10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2018

o 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)

STATE OF 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

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 ý No o

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 ý No o

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	ý	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	o
		Emerging growth company	o

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. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

At September 30, 2018, there were 236,770,924 shares of the registrant's common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended September 30, 2018

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, 2018 AND 2017	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2018 AND 2017	3
		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT SEPTEMBER 30, 2018 AND DECEMBER 31, 2017	4
		UNAUDITED CONDENSED CONOSLIDATED STATEMENT OF EQUITY FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018	5
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018 AND 2017	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	52
	ITEM 4.	CONTROLS AND PROCEDURES	57
PART II. OTHER INFORMATION			57
	ITEM 1.	LEGAL PROCEEDINGS	57
	ITEM 1A.	RISK FACTORS	57
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	62
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	62
	ITEM 4.	MINE SAFETY DISCLOSURES	62
	ITEM 5.	OTHER INFORMATION	62
	ITEM 6.	EXHIBITS	63
SIGNATURES			64

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

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

2

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018		2017			2018			2017
	(in millions)
Net income (loss)	$	7.3	$	(3.3	)	$	(382.3	)	$	119.0
Other comprehensive income, net of tax:
Postretirement medical plan change(1)	—		—			—			1.6
Fair value of plan assets adjustment(2)	—		—			0.3			—
Pension and other postretirement plans adjustments:
Amortization of prior service costs(3)	0.2		0.1			0.4			0.4
Amortization of actuarial losses(4)	0.1		0.1			0.5			0.2
Other comprehensive income	0.3		0.2			1.2			2.2
Comprehensive income (loss)	$	7.6	$	(3.1	)	$	(381.1	)	$	121.2

____________________________

⁽¹⁾  Presented net of income tax expense of $1.0 million during the nine months endedSeptember 30, 2017.

⁽²⁾  Adjustment recorded during the nine months endedSeptember 30, 2018, related to a change in the fair value of plan assets as of December 31, 2017.

⁽³⁾  Presented net of income tax expense of $0.1 million during the nine months endedSeptember 30, 2018. Presented net of income tax expense of $0.1 million and $0.3 million during the three and nine months endedSeptember 30, 2017, respectively.

⁽⁴⁾  Presented net of income tax benefit of $0.1 million and expense of $0.1 million during the three and nine months endedSeptember 30, 2018, respectively. Presented net of income tax expense of $0.1 million during the nine months endedSeptember 30, 2017.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

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

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

4

QEP RESOURCES, INC.

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

____________________________

⁽¹⁾  Refer to New Accounting Pronouncements 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. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Southern Region (primarily in Texas and Louisiana) and the Northern Region (primarily in North Dakota). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

Basis of Presentation of Interim Condensed Consolidated Financial Statements

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

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

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

Reclassifications

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

Impairment of Long-Lived Assets

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

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

Cash, Cash Equivalents and Restricted Cash

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

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

_______________________

⁽¹⁾  As of September 30, 2018, the restricted cash balance consisted of $27.2 million related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin and is included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet. As of September 30, 2017, the restricted cash balance consisted of $59.2 million related to cash deposited into an escrow account related to the 2017 Permian Basin Acquisition (defined below) and cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin and is included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet provided within the Quarterly Report on Form 10-Q.

New Accounting Pronouncements

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

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

8

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

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

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

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

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

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

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

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

9

Note 2 – Revenue

Adoption of ASC Topic 606, Revenue from Contracts with Customers

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

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

10

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

	Three Months Ended								Nine Months Ended
	September 30, 2018								September 30, 2018
	As Reported			ASC Topic 606 Adjustments		As Adjusted(1)			As Reported			ASC Topic 606 Adjustments		As Adjusted(1)
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	544.0		$	15.8	$	559.8		$	1,474.1		$	40.9	$	1,515.0
Other revenue	3.8			—		3.8			11.8			—		11.8
Purchased oil and gas sales	13.0			—		13.0			36.2			—		36.2
Total Revenues	560.8			15.8		576.6			1,522.1			40.9		1,563.0
OPERATING EXPENSES
Purchased oil and gas expense	13.3			—		13.3			38.6			—		38.6
Lease operating expense	64.6			—		64.6			203.6			—		203.6
Transportation and processing costs	28.0			15.8		43.8			93.2			40.9		134.1
Gathering and other expense	4.6			—		4.6			10.8			—		10.8
General and administrative	48.3			—		48.3			164.2			—		164.2
Production and property taxes	37.4			—		37.4			103.9			—		103.9
Depreciation, depletion and amortization	234.9			—		234.9			673.6			—		673.6
Exploration expenses	—			—		—			0.1			—		0.1
Impairment	—			—		—			404.4			—		404.4
Total Operating Expenses	431.1			15.8		446.9			1,692.4			40.9		1,733.3
Net gain (loss) from asset sales, inclusive of restructuring costs	27.1			—		27.1			26.7			—		26.7
OPERATING INCOME (LOSS)	156.8			—		156.8			(143.6		)	—		(143.6		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(108.0		)	—		(108.0		)	(240.3		)	—		(240.3		)
Interest and other income (expense)	(0.3		)	—		(0.3		)	(4.1		)	—		(4.1		)
Interest expense	(38.7		)	—		(38.7		)	(111.9		)	—		(111.9		)
INCOME (LOSS) BEFORE INCOME TAXES	9.8			—		9.8			(499.9		)	—		(499.9		)
Income tax (provision) benefit	(2.5		)	—		(2.5		)	117.6			—		117.6
NET INCOME (LOSS)	$	7.3		$	—	$	7.3		$	(382.3	)	$	—	$	(382.3	)
Earnings (loss) per common share
Basic	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)
Diluted	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)
Weighted-average common shares outstanding
Used in basic calculation	236.9			—		236.9			238.3			—		238.3
Used in diluted calculation	237.0			—		237.0			238.3			—		238.3

_______________________

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

11

Revenue Recognition

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

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

12

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

	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Three Months Ended September 30, 2018
Northern Region
Williston Basin	$	203.4	$	12.0	$	19.2	$	(12.3	)	$	222.3
Uinta Basin	7.3		6.8		1.4		—			15.5
Other Northern	1.1		0.5		0.1		—			1.7
Southern Region
Permian Basin	204.0		5.4		21.3		(3.5		)	227.2
Haynesville/Cotton Valley	0.2		76.9		—		—			77.1
Other Southern	0.1		0.1		—		—			0.2
Total oil and condensate, gas and NGL sales	$	416.1	$	101.7	$	42.0	$	(15.8	)	$	544.0
	Three Months Ended September 30, 2017(1)
Northern Region
Williston Basin	$	125.7	$	9.5	$	13.0	$	—		$	148.2
Pinedale	5.2		43.0		10.1		—			58.3
Uinta Basin	7.5		12.2		1.6		—			21.3
Other Northern	1.2		4.2		0.1		—			5.5
Southern Region
Permian Basin	78.1		4.5		7.3		—			89.9
Haynesville/Cotton Valley	0.3		57.2		0.1		—			57.6
Other Southern	—		0.1		—		—			0.1
Total oil and condensate, gas and NGL sales	$	218.0	$	130.7	$	32.2	$	—		$	380.9

_______________________

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

13

	Oil and condensate sales			Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Nine Months Ended September 30, 2018
Northern Region
Williston Basin	$	571.5		$	30.2	$	45.7	$	(32.9	)	$	614.5
Uinta Basin	25.2			24.8		4.8		—			54.8
Other Northern	3.9			1.7		—		—			5.6
Southern Region
Permian Basin	524.1			13.2		37.7		(8.0		)	567.0
Haynesville/Cotton Valley	0.8			231.2		—		—			232.0
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,125.3		$	301.5	$	88.2	$	(40.9	)	$	1,474.1
	Nine Months Ended September 30, 2017(1)
Northern Region
Williston Basin	$	416.5		$	32.5	$	34.8	$	—		$	483.8
Pinedale	18.0			154.8		30.1		—			202.9
Uinta Basin	21.8			39.1		4.3		—			65.2
Other Northern	4.0			15.0		0.3		—			19.3
Southern Region
Permian Basin	194.3			11.3		14.2		—			219.8
Haynesville/Cotton Valley	0.9			146.4		0.3		—			147.6
Other Southern	0.2			0.3		—		—			0.5
Total oil and condensate, gas and NGL sales	$	655.7		$	399.4	$	84.0	$	—		$	1,139.1

_______________________

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

14

Note 3 – Acquisitions and Divestitures

Acquisitions

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

During the nine months endedSeptember 30, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired in 2017.

Divestitures

In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives (Strategic Initiatives) including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. As of September 30, 2018, the Company closed the sale of its Uinta Basin assets and continued to engage in discussions with potential buyers for its Williston Basin and Haynesville/Cotton Valley assets. Assets are considered held for sale once it is deemed unlikely that there will be any significant changes to QEP's divestiture plan, which QEP believes is generally upon the execution of purchase and sale agreements (refer to Note 13 – Subsequent Event for an update on the Williston Basin assets).

Uinta Basin Divestiture

In early September 2018, QEP sold its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of $153.0 million, subject to post-closing purchase price adjustments (the Uinta Basin Divestiture). Pursuant to signing a purchase and sale agreement for the Uinta Basin Divestiture, QEP recorded $402.8 million of proved and unproved properties impairment during the nine months endedSeptember 30, 2018 (refer to Note 1 – Basis of Presentation for more information). In addition, QEP recorded $5.5 million of estimated restructuring costs related to this divestiture during the nine months endedSeptember 30, 2018, included in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations (refer to Note 8 – Restructuring for more information).

QEP accounted for revenues and expenses related to the Uinta Basin, including the pre-tax loss on sale of $12.4 million, during the three and nine months endedSeptember 30, 2018, as income from continuing operations on the Condensed Consolidated Statements of Operations because the Uinta Basin Divestiture did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. For the three and nine months endedSeptember 30, 2018, QEP recorded net loss before income taxes related to the divested Uinta Basin properties of $4.4 million and $419.3 million, respectively, which both include the pre-tax loss on sale of $12.4 million. The net loss before income taxes for the nine months endedSeptember 30, 2018 was primarily due to an impairment charge on proved and unproved properties of $402.8 million recognized as a result of signing the purchase and sale agreement. For the three and nine months endedSeptember 30, 2017, QEP recorded a net loss before income taxes related to the divested Uinta properties of $4.3 million and $12.8 million, respectively.

Pinedale Divestiture

In September 2017, QEP sold its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds of $718.2 million. For the nine months endedSeptember 30, 2018, QEP recorded a pre-tax gain on sale of $1.2 million, due to additional post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. For the three and nine months endedSeptember 30, 2017, QEP had net income before income taxes related to the divested Pinedale properties of $208.2 million and $251.2 million, respectively.

15

As a part of the Pinedale Divestiture, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million.As of September 30, 2018, the remaining liability associated with estimated future payments for this commitment was $23.0 million, which is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses".

Other Divestitures

During the nine months endedSeptember 30, 2018, QEP received net cash proceeds of $64.5 million and recorded a net pre-tax gain on sale of $37.9 million related to the divestiture of properties outside our main operating areas.

In addition to the Pinedale Divestiture, during the nine months endedSeptember 30, 2017, QEP received net cash proceeds of $69.7 million, resulting in a net pre-tax gain on sale of $26.4 million, primarily related to the divestiture of certain non-core properties in the Other Northern area.

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

Note 4 – Earnings Per Share

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

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. During the three and nine months endedSeptember 30, 2018 and 2017, there were no anti-dilutive shares.

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

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

16

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. Of the $160.5 million and $214.1 million ARO liability for the periods ended September 30, 2018 and December 31, 2017, respectively, $5.0 million and $3.5 million, respectively, were included as a current liability within "Asset retirement obligations" on the Condensed Consolidated Balance Sheets.

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

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

_______________________

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

⁽²⁾  Liabilities related to assets sold during the nine months endedSeptember 30, 2018, includes $51.0 million related to the Uinta Basin 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) 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.

17

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

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	September 30, 2018
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	16.6	$	—	$	(2.6	)	$	14.0
Fair value of derivative contracts – long-term	—		1.2		—		(1.1		)	0.1
Total financial assets	$	—	$	17.8	$	—	$	(3.7	)	$	14.1
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	203.3	$	—	$	(2.6	)	$	200.7
Fair value of derivative contracts – long-term	—		53.7		—		(1.1		)	52.6
Total financial liabilities	$	—	$	257.0	$	—	$	(3.7	)	$	253.3
	December 31, 2017
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	20.6	$	—	$	(17.2	)	$	3.4
Fair value of derivative contracts – long-term	—		2.3		—		(2.2		)	0.1
Total financial assets	$	—	$	22.9	$	—	$	(19.4	)	$	3.5
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	120.8	$	—	$	(17.2	)	$	103.6
Fair value of derivative contracts – long-term	—		34.0		—		(2.2		)	31.8
Total financial liabilities	$	—	$	154.8	$	—	$	(19.4	)	$	135.4

_______________________

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

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

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

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

18

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

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

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a periodic basis, at least annually, to review its proved oil and gas properties for potential impairment when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. The fair value of property is measured utilizing the income approach and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. Given the unobservable nature of the inputs, fair value calculations associated with proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. During the nine months endedSeptember 30, 2018, the Company recorded impairments on certain proved oil and gas properties of $397.6 million, resulting in a reduction of the associated carrying amount to fair value. During the nine months endedSeptember 30, 2017, the Company recorded no impairments on proved oil and gas properties.

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

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, QEP has historically entered into commodity derivative contracts on a portion of its storage transactions. QEP does not enter into commodity derivative contracts for speculative purposes.

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

19

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

Derivative Contracts – Production

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

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

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

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

___________________________

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

20

QEP Derivative Financial Statement Presentation

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

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

21

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,
	2018(1)			2017(2)			2018(1)			2017(2)
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(41.7	)	$	12.1		$	(138.0	)	$	21.6
Gas derivative contracts	3.3			(0.4		)	10.6			(19.7		)
Gas Storage
Gas derivative contracts	—			—			0.3			(0.2		)
Realized gains (losses) on commodity derivative contracts	(38.4		)	11.7			(127.1		)	1.7
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(60.6		)	(86.1		)	(88.1		)	88.7
Gas derivative contracts	(3.1		)	—			(18.9		)	100.5
Gas Storage
Gas derivative contracts	—			—			(0.3		)	2.3
Unrealized gains (losses) on commodity derivative contracts	(63.7		)	(86.1		)	(107.3		)	191.5
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	(102.1	)	$	(74.4	)	$	(234.4	)	$	193.2
Derivatives associated with divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(2.7	)	$	(1.3	)	$	(2.7	)	$	(1.3	)
Gas derivative contracts	—			(23.5		)	—			(23.5		)
NGL derivative contracts	(3.2		)	(5.1		)	(3.2		)	(5.1		)
Unrealized gains (losses) on commodity derivative contracts related to divestitures	$	(5.9	)	$	(29.9	)	$	(5.9	)	$	(29.9	)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(108.0	)	$	(104.3	)	$	(240.3	)	$	163.3

_______________________

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

⁽²⁾  The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

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Note 8 – Restructuring

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

Restructuring costs recognized associated with the restructuring are summarized below:

	Total recognized		Recognized in "General and administrative"		Recognized in "Net gain (loss) from asset sales, inclusive of restructuring costs"		Recognized in "Interest and other income (expense)"
	(in millions)
	Three Months Ended September 30, 2018
Termination benefits	$	6.7	$	5.3	$	1.4	$	—
Office lease termination costs	0.7		0.7		—		—
Accelerated share-based compensation	3.2		1.0		2.2		—
Retention expense	5.8		5.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	16.7	$	12.8	$	3.6	$	0.3
	Nine Months Ended September 30, 2018
Termination benefits	$	13.7	$	10.4	$	3.3	$	—
Office lease termination costs	1.0		1.0		—		—
Accelerated share-based compensation	7.2		5.0		2.2		—
Retention expense	13.8		13.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	36.0	$	30.2	$	5.5	$	0.3

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

____________________________

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

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

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

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

Note 9 – Debt

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

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

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

Credit Facility

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

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

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Senior Notes

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

Note 10 – 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, the ongoing discovery and/or development of information important to the matter.

Landowner Litigation – In October, 2017, the owners of certain surface and mineral interests in Martin and Andrews County, Texas filed suit against QEP, alleging QEP improperly used the surface of the properties and failed to correctly pay royalties, and are seeking money damages and a declaratory judgment that portions of the oil and gas leases covering the properties are no longer in effect. The Company continues to evaluate the allegations and its defenses. The Company is unable to make an estimate of the reasonably possible loss at this early stage.

Note 11 – Share-Based Compensation

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

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

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

Stock Options

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

In 2018, to better align our long-term incentive awards with those typical of the industry, QEP did not issue stock options.

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

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

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of stock options exercised was $0.1 million during the nine months endedSeptember 30, 2018. During the nine months endedSeptember 30, 2017, there were no exercises of stock options. As of September 30, 2018, $0.6 million of unrecognized compensation expense related to stock options granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.40 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program (refer to Note 8 – Restructuring for additional information).

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Restricted Share Awards

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

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

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

Performance Share Units

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

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

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

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

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

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

Note 12 – 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 endedSeptember 30, 2018, the Company made contributions of $4.0 million to the Pension Plan and expects to contribute an additional $1.0 million to the Pension Plan during the remainder of 2018. Contributions to the Pension Plan increase plan assets. The Pension Plan was amended in June 2015 and was frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services.

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

The Medical Plan is a self-insured plan. It is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired QEP employees. During the nine months endedSeptember 30, 2018, the Company made contributions of $0.2 million to its Medical Plan and does not expect to make additional contributions to its Medical Plan during the remainder of 2018. Contributions to the Medical Plan are used to fund current benefit payments.

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

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

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

____________________________

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

⁽²⁾  A curtailment is recognized when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses relate to the Uinta Basin Divestiture for the three and nine months endedSeptember 30, 2018 and the Pinedale Divestiture for the three and nine months endedSeptember 30, 2017. The Uinta Basin Divestiture curtailment is recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)" for the three and nine months endedSeptember 30, 2018. The Pinedale Divestiture curtailment is recognized on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of severance costs" for the three and nine months endedSeptember 30, 2017.

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. During the nine months endedSeptember 30, 2018, the Company made contributions of $4.9 million to the 401(k) Plan and expects to contribute an additional $1.1 million to the 401(k) Plan during the remainder of 2018. Due to the Company's Strategic Initiatives, the amount expected to be contributed to the 401(k) Plan is subject to change (refer to Note 8 – 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 in the form of Company Transition Credits to eligible participants. Eligible participants are certain highly and non-highly compensated employees who were active participants in the Pension Plan on December 31, 2015. During the nine months endedSeptember 30, 2018, the Company has not yet made a discretionary contribution to active participants of the Pension Plan but expects to contribute $0.3 million to eligible participants in the fourth quarter of 2018.

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Note 13 – Subsequent Event

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

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, 2017 (2017 Form 10-K) and analyzes the changes in the results of operations between the three and nine months endedSeptember 30, 2018 and 2017. 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 2017 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 Louisiana) and the Northern Region (primarily in North Dakota). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives (Strategic Initiatives), including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. The Company executed a purchase and sale agreement to sell its Uinta Basin assets in early July 2018 and closed on the sale of the Uinta Basin assets in September 2018. Refer to discussion of the Uinta Basin Divestiture below under Acquisitions and Divestitures. Additionally, the Company is engaged in discussions with potential buyers regarding a transaction involving its Haynesville/Cotton Valley assets. On November 6, 2018, the Company's wholly owned subsidiary, QEP Energy Company, entered into a definitive agreement to sell its assets in the Williston Basin for a purchase price of up to $1,725.0 million, subject to purchase price adjustments which may be material (the Williston Basin Divestiture). The purchase price is comprised of $1,650.0 million in cash and contractual rights to receive up to $50.0 million and $25.0 million in the buyer's common stock if the daily volume weighted average trading price of the buyer's common stock for 10 out of 20 consecutive trading days is at or above $12.00 per share and $15.00 per share, respectively. QEP shall be entitled to the equity consideration if the share price thresholds are met at any time during the five year period following closing of the transaction. The transaction is subject to certain conditions, including, but not limited to, approval of buyer's shareholder and regulatory approvals and is expected to close late in the first quarter or early in the second quarter of 2019. At September 30, 2018, the Williston Basin assets were classified as held and used as the assets did not meet the held for sale criteria. Beginning in the fourth quarter of 2018, the assets and liabilities of the Williston Basin will be classified as held for sale in our Consolidated Balance Sheets for all comparative periods presented. As a part of the Strategic Initiatives, QEP has incurred or expects to incur costs associated with contractual termination benefits including severance and accelerated vesting of share-based compensation. Refer to Note 3 – Acquisitions and Divestitures and Note 8 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for additional information.

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Since the beginning of 2014, the Company has made approximately $2.5 billion of acquisitions of properties in the Permian Basin and spent approximately 40% of its capital expenditures (excluding property acquisitions) on its properties in the Permian Basin. In 2018, the Company plans to spend approximately 70% of total planned capital expenditures to develop the Permian Basin.

Outlook

The Company continues to focus on reducing its operating costs and per well drilling costs and managing its liquidity as it executes on its plan to transition from a natural gas weighted company to a pure play Permian Basin company. We believe our balance sheet and sufficient liquidity will allow us to grow oil and condensate production in the Permian Basin and achieve our Strategic Initiatives.

Based on current commodity prices, we expect to be able to fund our planned capital program for the remainder of 2018 with cash flow from operating activities and borrowings under our credit facility. Our total capital expenditures (excluding property acquisitions) for 2018 are expected to be approximately $1,165.0 million, a decrease of approximately 4% from 2017 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 may adjust our capital investment program based on such evaluations. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures.

Acquisitions and Divestitures

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

Acquisitions

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

In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) for an aggregate purchase price of $720.7 million, subject to post-closing purchase price adjustments. The 2017 Permian Basin Acquisition consists of approximately 15,100 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the sale of QEP's Pinedale assets.

During the nine months endedSeptember 30, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired in 2017.

Divestitures

In early September 2018, QEP sold its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of $153.0 million, subject to post-closing purchase price adjustments (the Uinta Basin Divestiture). During the nine months endedSeptember 30, 2018, QEP recorded a pre-tax loss of $12.4 million related to the Uinta Basin Divestiture, which included $5.5 million related to estimated restructuring costs recorded on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of restructuring costs". In conjunction with the Uinta Basin Divestiture, QEP recorded $402.8 million of proved and unproved properties impairment during the nine months endedSeptember 30, 2018. Refer to Note 1 – Basis of Presentation, Note 3 – Acquisitions and Divestitures and Note 8 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for more information.

In addition to the Uinta Basin Divestiture, during the nine months endedSeptember 30, 2018, QEP recorded net cash proceeds of $64.5 million resulting in a net pre-tax gain on sale of $37.9 million related to the divestiture of properties outside our main operating areas.

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In September 2017, QEP closed on the Pinedale Divestiture for net cash proceeds (after purchase price adjustments) of $718.2 million. During the nine months endedSeptember 30, 2018, QEP recorded a pre-tax gain on sale of $1.2 million, due to post-closing purchase price adjustments, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. During the year ended December 31, 2017, QEP recorded a pre-tax gain on sale of $180.4 million, which was recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations. In connection with the Pinedale Divestiture, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. As of September 30, 2018, the remaining liability associated with estimated future payments for this commitment was $23.0 million.

In addition to the Pinedale Divestiture, during the nine months endedSeptember 30, 2017, QEP received net cash proceeds of $69.7 million, resulting in a net pre-tax gain on sale of $26.4 million, primarily related to the divestiture of certain properties in the Other Northern area.

Financial and Operating Highlights

During the three months endedSeptember 30, 2018, QEP:

• Closed the Uinta Basin Divestiture, for net cash proceeds of $153.0 million;

• Delivered record oil and condensate production of 6.6 MMbbls, a 38%increase over 2017 volumes;

• Increased oil and condensate production in the Permian Basin by 108% to a record 3.5 MMbbls;

• Increased gas production in Haynesville/Cotton Valley to 27.4 Bcf, a 38%increase over 2017 volumes, primarily due to successful refracturing and drilling programs;

• Reported net realized oil price of $56.38 per bbl, an 18%increase over 2017;

• Generated net income of $7.3 million or $0.03 per diluted share; and

• Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $326.2 million, a 69%increase over 2017.

During the nine months endedSeptember 30, 2018, QEP:

• Closed the Uinta Basin Divestiture, for net cash proceeds of $153.0 million;

• Delivered oil and condensate production of 18.2 MMbbls, a 26%increase over 2017 volumes;

• Increased oil and condensate production in the Permian Basin by 115% to a record 8.9 MMbbls;

• Increased gas production in Haynesville/Cotton Valley to 81.6 Bcf, a 67%increase over 2017 volumes, primarily due to successful refracturing and drilling programs;

• Reported net realized oil price of $54.30 per bbl, a 15%increase over 2017;

• Repurchased and retired 6.2 million shares of the Company's common stock outstanding for $58.4 million;

• Generated a net loss of $382.3 million, or $1.60 per diluted share; and

• Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $780.7 million, a 44%increase over 2017.

Factors Affecting Results of Operations

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

Oil and gas prices are affected by many factors outside of our control, including changes in market 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 and gas prices have been affected by supply growth, particularly in U.S. oil and gas production, driven by advances in drilling and completion technologies, and fluctuations in demand driven by a variety of factors.

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Changes in the market prices for oil, gas and NGL 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, our 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 and gas 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 $107.95 per barrel in June 2014. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. If prices of oil, gas or NGL decline to early 2016 levels or further, our operations, financial condition and level of expenditures for the development of our oil and gas 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 economic issues in South America, Asia, Europe, the Middle East, and Africa; 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, 2018, QEP forecasted its 2018 annual production to be approximately 51.5 MMboe and had approximately 64% of its forecasted oil production and 71% of its forecasted gas 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.

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 properties 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 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. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value.

During the nine months endedSeptember 30, 2018, QEP recorded impairment charges of $404.4 million, of which $402.8 million of proved and unproved properties impairment related to the Uinta Basin Divestiture. 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.

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

Triggered by signing the Williston Basin purchase and sale agreement in November 2018, the Company expects to incur proved and unproved impairment charges, in aggregate, of approximately $1.2 billion, of which approximately $1.1 billion is expected to be incurred in the fourth quarter 2018, and the remaining expense to be incurred in subsequent quarters through the estimated closing date, resulting in a reduction of the approximate net book value to fair value at each reporting period. The estimated fair value at each reporting period will be determined using the fair value of the equity consideration and the cash purchase price adjusted for estimated purchase price adjustments from the effective date of July 2018 through the estimated closing date of the transaction, discounted at the Company's weighted average cost of capital, less cost to sell the assets. The impairment charges will be determined using the fair value less cost to sell, compared to the net book value of the assets to be sold. The actual amount of impairment incurred will depend on a variety of factors including, but not limited to, the stock price of the buyer's common stock, revenues, operating expenses and capital costs incurred subsequent to the effective date.

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. In certain of our producing areas, wells drilled on a pad are not completed and brought into production until all wells on the pad are drilled and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the completion of wells and the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells may impact 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/or capital expenditures for a particular reporting period, including, but not limited to those described in Note 10 – 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 2017 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, capitalized exploratory well costs, impairment of long-lived assets, asset retirement obligations, revenue recognition, litigation and other contingencies, environmental obligations, 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.

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Drilling, Completion and Production Activities

The following table presents operated and non-operated wells in the process of being drilled or waiting on completion at September 30, 2018:

		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	—	—	—	—	—	—	—	—	—
Uinta Basin	—	—	—	—	—	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—	—
Southern Region
Permian Basin(1)	4	21	21.0	27	26.7	—	—	—	—
Haynesville/Cotton Valley	—	—	—	—	—	1	0.0	9	0.5
Other Southern	—	—	—	—	—	—	—	—	—

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⁽¹⁾  The gross operated drilling well count in the Permian Basin includes 13 wells for which surface casing has been set, but as of September 30, 2018, did not have a rig drilling.

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 27 gross operated wells waiting on completion as of September 30, 2018.

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 endedSeptember 30, 2018:

	Operated Put on Production				Non-operated Put on Production
	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
	September 30, 2018		September 30, 2018		September 30, 2018		September 30, 2018
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	—	—	11	10.1	11	0.1	13	0.2
Uinta Basin	—	—	2	2.0	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Permian Basin	21	21.0	89	88.1	—	—	—	—
Haynesville/Cotton Valley	1	1.0	4	4.0	1	0.0	10	0.5
Other Southern	—	—	—	—	—	—	—	—

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The following table presents the number of operated wells in the process of being drilled or waiting on completion at September 30, 2018 and operated wells completed and turned to sales (put on production) for the nine months endedSeptember 30, 2018:

	Permian Basin		Williston Basin		Haynesville/Cotton Valley		Uinta Basin
	As of September 30, 2018
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Well Progress
Drilling	21	21.0	—	—	—	—	—	—
At total depth - under drilling rig	—	—	—	—	—	—	—	—
Waiting to be completed	16	16.0	—	—	—	—	—	—
Undergoing completion	4	3.9	—	—	—	—	—	—
Completed, awaiting production	7	6.8	—	—	—	—	—	—
Waiting on completion	27	26.7	—	—	—	—	—	—
Put on production	89	88.1	11	10.1	4	4.0	2	2.0

RESULTS OF OPERATIONS

Net Income

QEP generated net income during the third quarter of 2018 of $7.3 million, or $0.03 per diluted share, compared to a net loss of $3.3 million, or $0.01 per diluted share, in the third quarter of 2017. QEP's net income was primarily driven by a $198.1 millionincrease in oil and condensate sales due to a 38%increase in oil and condensate production and an 18%increase in average net realized oil prices in the third quarter of 2018 compared to the third quarter of 2017. These increases were partially offset by a $158.3 milliondecrease in gain from asset sales, inclusive of restructuring costs due to the gain on sale from the Pinedale Divestiture in 2017.

QEP generated a net loss during the first three quarters of 2018 of $382.3 million or $1.60 per diluted share, compared to net income of $119.0 million or $0.49 per diluted share, in the first three quarters of 2017. QEP's net loss was primarily driven by a $403.6 millionincrease in realized and unrealized derivative losses, a $376.0 millionincrease in impairment expense, a $113.4 millionincrease in depreciation, depletion and amortization and a $55.9 millionincrease in general and administrative expense. These increases to the net loss were partially offset by a $469.6 millionincrease in oil and condensate sales due to a 26% increase in oil and condensate production and a 15%increase in average net realized oil prices and a $68.5 milliondecrease in adjusted transportation and processing costs (a non-GAAP measure defined and reconciled in Operating Expenses below) in the first three quarters of 2018 compared to the first three quarters of 2017 due to the Pinedale Divestiture and Uinta Basin Divestiture.

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.

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Below is a reconciliation of net income (loss) (a 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,
	2018			2017			2018			2017
	(in millions)
Net income (loss)	$	7.3		$	(3.3	)	$	(382.3	)	$	119.0
Interest expense	38.7			34.4			111.9			103.1
Interest and other (income) expense	0.3			(0.1		)	4.1			(2.5		)
Income tax provision (benefit)	2.5			(3.2		)	(117.6		)	69.7
Depreciation, depletion and amortization	234.9			176.9			673.6			560.2
Unrealized (gains) losses on derivative contracts	69.6			116.0			113.2			(161.6		)
Exploration expenses	—			21.3			0.1			21.7
Net (gain) loss from asset sales, inclusive of restructuring costs	(27.1		)	(185.4		)	(26.7		)	(205.2		)
Impairment	—			28.3			404.4			28.4
Other(1)	—			8.2			—			8.2
Adjusted EBITDA	$	326.2		$	193.1		$	780.7		$	541.0

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⁽¹⁾  Reflects legal expenses and loss contingencies incurred during the three and nine months endedSeptember 30, 2017. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.

In the third quarter of 2018, Adjusted EBITDA increased to $326.2 million compared to $193.1 million in the third quarter of 2017, primarily due to a 38%increase in oil and condensate production, mainly in the Permian Basin, an 18%increase in average net realized oil prices and a 38%increase in gas production in Haynesville/Cotton Valley, partially offset by a $50.1 millionincrease in realized derivative losses, a $29.0 milliondecrease in gas sales primarily due to the Pinedale Divestiture and a 1% reduction in average net realized gas price.

In the first three quarters of 2018, Adjusted EBITDA increased to $780.7 million compared to $541.0 million in the first three quarters of 2017, primarily due to a 26%increase in oil and condensate production, mainly in the Permian Basin, a 15%increase in average net realized oil prices, a 67%increase in gas production in Haynesville/Cotton Valley and a $128.8 milliondecrease in realized derivative losses, partially offset by a $97.9 milliondecrease in gas sales primarily due to the Pinedale Divestiture.

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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,
	2018			2017(1)		Change			2018			2017(1)		Change
	(in millions)
Oil and condensate sales	$	416.1		$	218.0	$	198.1		$	1,125.3		$	655.7	$	469.6
Gas sales	101.7			130.7		(29.0		)	301.5			399.4		(97.9		)
NGL sales	42.0			32.2		9.8			88.2			84.0		4.2
Oil and condensate, gas and NGL sales, as adjusted(2)	559.8			380.9		$	178.9		1,515.0			1,139.1		375.9
Transportation and processing costs included in revenue(3)	(15.8		)	—		(15.8		)	(40.9		)	—		(40.9		)
Oil and condensate, gas and NGL sales, as presented	$	544.0		$	380.9	$	163.1		$	1,474.1		$	1,139.1	$	335.0

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⁽¹⁾  Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule. Refer to Note 2 – Revenue in Part 1, Item I of this Quarterly Report on Form 10-Q.

⁽²⁾  Above is a reconciliation of Oil and condensate, gas and NGL sales (a GAAP measure) as presented on the Condensed Consolidated Statements of Operations to Oil and condensate, gas and NGL sales, as adjusted (a non-GAAP measure). Oil and condensate, gas and NGL sales, as adjusted excludes transportation and processing costs that are included as part of "Oil and condensate, gas and NGL sales" on the Condensed Consolidated Statements of Operations. Management removes these costs from "Oil and condensate, gas and NGL sales" included on the Condensed Consolidated Statements of Operations 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 and is a more comparable measure to reported revenue of its peers. 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. Refer to Note 2 – Revenue in Part 1, Item I of this Quarterly Report on Form 10-Q.

⁽³⁾  Transportation and processing costs in the table above is not representative of total transportation and processing costs incurred. Refer to the Operating Expenses section below for a reconciliation of total transportation and processing costs.

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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 endedSeptember 30, 2018, compared to the three and nine months endedSeptember 30, 2017:

	Oil and condensate		Gas			NGL			Total
	(in millions)
Oil and condensate, gas and NGL sales, as adjusted
Three months ended September 30, 2017	$	218.0	$	130.7		$	32.2		$	380.9
Changes associated with volumes(1)	82.0		(24.0		)	(2.1		)	55.9
Changes associated with prices(2)	116.1		(5.0		)	11.9			123.0
Three months ended September 30, 2018	$	416.1	$	101.7		$	42.0		$	559.8
Oil and condensate, gas and NGL sales, as adjusted
Nine months ended September 30, 2017	$	655.7	$	399.4		$	84.0		$	1,139.1
Changes associated with volumes(1)	173.4		(69.5		)	(15.0		)	88.9
Changes associated with prices(2)	296.2		(28.4		)	19.2			287.0
Nine months ended September 30, 2018	$	1,125.3	$	301.5		$	88.2		$	1,515.0

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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 endedSeptember 30, 2018, as compared to the three and nine months endedSeptember 30, 2017, by the average field-level price for the three and nine months endedSeptember 30, 2017.

⁽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 endedSeptember 30, 2018, as compared to the three and nine months endedSeptember 30, 2017, by the respective volumes for the three and nine months endedSeptember 30, 2018. 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,
	2018			2017		Change			2018			2017		Change
Total production volumes (Mboe)
Northern Region
Williston Basin	4,381.1			4,252.3		128.8			12,570.5			13,660.2		(1,089.7		)
Pinedale	—			3,010.8		(3,010.8		)	0.1			9,842.4		(9,842.3		)
Uinta Basin	606.0			905.3		(299.3		)	2,232.2			2,770.6		(538.4		)
Other Northern	63.1			278.1		(215.0		)	211.3			945.6		(734.3		)
Southern Region
Permian Basin	4,792.5			2,351.3		2,441.2			11,591.6			5,672.9		5,918.7
Haynesville/Cotton Valley	4,552.8			3,321.2		1,231.6			13,604.6			8,160.2		5,444.4
Other Southern	4.5			5.1		(0.6		)	20.4			23.1		(2.7		)
Total production	14,400.0			14,124.1		275.9			40,230.7			41,075.0		(844.3		)
Total equivalent prices (per Boe)
Average field-level equivalent price	$	38.87		$	26.97	$	11.90		$	37.66		$	27.73	$	9.93
Commodity derivative impact	(2.66		)	0.83		(3.49		)	(3.16		)	0.05		(3.21		)
Net realized equivalent price	$	36.21		$	27.80	$	8.41		$	34.50		$	27.78	$	6.72

39

Oil and Condensate Volumes and Prices

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018			2017		Change			2018			2017		Change
Oil and condensate production volumes (Mbbl)
Northern Region
Williston Basin	2,968.6			2,803.3		165.3			8,747.6			9,216.5		(468.9		)
Pinedale	—			124.0		(124.0		)	—			404.7		(404.7		)
Uinta Basin	124.7			169.7		(45.0		)	445.0			498.3		(53.3		)
Other Northern	19.8			30.0		(10.2		)	76.8			94.2		(17.4		)
Southern Region
Permian Basin	3,525.7			1,692.8		1,832.9			8,892.0			4,144.1		4,747.9
Haynesville/Cotton Valley	1.9			6.8		(4.9		)	12.2			19.7		(7.5		)
Other Southern	(0.2		)	0.5		(0.7		)	8.5			2.6		5.9
Total production	6,640.5			4,827.1		1,813.4			18,182.1			14,380.1		3,802.0
Average field-level oil prices (per bbl)
Northern Region	$	68.06		$	44.63	$	23.43		$	64.80		$	45.07	$	19.73
Southern Region	$	57.88		$	46.13	$	11.75		$	58.87		$	46.88	$	11.99
Average field-level price	$	62.65		$	45.16	$	17.49		$	61.89		$	45.60	$	16.29
Commodity derivative impact	(6.27		)	2.51		(8.78		)	(7.59		)	1.50		(9.09		)
Net realized price	$	56.38		$	47.67	$	8.71		$	54.30		$	47.10	$	7.20

Oil and condensate revenues increased $198.1 million, or 91%, in the third quarter of 2018 compared to the third quarter of 2017, due to higher average field-level prices and higher oil and condensate production volumes. Average field-level oil prices increased 39% in the third quarter of 2018 compared to the third quarter of 2017 primarily driven by an increase in average NYMEX-WTI oil prices for the comparable periods, partially offset by a $4.02, or 133% increase, in the basis differential relative to the average NYMEX-WTI oil price in the third quarter of 2018 compared to the third quarter of 2017. The 38%increase in production volumes was driven by increases in the Permian and Williston basins due to increased drilling activity as well as refracturing activity in the Williston Basin, partially offset by a loss of volumes as a result of the Pinedale Divestiture in September 2017 and the Uinta Basin Divestiture in early September 2018.

Oil and condensate revenues increased $469.6 million, or 72%, in the first three quarters of 2018 compared to the first three quarters of 2017, due to higher average field-level prices and higher oil and condensate production volumes. Average field-level oil prices increased 36% in the first three quarters of 2018 compared to the first three quarters of 2017 primarily driven by an increase in average NYMEX-WTI oil prices for the comparable periods, partially offset by a $1.36, or 37% increase, in the basis differential relative to the average NYMEX-WTI oil price in the third quarter of 2018 compared to the third quarter of 2017. The 26%increase in production volumes was driven by an increase in the Permian Basin due to increased drilling and completion activity, partially offset by a decrease in production in the Williston Basin and a loss of volumes from Pinedale as a result of the Pinedale Divestiture.

40

Gas Volumes and Prices

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018		2017			Change			2018		2017			Change
Gas production volumes (Bcf)
Northern Region
Williston Basin	4.4		3.7			0.7			11.6		11.8			(0.2		)
Pinedale	—		15.8			(15.8		)	—		51.9			(51.9		)
Uinta Basin	2.7		4.1			(1.4		)	10.1		12.9			(2.8		)
Other Northern	0.3		1.4			(1.1		)	0.8		5.0			(4.2		)
Southern Region
Permian Basin	3.3		1.8			1.5			7.3		4.3			3.0
Haynesville/Cotton Valley	27.4		19.9			7.5			81.6		48.8			32.8
Other Southern	—		—			—			0.1		0.1			—
Total production	38.1		46.7			(8.6		)	111.5		134.8			(23.3		)
Average field-level gas prices (per Mcf)
Northern Region	$	2.59	$	2.74		$	(0.15	)	$	2.52	$	2.95		$	(0.43	)
Southern Region	$	2.69	$	2.86		$	(0.17	)	$	2.75	$	2.97		$	(0.22	)
Average field-level price	$	2.67	$	2.80		$	(0.13	)	$	2.71	$	2.96		$	(0.25	)
Commodity derivative impact	0.09		(0.01		)	0.10			0.10		(0.15		)	0.25
Net realized price	$	2.76	$	2.79		$	(0.03	)	$	2.81	$	2.81		$	—

Gas revenues decreased $29.0 million, or 22%, in the third quarter of 2018 compared to the third quarter of 2017, due to lower gas production volumes and lower average field-level prices. Production volumes decreased 18% primarily due to the Pinedale Divestiture, the Uinta Basin Divestiture in early September 2018 and additional divestitures outside our main operating areas. These production decreases were partially offset by increases in Haynesville/Cotton Valley and the Permian and Williston basins due to increased drilling and completion activity in early 2018 as well as the refracturing programs in Haynesville/Cotton Valley and Williston Basin. The production increase in the Permian Basin was partially offset by lower gas capture rates in the third quarter of 2018 compared to the third quarter of 2017 due to midstream infrastructure construction and well connection activities in the area. Average field-level gas prices decreased 5% in the third quarter of 2018 compared to the third quarter of 2017, primarily driven by a decrease in average NYMEX-HH gas prices for the comparable periods.

Gas revenues decreased $97.9 million, or 25%, in the first three quarters of 2018 compared to the first three quarters of 2017, due to lower gas production volumes and lower average field-level prices. Production volumes decreased 17% in the first three quarters of 2018 compared to the first three quarters of 2017, primarily due to the Pinedale Divestiture, the Uinta Basin Divestiture in early September 2018 and additional divestitures outside our main operating areas. These production decreases were partially offset by increases in production in Haynesville/Cotton Valley and the Permian Basin. The increase in gas production in Haynesville/Cotton Valley was due to the refracturing and drilling programs. The increase in production in the Permian Basin was due to increased drilling and completion activity, partially offset by lower gas capture rates in the Permian Basin in the first three quarters of 2018 compared to the first three quarters of 2017, due to midstream infrastructure construction and well connection activities in the area. Average field-level gas prices decreased 8% in the first three quarters of 2018 compared to the first three quarters of 2017, primarily driven by a decrease in average NYMEX-HH gas prices for the comparable periods.

41

NGL Volumes and Prices

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018		2017			Change			2018		2017			Change
NGL production volumes (Mbbl)
Northern Region
Williston Basin	667.6		834.7			(167.1		)	1,885.7		2,480.6			(594.9		)
Pinedale	—		255.5			(255.5		)	—		779.5			(779.5		)
Uinta Basin	25.7		42.3			(16.6		)	96.9		117.3			(20.4		)
Other Northern	3.7		3.8			(0.1		)	9.4		12.0			(2.6		)
Southern Region
Permian Basin	717.9		376.0			341.9			1,479.2		823.6			655.6
Haynesville/Cotton Valley	0.1		4.9			(4.8		)	0.4		13.6			(13.2		)
Other Southern	0.3		(1.1		)	1.4			0.9		(0.2		)	1.1
Total production	1,415.3		1,516.1			(100.8		)	3,472.5		4,226.4			(753.9		)
Average field-level NGL prices (per bbl)
Northern Region	$	29.55	$	21.89		$	7.66		$	25.32	$	20.52		$	4.80
Southern Region	$	29.74	$	19.43		$	10.31		$	25.49	$	17.35		$	8.14
Average field-level price	$	29.65	$	21.28		$	8.37		$	25.39	$	19.89		$	5.50
Commodity derivative impact	—		—			—			—		—			—
Net realized price	$	29.65	$	21.28		$	8.37		$	25.39	$	19.89		$	5.50

NGL production volumes and revenues represent the sale of liquids derived from the processing of QEP's natural gas production. NGL revenues increased $9.8 million, or 30%, during the third quarter of 2018 compared to the third quarter of 2017, due to higher average field-level prices, partially offset by lower NGL production volumes. The 39%increase in NGL prices during the third quarter of 2018 compared to the third quarter of 2017 was primarily driven by an increase in propane, ethane and other NGL component prices. The increase in price was partially offset by a 7%decrease in NGL production volumes. The decrease was primarily driven by a loss of volumes from Pinedale due to the Pinedale Divestiture and a production decrease in the Williston Basin due to declining gas volumes and lower ethane recovery in the third quarter of 2018 compared to the third quarter of 2017. These production decreases were partially offset by an increase in production in the Permian Basin due to increased drilling and completion activity.

NGL revenues increased $4.2 million, or 5%, during the first three quarters of 2018 compared to the first three quarters of 2017, due to higher average field-level prices, partially offset by lower NGL production volumes. The 28%increase in NGL prices during the first three quarters of 2018 compared to the first three quarters of 2017 was primarily driven by an increase in propane, ethane and other NGL component prices. The increase in price was partially offset by an 18%decrease in NGL production volumes primarily driven by a loss of volumes from Pinedale due to the Pinedale Divestiture and production decreases in the Williston Basin due to declining gas volumes and lower ethane recovery during the first three quarters of 2018 compared to the first three quarters of 2017. These decreases were partially offset by an increase in production in the Permian Basin due to increased drilling and completion activity.

42

Resale Margin and Storage Activity

QEP purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. 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,
	2018			2017			Change			2018			2017			Change
	(in millions)
Purchased oil and gas sales	$	13.0		$	5.6		$	7.4		$	36.2		$	44.5		$	(8.3	)
Purchased oil and gas expense	(13.3		)	(6.9		)	(6.4		)	(38.6		)	(45.4		)	6.8
Realized gains (losses) on gas storage derivative contracts	—			—			—			0.3			(0.2		)	0.5
Resale margin	$	(0.3	)	$	(1.3	)	$	1.0		$	(2.1	)	$	(1.1	)	$	(1.0	)

Purchased oil and gas sales and expense increased during the third quarter of 2018 compared to third quarter of 2017, due to an increase in resale volumes to meet Northern Region gas transportation commitments retained in the various divestitures, partially offset by lower resale volumes needed to meet gas transportation commitments in the Southern Region due to increased production.

Purchased oil and gas sales and expense decreased during the first three quarters of 2018 compared to first three quarters of 2017, due to lower resale volumes following the sale of an underground gas storage facility in May 2018.

43

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,
	2018		2017		Change			2018		2017		Change
	(in millions)
Lease operating expense	$	64.6	$	76.2	$	(11.6	)	$	203.6	$	215.4	$	(11.8	)
Adjusted transportation and processing costs(1)	43.8		60.2		(16.4		)	134.1		202.6		(68.5		)
Production and property taxes	37.4		28.5		8.9			103.9		86.1		17.8
Total production costs	$	145.8	$	164.9	$	(19.1	)	$	441.6	$	504.1	$	(62.5	)
	(per Boe)
Lease operating expense	$	4.49	$	5.39	$	(0.90	)	$	5.06	$	5.24	$	(0.18	)
Adjusted transportation and processing costs(1)	3.04		4.26		(1.22		)	3.34		4.93		(1.59		)
Production and property taxes	2.60		2.02		0.58			2.58		2.10		0.48
Total production costs	$	10.13	$	11.67	$	(1.54	)	$	10.98	$	12.27	$	(1.29	)

____________________________

⁽¹⁾  Below are reconciliations of transportation and processing costs (a 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 with transportation and processing costs reflected on the Condensed Consolidated Statements of Operations 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 and is a more comparable measure to the operating costs of its peers. 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. 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,
	2018			2017(1)		Change			2018			2017(1)		Change
	(in millions)
Adjusted transportation and processing costs	$	43.8		$	60.2	$	(16.4	)	$	134.1		$	202.6	$	(68.5	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	(15.8		)	—		(15.8		)	(40.9		)	—		(40.9		)
Transportation and processing costs, as presented	$	28.0		$	60.2	$	(32.2	)	$	93.2		$	202.6	$	(109.4	)
	(per Boe)
Adjusted transportation and processing costs	$	3.04		$	4.26	$	(1.22	)	$	3.34		$	4.93	$	(1.59	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	(1.10		)	—		(1.10		)	(1.02		)	—		(1.02		)
Transportation and processing costs, as presented	$	1.94		$	4.26	$	(2.32	)	$	2.32		$	4.93	$	(2.61	)

____________________________

⁽¹⁾  Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule. Refer to Note 2 – Revenue in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

44

Lease operating expense (LOE). QEP's LOE decreased $11.6 million, or 15%, in the third quarter of 2018 compared to the third quarter of 2017 primarily due to the Pinedale Divestiture. Excluding Pinedale, LOE decreased $3.3 million, primarily driven by decreases in the Williston Basin and Haynesville/Cotton Valley due to lower workover expense and the Uinta Basin Divestiture, partially offset by increases in the Permian Basin due to the 2017 Permian Basin Acquisition, and increased power and fuel, maintenance and repairs and labor expenses.

During the third quarter of 2018, LOE decreased $0.90 per Boe, or 17%, compared with the third quarter of 2017 and decreased 28% per Boe excluding the Pinedale Divestiture, primarily due to lower cost production from the 2018 horizontal well completions in the Permian Basin, Williston Basin and Haynesville/Cotton Valley, and decreased workover expense in the Williston Basin and Haynesville/Cotton Valley.

QEP's LOE decreased $11.8 million in the first three quarters of 2018 compared to the first three quarters of 2017, due to the Pinedale Divestiture. Excluding Pinedale, LOE increased $16.8 million, primarily driven by increases in the Permian Basin due to the 2017 Permian Basin Acquisition, and increased maintenance and repairs, power and fuel and labor expenses. These increases were partially offset by decreases in workover expense in the Williston and Permian basins.

During the first three quarters of 2018, LOE decreased $0.18 per Boe, or 3%, compared with the first three quarters of 2017 and decreased 17% excluding the Pinedale Divestiture primarily due to lower cost production from the 2018 horizontal well completions in the Permian Basin and Haynesville/Cotton Valley, partially offset by an increase in our Williston Basin rate due to declining production volumes.

Adjusted transportation and processing costs. Adjusted transportation and processing costs decreased $16.4 million, or 27%, during the third quarter of 2018 compared to the third quarter of 2017. The decrease in expense was primarily attributable to the Pinedale Divestiture and the Uinta Basin Divestiture. These decreases were partially offset by the recovery of fees in the third quarter of 2017 for historical unutilized gathering and transportation capacity in Haynesville/Cotton Valley that was charged to QEP by the operator of wells in which QEP had a working interest and increased production in the third quarter of 2018.

During the third quarter of 2018, adjusted transportation and processing costs decreased $1.22 per Boe, or 29%, compared to the third quarter of 2017, due to the Pinedale Divestiture, which had higher adjusted transportation and processing costs per Boe. Excluding the Pinedale Divestiture, adjusted transportation and processing costs per Boe were down 17% due to a decrease in the Permian Basin, partially offset by an increase in Haynesville/Cotton Valley during the third quarter of 2018 compared to the third quarter of 2017. The cost per Boe decrease in the Permian Basin was driven by increased production and associated throughput under lower cost transportation and processing contracts. The cost per Boe increased in Haynesville/Cotton Valley due to the recovery of fees in the third quarter of 2017 for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest, partially offset by increased production in the third quarter of 2018.

Adjusted transportation and processing costs decreased $68.5 million, or 34%, during the first three quarters of 2018 compared to the first three quarters of 2017. The decrease in expense was primarily attributable to the Pinedale Divestiture and the Uinta Basin Divestiture. These decreases were partially offset by the recovery of fees in 2017 for historical unutilized gathering and transportation capacity in Haynesville/Cotton Valley that was charged to QEP by the operator of wells in which QEP had a working interest and increased production in the first three quarters of 2018.

During the first three quarters of 2018, adjusted transportation and processing costs decreased $1.59 per Boe, or 32%, compared to the first three quarters of 2017, due to the Pinedale Divestiture, which had higher adjusted transportation and processing costs per Boe. Excluding the Pinedale Divestiture, adjusted transportation and processing costs per Boe were down 21% due to a decrease in Haynesville/Cotton Valley and the Permian Basin during the first three quarters of 2018 compared to the first three quarters of 2017. The cost per Boe decreased in Haynesville/Cotton Valley due to increased production in 2018, partially offset by the recovery of fees in 2017 for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest in 2017. The cost per Boe decrease in the Permian Basin was driven by increased production and associated throughput under lower cost transportation and processing contracts in 2018.

45

General and administrative (G&A) expense. During the third quarter of 2018, G&A expense increased $4.9 million, or 11%, compared to the third quarter of 2017. During the third quarter of 2018, QEP incurred $12.8 million in restructuring costs associated with the implementation of our Strategic Initiatives (refer to Note 8 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). In addition to these restructuring related costs, QEP recognized a $4.5 million increase related to reduced overhead recoveries, primarily associated with our Pinedale Divestiture and a $2.0 million increase in outside services expenses. These increases were partially offset by an $8.2 million decrease in legal expenses and loss contingencies and a $2.9 million decrease in share-based compensation and changes in the mark-to-market value of the nonqualified, unfunded deferred compensation plan (the Wrap Plan).

During the first three quarters of 2018, G&A expense increased $55.9 million, or 52%, compared to the first three quarters of 2017. During the first three quarters of 2018, QEP incurred $30.2 million in restructuring costs associated with the implementation of our Strategic Initiatives (refer to Note 8 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q). In addition to these restructuring related costs, QEP recognized a $17.8 million increase in share-based compensation and changes in the mark-to-market value of the Wrap Plan, a $12.7 million increase related to reduced overhead recoveries, primarily associated with our Pinedale Divestiture, a $4.0 million increase in outside services, a $2.5 million increase in bad debt expense and increases in labor, benefits and employee expenses of $1.3 million. These increases were partially offset by a $5.0 million decrease in legal expenses and loss contingencies.

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 increased $8.9 million, or 31%, in the third quarter of 2018 compared to the third quarter of 2017, primarily due to increased oil pricing and increased oil and condensate production in the Permian and Williston basins, and increased gas production in Haynesville/Cotton Valley, partially offset by the Pinedale Divestiture.

During the third quarter of 2018, production and property taxes increased $0.58 per Boe, or 29%, compared to the third quarter of 2017, but increased 27% excluding the Pinedale Divestiture. The 27% increase was due to an increase in average field-level equivalent prices in the Permian and Williston basins offset by a lower rate per Boe in Haynesville/Cotton Valley due to lower non-operated ad valorem charges and franchise taxes per Boe and severance tax exemptions on production from horizontal well development.

Production and property taxes increased $17.8 million, or 21%, in the first three quarters of 2018 compared to the first three quarters of 2017, primarily due to increased oil pricing and increased oil and condensate production in the Permian Basin, and increased gas production in Haynesville/Cotton Valley, partially offset by the Pinedale Divestiture.

During the first three quarters of 2018, production and property taxes increased $0.48 per Boe, or 23%, compared to the first three quarters of 2017, but increased 21% excluding the Pinedale Divestiture. The 21% increase was due to an increase in average field-level equivalent prices in the Permian and Williston basins, partially offset by a lower rate per Boe in Haynesville/Cotton Valley due to lower non-operated ad valorem charges and franchise taxes per Boe and severance tax exemptions on production from horizontal well development.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $58.0 million in the third quarter of 2018 compared to the third quarter of 2017, primarily due to increased production and a higher DD&A rate in the Permian Basin and Haynesville/Cotton Valley, partially offset by lower DD&A due to the Pinedale Divestiture and the early September 2018 Uinta Basin Divestiture.

DD&A expense increased $113.4 million in the first three quarters of 2018 compared to the first three quarters of 2017, primarily due to increased production and a higher DD&A rate in the Permian Basin and Haynesville/Cotton Valley, partially offset by lower DD&A due to the Pinedale Divestiture and the early September 2018 Uinta Basin Divestiture.

Exploration expense. Exploration expense decreased $21.3 million during the third quarter of 2018 compared to the third quarter of 2017, primarily due to charging $21.2 million of exploratory well costs in 2017 related to the Central Basin Platform exploration project to exploration expense. During the third quarter of 2017, based on well performance and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project.

46

Exploration expense decreased $21.6 million during the first three quarters of 2018 compared to the first three quarters of 2017, primarily due to charging $21.2 million of exploratory well costs in 2017 related to the Central Basin Platform exploration project to exploration expense. During the third quarter of 2017, based on well performance and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project.

Impairment expense. During the third quarter of 2017, QEP recorded an impairment charge of $28.3 million, which were primarily related to the impairment of unproved leasehold acreage in the Central Basin Platform.

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 related to 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.

Net gain (loss) from asset sales, inclusive of restructuring costs. 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 Pinedale Divestiture, partially offset by a pre-tax loss on sale 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 8 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for more information). During the third quarter of 2017, QEP recognized a gain on the sale of assets of $185.4 million primarily related to the Pinedale Divestiture, in which we recorded a pre-tax gain on sale of $178.8 million, and the sale of Other Northern properties.

During the first three quarters of 2018, QEP recognized a gain on the sale of assets of $26.7 million, primarily related to a net pre-tax gain on sale of $37.9 million related to the divestiture of properties outside our main operating areas and an additional pre-tax gain on sale of $1.2 million related to the Pinedale Divestiture, partially offset by a pre-tax loss on sale 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 8 – Restructuring, in Item I of Part I of this Quarterly Report on Form 10-Q for more information). During the first three quarters of 2017, QEP recognized a gain on the sale of assets of $205.2 million primarily related to the Pinedale Divestiture, in which we recorded a pre-tax gain on sale of $178.8 million, and the sale of Other Northern properties.

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 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 third quarter of 2017, losses on commodity derivative contracts were $104.3 million, of which $86.1 million were unrealized losses on derivative contracts related to production and storage contracts, $29.9 million were unrealized losses related to the Pinedale Divestiture (Refer to Note 7 – Derivative Contracts, in Item I of Part I of the Quarterly Report on Form 10-Q for more information) and $11.7 million were realized gains.

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). During the first three quarters of 2017, gains on commodity derivative contracts were $163.3 million, of which $191.5 million were unrealized gains on derivative contracts related to production and storage contracts, $29.9 million were unrealized losses related to the Pinedale Divestiture (Refer to Note 7 – Derivative Contracts, in Item I of Part I of this Quarterly Report on Form 10-Q for more information) and $1.7 million were realized gains.

Interest expense. Interest expense increased $4.3 million, or 13%, during the third quarter of 2018 compared to the third quarter of 2017. The increase during the third quarter of 2018 was primarily related to increased interest on the borrowings under the credit facility, partially offset by lower interest rates on senior notes.

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Interest expense increased $8.8 million, or 9%, during the first three quarters of 2018 compared to the first three quarters of 2017. The increase during the first three quarters of 2018 was primarily related to increased interest on the borrowings under the credit facility, partially offset by lower interest rates on senior notes.

Income tax (provision) benefit. Income tax expenseincreased $5.7 million during the third quarter of 2018 compared to the third quarter of 2017. The increase in expense was the result of net income during the third quarter of 2018 compared to a net loss during the third quarter of 2017. QEP's income tax expense was impacted by a lower combined effective federal and state income tax rate of 25.5% during the third quarter of 2018 compared to a rate of 49.2% during the third quarter of 2017. The decrease in income tax rate was primarily the result of the Tax Cuts and Job Act (H.R. 1) signed into law in December 2017.

Income tax benefitincreased $187.3 million during the first three quarters of 2018 compared to the first three quarters of 2017. The increase in benefit was the result of a net loss during the first three quarters of 2018 compared to net income during the first three quarters of 2017. QEP's income tax benefit was impacted by a lower combined effective federal and state income tax rate of 23.5% during the first three quarters of 2018 compared to a rate of 36.9% during the first three quarters of 2017. The decrease in income tax rate was primarily the result of the Tax Cuts and Job Act (H.R. 1) signed into law in December 2017.

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

During the quarter ended September 30, 2018, QEP closed on the Uinta Basin Divestiture as well as the divestiture of other assets outside its main operating areas and used the net cash proceeds to pay down long-term debt outstanding under QEP's revolving credit facility. To the extent that the Company sells additional assets, the Company plans to use the proceeds to fund on-going operations, reduce debt, repurchase shares and for general corporate purposes.

The Company estimates, that as of September 30, 2018, it could incur additional indebtedness of approximately $1.4 billion 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 liquidity could be adversely affected.

Credit Facility

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

During the nine months endedSeptember 30, 2018, QEP's weighted-average interest rate on borrowings from its credit facility was 4.30%. As of September 30, 2018, QEP had $375.5 million of borrowings outstanding and $0.3 million in letters of credit outstanding under the credit facility. As of December 31, 2017, QEP had $89.0 million of borrowings outstanding and $1.0 million in letters of credit outstanding under the credit facility. As of October 31, 2018, QEP had $370.0 million of borrowings outstanding, had $0.3 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.

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Senior Notes

The Company's senior notes outstanding as of September 30, 2018, totaled $2,099.3 million principal amount and are comprised of five issuances as follows:

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

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

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

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

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

Cash Flow from Operating Activities

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

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

	Nine Months Ended September 30,
	2018			2017		Change
	(in millions)
Net income (loss)	$	(382.3	)	$	119.0	$	(501.3	)
Non-cash adjustments to net income (loss)	1,076.1			318.7		757.4
Changes in operating assets and liabilities	(18.9		)	45.1		(64.0		)
Net cash provided by (used in) operating activities	$	674.9		$	482.8	$	192.1

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, $1,076.1 million of non-cash adjustments to the net loss and $18.9 million in changes in operating assets and liabilities. Non-cash adjustments to the net loss of $1,076.1 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 $28.3 million of share-based compensation expense, partially offset by $119.6 million of deferred income taxes. The decrease in changes in operating assets and liabilities of $18.9 million primarily resulted from an increase in accounts receivable of $49.8 million, partially offset by a decrease in other assets of $18.8 million and an increase in accounts payable and accrued expenses of $11.8 million.

Net cash provided by operating activities was $482.8 million during the first three quarters of 2017, which included $119.0 million of net income, $318.7 million of non-cash adjustments to net income and a $45.1 millionincrease in changes in operating assets and liabilities. Non-cash adjustments to net income of $318.7 million primarily included DD&A expense of $560.2 million and $68.5 million of deferred income taxes, partially offset by a net gain on asset sales of $205.2 million and unrealized gains on derivative contracts of $161.6 million. The increase in changes in operating assets and liabilities primarily resulted from a decrease in accounts receivable of $18.5 million, an increase in accounts payable and accrued expenses of $17.8 million and an increase in production and property taxes of $7.3 million, partially offset by a decrease in the ARO liability of $3.0 million.

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Cash Flow from Investing Activities

A comparison of capital expenditures for the first three quarters of 2018 and 2017, are presented in the table below:

	Nine Months Ended September 30,
	2018		2017			Change
	(in millions)
Property acquisitions(1)	$	48.3	$	94.5		$	(46.2	)
Property, plant and equipment capital expenditures	988.2		847.6			140.6
Total accrued capital expenditures	1,036.5		942.1			94.4
Change in accruals and other non-cash adjustments	43.9		(68.0		)	111.9
Total cash capital expenditures	$	1,080.4	$	874.1		$	206.3

____________________________

⁽¹⁾  Excludes acquisition deposits held in escrow of $36.6 million for the nine months endedSeptember 30, 2017.

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), an increase of $140.6 million compared to the first three quarters of 2017. In the first three quarters of 2018, QEP's significant capital expenditures included $689.7 million in the Permian Basin (including midstream infrastructure of $21.0 million, primarily related to oil and gas gathering), $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.

In the first three quarters of 2017, on an accrual basis, the Company invested $847.6 million on property, plant and equipment capital expenditures (which excludes property acquisitions), including $489.1 million in the Permian Basin, $195.4 million in the Williston Basin, $121.2 million in Haynesville/Cotton Valley and $24.8 million in Pinedale. In addition, during the first three quarters of 2017, QEP acquired various oil and gas properties, primarily proved and unproved leaseholds and additional surface acreage primarily in the Permian Basin, for an aggregate purchase price of $94.5 million. These cash outflows were partially offset by proceeds from the Pinedale Divestiture, which closed in the third quarter of 2017, and the sale of other assets of approximately $787.9 million in the aggregate.

The mid-point of our 2018 forecasted capital expenditures (excluding property acquisitions) is $1,165.0 million. QEP intends to fund capital expenditures (excluding property acquisitions) with cash flow from operating activities and borrowings under the credit facility. The aggregate levels of capital expenditures for 2018 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, oil, gas and NGL prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management's business assessments as to where QEP's capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP's estimates.

Cash Flow from Financing Activities

In the first three quarters of 2018, net cash provided by financing activities was $191.8 million compared to net cash used in financing activities of $20.2 million in the first three quarters of 2017. During the first three quarters of 2018, QEP had borrowings from the 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 had a decrease in checks outstanding in excess of cash balances of $28.7 million. During the first three quarters of 2017, QEP had a decrease in checks outstanding in excess of cash balances of $12.3 million, had treasury stock repurchases of $6.8 million and paid long-term debt issuance costs of $1.1 million.

As of September 30, 2018, long-term debt consisted of $2,451.1 million, of which $2,099.3 million is senior notes, $375.5 million outstanding on the credit facility and a $23.7 million reduction related to the net original issue discount and unamortized debt issuance costs.

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Significant Accounting Policies

Refer to Note 2 – Revenue in Part 1, Item 1 of this Quarterly Report on Form 10-Q for changes in QEP's revenue recognition policy as a result of the adoption of ASC Topic 606, effective January 1, 2018.

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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. QEP has long-term contracts for pipeline capacity and is obligated to pay for transportation services with no guarantee that it also will be able to fully utilize the contractual capacity of these transportation commitments. 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. 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, 2018, QEP held commodity price derivative contracts, excluding basis swaps, totaling 18.0 million barrels of oil and 69.0 million MMBtu of gas.

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The following tables present QEP's volumes and average prices for its derivative positions as of October 31, 2018. 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, 2018.

Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2018	NYMEX WTI	2.7	$	52.45
2019	NYMEX WTI	11.0	$	54.49
2020	NYMEX WTI	2.9	$	62.37
Gas sales		(MMBtu)	($/MMBtu)
2018	NYMEX HH	8.1	$	3.01
2019	NYMEX HH	43.8	$	2.86

Production Commodity Derivative Basis Swaps
Year	Index	Basis	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2018	NYMEX WTI	Argus WTI Midland	1.5	$	(0.99	)
2018	NYMEX WTI	Argus WTI Houston	0.1	$	6.30
2019	NYMEX WTI	Argus WTI Midland	6.6	$	(2.22	)
2019	NYMEX WTI	Argus WTI Houston	0.4	$	4.35
2020	NYMEX WTI	Argus WTI Midland	1.5	$	(1.01	)
Gas sales			(MMBtu)	($/MMBtu)
2018	NYMEX HH	IFNPCR	1.2	$	(0.16	)

Changes in the fair value of derivative contracts from December 31, 2017 to September 30, 2018, are presented below:

	Commodity derivative contracts
	(in millions)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2017	$	(131.9	)
Contracts settled	127.1
Change in oil and gas prices on futures markets	139.1
Contracts added	(373.5		)
Net fair value of oil and gas derivative contracts outstanding at September 30, 2018	$	(239.2	)

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

	September 30, 2018
	(in millions)
Net fair value – asset (liability)	$	(239.2	)
Fair value if market prices of oil, gas and basis differentials decline by 10%	$	(215.3	)
Fair value if market prices of oil, gas and basis differentials increase by 10%	$	(263.2	)

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Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $24.0 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $23.9 million as of September 30, 2018. 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 ability to borrow and the rates offered by lenders can be adversely affected by illiquid credit markets and the Company's credit rating, as described in the risk factors in Item 1A of Part I of its 2017 Form 10-K. 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, 2018, the Company had $375.5 million of borrowings outstanding under its revolving credit facility. If interest rates were to increase or decrease 10% during the nine months endedSeptember 30, 2018, at our average level of borrowing for those same periods, the Company's interest expense would increase or decrease by $1.5 million for the nine months endedSeptember 30, 2018, or approximately 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 9 – 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 Strategic Initiatives to transition to a pure-play Permian Basin company, including our ability to divest of assets and the use of proceeds from asset divestitures;

• reducing operating and per well drilling costs and managing liquidity;

• plans to grow oil and condensate production in the Permian Basin;

• drilling and completion plans and strategies;

• acquiring acreage in the Permian Basin to add development opportunities and facilitate the drilling of long lateral wells;

• estimated future payments to reimburse the buyer in the Pinedale Divestiture for certain deficiency charges related to the gas processing and NGL transportation and fractionation contracts;

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

• the usefulness of non-GAAP financial measures;

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

• our balance sheet and liquidity position allowing us to grow oil production in the Permian Basin and achieve our Strategic Initiatives;

• amount and allocation of forecasted capital expenditures and factors impacting same;

• plans for funding operations and capital investments;

• potential for asset impairments, including estimated impairment amounts, and factors impacting the timing and amount of impairment;

• when assets are deemed held for sale;

• classification of the Williston Basin assets as held for sale beginning in the fourth quarter of 2018;

• purchase price and estimated amount and materiality of purchase price adjustments for the Williston Basin Divestiture;

• expected closing date of Williston Basin Divestiture;

• fair value estimates and related assumptions and assessment of the sensitivity of changes in assumptions;

• critical accounting estimates;

• impact of global geopolitical and macroeconomic events on oil and gas prices and our financial position, results of operations and cash flows;

• forecasted production;

• plans regarding derivative contracts, including the types of commodity derivative instruments utilized, volumes utilized, and the anticipated benefits;

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

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

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

• implementation and impact of new accounting pronouncements;

• assumptions regarding share-based compensation;

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

• recognition of compensation expense related to share-based compensation grants;

• expected contributions to our employee benefit plans;

• effect of the Strategic Initiatives on employee benefit plans;

• costs associated with employee retention program and contractual termination benefits, including severance and accelerated vesting of share-based compensations; and

• loss of services of key personnel.

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

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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 2017 Form 10-K and Item 1A of Part II of this Quarterly Report on Form 10-Q;

• changes in oil, gas and NGL prices;

• global geopolitical and macroeconomic factors;

• general economic conditions, including the performance of financial markets and interest rates and our vulnerability to such economic conditions given our higher levels of debt;

• the risks and liabilities associated with acquired assets;

• asset impairments;

• fair value estimates;

• timing of and proceeds from asset divestitures;

• 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, gas recapture plans, 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;

• 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;

• 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

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• 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, 2018. Based on such evaluation, such officers have concluded that, as of September 30, 2018, 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, 2018, 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

There have been no material changes with respect to the legal proceedings reported in our 2017 Form 10-K. Refer to Note 10 – Commitments and Contingencies in Item I of Part I of this Quarterly Report on Form 10-Q for additional information regarding our legal proceedings.

ITEM 1A. RISK FACTORS

Risk factors relating to the Company are set forth in its 2017 Form 10-K. There have been no material changes to such risk factors since filing the 2017 Form 10-K, except for the risk factors below. The risks described below and in the 2017 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.

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QEP's debt and other financial commitments may limit its financial and operating flexibility. QEP's total debt was approximately $2.5 billion and $2.2 billion at September 30, 2018 and December 31, 2017, respectively. QEP also has various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties. QEP's financial commitments could have important consequences to its business, including, but not limited to, limiting QEP's ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, to repurchase shares of its common stock, or to otherwise realize the value of its assets and opportunities fully because of the need to dedicate a substantial portion of its cash flows from operations and proceeds from the divestiture of its assets to payments on its debt or to comply with any restrictive terms of its debt. QEP may be at a competitive disadvantage as compared to similar companies that have less debt. Higher levels of debt may make QEP more vulnerable to general adverse economic and industry conditions. Additionally, the agreement governing QEP's revolving credit facility and the indentures covering QEP's senior notes contain a number of covenants that impose constraints on the Company, including requirements to comply with certain financial covenants and restrictions on QEP's ability to dispose of assets, make certain investments, incur liens and additional debt, and engage in transactions with affiliates. If commodity prices decline and QEP reduces its level of capital spending and production declines or QEP incurs additional impairment expense or the value of the Company's proved reserves declines, the Company may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance with the financial covenants in its credit agreement in the future. Refer to Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations in Part II of this Annual Report on Form 10-K and Note 8 - Debt, in Item 8 of Part II of this Annual Report on Form 10-K for additional information regarding the financial covenants and our revolving credit agreement.

QEP may be unable to successfully execute certain aspects of its announced Strategic Initiatives.In February 2018,QEP announced Strategic Initiatives to transition to a pure-play Permian Basin company. This transition contemplates QEP divesting its assets in the Williston Basin, Uinta Basin and Haynesville Shale. In September 2018, QEP closed on the sale of its Uinta Basin assets. Any divestiture of a business or assets involves potential risks.

Organizational modifications due to divestitures or other strategic changes can alter the risk and control environments; disrupt ongoing business; distract management and employees; increase expenses; result in additional liabilities, investigations and litigation; harm QEP's strategy; and adversely affect results of operations. Even if these challenges are dealt with successfully, the anticipated benefits of the divestitures may not be realized.

QEP is subject to complex federal, state, tribal, local and other laws and regulations that could adversely affect its cost of doing business and recording of proved reserves. QEP's operations are subject to extensive federal, state, tribal and local tax, energy, environmental, health and safety laws and regulations. The failure to comply with applicable laws and regulations can result in substantial penalties and may threaten the Company's authorization to operate.

Environmental laws and regulations are complex, change frequently and have tended to become more onerous over time. This regulatory burden on the Company's operations increases its cost of doing business and, consequently, affects its profitability. In addition to the costs of compliance, substantial costs may be incurred to take corrective actions at both owned and previously owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of QEP's business. As standards change, the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time, but now require remedial work to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, other damages, or injunctions that could limit the scope of QEP's planned operations.

Clean Air Act regulations at 40 C.F.R Part 60, Subpart OOOO (Subpart OOOO) became effective in 2012, with further amendments effective in 2013 and 2014. Subpart OOOO imposes air quality controls and requirements upon QEP's operations. Additionally, in June 2016, the EPA finalized closely related rules in new Subpart OOOOa to achieve additional methane and volatile organic compound reductions from certain activities in the oil and gas industry. The new rules include, among others, new requirements for finding and repairing leaks at new well sites and "reduced emission completion" requirements for hydraulically fractured oil and gas wells. The future status of Subpart OOOOa remains uncertain given ongoing litigation and administrative regulatory actions. In September 2018, EPA announced proposed revisions to Subpart OOOOa which may reduce compliance burden on some facilities, but the regulatory uncertainty surrounding the implementation of such revisions and the potential for legal challenges to them pose some complications for QEP's operations and compliance efforts. Additionally, many states are adopting air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that are more stringent than existing requirements under federal regulations and the proposed revisions to such regulations.

58

QEP may be unable to divest of assets on financially attractive terms, resulting in reduced cash proceeds. QEP has announced the sale of certain upstream and midstream assets. QEP's success in divesting assets depends, in part, upon QEP's ability to identify suitable buyers or joint venture partners; assess potential transaction terms; negotiate agreements; and, if applicable, obtain required approvals. Various factors could materially affect QEP's ability to dispose of assets on terms acceptable to QEP. Such factors include, but are not limited to: current and forecasted commodity prices; current laws, regulations and permitting processes impacting oil and gas operations in the areas where the assets are located; covenants under QEP's credit agreement; tax impacts; willingness of the purchaser to assume certain liabilities such as asset retirement obligations and firm transportation contracts; QEP's willingness to indemnify buyers for certain matters; and other factors.

In addition, QEP's credit agreement contains limitations on the amount of asset sales that it is permitted to divest each year. If QEP seeks to sell more assets than is permitted under the credit agreement and is unable to receive waivers of such restrictions, then it may be unable to divest of these assets.

Regulatory requirements to reduce gas flaring and to further restrict emissions could have an adverse effect on our operations.  Wells in the Williston Basin of North Dakota and the Permian Basin of Texas, where QEP has significant operations, produce natural gas as well as crude oil. Constraints in third party gas gathering and processing systems in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In June 2014, the North Dakota Industrial Commission (NDI Commission), North Dakota's chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Williston Basin. The NDI Commission requires operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties may be imposed on certain wells that cannot meet the capture goals. It is possible that other states in which QEP operates will require gas capture plans in the future to reduce flaring.

Additionally, in November 2016, the Bureau of Land Management (BLM) finalized a new rule related to further controls on the venting, flaring and emissions of natural gas on BLM and tribal leases (the 2016 Waste Prevention Rule). The rule took effect in January 2017. Some provisions of the rule required compliance in January 2017, including the royalty provisions, while other provisions, including those related to further controls on the venting and flaring of natural gas, did not require compliance until January 2018. The provisions of the 2016 Waste Prevention Rule with a January 2018 compliance deadline have, however, been either administratively suspended or judicially stayed for most of 2018. In September 2018, the BLM released a rule that revises and replaces the 2016 Waste Prevention Rule effective November 27, 2018 (Revised Waste Prevention Rule). The Revised Waste Prevention Rule rescinds the requirements of the 2016 Waste Prevention Rule pertaining to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detection and repair. The Revised Waste Prevention Rule also revises provisions of the 2016 Waste Prevention Rule related to venting and flaring of natural gas and adds provisions deeming gas vented or flared in accordance with applicable state or tribal requirements to be royalty free. Environmental nongovernmental organizations (ENGOs) and certain states have challenged the Revised Waste Prevention Rule in the U.S. District Court for the Northern District of California. State and federal gas capture requirements, and any similar future obligations in North Dakota or our other locations, increase our operational costs and may restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.  Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various species and wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened and endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse effect on our ability to develop and produce our reserves. For example, the Department of the Interior's Fish and Wildlife Service (FWS) listed the Louisiana Pine Snake as threatened under the Endangered Species Act (ESA) in April 2018. The FWS identified Bienville Parish as one of the parishes where the snake can be found. QEP operates within Bienville Parish. Additionally, in 2018, the FWS plans to issue a proposed rule listing the Lesser Prairie-Chicken as a threatened or endangered species. The Lesser Prairie-Chicken is a grouse species native to Texas, including parts of the Permian Basin where QEP operates.

59

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce. Climate change, the costs that may be associated with its effects and the regulation of greenhouse gas (GHG) emissions have the potential to affect our business in many ways, including increasing the costs to provide our products, reducing the demand for and consumption of our products (due to changes in both costs and weather patterns) and negatively impacting the economic health of the regions in which we operate, all of which can create financial risks. In addition, if restrictions on GHG emissions significantly increase our costs to produce oil and gas, or significantly decrease demand for our products, the value of our oil and gas reserves may decrease. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. In addition, legislative and regulatory responses related to GHG emissions and climate change may result in increased operating costs, delays in obtaining air emissions and other necessary permits for new or modified facilities and reduced demand for the oil, gas and NGL that QEP produces. Federal and state courts and administrative agencies are considering the scope and scale of climate change regulation under various laws pertaining to the environment, energy use and energy resource development. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, or restricting or banning the use of gasoline or diesel powered vehicles, which may reduce demand for oil and natural gas. Further, state and local governments may pursue litigation against producers for damages allegedly resulting from climate change. QEP's ability to access and develop new oil and gas reserves may also be restricted by climate change regulations, including GHG reporting and regulation.

Congress has previously considered but not adopted proposed legislation aimed at reducing GHG emissions. The EPA has adopted final regulations under the Clean Air Act for the measurement and reporting of GHG emitted from certain large facilities and, as discussed above, has adopted additional regulations at 40 C.F.R Part 60, Subparts OOOO and OOOOa, to include additional requirements to reduce methane and volatile organic compound emissions from oil and natural gas facilities. The status of Subpart OOOOa is uncertain given the ongoing litigation, administrative reconsideration, proposed revisions to those rules announced in September 2018, and the prospects for legal challenges to such revisions. Additionally, in June 2014, the United States Supreme Court upheld a portion of EPA's GHG stationary source permitting program in Utility Air Regulatory Group v. EPA, but also invalidated a portion of it. The Court's holding does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations to which QEP's operations are subject.

In December 2015, over 190 countries, including the U.S., reached an agreement in Paris (COP 21) to reduce global emissions of GHG (the Paris Agreement). The Paris Agreement provides for the cutting of carbon emissions every five years, beginning in 2023, and sets a goal of keeping global warming to a maximum limit of two degrees Celsius and a target limit of 1.5 degrees Celsius greater than pre-industrial levels. In June 2017, President Trump announced that the U.S. would initiate the formal process to withdraw from the Paris Agreement. Withdrawal will take a few years to implement due to the Paris Agreement's legal structure and language. The current state of development of ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties or domestic regulations. Following the initiation of the U.S. withdrawal from the Paris Agreement, state and local regulation efforts are expected to increase. In several of the states in which QEP operates the regulatory authorities are considering various GHG registration and reduction programs, including methane leak detection monitoring and repair requirements specific to oil and gas facilities. In addition, the failure of the federal government to address climate change concerns, including, for example, a protracted delay by President Trump's administration in determining its own carbon-cost estimate (i.e., the estimate of how much carbon pollution costs society via climate damages) after rejecting the $40 per ton of carbon dioxide equivalent estimate of the Obama administration, could afford ENGOs additional opportunities to pursue further legal challenges to oil and gas drilling and pipeline projects.

Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in precipitation and extreme weather events. In addition, warmer winters as a result of global warming could also decrease demand for natural gas. To the extent that such unfavorable weather conditions are exacerbated by climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make any estimations of future financial risk to our operations caused by these potential physical risks of climate change unreliable.

60

QEP relies on highly skilled personnel and, if QEP is unable to retain or motivate key personnel, hire qualified personnel, or transfer knowledge from retiring personnel, QEP's operations may be negatively impacted. QEP's performance largely depends on the talents and efforts of highly skilled individuals. QEP's future success depends on its continuing ability to identify, hire, develop, motivate, and retain highly skilled personnel for all areas of its organization. Competition in the oil and gas industry for qualified employees is intense. QEP's continued ability to compete effectively depends on its ability to attract new employees and to retain and motivate its existing employees. QEP does not maintain key-man insurance for its key management personnel. In connection with the announcement of its plans to divest of its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley, QEP entered into retention and severance agreements with its executives and other key management personnel. Nonetheless, the loss of services of one or more of its key management personnel could have a negative impact on QEP's financial condition and results of operations.

General economic and other conditions could negatively impact QEP's operating results. QEP's operating results may also be negatively affected by changes in global economic conditions; availability and economic viability of oil and gas properties for sale or exploration; rate of inflation and interest rates; weather and natural disasters; changes in customers' credit ratings; competition from other forms of energy and other pipeline and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; tariffs on steel and steel products used in oil and gas operations; tariffs on oil, gas and NGLs: and terrorist attacks or acts of war.

61

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, market conditions and proceeds from the asset sales. The share repurchase program does not obligate QEP to acquire any specific number of shares and may be discontinued at any time.

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, 2018 - July 31, 2018	5,755	$	11.88	—	$	1,191.6
August 1, 2018 - August 31, 2018	—	$	—	—	$	1,191.6
September 1, 2018 - September 30, 2018	175,524	$	10.52	—	$	1,191.6
Total	181,279			—

____________________________

⁽¹⁾  During the three months endedSeptember 30, 2018, QEP purchased 181,279 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.

62

ITEM 6. EXHIBITS

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

Exhibit No.	Exhibits
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, dated effective October 23, 2017 (incorporated by reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on October 25, 2017).
31.1	Certification signed by Charles B. Stanley, 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 Charles B. Stanley 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
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

** These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.

63

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)
November 7, 2018	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer
November 7, 2018	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

64

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Charles B. Stanley, 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.

November 7, 2018

/s/ Charles B. Stanley

Charles B. Stanley

Chairman, 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.

November 7, 2018

/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, 2018, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, Chairman, 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.
November 7, 2018
	/s/ Charles B. Stanley
	Charles B. Stanley
	Chairman, President and Chief Executive Officer
November 7, 2018
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer

XML

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

XML

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

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 7.3	$ (3.3)	$ (382.3)	$ 119.0
Postretirement medical plan change(1)	[1]	0.0	0.0	0.0	1.6
Fair value of plan assets adjustment(2)	[2]	0.0	0.0	0.3	0.0
Pension and other postretirement plans adjustments:
Amortization of prior service costs(3)	[3]	0.2	0.1	0.4	0.4
Amortization of actuarial losses(4)	[4]	0.1	0.1	0.5	0.2
Other comprehensive income		0.3	0.2	1.2	2.2
Comprehensive income (loss)		7.6	(3.1)	(381.1)	121.2
Postretirement medical plan changes, income tax expense		0.0	0.0	0.0	(1.0)
Amortization of prior service cost, income tax expense		0.0	(0.1)	(0.1)	(0.3)
Amortization of net actuarial loss, income tax expense		$ 0.1	$ 0.0	$ (0.1)	$ (0.1)

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

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

[3] Presented net of income tax expense of $0.1 million during the nine months ended September 30, 2018. Presented net of income tax expense of $0.1 million and $0.3 million during the three and nine months ended September 30, 2017, respectively.

[4] Presented net of income tax benefit of $0.1 million and expense of $0.1 million during the three and nine months ended September 30, 2018, respectively. Presented net of income tax expense of $0.1 million during the nine months ended September 30, 2017.

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

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

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

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CONDENSED CONSOLIDATED STATEMENT OF EQUITY (Unaudited) Statement - USD ($) shares in Millions, $ in Millions	Total		Common Stock, Value [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Other Comprehensive Income (Loss) [Member]	Total [Member]
Common Stock, Shares			243.0
Treasury Stock, Shares	(2.0)			(2.0)
Stockholders' Equity	$ 3,797.9		$ 2.4	$ (34.2)	$ 1,398.2	$ 2,442.6	$ (11.1)	$ 3,797.9
Net income (loss), Shares			0.0	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	58.4		$ (0.1)	$ 0.0	0.0	(58.3)	0.0	58.4
Share-based compensation, Shares			3.0
Share-based compensation			$ 0.1
Stock Issued During Period, Shares, Treasury Stock Reissued				(1.0)
Share-based compensation				$ (10.0)	26.4	0.0	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	[1]	$ 0.0	$ 0.0	0.0	0.0	1.2	1.2
Common Stock, Shares			239.8
Treasury Stock, Shares	(3.0)			(3.0)
Stockholders' Equity	$ 3,374.9		$ 2.4	$ (44.2)	$ 1,424.6	$ 2,002.0	$ (9.9)	$ 3,374.9

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

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

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Basis of Presentation

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation [Text Block]

Nature of Business

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

Basis of Presentation of Interim Condensed Consolidated Financial Statements

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

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

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

Reclassifications

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

Impairment of Long-Lived Assets

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

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

Cash, Cash Equivalents and Restricted Cash

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

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

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

_______________________

⁽¹⁾  As of September 30, 2018, the restricted cash balance consisted of $27.2 million related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin and is included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet. As of September 30, 2017, the restricted cash balance consisted of $59.2 million related to cash deposited into an escrow account related to the 2017 Permian Basin Acquisition (defined below) and cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin and is included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet provided within the Quarterly Report on Form 10-Q.

New Accounting Pronouncements

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

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

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

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

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

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

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

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

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

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

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Revenue Revenue

9 Months Ended

Sep. 30, 2018

Revenue Recognition [Abstract]

Revenue Recognition [Text Block]

Note 2 – Revenue

Adoption of ASC Topic 606, Revenue from Contracts with Customers

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

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

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

	Three Months Ended								Nine Months Ended
	September 30, 2018								September 30, 2018
	As Reported			ASC Topic 606 Adjustments		As Adjusted(1)			As Reported			ASC Topic 606 Adjustments		As Adjusted(1)
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	544.0		$	15.8	$	559.8		$	1,474.1		$	40.9	$	1,515.0
Other revenue	3.8			—		3.8			11.8			—		11.8
Purchased oil and gas sales	13.0			—		13.0			36.2			—		36.2
Total Revenues	560.8			15.8		576.6			1,522.1			40.9		1,563.0
OPERATING EXPENSES
Purchased oil and gas expense	13.3			—		13.3			38.6			—		38.6
Lease operating expense	64.6			—		64.6			203.6			—		203.6
Transportation and processing costs	28.0			15.8		43.8			93.2			40.9		134.1
Gathering and other expense	4.6			—		4.6			10.8			—		10.8
General and administrative	48.3			—		48.3			164.2			—		164.2
Production and property taxes	37.4			—		37.4			103.9			—		103.9
Depreciation, depletion and amortization	234.9			—		234.9			673.6			—		673.6
Exploration expenses	—			—		—			0.1			—		0.1
Impairment	—			—		—			404.4			—		404.4
Total Operating Expenses	431.1			15.8		446.9			1,692.4			40.9		1,733.3
Net gain (loss) from asset sales, inclusive of restructuring costs	27.1			—		27.1			26.7			—		26.7
OPERATING INCOME (LOSS)	156.8			—		156.8			(143.6		)	—		(143.6		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(108.0		)	—		(108.0		)	(240.3		)	—		(240.3		)
Interest and other income (expense)	(0.3		)	—		(0.3		)	(4.1		)	—		(4.1		)
Interest expense	(38.7		)	—		(38.7		)	(111.9		)	—		(111.9		)
INCOME (LOSS) BEFORE INCOME TAXES	9.8			—		9.8			(499.9		)	—		(499.9		)
Income tax (provision) benefit	(2.5		)	—		(2.5		)	117.6			—		117.6
NET INCOME (LOSS)	$	7.3		$	—	$	7.3		$	(382.3	)	$	—	$	(382.3	)
Earnings (loss) per common share
Basic	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)
Diluted	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)
Weighted-average common shares outstanding
Used in basic calculation	236.9			—		236.9			238.3			—		238.3
Used in diluted calculation	237.0			—		237.0			238.3			—		238.3

_______________________

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

Revenue Recognition

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

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

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

	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Three Months Ended September 30, 2018
Northern Region
Williston Basin	$	203.4	$	12.0	$	19.2	$	(12.3	)	$	222.3
Uinta Basin	7.3		6.8		1.4		—			15.5
Other Northern	1.1		0.5		0.1		—			1.7
Southern Region
Permian Basin	204.0		5.4		21.3		(3.5		)	227.2
Haynesville/Cotton Valley	0.2		76.9		—		—			77.1
Other Southern	0.1		0.1		—		—			0.2
Total oil and condensate, gas and NGL sales	$	416.1	$	101.7	$	42.0	$	(15.8	)	$	544.0
	Three Months Ended September 30, 2017(1)
Northern Region
Williston Basin	$	125.7	$	9.5	$	13.0	$	—		$	148.2
Pinedale	5.2		43.0		10.1		—			58.3
Uinta Basin	7.5		12.2		1.6		—			21.3
Other Northern	1.2		4.2		0.1		—			5.5
Southern Region
Permian Basin	78.1		4.5		7.3		—			89.9
Haynesville/Cotton Valley	0.3		57.2		0.1		—			57.6
Other Southern	—		0.1		—		—			0.1
Total oil and condensate, gas and NGL sales	$	218.0	$	130.7	$	32.2	$	—		$	380.9

_______________________

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

	Oil and condensate sales			Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Nine Months Ended September 30, 2018
Northern Region
Williston Basin	$	571.5		$	30.2	$	45.7	$	(32.9	)	$	614.5
Uinta Basin	25.2			24.8		4.8		—			54.8
Other Northern	3.9			1.7		—		—			5.6
Southern Region
Permian Basin	524.1			13.2		37.7		(8.0		)	567.0
Haynesville/Cotton Valley	0.8			231.2		—		—			232.0
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,125.3		$	301.5	$	88.2	$	(40.9	)	$	1,474.1
	Nine Months Ended September 30, 2017(1)
Northern Region
Williston Basin	$	416.5		$	32.5	$	34.8	$	—		$	483.8
Pinedale	18.0			154.8		30.1		—			202.9
Uinta Basin	21.8			39.1		4.3		—			65.2
Other Northern	4.0			15.0		0.3		—			19.3
Southern Region
Permian Basin	194.3			11.3		14.2		—			219.8
Haynesville/Cotton Valley	0.9			146.4		0.3		—			147.6
Other Southern	0.2			0.3		—		—			0.5
Total oil and condensate, gas and NGL sales	$	655.7		$	399.4	$	84.0	$	—		$	1,139.1

_______________________

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

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Acquisitions & Divestitures

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Acquisitions & Divestitures [Text Block]

Acquisitions

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

During the nine months endedSeptember 30, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired in 2017.

Divestitures

In February 2018, QEP's Board of Directors unanimously approved certain strategic and financial initiatives (Strategic Initiatives) including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin. As of September 30, 2018, the Company closed the sale of its Uinta Basin assets and continued to engage in discussions with potential buyers for its Williston Basin and Haynesville/Cotton Valley assets. Assets are considered held for sale once it is deemed unlikely that there will be any significant changes to QEP's divestiture plan, which QEP believes is generally upon the execution of purchase and sale agreements (refer to Note 13 – Subsequent Event for an update on the Williston Basin assets).

Uinta Basin Divestiture

In early September 2018, QEP sold its natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin for net cash proceeds of $153.0 million, subject to post-closing purchase price adjustments (the Uinta Basin Divestiture). Pursuant to signing a purchase and sale agreement for the Uinta Basin Divestiture, QEP recorded $402.8 million of proved and unproved properties impairment during the nine months endedSeptember 30, 2018 (refer to Note 1 – Basis of Presentation for more information). In addition, QEP recorded $5.5 million of estimated restructuring costs related to this divestiture during the nine months endedSeptember 30, 2018, included in "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations (refer to Note 8 – Restructuring for more information).

QEP accounted for revenues and expenses related to the Uinta Basin, including the pre-tax loss on sale of $12.4 million, during the three and nine months endedSeptember 30, 2018, as income from continuing operations on the Condensed Consolidated Statements of Operations because the Uinta Basin Divestiture did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. For the three and nine months endedSeptember 30, 2018, QEP recorded net loss before income taxes related to the divested Uinta Basin properties of $4.4 million and $419.3 million, respectively, which both include the pre-tax loss on sale of $12.4 million. The net loss before income taxes for the nine months endedSeptember 30, 2018 was primarily due to an impairment charge on proved and unproved properties of $402.8 million recognized as a result of signing the purchase and sale agreement. For the three and nine months endedSeptember 30, 2017, QEP recorded a net loss before income taxes related to the divested Uinta properties of $4.3 million and $12.8 million, respectively.

Pinedale Divestiture

In September 2017, QEP sold its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds of $718.2 million. For the nine months endedSeptember 30, 2018, QEP recorded a pre-tax gain on sale of $1.2 million, due to additional post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations. For the three and nine months endedSeptember 30, 2017, QEP had net income before income taxes related to the divested Pinedale properties of $208.2 million and $251.2 million, respectively.

As a part of the Pinedale Divestiture, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million.As of September 30, 2018, the remaining liability associated with estimated future payments for this commitment was $23.0 million, which is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses".

Other Divestitures

During the nine months endedSeptember 30, 2018, QEP received net cash proceeds of $64.5 million and recorded a net pre-tax gain on sale of $37.9 million related to the divestiture of properties outside our main operating areas.

In addition to the Pinedale Divestiture, during the nine months endedSeptember 30, 2017, QEP received net cash proceeds of $69.7 million, resulting in a net pre-tax gain on sale of $26.4 million, primarily related to the divestiture of certain non-core properties in the Other Northern area.

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

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Earnings Per Share

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

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

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. During the three and nine months endedSeptember 30, 2018 and 2017, there were no anti-dilutive shares.

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

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

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations [Text Block]

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

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

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

_______________________

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

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

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Fair Value Measurements

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

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

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

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

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

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	September 30, 2018
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	16.6	$	—	$	(2.6	)	$	14.0
Fair value of derivative contracts – long-term	—		1.2		—		(1.1		)	0.1
Total financial assets	$	—	$	17.8	$	—	$	(3.7	)	$	14.1
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	203.3	$	—	$	(2.6	)	$	200.7
Fair value of derivative contracts – long-term	—		53.7		—		(1.1		)	52.6
Total financial liabilities	$	—	$	257.0	$	—	$	(3.7	)	$	253.3
	December 31, 2017
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	20.6	$	—	$	(17.2	)	$	3.4
Fair value of derivative contracts – long-term	—		2.3		—		(2.2		)	0.1
Total financial assets	$	—	$	22.9	$	—	$	(19.4	)	$	3.5
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	120.8	$	—	$	(17.2	)	$	103.6
Fair value of derivative contracts – long-term	—		34.0		—		(2.2		)	31.8
Total financial liabilities	$	—	$	154.8	$	—	$	(19.4	)	$	135.4

_______________________

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

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

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

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

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

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

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a periodic basis, at least annually, to review its proved oil and gas properties for potential impairment when events and changes in circumstances indicate that the carrying amount of such property may not be recoverable. The fair value of property is measured utilizing the income approach and utilizing inputs that are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. Given the unobservable nature of the inputs, fair value calculations associated with proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. In addition, the signing of a purchase and sale agreement could also trigger an impairment of proved properties. For assets subject to a purchase and sale agreement, the terms of the purchase and sale agreement are used as an indicator of fair value. During the nine months endedSeptember 30, 2018, the Company recorded impairments on certain proved oil and gas properties of $397.6 million, resulting in a reduction of the associated carrying amount to fair value. During the nine months endedSeptember 30, 2017, the Company recorded no impairments on proved oil and gas properties.

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

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Derivative Contracts

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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

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

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

Derivative Contracts – Production

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

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

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

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

___________________________

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

QEP Derivative Financial Statement Presentation

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

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

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

	Three Months Ended						Nine Months Ended
Derivative contracts	September 30,						September 30,
	2018(1)			2017(2)			2018(1)			2017(2)
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(41.7	)	$	12.1		$	(138.0	)	$	21.6
Gas derivative contracts	3.3			(0.4		)	10.6			(19.7		)
Gas Storage
Gas derivative contracts	—			—			0.3			(0.2		)
Realized gains (losses) on commodity derivative contracts	(38.4		)	11.7			(127.1		)	1.7
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(60.6		)	(86.1		)	(88.1		)	88.7
Gas derivative contracts	(3.1		)	—			(18.9		)	100.5
Gas Storage
Gas derivative contracts	—			—			(0.3		)	2.3
Unrealized gains (losses) on commodity derivative contracts	(63.7		)	(86.1		)	(107.3		)	191.5
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	(102.1	)	$	(74.4	)	$	(234.4	)	$	193.2
Derivatives associated with divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(2.7	)	$	(1.3	)	$	(2.7	)	$	(1.3	)
Gas derivative contracts	—			(23.5		)	—			(23.5		)
NGL derivative contracts	(3.2		)	(5.1		)	(3.2		)	(5.1		)
Unrealized gains (losses) on commodity derivative contracts related to divestitures	$	(5.9	)	$	(29.9	)	$	(5.9	)	$	(29.9	)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(108.0	)	$	(104.3	)	$	(240.3	)	$	163.3

_______________________

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

⁽²⁾  The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

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Restructuring Costs

9 Months Ended

Sep. 30, 2018

Restructuring [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

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

Restructuring costs recognized associated with the restructuring are summarized below:

	Total recognized		Recognized in "General and administrative"		Recognized in "Net gain (loss) from asset sales, inclusive of restructuring costs"		Recognized in "Interest and other income (expense)"
	(in millions)
	Three Months Ended September 30, 2018
Termination benefits	$	6.7	$	5.3	$	1.4	$	—
Office lease termination costs	0.7		0.7		—		—
Accelerated share-based compensation	3.2		1.0		2.2		—
Retention expense	5.8		5.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	16.7	$	12.8	$	3.6	$	0.3
	Nine Months Ended September 30, 2018
Termination benefits	$	13.7	$	10.4	$	3.3	$	—
Office lease termination costs	1.0		1.0		—		—
Accelerated share-based compensation	7.2		5.0		2.2		—
Retention expense	13.8		13.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	36.0	$	30.2	$	5.5	$	0.3

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

____________________________

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

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

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

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

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Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Debt [Text Block]

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

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

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

Credit Facility

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

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

Senior Notes

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

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Commitment and Contingencies

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitment and Contingencies [Text Block]

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Condensed Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

Legal proceedings are inherently unpredictable and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter.

Landowner Litigation – In October, 2017, the owners of certain surface and mineral interests in Martin and Andrews County, Texas filed suit against QEP, alleging QEP improperly used the surface of the properties and failed to correctly pay royalties, and are seeking money damages and a declaratory judgment that portions of the oil and gas leases covering the properties are no longer in effect. The Company continues to evaluate the allegations and its defenses. The Company is unable to make an estimate of the reasonably possible loss at this early stage.

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Share-Based Compensation

9 Months Ended

Sep. 30, 2018

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

Share-Based Compensation [Text Block]

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

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

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

Stock Options

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

In 2018, to better align our long-term incentive awards with those typical of the industry, QEP did not issue stock options.

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

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

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of stock options exercised was $0.1 million during the nine months endedSeptember 30, 2018. During the nine months endedSeptember 30, 2017, there were no exercises of stock options. As of September 30, 2018, $0.6 million of unrecognized compensation expense related to stock options granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.40 years. The weighted-average vesting period may be reduced due to accelerated vestings under the restructuring program (refer to Note 8 – Restructuring for additional information).

Restricted Share Awards

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

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

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

Performance Share Units

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

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

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

Restricted Share Units

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

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

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

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Employee Benefits

9 Months Ended

Sep. 30, 2018

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

Employee Benefits [Text Block]

Pension and Other Postretirement Benefits

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

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

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

The Medical Plan is a self-insured plan. It is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired QEP employees. During the nine months endedSeptember 30, 2018, the Company made contributions of $0.2 million to its Medical Plan and does not expect to make additional contributions to its Medical Plan during the remainder of 2018. Contributions to the Medical Plan are used to fund current benefit payments.

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

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

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

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

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

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

⁽²⁾  A curtailment is recognized when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses relate to the Uinta Basin Divestiture for the three and nine months endedSeptember 30, 2018 and the Pinedale Divestiture for the three and nine months endedSeptember 30, 2017. The Uinta Basin Divestiture curtailment is recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)" for the three and nine months endedSeptember 30, 2018. The Pinedale Divestiture curtailment is recognized on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of severance costs" for the three and nine months endedSeptember 30, 2017.

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Subsequent Event (Notes)

9 Months Ended

Sep. 30, 2018

Subsequent Event [Line Items]

Subsequent Events [Text Block]

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

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Basis of Presentation Restricted Cash (Tables)

9 Months Ended

Sep. 30, 2018

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

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⁽¹⁾  As of September 30, 2018, the restricted cash balance consisted of $27.2 million related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin and is included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet. As of September 30, 2017, the restricted cash balance consisted of $59.2 million related to cash deposited into an escrow account related to the 2017 Permian Basin Acquisition (defined below) and cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin and is included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet provided within the Quarterly Report on Form 10-Q.

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Revenue (Tables)

9 Months Ended

Sep. 30, 2018

Revenue Recognition [Abstract]

Revenue Recognition 606 [Table Text Block]

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

	Three Months Ended								Nine Months Ended
	September 30, 2018								September 30, 2018
	As Reported			ASC Topic 606 Adjustments		As Adjusted(1)			As Reported			ASC Topic 606 Adjustments		As Adjusted(1)
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	544.0		$	15.8	$	559.8		$	1,474.1		$	40.9	$	1,515.0
Other revenue	3.8			—		3.8			11.8			—		11.8
Purchased oil and gas sales	13.0			—		13.0			36.2			—		36.2
Total Revenues	560.8			15.8		576.6			1,522.1			40.9		1,563.0
OPERATING EXPENSES
Purchased oil and gas expense	13.3			—		13.3			38.6			—		38.6
Lease operating expense	64.6			—		64.6			203.6			—		203.6
Transportation and processing costs	28.0			15.8		43.8			93.2			40.9		134.1
Gathering and other expense	4.6			—		4.6			10.8			—		10.8
General and administrative	48.3			—		48.3			164.2			—		164.2
Production and property taxes	37.4			—		37.4			103.9			—		103.9
Depreciation, depletion and amortization	234.9			—		234.9			673.6			—		673.6
Exploration expenses	—			—		—			0.1			—		0.1
Impairment	—			—		—			404.4			—		404.4
Total Operating Expenses	431.1			15.8		446.9			1,692.4			40.9		1,733.3
Net gain (loss) from asset sales, inclusive of restructuring costs	27.1			—		27.1			26.7			—		26.7
OPERATING INCOME (LOSS)	156.8			—		156.8			(143.6		)	—		(143.6		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(108.0		)	—		(108.0		)	(240.3		)	—		(240.3		)
Interest and other income (expense)	(0.3		)	—		(0.3		)	(4.1		)	—		(4.1		)
Interest expense	(38.7		)	—		(38.7		)	(111.9		)	—		(111.9		)
INCOME (LOSS) BEFORE INCOME TAXES	9.8			—		9.8			(499.9		)	—		(499.9		)
Income tax (provision) benefit	(2.5		)	—		(2.5		)	117.6			—		117.6
NET INCOME (LOSS)	$	7.3		$	—	$	7.3		$	(382.3	)	$	—	$	(382.3	)
Earnings (loss) per common share
Basic	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)
Diluted	$	0.03		$	—	$	0.03		$	(1.60	)	$	—	$	(1.60	)
Weighted-average common shares outstanding
Used in basic calculation	236.9			—		236.9			238.3			—		238.3
Used in diluted calculation	237.0			—		237.0			238.3			—		238.3

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

Revenue Recognition [Table Text Block]

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

	Oil and condensate sales		Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Three Months Ended September 30, 2018
Northern Region
Williston Basin	$	203.4	$	12.0	$	19.2	$	(12.3	)	$	222.3
Uinta Basin	7.3		6.8		1.4		—			15.5
Other Northern	1.1		0.5		0.1		—			1.7
Southern Region
Permian Basin	204.0		5.4		21.3		(3.5		)	227.2
Haynesville/Cotton Valley	0.2		76.9		—		—			77.1
Other Southern	0.1		0.1		—		—			0.2
Total oil and condensate, gas and NGL sales	$	416.1	$	101.7	$	42.0	$	(15.8	)	$	544.0
	Three Months Ended September 30, 2017(1)
Northern Region
Williston Basin	$	125.7	$	9.5	$	13.0	$	—		$	148.2
Pinedale	5.2		43.0		10.1		—			58.3
Uinta Basin	7.5		12.2		1.6		—			21.3
Other Northern	1.2		4.2		0.1		—			5.5
Southern Region
Permian Basin	78.1		4.5		7.3		—			89.9
Haynesville/Cotton Valley	0.3		57.2		0.1		—			57.6
Other Southern	—		0.1		—		—			0.1
Total oil and condensate, gas and NGL sales	$	218.0	$	130.7	$	32.2	$	—		$	380.9

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

	Oil and condensate sales			Gas sales		NGL sales		Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as reported
	(in millions)
	Nine Months Ended September 30, 2018
Northern Region
Williston Basin	$	571.5		$	30.2	$	45.7	$	(32.9	)	$	614.5
Uinta Basin	25.2			24.8		4.8		—			54.8
Other Northern	3.9			1.7		—		—			5.6
Southern Region
Permian Basin	524.1			13.2		37.7		(8.0		)	567.0
Haynesville/Cotton Valley	0.8			231.2		—		—			232.0
Other Southern	(0.2		)	0.4		—		—			0.2
Total oil and condensate, gas and NGL sales	$	1,125.3		$	301.5	$	88.2	$	(40.9	)	$	1,474.1
	Nine Months Ended September 30, 2017(1)
Northern Region
Williston Basin	$	416.5		$	32.5	$	34.8	$	—		$	483.8
Pinedale	18.0			154.8		30.1		—			202.9
Uinta Basin	21.8			39.1		4.3		—			65.2
Other Northern	4.0			15.0		0.3		—			19.3
Southern Region
Permian Basin	194.3			11.3		14.2		—			219.8
Haynesville/Cotton Valley	0.9			146.4		0.3		—			147.6
Other Southern	0.2			0.3		—		—			0.5
Total oil and condensate, gas and NGL sales	$	655.7		$	399.4	$	84.0	$	—		$	1,139.1

_______________________

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

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

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

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

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

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation [Abstract]

Asset retirement obligations rollforward [Table Text Block]

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

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

_______________________

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

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

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2018

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

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

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

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	September 30, 2018
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	16.6	$	—	$	(2.6	)	$	14.0
Fair value of derivative contracts – long-term	—		1.2		—		(1.1		)	0.1
Total financial assets	$	—	$	17.8	$	—	$	(3.7	)	$	14.1
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	203.3	$	—	$	(2.6	)	$	200.7
Fair value of derivative contracts – long-term	—		53.7		—		(1.1		)	52.6
Total financial liabilities	$	—	$	257.0	$	—	$	(3.7	)	$	253.3
	December 31, 2017
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	20.6	$	—	$	(17.2	)	$	3.4
Fair value of derivative contracts – long-term	—		2.3		—		(2.2		)	0.1
Total financial assets	$	—	$	22.9	$	—	$	(19.4	)	$	3.5
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	120.8	$	—	$	(17.2	)	$	103.6
Fair value of derivative contracts – long-term	—		34.0		—		(2.2		)	31.8
Total financial liabilities	$	—	$	154.8	$	—	$	(19.4	)	$	135.4

_______________________

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

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

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

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

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Derivative Contracts (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

Derivative Contracts – Production

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

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

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

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

___________________________

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

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

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

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,
	2018(1)			2017(2)			2018(1)			2017(2)
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(41.7	)	$	12.1		$	(138.0	)	$	21.6
Gas derivative contracts	3.3			(0.4		)	10.6			(19.7		)
Gas Storage
Gas derivative contracts	—			—			0.3			(0.2		)
Realized gains (losses) on commodity derivative contracts	(38.4		)	11.7			(127.1		)	1.7
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(60.6		)	(86.1		)	(88.1		)	88.7
Gas derivative contracts	(3.1		)	—			(18.9		)	100.5
Gas Storage
Gas derivative contracts	—			—			(0.3		)	2.3
Unrealized gains (losses) on commodity derivative contracts	(63.7		)	(86.1		)	(107.3		)	191.5
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage	$	(102.1	)	$	(74.4	)	$	(234.4	)	$	193.2
Derivatives associated with divestitures
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(2.7	)	$	(1.3	)	$	(2.7	)	$	(1.3	)
Gas derivative contracts	—			(23.5		)	—			(23.5		)
NGL derivative contracts	(3.2		)	(5.1		)	(3.2		)	(5.1		)
Unrealized gains (losses) on commodity derivative contracts related to divestitures	$	(5.9	)	$	(29.9	)	$	(5.9	)	$	(29.9	)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(108.0	)	$	(104.3	)	$	(240.3	)	$	163.3

_______________________

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

⁽²⁾  The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Condensed Consolidated Statements of Operations.

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Restructuring Costs Restructuring Costs (Tables)

9 Months Ended

Sep. 30, 2018

Restructuring and Related Activities [Abstract]

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

Restructuring costs recognized associated with the restructuring are summarized below:

	Total recognized		Recognized in "General and administrative"		Recognized in "Net gain (loss) from asset sales, inclusive of restructuring costs"		Recognized in "Interest and other income (expense)"
	(in millions)
	Three Months Ended September 30, 2018
Termination benefits	$	6.7	$	5.3	$	1.4	$	—
Office lease termination costs	0.7		0.7		—		—
Accelerated share-based compensation	3.2		1.0		2.2		—
Retention expense	5.8		5.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	16.7	$	12.8	$	3.6	$	0.3
	Nine Months Ended September 30, 2018
Termination benefits	$	13.7	$	10.4	$	3.3	$	—
Office lease termination costs	1.0		1.0		—		—
Accelerated share-based compensation	7.2		5.0		2.2		—
Retention expense	13.8		13.8		—		—
Pension curtailment	0.3		—		—		0.3
Total restructuring costs	$	36.0	$	30.2	$	5.5	$	0.3

Restructuring Costs [Table Text Block]

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

____________________________

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

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

Restructuring Costs, Liability [Table Text Block]

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

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

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Debt (Tables)

9 Months Ended

Sep. 30, 2018

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

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2018

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

Share-based Compensation Expense [Table Text Block]

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

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

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

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

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

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

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

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

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

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

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

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

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

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Employee Benefits (Tables)

9 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

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

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

____________________________

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

⁽²⁾  A curtailment is recognized when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses relate to the Uinta Basin Divestiture for the three and nine months endedSeptember 30, 2018 and the Pinedale Divestiture for the three and nine months endedSeptember 30, 2017. The Uinta Basin Divestiture curtailment is recognized on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)" for the three and nine months endedSeptember 30, 2018. The Pinedale Divestiture curtailment is recognized on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales, inclusive of severance costs" for the three and nine months endedSeptember 30, 2017.

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

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Basis of Presentation Restricted Cash (Details) - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents		$ 0.0	$ 0.0	$ 782.6
Restricted cash(1)	[1]	27.2		59.2
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows		27.2	$ 23.4	841.8	$ 465.4
Long-term [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash(1)		$ 27.2		$ 59.2

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

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

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

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

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Acquisitions & Divestitures Uinta Basin (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			$ 217.5	$ 787.9
Impairment of Oil and Gas Properties			404.4
Noncurrent assets held for sale	$ 0.0		0.0		$ 632.8
Gain (Loss) on Disposition of Oil and Gas Property	27.1	$ 185.4	26.7	205.2
Uinta Basin Divestiture [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			153.0
Impairment of Oil and Gas Properties			402.8
Gain (Loss) on Disposition of Oil and Gas Property			(12.4)
Results of Operations, Loss before Income Taxes	$ (4.4)	$ (4.3)	(419.3)	$ (12.8)
Restructuring Charges			$ 5.5

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

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

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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, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	0.0	0.0	0.0	0.0
Weighted-average basic common shares outstanding	236.9	240.7	238.3	240.5
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	0.1	0.0	0.0	0.0
Average diluted common shares outstanding	237.0	240.7	238.3	240.5

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Earnings Per Share Earnings per share (non-printing) (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share [Abstract]
Anti-dilutive shares	0.0	0.0	0.0	0.0

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

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Fair Value Measurements Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions		Sep. 30, 2018	Dec. 31, 2017
Financial Assets
Derivative Asset, Netting Adjustments	[1]	$ (3.7)	$ (19.4)
Derivative Asset, Net		14.1	3.5
Financial liabilities
Derivative Liability, Netting Adjustments	[1]	(3.7)	(19.4)
Derivative Liability, Net		253.3	135.4
Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		17.8	22.9
Financial liabilities
Derivative Liability, Fair Value, Gross		257.0	154.8
Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Short-term [Member]
Financial Assets
Derivative Asset, Netting Adjustments	[1]	(2.6)	(17.2)
Derivative Asset, Net		14.0	3.4
Financial liabilities
Derivative Liability, Netting Adjustments	[1]	(2.6)	(17.2)
Derivative Liability, Net		200.7	103.6
Short-term [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Short-term [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		16.6	20.6
Financial liabilities
Derivative Liability, Fair Value, Gross		203.3	120.8
Short-term [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Long-term [Member]
Financial Assets
Derivative Asset, Netting Adjustments	[1]	(1.1)	(2.2)
Derivative Asset, Net		0.1	0.1
Financial liabilities
Derivative Liability, Netting Adjustments	[1]	(1.1)	(2.2)
Derivative Liability, Net		52.6	31.8
Long-term [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Long-term [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		1.2	2.3
Financial liabilities
Derivative Liability, Fair Value, Gross		53.7	34.0
Long-term [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		$ 0.0	$ 0.0

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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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, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested balance at beginning of period	21,946
Shares granted	31,835
Shares vested	(11,106)
Unvested balance at end of period	42,675
Weighted average grant date fair value, beginning of period	$ 13.22
Weighted average grant date fair value, grants	9.55	$ 16.98
Weighted average grant date fair value, vested	13.27
Weighted average grant date fair value, end of period	$ 10.47

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

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Employee Benefits Schedule of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension Plan and SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost		$ 0.2	$ 0.2	$ 0.6	$ 0.6
Interest cost		1.2	1.2	3.4	3.6
Expected return on plan assets		(1.4)	(1.3)	(4.3)	(4.0)
Amortization of prior service costs(1)	[1]	0.2	0.3	0.6	0.9
Amortization of actuarial losses(1)	[1]	0.0	0.1	0.6	0.3
Curtailment loss(2)	[2]	0.3	0.7	0.3	0.7
Periodic expense		0.5	(1.2)	(1.2)	(2.1)
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Interest cost		0.0	0.0	0.1	0.1
Amortization of prior service costs(1)	[1]	(0.1)	(0.1)	(0.2)	(0.2)
Periodic expense		$ 0.1	$ 0.1	$ 0.1	$ 0.1

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

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

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