.5
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	6.2
Weighted-Average Differential | $ / MMBTU	0.13
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 | $	$ 93,000,000.0	$ 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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Restructuring Costs Restructuring Expense Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Termination Benefits [Member]
Costs recognized from inception to September 30, 2019(1)	$ 43.2		$ 43.2
Total remaining costs expected to be incurred			0.0
Office lease Termination Costs [Member]
Costs recognized from inception to September 30, 2019(1)	1.6		1.6
Total remaining costs expected to be incurred			0.0
Accelerated Share Based Compensation [Member]
Costs recognized from inception to September 30, 2019(1)	22.6		22.6
Total remaining costs expected to be incurred			0.0
Retention Expense [Member]
Costs recognized from inception to September 30, 2019(1)	34.2		34.2
Total remaining costs expected to be incurred			5.0
Pension curtailment [Member]
Costs recognized from inception to September 30, 2019(1)	(0.2)		(0.2)
Total remaining costs expected to be incurred			0.0
Total [Member]
Termination benefits	4.3	$ 6.7	11.0	$ 13.7
Office lease termination costs		0.7	0.6	1.0
Accelerated share-based compensation(1)	1.6	3.2	11.3	7.2
Retention expense (including share-based compensation)	4.5	5.8	15.4	13.8
Pension and Medical Plan curtailment		0.3	(0.4)	0.3
Total restructuring costs	10.4	16.7	37.9	36.0
Costs recognized from inception to September 30, 2019(1)	101.4		101.4
Total remaining costs expected to be incurred			5.0
General and Administrative Expense [Member]
Termination benefits	4.3	5.3	10.9	10.4
Office lease termination costs		0.7	0.6	1.0
Accelerated share-based compensation(1)	1.6	1.0	9.8	5.0
Retention expense (including share-based compensation)	4.5	5.8	15.4	13.8
Pension and Medical Plan curtailment		0.0	0.0	0.0
Total restructuring costs	10.4	12.8	36.7	30.2
Net gain (loss) from asset sales [Member]
Termination benefits	0.0	1.4	0.1	3.3
Office lease termination costs		0.0	0.0	0.0
Accelerated share-based compensation(1)	0.0	2.2	1.5	2.2
Retention expense (including share-based compensation)	0.0	0.0	0.0	0.0
Pension and Medical Plan curtailment		0.0	(0.2)	0.0
Total restructuring costs	0.0	3.6	1.4	5.5
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
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		0.3	(0.2)	0.3
Total restructuring costs	0.0	$ 0.3	(0.2)	$ 0.3
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)	$ 3.5		$ 25.2

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Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Minimum Lease Payments [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 6.2	$ 17.4
Operating Leases, Future Minimum Payments, Due in Two Years	21.7	13.8
Operating Leases, Future Minimum Payments, Due in Three Years	19.9	9.1
Operating Leases, Future Minimum Payments, Due in Four Years	15.4	7.4
Operating Leases, Future Minimum Payments, Due in Five Years	9.8	4.5
Operating Leases, Future Minimum Payments, Due Thereafter	$ 0.7	$ 0.0

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Acquisitions & Divestitures Acquisitions (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 676.5	$ 217.5
Payments to acquire oil and gas property	$ 3.6	48.3
Permian Basin [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property		$ 37.6

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Employee Benefits (Tables)

9 Months Ended

Sep. 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						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.1		$	0.2		$	0.2		$	0.6
Interest cost	1.2			1.2			3.6			3.4
Expected return on plan assets	(1.5		)	(1.4		)	(4.4		)	(4.3		)
Amortization of prior service costs(1)	—			0.2			0.2			0.6
Amortization of actuarial losses(1)	—			—			0.1			0.6
Curtailment (gain) loss(2)	—			0.3			0.4			0.3
Periodic expense	$	(0.2	)	$	0.5		$	0.1		$	1.2
Medical Plan benefits
Interest cost	$	—		$	—		$	0.1		$	0.1
Amortization of prior service costs(1)	—			(0.1		)	—			(0.2		)
Curtailment (gain) loss(2)	—			—			(0.8		)	—
Periodic expense	$	—		$	(0.1	)	$	(0.7	)	$	(0.1	)

____________________________

⁽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 nine months ended September 30, 2019.

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Restructuring Costs Restructuring Costs (Tables)

9 Months Ended

Sep. 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 September 30, 2019
	(in millions)
Termination benefits	$	4.3		$	4.3	$	—		$	—
Accelerated share-based compensation(1)	1.6			1.6		—			—
Retention expense (including share-based compensation)	4.5			4.5		—			—
Total restructuring costs	$	10.4		$	10.4	$	—		$	—
	Nine Months Ended September 30, 2019
Termination benefits	$	11.0		$	10.9	$	0.1		$	—
Office lease termination costs	0.6			0.6		—			—
Accelerated share-based compensation(1)	11.3			9.8		1.5			—
Retention expense (including share-based compensation)	15.4			15.4		—			—
Pension and Medical Plan curtailment	(0.4		)	—		(0.2		)	(0.2		)
Total restructuring costs	$	37.9		$	36.7	$	1.4		$	(0.2	)
	Three Months Ended September 30, 2018
Termination benefits	$	6.7		$	5.3	$	1.4		—
Office lease termination costs	0.7			0.7		—			—
Accelerated share-based compensation	3.2			1.0		2.2			—
Retention expense (including share-based compensation)	5.8			5.8		—			—
Pension and Medical Plan curtailment	0.3			—		—			0.3
Total restructuring costs	$	16.7		$	12.8	$	3.6		$	0.3
	Nine Months Ended September 30, 2018
Termination benefits	$	13.7		$	10.4	$	3.3		—
Office lease termination costs	1.0			1.0		—			—
Accelerated share-based compensation	7.2			5.0		2.2			—
Retention expense (including share-based compensation)	13.8			13.8		—			—
Pension and Medical Plan curtailment	0.3			—		—			0.3
Total restructuring costs	$	36.0		$	30.2	$	5.5		$	0.3

Restructuring Costs [Table Text Block]

	Costs recognized from inception through September 30, 2019(1)			Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	43.2		$	—	(2)
Office lease termination costs	1.6			—		(2)
Accelerated share-based compensation	22.6			—		(2)
Retention expense (including share-based compensation)	34.2			5.0
Pension and Medical Plan curtailment	(0.2		)	—		(2)
Total restructuring costs	$	101.4		$	5.0

 ____________________________

⁽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 September 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	11.0			0.6			11.3			15.4			(0.4		)	37.9
Costs paid or otherwise settled	(28.3		)	(0.6		)	(11.3		)	(23.6		)	0.4			(63.4		)
Balance at September 30, 2019	$	2.2		$	—		$	—		$	2.6		$	—		$	4.8

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Earnings Per Share

9 Months Ended

Sep. 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 nine months ended September 30, 2019 and 2018 there were no anti-dilutive shares.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019	2018	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	237.9	236.9	237.7	238.3
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	0.1	—	—
Average diluted common shares outstanding	237.9	237.0	237.7	238.3

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Leases (Notes)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Leases of Lessee Disclosure [Text Block]

Adoption of ASC Topic 842, Leases

On January 1, 2019, QEP adopted ASC Topic 842, Leases, using the modified retrospective approach, which was applied to historical leases that were still effective as of January 1, 2019. Results for 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 September 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		Nine Months Ended
	September 30, 2019(1)		September 30, 2019(1)
Lease Cost included in the Condensed Consolidated Balance Sheets	(in millions)
Property, Plant and Equipment acquisitions(2)	$	2.5	$	11.3
	Three Months Ended		Nine Months Ended
	September 30, 2019(1)		September 30, 2019(1)
Lease Cost included in the Condensed Consolidated Statement of Operations	(in millions)
Lease operating expense	$	2.9	$	9.0
Gathering and other expense	2.0		5.8
General and administrative	1.3		4.5
Total lease cost	$	8.7	$	30.6

 ____________________________

⁽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 nine months ended September 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:

	September 30, 2019(1)
Weighted-average remaining lease term (years)	3.4
Weighted-average discount rate	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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Commitments and Contingencies Minimum Lease Payments Under ASC 842 (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Minimum Lease Payments [Abstract]
Current operating lease lease liabilities	$ 18.4	$ 0.0
Operating lease liabilities	45.3	0.0
Operating Leases, Future Minimum Payments Due, Next Twelve Months	6.2	17.4
Operating Leases, Future Minimum Payments, Due in Two Years	21.7	13.8
Operating Leases, Future Minimum Payments, Due in Three Years	19.9	9.1
Operating Leases, Future Minimum Payments, Due in Four Years	15.4	7.4
Operating Leases, Future Minimum Payments, Due in Five Years	9.8	4.5
Operating Leases, Future Minimum Payments, Due Thereafter	0.7	$ 0.0
Less: Interest (1)	(10.0)
Operating Lease, Liability	$ 63.7

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Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Inputs, Level 2 [Member] - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	$ 93.0	$ 123.6
Derivative Liability, Fair Value, Gross	1.2	1.1
Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	69.8	88.2
Derivative Liability, Fair Value, Gross	0.8	0.4
Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	23.2	35.4
Derivative Liability, Fair Value, Gross	0.4	0.7
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	93.0	123.6
Derivative Liability, Fair Value, Gross	1.2	1.1
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	69.8	88.2
Derivative Liability, Fair Value, Gross	0.8	0.4
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	23.2	35.4
Derivative Liability, Fair Value, Gross	$ 0.4	$ 0.7

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Restructuring Costs Restructuring Liability (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	$ 2.2	$ 19.5
Costs incurred and charged to expense	11.0
Costs paid or otherwise settled	(28.3)
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	11.3
Costs paid or otherwise settled	(11.3)
Retention Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Liability	2.6	10.8
Costs incurred and charged to expense	15.4
Costs paid or otherwise settled	(23.6)
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	4.8	$ 30.3
Costs incurred and charged to expense	37.9
Costs paid or otherwise settled	$ (63.4)

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019(1)			2018(2)			2019(1)		2018(2)
	(in millions)
Stock options	$	—		$	0.2		$	0.3	$	0.9
Restricted share awards	5.0			5.3			15.9		20.9
Performance share units	(0.9		)	(2.9		)	4.6		4.1
Restricted share units	—			0.1			0.2		0.2
Total share-based compensation expense	$	4.1		$	2.7		$	21.0	$	26.1

 ________________________

⁽¹⁾  During the three and nine months ended September 30, 2019, the Company recorded an additional $1.6 million and $11.3 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 nine months ended September 30, 2019 and the remaining $1.6 million and $9.8 million, respectively, is included in the table above. Refer to Note 9 – Restructuring for additional information.

⁽²⁾ 

During the three and nine months ended September 30, 2018, the Company recorded an additional $3.2 million and $7.2 million, respectively of share-based compensation expense, related to the acceleration of vesting that occurred as part of the restructuring program, of which $2.2 million was recorded in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statement of Operations during the three and nine months ended September 30, 2018 and the remaining $1.0 million and $5.0 million, respectively, is included in the table above. Refer to Note 9 – Restructuring for additional information.

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	(292,921	)	30.82
Outstanding at September 30, 2019	1,806,012		$	20.88	2.56	$	—
Options Exercisable at September 30, 2019	1,761,836		$	21.00	2.52	$	—
Unvested Options at September 30, 2019	44,176		$	16.32	4.41	$	—

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

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

	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2018	42,675		$	10.47
Granted	37,498		7.90
Vested and paid	(47,807	)	10.04
Unvested balance at September 30, 2019	32,366		$	8.13

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	2,330,254		7.79
Vested	(2,780,285	)	10.66
Forfeited	(239,489	)	9.15
Unvested balance at September 30, 2019	3,132,613		$	8.76

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	614,633		7.93
Vested and paid	(1,206,165	)	10.68
Unvested balance at September 30, 2019	967,780		$	9.50

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Leases (Tables)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Lease, Cost [Table Text Block]

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

	Three Months Ended		Nine Months Ended
	September 30, 2019(1)		September 30, 2019(1)
Lease Cost included in the Condensed Consolidated Balance Sheets	(in millions)
Property, Plant and Equipment acquisitions(2)	$	2.5	$	11.3
	Three Months Ended		Nine Months Ended
	September 30, 2019(1)		September 30, 2019(1)
Lease Cost included in the Condensed Consolidated Statement of Operations	(in millions)
Lease operating expense	$	2.9	$	9.0
Gathering and other expense	2.0		5.8
General and administrative	1.3		4.5
Total lease cost	$	8.7	$	30.6

 ____________________________

⁽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 nine months ended September 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:

	September 30, 2019(1)
Weighted-average remaining lease term (years)	3.4
Weighted-average discount rate	7.7	%

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Revenue Disaggregated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Oil and Condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 298.8	$ 416.1	$ 834.0	$ 1,125.3
Oil and Condensate [Member] | Williston Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	88.9	203.4	306.3	571.5
Oil and Condensate [Member] | Uinta Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		7.3		25.2
Oil and Condensate [Member] | Other Northern [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	1.1	0.9	3.9
Oil and Condensate [Member] | Permian Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	209.9	204.0	526.7	524.1
Oil and Condensate [Member] | Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.2		0.8
Oil and Condensate [Member] | Other Southern [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.1	0.1	(0.2)
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9.1	101.7	39.4	301.5
Natural Gas [Member] | Williston Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5.5	12.0	25.5	30.2
Natural Gas [Member] | Uinta Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6.8		24.8
Natural Gas [Member] | Other Northern [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.1	0.5	0.4	1.7
Natural Gas [Member] | Permian Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	3.4	5.4	7.4	13.2
Natural Gas [Member] | Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		76.9		231.2
Natural Gas [Member] | Other Southern [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.1	0.1	6.1	0.4
Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	11.9	42.0	43.1	88.2
Natural Gas Liquids [Member] | Williston Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2.4	19.2	15.6	45.7
Natural Gas Liquids [Member] | Uinta Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1.4		4.8
Natural Gas Liquids [Member] | Other Northern [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.1	0.1	0.1	0.0
Natural Gas Liquids [Member] | Permian Basin [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9.4	21.3	27.4	37.7
Natural Gas Liquids [Member] | Haynesville [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0		0.0
Natural Gas Liquids [Member] | Other Southern [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0	0.0	0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold	(14.2)	(15.8)	(40.7)	(40.9)
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | Williston Basin [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold	(7.0)	(12.3)	(26.0)	(32.9)
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | Uinta Basin [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold		0.0		0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | Other Northern [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold	0.0	0.0	0.0	0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | Permian Basin [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold	(7.2)	(3.5)	(14.7)	(8.0)
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | Haynesville [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold		0.0		0.0
Natural Gas, Gathering, Transportation, Marketing and Processing [Member] | Other Southern [Member]
Disaggregation of Revenue [Line Items]
Cost of Goods and Services Sold	0.0	0.0	0.0	0.0
Oil and Gas, Exploration and Production [Member] | As reported [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	305.6	544.0	875.8	1,474.1
Oil and Gas, Exploration and Production [Member] | Williston Basin [Member] | As reported [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	89.8	222.3	321.4	614.5
Oil and Gas, Exploration and Production [Member] | Uinta Basin [Member] | As reported [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		15.5		54.8
Oil and Gas, Exploration and Production [Member] | Other Northern [Member] | As reported [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.2	1.7	1.4	5.6
Oil and Gas, Exploration and Production [Member] | Permian Basin [Member] | As reported [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	215.5	227.2	546.8	567.0
Oil and Gas, Exploration and Production [Member] | Haynesville [Member] | As reported [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		77.1		232.0
Oil and Gas, Exploration and Production [Member] | Other Southern [Member] | As reported [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 0.1	$ 0.2	$ 6.2	$ 0.2

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Asset Retirement Obligations

9 Months Ended

Sep. 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
	September 30,		December 31,
	2019		2018
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.7	$	5.1
Long-term:
Asset retirement obligations	95.5		96.9
Other long-term liabilities held for sale	—		57.6
Total ARO Liability	$	102.2	$	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	4.1
Additions	0.8
Revisions	(0.3		)
Liabilities related to assets sold(1)	(60.7		)
Liabilities settled	(1.3		)
ARO liability at September 30, 2019	$	102.2

_______________________

⁽¹⁾ 

Liabilities related to assets sold during the nine months ended September 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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Restructuring Costs

9 Months Ended

Sep. 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 September 30, 2019
	(in millions)
Termination benefits	$	4.3		$	4.3	$	—		$	—
Accelerated share-based compensation(1)	1.6			1.6		—			—
Retention expense (including share-based compensation)	4.5			4.5		—			—
Total restructuring costs	$	10.4		$	10.4	$	—		$	—
	Nine Months Ended September 30, 2019
Termination benefits	$	11.0		$	10.9	$	0.1		$	—
Office lease termination costs	0.6			0.6		—			—
Accelerated share-based compensation(1)	11.3			9.8		1.5			—
Retention expense (including share-based compensation)	15.4			15.4		—			—
Pension and Medical Plan curtailment	(0.4		)	—		(0.2		)	(0.2		)
Total restructuring costs	$	37.9		$	36.7	$	1.4		$	(0.2	)
	Three Months Ended September 30, 2018
Termination benefits	$	6.7		$	5.3	$	1.4		—
Office lease termination costs	0.7			0.7		—			—
Accelerated share-based compensation	3.2			1.0		2.2			—
Retention expense (including share-based compensation)	5.8			5.8		—			—
Pension and Medical Plan curtailment	0.3			—		—			0.3
Total restructuring costs	$	16.7		$	12.8	$	3.6		$	0.3
	Nine Months Ended September 30, 2018
Termination benefits	$	13.7		$	10.4	$	3.3		—
Office lease termination costs	1.0			1.0		—			—
Accelerated share-based compensation	7.2			5.0		2.2			—
Retention expense (including share-based compensation)	13.8			13.8		—			—
Pension and Medical Plan curtailment	0.3			—		—			0.3
Total restructuring costs	$	36.0		$	30.2	$	5.5		$	0.3

 ____________________________

⁽¹⁾  Accelerated share-based compensation represents the additional expense or loss recognized in the Condensed Consolidated Statement of Operations for the three and nine months ended September 30, 2019. Total accelerated share based compensation was $3.5 million and $25.2 million for the three and nine months ended September 30, 2019, respectively, and was determined based on the contractual vesting date, with $1.6 million and $11.3 million recognized during the three and nine months ended September 30, 2019, respectively, as shown above, and the remaining amount recognized in prior periods.

	Costs recognized from inception through September 30, 2019(1)			Total remaining costs expected to be incurred
	(in millions)
Termination benefits	$	43.2		$	—	(2)
Office lease termination costs	1.6			—		(2)
Accelerated share-based compensation	22.6			—		(2)
Retention expense (including share-based compensation)	34.2			5.0
Pension and Medical Plan curtailment	(0.2		)	—		(2)
Total restructuring costs	$	101.4		$	5.0

 ____________________________

⁽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 September 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	11.0			0.6			11.3			15.4			(0.4		)	37.9
Costs paid or otherwise settled	(28.3		)	(0.6		)	(11.3		)	(23.6		)	0.4			(63.4		)
Balance at September 30, 2019	$	2.2		$	—		$	—		$	2.6		$	—		$	4.8

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Derivative Contracts (Tables)

9 Months Ended

Sep. 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 September 30, 2019:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	3.6	$	55.44
2019	ICE Brent	0.5	$	66.73
2019	Argus WTI Midland	0.2	$	54.60
2019	Argus WTI Houston	0.1	$	65.70
2020	NYMEX WTI	11.3	$	58.29
2020	Argus WTI Midland	1.5	$	57.30
2020 (January - June)	Argus WTI Houston	1.0	$	60.06

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

Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2019	NYMEX WTI	Argus WTI Midland	1.7	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.5	$	3.69
2020	NYMEX WTI	Argus WTI Midland	6.2	$	0.13
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	September 30, 2019		December 31, 2018		September 30, 2019		December 31, 2018
Current:		(in millions)
Commodity(1)	Fair value of derivative contracts	$	69.8	$	88.2	$	0.8	$	0.4
Long-term:
Commodity	Fair value of derivative contracts	23.2		35.4		0.4		0.7
Total derivative instruments		$	93.0	$	123.6	$	1.2	$	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						Nine Months Ended
Derivative contracts	September 30,						September 30,
	2019			2018(2)			2019(1)			2018(2)
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(4.9	)	$	(41.7	)	$	(23.9	)	$	(138.0	)
Gas derivative contracts	—			3.3			(2.9		)	10.6
Gas Storage
Gas derivative contracts	—			—			—			0.3
Realized gains (losses) on commodity derivative contracts	(4.9		)	(38.4		)	(26.8		)	(127.1		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	92.3			(60.6		)	(30.5		)	(88.1		)
Gas derivative contracts	—			(3.1		)	(0.3		)	(18.9		)
Gas Storage
Gas derivative contracts	—			—			—			(0.3		)
Unrealized gains (losses) on commodity derivative contracts	92.3			(63.7		)	(30.8		)	(107.3		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	87.4		$	(102.1	)	$	(57.6	)	$	(234.4	)
Derivatives associated with divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	—		$	(2.7	)	$	—		$	(2.7	)
Gas derivative contracts	—			—			1.8			—
NGL derivative contracts	—			(3.2		)	—			(3.2		)
Unrealized gains (losses) on commodity derivative contracts related to divestitures	$	—		$	(5.9	)	$	1.8		$	(5.9	)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	87.4		$	(108.0	)	$	(55.8	)	$	(240.3	)

_______________________

⁽¹⁾  During the nine months ended September 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.

⁽²⁾ 

During the three and nine months ended September 30, 2018, the unrealized gains (losses) on commodity derivative contracts related to the Uinta Basin Divestiture were comprised of derivatives included as a part of the Uinta Basin purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2018. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Uinta Basin Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

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Employee Benefits

9 Months Ended

Sep. 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 nine months ended September 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 participants do not earn additional defined benefits for future services.

The SERP is a nonqualified retirement plan that is unfunded and provides postretirement benefits to certain QEP employees. During the nine months ended September 30, 2019, the Company made contributions of $0.4 million to the SERP and expects to contribute an additional $0.1 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 nine months ended September 30, 2019, the Company made contributions of $0.2 million to the Medical Plan and does not expect to make additional contributions 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.

During the nine months ended September 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. Refer to Note 9 – Restructuring for more information.

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.1		$	0.2		$	0.2		$	0.6
Interest cost	1.2			1.2			3.6			3.4
Expected return on plan assets	(1.5		)	(1.4		)	(4.4		)	(4.3		)
Amortization of prior service costs(1)	—			0.2			0.2			0.6
Amortization of actuarial losses(1)	—			—			0.1			0.6
Curtailment (gain) loss(2)	—			0.3			0.4			0.3
Periodic expense	$	(0.2	)	$	0.5		$	0.1		$	1.2
Medical Plan benefits
Interest cost	$	—		$	—		$	0.1		$	0.1
Amortization of prior service costs(1)	—			(0.1		)	—			(0.2		)
Curtailment (gain) loss(2)	—			—			(0.8		)	—
Periodic expense	$	—		$	(0.1	)	$	(0.7	)	$	(0.1	)

____________________________

⁽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 nine months ended September 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 nine months ended September 30, 2019, the Company made contributions of $3.2 million to the 401(k) Plan and expects to contribute an additional $0.8 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 nine months ended September 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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Acquisitions & Divestitures Schedule of Assets and Liabilities Held for Sale (Tables)

9 Months Ended

Sep. 30, 2019

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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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues [Abstract]
Revenues	$ 307.5	$ 560.8	$ 884.3	$ 1,522.1
Operating Expenses [Abstract]
General and administrative	29.6	48.3	124.4	164.2
Production and property taxes	20.0	37.4	67.6	103.9
Depreciation, depletion and amortization	144.2	234.9	395.5	673.6
Exploration expenses	0.0	0.0	0.0	0.1
Impairment	0.0	0.0	5.0	404.4
Total Operating Expenses	253.3	431.1	778.2	1,692.4
Net gain (loss) from asset sales, inclusive of restructuring costs	(2.1)	27.1	2.5	26.7
OPERATING INCOME (LOSS)	52.1	156.8	108.6	(143.6)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	87.4	(108.0)	(55.8)	(240.3)
Interest and other income (expense)	0.9	(0.3)	4.6	(4.1)
Interest expense	(32.8)	(38.7)	(100.0)	(111.9)
INCOME (LOSS) BEFORE INCOME TAXES	107.6	9.8	(42.6)	(499.9)
Income tax (provision) benefit	(26.6)	(2.5)	55.7	117.6
Net income (loss)	$ 81.0	$ 7.3	$ 13.1	$ (382.3)
Earnings Per Share [Abstract]
Basic	$ 0.34	$ 0.03	$ 0.06	$ (1.60)
Diluted	$ 0.34	$ 0.03	$ 0.06	$ (1.60)
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Used in basic calculation	237.9	236.9	237.7	238.3
Used in diluted calculation	237.9	237.0	237.7	238.3
Oil and Gas, Exploration and Production [Member]
Revenues [Abstract]
Revenues	$ 305.6	$ 544.0	$ 875.8	$ 1,474.1
Product and Service, Other [Member]
Revenues [Abstract]
Revenues	1.8	3.8	7.1	11.8
Oil and Gas, Purchased [Member]
Revenues [Abstract]
Revenues	0.1	13.0	1.4	36.2
Operating Expenses [Abstract]
Operating Costs and Expenses	0.1	13.3	1.5	38.6
Lease Operating Expense [Member]
Operating Expenses [Abstract]
Operating Costs and Expenses	38.3	64.6	135.5	203.6
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Operating Expenses [Abstract]
Operating Costs and Expenses	18.0	28.0	38.8	93.2
Gathering and other expense [Member]
Operating Expenses [Abstract]
Operating Costs and Expenses	$ 3.1	$ 4.6	$ 9.9	$ 10.8

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares shares in Millions	Sep. 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)	242.1	239.8
Treasury stock (in shares)	4.3	3.1

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Share-Based Compensation Schedule of Restricted Share Awards Transactions (Details) - Restricted Share Awards [Member] - $ / shares	9 Months Ended
	Sep. 30, 2019	Sep. 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	2,330,254
Shares vested	(2,780,285)
Shares forfeited	(239,489)
Unvested balance at end of period	3,132,613
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	7.79	$ 9.56
Weighted average grant date fair value, vested	10.66
Weighted average grant date fair value, forfeited	9.15
Weighted average grant date fair value, end of period	$ 8.76

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Employee Benefits Schedule of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Pension Plan and SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost		$ 0.1	$ 0.2	$ 0.2	$ 0.6
Interest cost		1.2	1.2	3.6	3.4
Expected return on plan assets		(1.5)	(1.4)	(4.4)	(4.3)
Amortization of prior service costs(1)	[1]	0.0	0.2	0.2	0.6
Amortization of actuarial losses(1)	[1]	0.0	0.0	0.1	0.6
Curtailment (gain) loss(2)	[2]	0.0	0.3	0.4	0.3
Periodic expense		(0.2)	0.5	0.1	1.2
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Interest cost		0.0	0.0	0.1	0.1
Amortization of prior service costs(1)	[1]	0.0	(0.1)	0.0	(0.2)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Curtailment	[2]	0.0	0.0	(0.8)	0.0
Periodic expense		$ 0.0	$ (0.1)	$ (0.7)	$ (0.1)

[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 nine months ended September 30, 2019.

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Asset Retirement Obligations Consolidated Balance Sheet Line Items of ARO Liability (Details) - USD ($) $ in Millions	Sep. 30, 2019	Jan. 01, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, current liability	$ 6.7		$ 5.1
Asset retirement obligations	95.5		96.9
Other long-term liabilities held for sale	0.0		57.6
Total ARO Liability	$ 102.2	$ 159.6	$ 159.6

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Acquisitions & Divestitures Haynesville Divestiture (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Business Acquisition [Line Items]
Noncurrent assets held for sale	$ 0.0		$ 0.0		$ 692.7
Payments to acquire oil and gas property			3.6	$ 48.3
Proceeds from Sale of Oil and Gas Property and Equipment			676.5	217.5
Gain (Loss) on Disposition of Oil and Gas Property	(2.1)	$ 27.1	2.5	26.7
Haynesville Divestiture [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			633.9
Gain (Loss) on Disposition of Oil and Gas Property	(0.3)		(1.0)
Results of Operations, (Income) Loss before Income Taxes	$ (0.2)	18.0	3.1	37.7
Restructuring Charges			(1.4)
Haynesville Divestiture [Member] | Total incurred to date [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Oil and Gas Property			(4.0)
Uinta Basin [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				153.0
Gain (Loss) on Disposition of Oil and Gas Property				(12.4)
Results of Operations, (Income) Loss before Income Taxes		$ (4.4)	$ (0.2)	$ (419.3)
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

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Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 92.4	$ 0.0	$ 0.0
Checks outstanding in excess of cash balances	0.7	14.6
Debt, Long-term and Short-term, Combined Amount	2,081.1	2,507.1
Long-term debt	2,029.4	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	92.4	0.0
Checks outstanding in excess of cash balances	0.7	14.6
Long-term debt, fair value	$ 1,959.1	$ 2,350.5

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Leases (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019 USD ($)	Sep. 30, 2019 USD ($)
Lessor, Lease, Description [Line Items]
Lease, Cost	$ 8.7	$ 30.6
Operating Lease, Weighted Average Remaining Lease Term	3 years 4 months 24 days	3 years 4 months 24 days
Operating Lease, Weighted Average Discount Rate, Percent	7.70%	7.70%
Property, Plant and Equipment [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	$ 2.5	$ 11.3
Lease Operating Expense [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	2.9	9.0
Gathering and other expense [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	2.0	5.8
General and Administrative Expense [Member]
Lessor, Lease, Description [Line Items]
Lease, Cost	$ 1.3	$ 4.5

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Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Less unamortized discount	$ (18.2)	$ (22.2)
Debt, Long-term and Short-term, Combined Amount	2,081.1	2,507.1
Long-term debt	2,029.4	2,507.1
Total long-term debt outstanding	2,029.4	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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Acquisitions & Divestitures

9 Months Ended

Sep. 30, 2019

Business Combinations [Abstract]

Acquisitions & Divestitures [Text Block]

Acquisitions

During the nine months ended September 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 $3.6 million, subject to post-closing purchase price adjustments.

During the nine months ended September 30, 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin for an aggregate purchase price of $48.3 million. Of the $48.3 million, $37.6 million was related to acquisitions from various entities that owned additional oil and gas interests in certain properties included in the 2017 acquisition of oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) on substantially the same terms and conditions as the 2017 Permian Basin Acquisition.

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. QEP received net cash proceeds of $633.9 million during the nine months ended September 30, 2019. The total pre-tax loss on sale was $4.0 million, of which $1.0 million was recognized during the nine months ended September 30, 2019, within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. Included in the $1.0 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, and therefore 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 nine months ended September 30, 2019, QEP accounted for revenues and expenses related to Haynesville/Cotton Valley, including the pre-tax loss on sale of $1.0 million, as income from continuing operations on the 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 September 30, 2019, QEP recorded a net loss before income taxes related to the divested Haynesville/Cotton Valley properties of $0.2 million, which includes a pre-tax loss on sale of $0.3 million. During the nine months ended September 30, 2019, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $3.1 million, which includes the pre-tax loss on sale of $1.0 million. For the three and nine months ended September 30, 2018, QEP recorded net income before income taxes related to the divested Haynesville/Cotton Valley properties of $18.0 million and $37.7 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 September 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 nine months ended September 30, 2019, QEP recorded a pre-tax loss on sale of $0.2 million due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs". For the three and nine months ended September 30, 2018, QEP recorded a net loss before income taxes related to the divested Uinta Basin assets of $4.4 million and $419.3 million, respectively, which both include a pre-tax loss on sale of $12.4 million. 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.

Other Divestitures

During the nine months ended September 30, 2019, QEP received net cash proceeds of $42.7 million and recorded a net pre-tax gain on sale of $3.7 million, primarily related to the divestiture of properties outside its main operating areas and the sale of corporate equipment.

During the nine months ended September 30, 2018, QEP received net cash proceeds of $64.5 million and recorded a pre-tax gain on sale of $39.1 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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Derivative Contracts

9 Months Ended

Sep. 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, basis 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. QEP has also entered into oil price derivative swaps that use Intercontinental Exchange, Inc. (ICE) Brent or regional price indices as the reference price. 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 September 30, 2019:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2019	NYMEX WTI	3.6	$	55.44
2019	ICE Brent	0.5	$	66.73
2019	Argus WTI Midland	0.2	$	54.60
2019	Argus WTI Houston	0.1	$	65.70
2020	NYMEX WTI	11.3	$	58.29
2020	Argus WTI Midland	1.5	$	57.30
2020 (January - June)	Argus WTI Houston	1.0	$	60.06

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

Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2019	NYMEX WTI	Argus WTI Midland	1.7	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.5	$	3.69
2020	NYMEX WTI	Argus WTI Midland	6.2	$	0.13
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	September 30, 2019		December 31, 2018		September 30, 2019		December 31, 2018
Current:		(in millions)
Commodity(1)	Fair value of derivative contracts	$	69.8	$	88.2	$	0.8	$	0.4
Long-term:
Commodity	Fair value of derivative contracts	23.2		35.4		0.4		0.7
Total derivative instruments		$	93.0	$	123.6	$	1.2	$	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						Nine Months Ended
Derivative contracts	September 30,						September 30,
	2019			2018(2)			2019(1)			2018(2)
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(4.9	)	$	(41.7	)	$	(23.9	)	$	(138.0	)
Gas derivative contracts	—			3.3			(2.9		)	10.6
Gas Storage
Gas derivative contracts	—			—			—			0.3
Realized gains (losses) on commodity derivative contracts	(4.9		)	(38.4		)	(26.8		)	(127.1		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	92.3			(60.6		)	(30.5		)	(88.1		)
Gas derivative contracts	—			(3.1		)	(0.3		)	(18.9		)
Gas Storage
Gas derivative contracts	—			—			—			(0.3		)
Unrealized gains (losses) on commodity derivative contracts	92.3			(63.7		)	(30.8		)	(107.3		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	87.4		$	(102.1	)	$	(57.6	)	$	(234.4	)
Derivatives associated with divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	—		$	(2.7	)	$	—		$	(2.7	)
Gas derivative contracts	—			—			1.8			—
NGL derivative contracts	—			(3.2		)	—			(3.2		)
Unrealized gains (losses) on commodity derivative contracts related to divestitures	$	—		$	(5.9	)	$	1.8		$	(5.9	)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	87.4		$	(108.0	)	$	(55.8	)	$	(240.3	)

_______________________

⁽¹⁾  During the nine months ended September 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.

⁽²⁾ 

During the three and nine months ended September 30, 2018, the unrealized gains (losses) on commodity derivative contracts related to the Uinta Basin Divestiture were comprised of derivatives included as a part of the Uinta Basin purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2018. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Uinta Basin Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

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Commitment and Contingencies

9 Months Ended

Sep. 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.  

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

In many cases, the Company is unable to make an estimate of the range of reasonably possible loss related to its contingencies. To the extent that the Company can reasonably estimate losses for contingencies where the risk of material loss (in excess of

accruals, if any) is reasonably possible, the Company estimates such losses to be in a range of zero to approximately $10.0 million, in the aggregate.

Commitments

QEP has 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 September 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	$	6.2
2020	$	21.7
2021	$	19.9
2022	$	15.4
2023	$	9.8
After 2023	$	0.7
Less: Interest(1)	$	(10.0	)
Present value of lease liabilities(2)	$	63.7

 ____________________________

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

⁽²⁾  Of the total present value of lease liabilities, $18.4 million was recorded in "Current operating lease liabilities" and $45.3 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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Basis of Presentation ImpaIrment of Long Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 0.0	$ 0.0	$ 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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Debt (Tables)

9 Months Ended

Sep. 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:

	September 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	(18.2		)	(22.2		)
Total principal amount of debt (including current portion)	2,081.1			2,507.1
Less: current portion of long-term debt	(51.7		)	—
Total long-term debt outstanding	$	2,029.4		$	2,507.1

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018		Sep. 30, 2019		Sep. 30, 2018
Pension and other postretirement plans adjustments:
Amortization of prior service cost, income tax expense	$ 0.0	$ 0.0	[1]	$ 0.0		$ 0.1	[1]
Amortization of net actuarial loss, income tax expense	0.0	(0.1)		0.0		0.1	[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 for the nine months ended September 30, 2018.

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

[3] Presented net of income tax benefit of $0.1 million for the nine months ended September 30, 2019

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
OPERATING ACTIVITIES
Net income (loss)	$ 13.1	$ (382.3)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	395.5	673.6
Deferred income taxes (benefit)	(61.2)	(119.6)
Impairment	5.0	404.4
Non-cash share-based compensation	16.2	24.0
Amortization of debt issuance costs and discounts	4.0	4.0
Net (gain) loss from asset sales, inclusive of restructuring costs	(2.5)	(26.7)
Unrealized (gains) losses on marketable securities	(2.8)	(1.1)
Unrealized (gains) losses on derivative contracts	29.0	113.2
Changes in operating assets and liabilities	(54.3)	(14.6)
Net Cash Provided by (Used in) Operating Activities	342.0	674.9
INVESTING ACTIVITIES
Property acquisitions	(3.6)	(48.3)
Property, plant and equipment, including exploratory well expense	(465.2)	(1,032.1)
Proceeds from disposition of assets	676.5	217.5
Net Cash Provided by (Used in) Investing Activities	207.7	(862.9)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(13.9)	(28.7)
Long-term debt issuance costs paid	0.0	(0.1)
Proceeds from credit facility	56.0	2,616.0
Repayments of credit facility	(486.0)	(2,329.5)
Common stock repurchased and retired	0.0	(58.4)
Treasury stock repurchases	(7.0)	(7.8)
Dividends paid	(4.8)	0.0
Other capital contributions	0.0	0.3
Net Cash Provided by (Used in) Financing Activities	(455.7)	191.8
Change in cash, cash equivalents and restricted cash(1)	94.0	3.8
Beginning cash, cash equivalents and restricted cash(1)	28.1	23.4
Ending cash, cash equivalents and restricted cash(1)	122.1	27.2
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	94.1	100.2
Cash paid for income taxes, net	5.0	0.3
Cash Paid for Amounts Included in the Measurement of Lease Liabilities	14.5	0.0
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	11.1	0.0
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$ 0.8	$ (43.9)

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Basis of Presentation Restricted Cash (Tables)

9 Months Ended

Sep. 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:

	September 30,
	2019		2018
	(in millions)
Cash and cash equivalents	$	92.4	$	—
Restricted cash(1)	29.7		27.2
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	122.1	$	27.2

_______________________

⁽¹⁾ As of September 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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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2019

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

	Asset Retirement Obligations
	September 30,		December 31,
	2019		2018
Balance Sheet line item	(in millions)
Current:
Asset retirement obligations, current liability	$	6.7	$	5.1
Long-term:
Asset retirement obligations	95.5		96.9
Other long-term liabilities held for sale	—		57.6
Total ARO Liability	$	102.2	$	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	4.1
Additions	0.8
Revisions	(0.3		)
Liabilities related to assets sold(1)	(60.7		)
Liabilities settled	(1.3		)
ARO liability at September 30, 2019	$	102.2

_______________________

⁽¹⁾ 

Liabilities related to assets sold during the nine months ended September 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 nine months ended September 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 Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment	$ 0.0	$ 0.0	$ 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				$ 397.6

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Acquisitions & Divestitures Other Divestitures (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Divestitures [Line Items]
Proceeds from disposition of assets			$ 676.5	$ 217.5
Net gain (loss) from asset sales, inclusive of restructuring costs	$ (2.1)	$ 27.1	2.5	26.7
Non-core properties Divestitures [Member]
Divestitures [Line Items]
Proceeds from disposition of assets			42.7	64.5
Net gain (loss) from asset sales, inclusive of restructuring costs			$ 3.7	$ 39.1

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Share-Based Compensation Share-based compensation expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	$ 4.1	$ 2.7	$ 21.0	$ 26.1
Stock Options [Member]
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	0.0	0.2	0.3	0.9
Performance Share Units [Member]
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	(0.9)	(2.9)	4.6	4.1
Restricted Shares [Member]
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	5.0	5.3	15.9	20.9
Restricted Share Units (RSUs) [Member]
Share-based Compensation Expense [Line Items]
Allocated Share-based Compensation Expense	0.0	0.1	0.2	0.2
Net gain (loss) from asset sales [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	0.0	2.2	1.5	2.2
General and Administrative Expense [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	1.6	1.0	9.8	5.0
Total [Member]
Share-based Compensation Expense [Line Items]
Accelerated Share Based Compensation	$ 1.6	$ 3.2	$ 11.3	$ 7.2

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Share-Based Compensation Schedule of Restricted Share Unit Transactions (Details) - Restricted Share Units (RSUs) [Member] - $ / shares	9 Months Ended
	Sep. 30, 2019	Sep. 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	37,498
Shares vested and paid	(47,807)
Unvested balance at end of period	32,366
Weighted average grant date fair value, beginning of period	$ 10.47
Weighted average grant date fair value, grants	7.90	$ 9.55
Weighted average grant date fair value, vested	10.04
Weighted average grant date fair value, end of period	$ 8.13

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Basis of Presentation

9 Months Ended

Sep. 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 nine months ended September 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 nine months ended September 30, 2019, QEP recorded impairment charges of $5.0 million related to an office building lease.

During the nine months ended September 30, 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment 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 primarily consist of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day. Restricted cash are funds that are legally or contractually reserved for a specific purpose and therefore not available for immediate or general business use.

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

	September 30,
	2019		2018
	(in millions)
Cash and cash equivalents	$	92.4	$	—
Restricted cash(1)	29.7		27.2
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	122.1	$	27.2

_______________________

⁽¹⁾ As of September 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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Document and Entity Information	9 Months Ended
	Sep. 30, 2019 shares
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 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	Q3
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	237,791,780

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 92.4	$ 0.0
Accounts receivable, net	104.3	104.3
Income tax receivable	75.5	75.9
Fair value of derivative contracts	69.8	87.5
Prepaid expenses	8.1	12.9
Total Current Assets	350.1	280.6
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	9,416.9	9,096.9
Unproved properties	698.3	705.5
Gathering and other	162.7	167.7
Materials and supplies	19.3	29.9
Total Property, Plant and Equipment	10,297.2	10,000.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	5,153.3	4,882.4
Gathering and other	58.5	58.1
Total Accumulated Depreciation, Depletion and Amortization	5,211.8	4,940.5
Net Property, Plant and Equipment	5,085.4	5,059.5
Fair value of derivative contracts	23.2	35.4
Operating lease right-of-use assets, net	57.4	0.0
Other noncurrent assets	54.5	49.6
Noncurrent assets held for sale	0.0	692.7
TOTAL ASSETS	5,570.6	6,117.8
Current Liabilities
Checks outstanding in excess of cash balances	0.7	14.6
Accounts payable and accrued expenses	206.2	258.1
Production and property taxes	17.7	24.1
Current portion of long term debt	51.7	0.0
Interest payable	33.0	32.4
Fair value of derivative contracts	0.8	0.0
Current operating lease lease liabilities	18.4	0.0
Asset retirement obligations	6.7	5.1
Total Current Liabilities	335.2	334.3
Long-term debt	2,029.4	2,507.1
Deferred income taxes	208.0	269.2
Asset retirement obligations	95.5	96.9
Fair value of derivative contracts	0.4	0.7
Operating lease liabilities	45.3	0.0
Other long-term liabilities	86.8	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; 242.1 million and 239.8 million shares issued, respectively	2.4	2.4
Treasury stock – 4.3 million and 3.1 million shares, respectively	(54.8)	(45.6)
Additional paid-in capital	1,451.9	1,431.9
Retained earnings	1,384.8	1,376.5
Accumulated other comprehensive income (loss)	(14.3)	(14.3)
Total Common Shareholders' Equity	2,770.0	2,750.9
TOTAL LIABILITIES AND EQUITY	$ 5,570.6	$ 6,117.8

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Subsequent Event (Notes)

9 Months Ended

Sep. 30, 2019

Subsequent Events [Abstract]

Subsequent Events [Text Block]

On October 23, 2019, the Company issued a notice to holders of its outstanding 6.80% Senior Notes due March 1, 2020, of the Company’s intent to redeem all of the outstanding notes on November 22, 2019. The Company expects that the redemption will decrease the "Current portion of long term debt" on the Condensed Consolidated Balance Sheets by $51.7 million and expects to incur a loss on early extinguishment of debt of approximately $0.7 million in connection with the redemption of the Senior Notes.

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Earnings Per Share (Tables)

9 Months Ended

Sep. 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		Nine Months Ended
	September 30,		September 30,
	2019	2018	2019	2018
	(in millions)
Weighted-average basic common shares outstanding	237.9	236.9	237.7	238.3
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	0.1	—	—
Average diluted common shares outstanding	237.9	237.0	237.7	238.3

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Fair Value Measurements Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018
Financial Assets
Derivative Asset, Netting Adjustments	[1]	$ 0.0	$ (0.4)
Derivative Asset, Net		93.0	123.2
Financial liabilities
Derivative Liability, Netting Adjustments	[1]	0.0	(0.4)
Derivative Liability, Net		1.2	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		93.0	123.6
Financial liabilities
Derivative Liability, Fair Value, Gross		1.2	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		23.2	35.4
Financial liabilities
Derivative Liability, Netting Adjustments	[1]	0.0	0.0
Derivative Liability, Net		0.4	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		23.2	35.4
Financial liabilities
Derivative Liability, Fair Value, Gross		0.4	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		69.8	87.8
Financial liabilities
Derivative Liability, Netting Adjustments	[1]	0.0	(0.4)
Derivative Liability, Net		0.8	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		69.8	88.2
Financial liabilities
Derivative Liability, Fair Value, Gross		0.8	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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Earnings Per Share Components of Basic and Diluted Shares Used In EPS Calculation (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	0.0	0.0	0.0	0.0
Weighted-average basic common shares outstanding	237.9	236.9	237.7	238.3
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	0.0	0.1	0.0	0.0
Average diluted common shares outstanding	237.9	237.0	237.7	238.3

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Subsequent Event (Details) - Senior Notes Due 2020 [Member] - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term debt, interest rate (in hundredths)	6.80%	6.80%
Debt Instrument, Maturity Date		Mar. 01, 2020
Carrying amount of long term debt	$ 51.7	$ 51.7	$ 51.7
Gain (Loss) on Early Extinguishment of Debt	$ 0.7

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Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 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		10.0
Shares available for future grants	8.3		8.3
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$ 0.1		$ 0.1
Weighted average vesting period			6 months 14 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			$ 7.79	$ 9.56
Unrecognized compensation costs	13.8		$ 13.8
Weighted average vesting period			2 years 1 month 24 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			$ 29.6	$ 30.7
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			$ 12.1	$ 2.0
Weighted average grant date fair value, grants			$ 7.93	$ 9.55
Unrecognized compensation costs	2.6		$ 2.6
Weighted average vesting period			2 years 1 month 28 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			$ 7.90	$ 9.55
Unrecognized compensation costs	0.1		$ 0.1
Weighted average vesting period			1 year 2 months 19 days
Total [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accelerated Share Based Compensation	1.6	$ 3.2	$ 11.3	$ 7.2
Net gain (loss) from asset sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accelerated Share Based Compensation	0.0	2.2	1.5	2.2
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accelerated Share Based Compensation	$ 1.6	$ 1.0	$ 9.8	$ 5.0

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Share-Based Compensation Schedule Of Performance Share Unit Transactions (Details) - Performance Share Units [Member] - USD ($) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 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	$ 12.1	$ 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	614,633
Shares vested	(1,206,165)
Unvested balance at end of period	967,780
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	10.68
Weighted average grant date fair value, end of period	$ 9.50

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Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	$ (4.9)	$ (38.4)	$ (26.8)	$ (127.1)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	92.3	(63.7)	(30.8)	(107.3)
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	87.4	(108.0)	(55.8)	(240.3)
Storage [Member] | Gas derivative contracts [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.0	0.0	0.3
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.0	0.0	(0.3)
Production [Member] | Oil derivative contracts [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	(4.9)	(41.7)	(23.9)	(138.0)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	92.3	(60.6)	(30.5)	(88.1)
Production [Member] | Gas derivative contracts [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	3.3	(2.9)	10.6
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	(3.1)	(0.3)	(18.9)
Total [Member]
Derivative [Line Items]
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	87.4	(102.1)	(57.6)	(234.4)
Uinta Basin [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	(5.9)	1.8	(5.9)
Uinta Basin [Member] | Production [Member] | Oil derivative contracts [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	(2.7)	0.0	(2.7)
Uinta Basin [Member] | Production [Member] | Gas derivative contracts [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	0.0	1.8	0.0
Uinta Basin [Member] | Production [Member] | NGL derivative contracts [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	$ 0.0	$ (3.2)	$ 0.0	$ (3.2)

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Debt (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 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

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Debt [Text Block]

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

	September 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	(18.2		)	(22.2		)
Total principal amount of debt (including current portion)	2,081.1			2,507.1
Less: current portion of long-term debt	(51.7		)	—
Total long-term debt outstanding	$	2,029.4		$	2,507.1

Of the total debt outstanding on September 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 unsecured 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 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 September 30, 2019 and December 31, 2018, QEP was in compliance with the covenants under the credit agreement.

During the nine months ended September 30, 2019, QEP's weighted-average interest rate on borrowings from its credit facility was 4.73%. As of September 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 September 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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Revenue (Notes)

9 Months Ended

Sep. 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, Revenue Recognition.

	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Three Months Ended September 30, 2019
Northern Region
Williston Basin	$	88.9	$	5.5	$	2.4	$	(7.0	)	$	89.8
Other Northern	—		0.1		0.1		—			0.2
Southern Region
Permian Basin	209.9		3.4		9.4		(7.2		)	215.5
Other Southern	—		0.1		—		—			0.1
Total oil and condensate, gas and NGL sales	$	298.8	$	9.1	$	11.9	$	(14.2	)	$	305.6
	Three Months Ended September 30, 2018
Northern Region
Williston Basin	$	203.4	$	12.0	$	19.2	$	(12.3	)	$	222.3
Uinta Basin	7.3		6.8		1.4		—			15.5
Other Northern	1.1		0.5		0.1		—			1.7
Southern Region
Permian Basin	204.0		5.4		21.3		(3.5		)	227.2
Haynesville/Cotton Valley	0.2		76.9		—		—			77.1
Other Southern	0.1		0.1		—		—			0.2
Total oil and condensate, gas and NGL sales	$	416.1	$	101.7	$	42.0	$	(15.8	)	$	544.0

	Oil and condensate sales			Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Nine Months Ended September 30, 2019
Northern Region
Williston Basin	$	306.3		$	25.5	$	15.6	$	(26.0	)	$	321.4
Other Northern	0.9			0.4		0.1		—			1.4
Southern Region
Permian Basin	526.7			7.4		27.4		(14.7		)	546.8
Other Southern	0.1			6.1		—		—			6.2
Total oil and condensate, gas and NGL sales	$	834.0		$	39.4	$	43.1	$	(40.7	)	$	875.8
	Nine Months Ended September 30, 2018
Northern Region
Williston Basin	$	571.5		$	30.2	$	45.7	$	(32.9	)	$	614.5
Uinta Basin	25.2			24.8		4.8		—			54.8
Other Northern	3.9			1.7		—		—			5.6
Southern Region
Permian Basin	524.1			13.2		37.7		(8.0		)	567.0
Haynesville/Cotton Valley	0.8			231.2		—		—			232.0
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,125.3		$	301.5	$	88.2	$	(40.9	)	$	1,474.1

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Fair Value Measurements

9 Months Ended

Sep. 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 September 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	September 30, 2019
Fair value of derivative contracts – short-term	$	—	$	69.8	$	—	$	—		$	69.8
Fair value of derivative contracts – long-term	—		23.2		—		—			23.2
Total financial assets	$	—	$	93.0	$	—	$	—		$	93.0
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	0.8	$	—	$	—		$	0.8
Fair value of derivative contracts – long-term	—		0.4		—		—			0.4
Total financial liabilities	$	—	$	1.2	$	—	$	—		$	1.2
	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
	September 30, 2019				December 31, 2018
Financial Assets	(in millions)
Cash and cash equivalents	$	92.4	$	92.4	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	0.7	$	0.7	$	14.6	$	14.6
Total debt outstanding	$	2,081.1	$	1,959.1	$	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 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 nine months ended September 30, 2019, the Company recorded impairment charges of $5.0 million related to an office building lease. During the nine months ended September 30, 2018, the Company recorded impairments on certain proved oil and gas properties, primarily in the Uinta Basin, of $397.6 million, resulting in a reduction of the associated carrying amount to fair value.

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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Basis of Presentation Restricted Cash (Details) - USD ($) $ in Millions		Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents		$ 92.4	$ 0.0	$ 0.0
Restricted cash(1)	[1]	29.7		27.2
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows		$ 122.1	$ 28.1	$ 27.2	$ 23.4

[1] As of September 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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Commitments and Contingencies Minimum Lease Payments (Tables)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

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

As of September 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	$	6.2
2020	$	21.7
2021	$	19.9
2022	$	15.4
2023	$	9.8
After 2023	$	0.7
Less: Interest(1)	$	(10.0	)
Present value of lease liabilities(2)	$	63.7

 ____________________________

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

⁽²⁾ 

Of the total present value of lease liabilities, $18.4 million was recorded in "Current operating lease liabilities" and $45.3 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	$	—