Document

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 March 31, 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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post 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 (Do not check if a smaller reporting company)	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 March 31, 2018, there were 237,708,346 shares of the registrant's common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended March 31, 2018

TABLE OF CONTENTS



			Page
PART I. FINANCIAL INFORMATION			2

	ITEM 1.	FINANCIAL STATEMENTS	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2018 AND 2017	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE MONTHS ENDED MARCH 31, 2018 AND 2017	3

		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT MARCH 31, 2018 AND DECEMBER 31, 2017	4

		UNAUDITED CONDENSED CONOSLIDATED STATEMENT OF EQUITY FOR THE THREE MONTHS ENDED MARCH 31, 2018	5

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 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	23

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41

	ITEM 4.	CONTROLS AND PROCEDURES	45

PART II. OTHER INFORMATION			45

	ITEM 1.	LEGAL PROCEEDINGS	45

	ITEM 1A.	RISK FACTORS	45

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	47

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	47

	ITEM 4.	MINE SAFETY DISCLOSURES	47

	ITEM 5.	OTHER INFORMATION	47

	ITEM 6.	EXHIBITS	48

SIGNATURES			49

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended
	March 31,
	2018			2017
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	409.8		$	385.2
Other revenue	5.0			4.0
Purchased oil and gas sales	14.1			30.9
Total Revenues	428.9			420.1
OPERATING EXPENSES
Purchased oil and gas expense	15.5			29.4
Lease operating expense	72.5			69.2
Transportation and processing costs	34.0			70.2
Gathering and other expense	2.8			1.5
General and administrative	60.1			33.6
Production and property taxes	28.9			29.1
Depreciation, depletion and amortization	196.5			191.8
Exploration expenses	—			0.4
Impairment	0.7			0.1
Total Operating Expenses	411.0			425.3
Net gain (loss) from asset sales	3.5			—
OPERATING INCOME (LOSS)	21.4			(5.2		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(53.2		)	160.9
Interest and other income (expense)	(0.7		)	0.6
Interest expense	(35.0		)	(33.8		)
INCOME (LOSS) BEFORE INCOME TAXES	(67.5		)	122.5
Income tax (provision) benefit	13.9			(45.6		)
NET INCOME (LOSS)	$	(53.6	)	$	76.9

Earnings (loss) per common share
Basic	$	(0.22	)	$	0.32
Diluted	$	(0.22	)	$	0.32

Weighted-average common shares outstanding
Used in basic calculation	240.9			240.2
Used in diluted calculation	240.9			240.3
Dividends per common share	$	—		$	—

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended
	March 31,
	2018			2017
	(in millions)
Net income (loss)	$	(53.6	)	$	76.9
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⁾	0.1			0.1
Amortization of actuarial losses⁽⁴⁾	0.2			0.2
Other comprehensive income	0.6			1.9
Comprehensive income (loss)	$	(53.0	)	$	78.8

____________________________


⁽¹⁾	Presented net of income tax expense of $1.0 million for the three months ended March 31, 2017.


⁽²⁾	Adjustment recorded during the three months ended March 31, 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 for the three months ended March 31, 2017.


⁽⁴⁾	Presented net of income tax expense of $0.1 million for the three months ended March 31, 2018 and 2017, respectively.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2018			December 31, 2017
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	—		$	—
Accounts receivable, net	130.2			142.1
Income tax receivable	4.7			4.9
Fair value of derivative contracts	3.2			3.4
Hydrocarbon inventories, at lower of average cost or net realizable value	2.1			3.6
Prepaid expenses	9.4			10.7
Other current assets	0.2			0.7
Total Current Assets	149.8			165.4
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	12,676.1			12,470.9
Unproved properties	1,073.7			1,095.8
Gathering and other	383.4			319.7
Materials and supplies	38.4			37.8
Total Property, Plant and Equipment	14,171.6			13,924.2
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,660.8			6,642.9
Gathering and other	130.6			124.3
Total Accumulated Depreciation, Depletion and Amortization	6,791.4			6,767.2
Net Property, Plant and Equipment	7,380.2			7,157.0
Fair value of derivative contracts	4.5			0.1
Other noncurrent assets	74.1			72.3
TOTAL ASSETS	$	7,608.6		$	7,394.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	19.8		$	44.0
Accounts payable and accrued expenses	400.9			364.6
Production and property taxes	31.9			31.6
Interest payable	33.4			26.0
Fair value of derivative contracts	116.9			103.6
Asset retirement obligations	10.1			7.5
Total Current Liabilities	613.0			577.3
Long-term debt	2,458.1			2,160.8
Deferred income taxes	504.0			518.0
Asset retirement obligations	200.4			206.6
Fair value of derivative contracts	32.8			31.8
Other long-term liabilities	103.6			102.4
Commitments and contingencies (Note 10)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 240.3 million and 243.0 million shares issued, respectively	2.4			2.4
Treasury stock – 2.6 million and 2.0 million shares, respectively	(39.5		)	(34.2		)
Additional paid-in capital	1,408.0			1,398.2
Retained earnings	2,336.3			2,442.6
Accumulated other comprehensive income (loss)	(10.5		)	(11.1		)
Total Common Shareholders' Equity	3,696.7			3,797.9
TOTAL LIABILITIES AND EQUITY	$	7,608.6		$	7,394.8

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

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			Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income(Loss)			Total
	(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)	—		—			—		—			—		(53.6		)	—			(53.6		)
Common stock repurchased and retired	(5.6	)	(0.1		)	—		—			—		(52.7		)	—			(52.8		)
Share-based compensation	2.9		0.1			(0.6	)	(5.3		)	9.8		—			—			4.6
Change in pension and postretirement liability, net of tax	—		—			—		—			—		—			0.6			0.6
Balance at March 31, 2018	240.3		$	2.4		(2.6	)	$	(39.5	)	$	1,408.0	$	2,336.3		$	(10.5	)	$	3,696.7

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended
	March 31,
	2018			2017
OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	(53.6	)	$	76.9
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	196.5			191.8
Deferred income taxes (benefit)	(14.1		)	45.6
Impairment	0.7			0.1
Share-based compensation	11.2			6.0
Amortization of debt issuance costs and discounts	1.3			1.5
Bargain purchase gain from acquisition	—			0.4
Net (gain) loss from asset sales	(3.5		)	—
Unrealized (gains) losses on marketable securities	0.1			(0.8		)
Unrealized (gains) losses on derivative contracts	10.0			(177.3		)
Changes in operating assets and liabilities	11.8			5.7
Net Cash Provided by (Used in) Operating Activities	160.4			149.9
INVESTING ACTIVITIES
Property acquisitions	(36.2		)	(68.2		)
Property, plant and equipment, including exploratory well expense	(370.7		)	(177.3		)
Proceeds from disposition of assets	33.3			0.2
Net Cash Provided by (Used in) Investing Activities	(373.6		)	(245.3		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(24.2		)	(3.1		)
Proceeds from credit facility	1,068.5			—
Repayments of credit facility	(772.5		)	—
Common stock repurchased and retired	(52.8		)	—
Treasury stock repurchases	(4.7		)	(6.4		)
Net Cash Provided by (Used in) Financing Activities	214.3			(9.5		)
Change in cash, cash equivalents and restricted cash	1.1			(104.9		)
Beginning cash, cash equivalents and restricted cash⁽¹⁾	23.4			465.4
Ending cash, cash equivalents and restricted cash⁽¹⁾	$	24.5		$	360.5

Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	26.0		$	32.3
Cash paid for income taxes, net	$	—		$	—
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$	48.1		$	37.0

____________________________


⁽¹⁾	Refer to New Accounting Pronouncements in Note 1 – Basis of Presentation.

Refer to Notes accompanying the Condensed Consolidated Financial Statements.

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 and Utah). 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 months ended March 31, 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 Statements of Cash Flows have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share or retained earnings previously reported.

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:



	March 31,
	2018		2017
	(in millions)
Cash and cash equivalents	$	—	$	338.4
Restricted cash⁽¹⁾	24.5		22.1
Total cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	24.5	$	360.5

_______________________

⁽¹⁾

As of March 31, 2018, the restricted cash balance consisted of $24.5 million included within "Other noncurrent assets" on the Condensed Consolidated Balance Sheet. As of March 31, 2017, the restricted cash balance consisted of $20.9 million included within "Other noncurrent assets" and $1.2 million included within "Prepaid expenses" on the Condensed Consolidated Balance Sheet provided within the Quarterly Report on Form 10-Q. QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin.

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 are 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 has 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 is 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. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

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 of this new standard 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 of this standard 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.

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 Statement 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 Statement 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 Statement of Operations as a result of adopting ASC Topic 606.



	Three Months Ended
	March 31, 2018
	As Reported			ASC 606 Adjustments		As Adjusted⁽¹⁾
REVENUES	(in millions, except per share amounts)
Oil and condensate, gas and NGL sales	$	409.8		$	12.7	$	422.5
Other revenue	5.0			—		5.0
Purchased oil and gas sales	14.1			—		14.1
Total Revenues	428.9			12.7		441.6
OPERATING EXPENSES
Purchased oil and gas expense	15.5			—		15.5
Lease operating expense	72.5			—		72.5
Transportation and processing costs	34.0			12.7		46.7
Gathering and other expense	2.8			—		2.8
General and administrative	60.1			—		60.1
Production and property taxes	28.9			—		28.9
Depreciation, depletion and amortization	196.5			—		196.5
Exploration expenses	—			—		—
Impairment	0.7			—		0.7
Total Operating Expenses	411.0			12.7		423.7
Net gain (loss) from asset sales	3.5			—		3.5
OPERATING INCOME (LOSS)	21.4			—		21.4
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(53.2		)	—		(53.2		)
Interest and other income (expense)	(0.7		)	—		(0.7		)
Interest expense	(35.0		)	—		(35.0		)
INCOME (LOSS) BEFORE INCOME TAXES	(67.5		)	—		(67.5		)
Income tax (provision) benefit	13.9			—		13.9
NET INCOME (LOSS)	$	(53.6	)	$	—	$	(53.6	)

Earnings (loss) per common share
Basic	$	(0.22	)	$	—	$	(0.22	)
Diluted	$	(0.22	)	$	—	$	(0.22	)

Weighted-average common shares outstanding
Used in basic calculation	240.9			—		240.9
Used in diluted calculation	240.9			—		240.9
Dividends per common share	$	—		$	—	$	—

_______________________


⁽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 variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. 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 sold under a limited number of contract types that are also 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 current 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 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 606.



	Oil and condensate sales			Gas sales		NGL sales			Transportation and processing costs included in revenue			Oil and condensate, gas and NGL sales, as presented
	(in millions)
	Three Months Ended March 31, 2018
Northern Region
Williston Basin	$	160.5		$	9.8	$	11.8		$	(9.9	)	$	172.2
Uinta Basin	8.4			10.1		1.7			—			20.2
Other Northern	1.9			1.0		(0.2		)	—			2.7
Southern Region
Permian Basin	129.8			4.6		6.5			(2.8		)	138.1
Haynesville/Cotton Valley	0.4			76.4		—			—			76.8
Other Southern	(0.3		)	0.1		—			—			(0.2		)
Total oil and condensate, gas and NGL sales	$	300.7		$	102.0	$	19.8		$	(12.7	)	$	409.8

	Three Months Ended March 31, 2017⁽¹⁾
Northern Region
Williston Basin	$	155.4		$	12.0	$	12.5		$	—		$	179.9
Pinedale	6.8			60.6		11.6			—			79.0
Uinta Basin	7.4			14.6		1.6			—			23.6
Other Northern	1.4			5.9		0.1			—			7.4
Southern Region
Permian Basin	50.2			3.2		3.1			—			56.5
Haynesville/Cotton Valley	0.4			38.2		0.1			—			38.7
Other Southern	0.1			—		—			—			0.1
Total oil and condensate, gas and NGL sales	$	221.7		$	134.5	$	29.0		$	—		$	385.2

_______________________


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

Note 3 – Acquisitions and Divestitures

Acquisitions

During the three months ended March 31, 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 $36.2 million, subject to customary purchase price adjustments. Of the $36.2 million, $35.7 million was related to acquisitions from various persons who 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 three months ended March 31, 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 $68.2 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired in 2017.

2018 Strategic Initiatives

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 a part of this process, in February 2018, the Company engaged advisors to assist with the divestitures of its Williston Basin and Uinta Basin assets and has provided data for potential buyers in April 2018. The assets will be considered held for sale once it is deemed unlikely that there will be any significant changes to QEP's divestiture plan, which QEP believes will be upon the execution of purchase and sale agreements.

Pinedale Divestiture

In September 2017, QEP sold its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to additional post-closing purchase price adjustments. For the three months ended March 31, 2018, QEP recorded a pre-tax gain on sale of $1.0 million, due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations. For the three months ended March 31, 2017, QEP had net income before income taxes related to the divested Pinedale properties of $28.0 million.

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 March 31, 2018, the liability associated with estimated future payments for this commitment was $27.3 million, of which $22.9 million is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses" and $4.4 million is reported on the Condensed Consolidated Balance Sheets within "Other long-term liabilities".

Other Divestitures

During the three months ended March 31, 2018, QEP received proceeds of $33.3 million and recorded a pre-tax gain on sale of $2.5 million, primarily related to the divestiture of properties outside our main operating areas in the Williston Basin and Other Northern area.

The gains and losses were recorded within "Net gain (loss) from asset sales" 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 months ended March 31, 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
	March 31,
	2018	2017
	(in millions)
Weighted-average basic common shares outstanding	240.9	240.2
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	240.9	240.3

Note 5 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $210.5 million and $214.1 million ARO liability for the periods ended March 31, 2018 and December 31, 2017, respectively, $10.1 million and $7.5 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
	2018
	(in millions)
ARO liability at January 1,	$	214.1
Accretion	1.7
Additions	1.5
Revisions	(3.4		)
Liabilities related to assets sold	(3.4		)
ARO liability at March 31,	$	210.5

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.

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



	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
	March 31, 2018
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	16.3	$	—	$	(13.1	)	$	3.2
Fair value of derivative contracts – long-term	—		8.1		—		(3.6		)	4.5
Total financial assets	$	—	$	24.4	$	—	$	(16.7	)	$	7.7

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	130.0	$	—	$	(13.1	)	$	116.9
Fair value of derivative contracts – long-term	—		36.4		—		(3.6		)	32.8
Total financial liabilities	$	—	$	166.4	$	—	$	(16.7	)	$	149.7

	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
	March 31, 2018				December 31, 2017
Financial Assets	(in millions)
Cash and cash equivalents	$	—	$	—	$	—	$	—
Financial Liabilities
Checks outstanding in excess of cash balances	$	19.8	$	19.8	$	44.0	$	44.0
Long-term debt	$	2,458.1	$	2,456.7	$	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.

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 to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. 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. During the three months ended March 31, 2018, the Company recorded impairments on certain proved oil and gas properties of $0.5 million, resulting in a reduction of the associated carrying amount to fair value. During the three months ended March 31, 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 may enter 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 or oil price swaps that use Intercontinental Exchange, Inc. (ICE) Brent oil prices as the reference price. Gas price derivative instruments are typically structured as fixed-price swaps or collars at NYMEX Henry Hub or regional price indices. QEP also enters into oil 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 March 31, 2018:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2018 (April through December)	NYMEX WTI	12.7	$	52.48
2019	NYMEX WTI	9.5	$	52.66
Gas sales		(MMBtu)	($/MMBtu)
2018 (April through December)	NYMEX HH	82.5	$	2.99
2018 (July through December)	NYMEX HH	1.8	$	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 March 31, 2018:



Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2018 (April through December)	NYMEX WTI	Argus WTI Midland	5.5	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.9	$	(0.71	)
2019	NYMEX WTI	Argus WTI Midland	4.7	$	(0.77	)
Gas sales			(MMBtu)	($/MMBtu)
2018 (April through December)	NYMEX HH	IFNPCR	5.5	$	(0.16	)

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	March 31, 2018		December 31, 2017		March 31, 2018		December 31, 2017
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	16.3	$	20.6	$	130.0	$	120.8
Long-term:
Commodity	Fair value of derivative contracts	8.1		2.3		36.4		34.0
Total derivative instruments		$	24.4	$	22.9	$	166.4	$	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
Derivative contracts not designated as cash flow hedges	March 31,
	2018			2017
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(44.3	)	$	(2.0	)
Gas derivative contracts	0.9			(14.2		)
Gas Storage
Gas derivative contracts	0.2			(0.2		)
Realized gains (losses) on commodity derivative contracts	(43.2		)	(16.4		)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(6.9		)	104.3
Gas derivative contracts	(2.8		)	71.1
Gas Storage
Gas derivative contracts	(0.3		)	1.9
Unrealized gains (losses) on commodity derivative contracts	(10.0		)	177.3
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(53.2	)	$	160.9

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 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. During the first quarter of 2018, the Company incurred but has not yet paid $6.2 million of costs associated with these termination benefits, including $3.4 million of severance and $2.8 million of accelerated share-based compensation, recorded in "Accounts payable and accrued expenses" and "General and administrative" expense in the Condensed Consolidated Financial Statements. Due to the nature of the Strategic Initiatives and uncertain factors such as 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.

In connection with the Strategic Initiatives, QEP also approved an employee retention program and recognized $1.7 million of expense during the three months ended March 31, 2018 and recorded these costs in "Accounts payable and accrued expenses" and "General and administrative" expense in the Condensed Consolidated Financial Statements. QEP expects to incur an additional $18.3 million of expense in 2018 and $5.0 million in 2019 related to the retention program.

Note 9 – Debt

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



	March 31, 2018			December 31, 2017
	(in millions)
Revolving Credit Facility due 2022	$	385.0		$	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	(26.2		)	(27.5		)
Total long-term debt outstanding	$	2,458.1		$	2,160.8

Of the total debt outstanding on March 31, 2018, the 6.80% Senior Notes due March 1, 2020, the 6.875% Senior Notes due March 1, 2021 and the 5.375% Senior Notes due October 1, 2022, 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 March 31, 2018 and December 31, 2017, QEP was in compliance with the covenants under the credit agreement.

During the three months ended March 31, 2018, QEP's weighted-average interest rates on borrowings from its credit facility were 3.75%. As of March 31, 2018, QEP had $385.0 million of borrowings outstanding and $1.0 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 March 31, 2018, the Company had $2,099.3 million 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

QEP issues stock options, restricted share awards and restricted share units under its Long-Term Stock Incentive Plan (LTSIP) and awards performance share units under its Cash Incentive Plan (CIP) to certain officers, employees and non-employee directors. QEP recognizes the expense over the vesting periods for the stock options, restricted share awards, restricted share units and performance share units. There were 2.4 million shares available for future grants under the LTSIP at March 31, 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 months ended March 31, 2018, the Company recorded an additional $2.8 million of share-based compensation expense related to the acceleration of vesting incurred as part of the severance program (refer to Note 8 – Restructuring for additional information):



	Three Months Ended
	March 31,
	2018		2017
	(in millions)
Stock options	$	0.5	$	0.6
Restricted share awards	8.8		7.3
Performance share units	1.9		(1.9		)
Restricted share units	—		—
Total share-based compensation expense	$	11.2	$	6.0

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 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, QEP did not issue stock options as the Company continues to evaluate the components of its incentive compensation package to better align our Long-Term Incentive awards with those typical of the industry.

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
Canceled	(202,235	)	39.07
Outstanding at March 31, 2018	2,152,042		$	22.17	3.56	$	—
Options Exercisable at March 31, 2018	1,743,963		$	23.96	3.10	$	—
Unvested Options at March 31, 2018	408,079		$	14.51	5.56	$	—

During the three months ended March 31, 2018 and 2017, there were no exercises of stock options. As of March 31, 2018, $1.1 million of unrecognized compensation expense related to stock options granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.87 years. The weighted-average vesting period may be reduced under the severance 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 three months ended March 31, 2018 and 2017 was $21.0 million and $20.3 million, respectively. The weighted-average grant date fair value of restricted share awards was $9.55 per share and $17.02 per share for the three months ended March 31, 2018 and 2017, respectively. As of March 31, 2018, $37.4 million of unrecognized compensation expense related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.59 years. The weighted-average vesting period may be reduced under the severance program (refer to Note 8 – Restructuring for additional information).

Transactions involving restricted share awards under the terms of the LTSIP 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	2,929,369		9.55
Vested	(1,414,155	)	14.83
Forfeited	(86,386	)	11.31
Unvested balance at March 31, 2018	5,150,162		$	10.73

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 LTSIP; however, as of March 31, 2018, the Company expects to settle all awards in cash. 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 $16.98 per share for the three months ended March 31, 2018 and 2017, respectively. As of March 31, 2018, $10.1 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 2.39 years. The weighted-average vesting period may be reduced under the severance 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 and Paid	(229,620	)	21.69
Unvested balance at March 31, 2018	1,693,811		$	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 three months ended March 31, 2018 and 2017, respectively. As of March 31, 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 2.00 years. The weighted-average vesting period may be reduced under the severance 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	(9,320	)	12.56
Unvested balance at March 31, 2018	44,461		$	10.73

Note 12 – Employee Benefits

Pension and Other Postretirement Benefits

The Company provides pension and other postretirement benefits to certain employees through three retirement 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 three months ended March 31, 2018, the Company made contributions of $2.0 million to the Pension Plan and expects to make an additional $2.0 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 three months ended March 31, 2018, the Company made contributions of $0.2 million to its SERP and expects to contribute an additional $0.5 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 three months ended March 31, 2018, the Company made contributions of $0.1 million to its Medical Plan and expects to contribute an additional $0.1 million 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 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
	March 31,
	2018			2017
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.2		$	0.3
Interest cost	1.1			1.2
Expected return on plan assets	(1.4		)	(1.3		)
Amortization of prior service costs⁽¹⁾	0.2			0.3
Amortization of actuarial losses⁽¹⁾	0.3			0.3
Periodic expense	$	0.4		$	0.8

Medical Plan benefits
Amortization of prior service costs⁽¹⁾	(0.1		)	(0.1		)
Periodic expense	$	(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)".

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 months ended March 31, 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

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 a part of this process, in February 2018, the Company engaged advisors to assist with the divestitures of its Williston Basin and Uinta Basin assets and has provided data for potential buyers in April 2018. The Company expects to have these asset sales completed during the second half of 2018. 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.

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

Since the commodity price downturn in late 2014, the Company has focused on operating costs, per well drilling costs and managing its liquidity while continuing its 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 $1,120.0 million, a decrease of approximately 8% 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 make adjustments to 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, the Company continues to evaluate and acquire properties in the Permian Basin to add additional development opportunities and facilitate the drilling of long lateral wells. As part of the Company's plan to focus its operations in the Permian Basin, the Company has engaged advisors to assist in divesting its Williston and Uinta basin assets.

Acquisitions

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. In addition, QEP has made offers to various persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the original purchase. During the three months ended March 31, 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 $36.2 million, subject to customary purchase price adjustments. Of the $36.2 million, $35.7 million was related to the 2017 Permian Basin Acquisition. If all remaining offers are accepted, QEP now expects that the aggregate purchase price will not exceed $10.5 million, and these transactions are expected to be funded with borrowings under the credit facility and are expected to close in the second quarter of 2018.

Divestitures

In September 2017, QEP sold its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments. For the three months ended March 31, 2018, QEP recorded a pre-tax gain on sale of $1.0 million, which was recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations related to additional post-closing purchase price adjustments. 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" 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 March 31, 2018, the liability associated with estimated future payments for this commitment was $27.3 million.

In addition to the $1.0 million gain on sale related to the Pinedale Divestiture, during the three months ended March 31, 2018, QEP received proceeds of $33.3 million and recorded a pre-tax gain on sale of $2.5 million, primarily related to the divestiture of properties in the Williston Basin and in the Other Northern area.

Financial and Operating Results

During the three months ended March 31, 2018, QEP:


•	Delivered oil and condensate production of 5.0 MMbbls, including a record 2.2 MMbbls in the Permian Basin;


•	Increased gas production in Haynesville/Cotton Valley to 25.7 Bcf, a 111% increase over 2017 volumes, primarily due to a successful refracturing program and initiation of a drilling program;


•	Reported realized oil prices of $51.54 per bbl, a 10% increase over 2017, realized gas prices of $2.94 per Mcf, a 4% increase over 2017 and realized NGL prices of $21.99 per bbl, a 3% increase over 2017;


•	Repurchased and retired 5.6 million shares of the Company's outstanding shares of common stock for $52.8 million;


•	Generated a net loss of $53.6 million, or $0.22 per diluted share; and


•	Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $171.9 million, a 1% 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.

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 $110.62 per barrel in September 2013. 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.

NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient domestic demand and export capacity. Prices of heavier NGL components, typically correlated to oil prices, have declined in concert with weakening oil prices. Concurrently, the lighter NGL components, ethane and propane, have experienced declines as a result of growing North American oversupply. In addition to commodity price movements, QEP's composite NGL prices are affected by ethane recovery or rejection. When ethane is recovered as a discrete NGL component instead of being sold as part of the natural gas stream, the average sales price of a NGL barrel decreases as the ethane price is generally lower than the prices of the remaining NGL components. As permitted in some of its processing agreements, QEP recovers ethane when gas processing economics support the recovery of ethane from the natural gas stream. When gas processing economics do not support ethane recovery, and processing agreements permit it to do so, QEP elects to reject ethane from the NGL stream.

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. In December 2015, the U.S. lifted a 40-year ban on the export of oil, giving U.S. producers access to a wider market. As a result, the U.S. may in the future become a significant exporter of oil if the necessary infrastructure is built to support oil exports. 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 March 31, 2018, QEP forecasted its 2018 annual production to be approximately 50.1 MMboe and had approximately 76% of its forecasted oil production and 78% of its forecasted gas production covered with fixed-price swaps and collars. 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.

If forward oil prices decline from March 31, 2018 levels or we experience negative changes in estimated reserve quantities or we enter into purchase and sale agreements for less than net book value, we have proved and unproved property with a net book value of approximately $3.3 billion at risk for impairment, primarily associated with our Williston Basin and Uinta Basin fields as of March 31, 2018. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, the additional risk-adjusted value of probable and possible reserves associated with the properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.

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.

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 March 31, 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	1	1	0.5	10	9.6	—	—	8	0.1
Uinta Basin	—	—	—	—	—	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—	—
Southern Region
Permian Basin⁽¹⁾	6	20	19.6	38	37.1	—	—	—	—
Haynesville/Cotton Valley	1	2	2.0	—	—	3	0.2	12	0.4
Other Southern	—	—	—	—	—	—	—	—	—

____________________________


⁽¹⁾	The gross operated drilling well count in the Permian Basin includes nine wells for which surface casing has been set, but as of March 31, 2018, did not have a rig drilling.

Each gross well completed in more than one producing zone is counted as a single well. 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. 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 48 gross operated wells waiting on completion as of March 31, 2018.

The following table presents the number of operated and non-operated wells completed and turned to sales (put on production) for the three months ended March 31, 2018:



	Operated Put on Production		Non-operated Put on Production
	Three Months Ended		Three Months Ended
	March 31, 2018		March 31, 2018
	Gross	Net	Gross	Net
Northern Region
Williston Basin	—	—	—	—
Uinta Basin	2	2.0	—	—
Other Northern	—	—	—	—
Southern Region
Permian Basin	31	31.0	—	—
Haynesville/Cotton Valley	2	2.0	6	0.6
Other Southern	—	—	—	—

The following table presents the number of operated wells in the process of being drilled or waiting on completion at March 31, 2018 and operated wells completed and turned to sales (put on production) for the three months ended March 31, 2018:



	Permian Basin		Williston Basin		Haynesville/Cotton Valley		Uinta Basin
	As of March 31, 2018
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Well Progress
Drilling	20	19.6	1	0.5	2	2.0	—	—

At total depth - under drilling rig	8	7.7	5	5.0	—	—	—	—
Waiting to be completed	15	14.4	2	2.0	—	—	—	—
Undergoing completion	6	6.0	2	2.0	—	—	—	—
Completed, awaiting production	9	9.0	1	1.0	—	—	—	—
Waiting on completion	38	37.1	10	10.0	—	—	—	—

Put on production	31	31.0	—	—	2	2.0	2	2.0

RESULTS OF OPERATIONS

Net Income

QEP generated a net loss during the first quarter of 2018 of $53.6 million, or $0.22 per diluted share, compared to a net income of $76.9 million, or $0.32 per diluted share, in the first quarter of 2017. QEP's net loss was primarily due to a $187.3 million increase in unrealized derivative losses, a $26.5 million increase in general and administrative expenses and a 10% decrease in oil equivalent production, primarily due to the Pinedale Divestiture. These decreases were partially offset by a 15% increase in average realized oil equivalent prices, a $59.5 million increase in income tax benefit and a $23.5 million decrease in adjusted transportation and processing costs (refer to Operating Expense discussion for adjusted transportation and processing costs non-GAAP financial measure disclosures) in the first quarter of 2018 compared to the first quarter of 2017.

Adjusted EBITDA (Non-GAAP)

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

Below is a reconciliation of net income (loss) (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 March 31,
	2018			2017
	(in millions)
Net income (loss)	$	(53.6	)	$	76.9
Interest expense	35.0			33.8
Interest and other (income) expense	0.7			(0.6		)
Income tax provision (benefit)	(13.9		)	45.6
Depreciation, depletion and amortization	196.5			191.8
Unrealized (gains) losses on derivative contracts	10.0			(177.3		)
Exploration expenses	—			0.4
Net (gain) loss from asset sales	(3.5		)	—
Impairment	0.7			0.1
Adjusted EBITDA	$	171.9		$	170.7

Adjusted EBITDA increased to $171.9 million in the first quarter of 2018 from $170.7 million in the first quarter of 2017, primarily due to a 15% increase in average realized oil equivalent prices and a 106% increase in oil equivalent production in Permian Basin and Haynesville/Cotton Valley. These changes were partially offset by the loss of Adjusted EBITDA from the Pinedale Divestiture and a $26.5 million increase in general and administrative expense and a $3.3 million increase in lease operating expense in the first quarter of 2018 compared to the first quarter of 2017.

Revenue

The following table presents our revenues disaggregated by revenue source.



	Three Months Ended
	March 31,
	2018			2017⁽¹⁾		Change
	(in millions)
Oil and condensate sales	$	300.7		$	221.7	$	79.0
Gas sales	102.0			134.5		(32.5		)
NGL sales	19.8			29.0		(9.2		)
Oil and condensate, gas and NGL sales, as adjusted⁽²⁾	422.5			385.2		37.3
Transportation and processing costs included in revenue⁽³⁾	(12.7		)	—		(12.7		)
Oil and condensate, gas and NGL sales, as presented	$	409.8		$	385.2	$	24.6

____________________________


⁽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. 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.

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 months ended March 31, 2018, compared to the three months ended March 31, 2017:



	Oil and condensate		Gas			NGL			Total
	(in millions)
Oil and condensate, gas and NGL sales, as adjusted
Three months ended March 31, 2017	$	221.7	$	134.5		$	29.0		$	385.2
Changes associated with volumes⁽¹⁾	13.8		(22.9		)	(9.7		)	(18.8		)
Changes associated with prices⁽²⁾	65.2		(9.6		)	0.5			56.1
Three months ended March 31, 2018	$	300.7	$	102.0		$	19.8		$	422.5

____________________________


⁽¹⁾	The revenue variance attributed to the change in volume is calculated by multiplying the change in volume from the three months ended March 31, 2018, as compared to the three months ended March 31, 2017, by the average field-level price for the three months ended March 31, 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 months ended March 31, 2018, as compared to the three months ended March 31, 2017, by the respective volumes for the three months ended March 31, 2018. Pricing changes are driven by changes in commodity average field-level prices, excluding the impact from commodity derivatives.

Production, Prices and Production Costs



	Three Months Ended March 31,
	2018			2017			Change
Total production volumes (Mboe)
Northern Region
Williston Basin	3,729.7			4,834.0			(1,104.3		)
Pinedale	0.1			3,514.9			(3,514.8		)
Uinta Basin	804.5			968.3			(163.8		)
Other Northern	105.4			330.4			(225.0		)
Southern Region
Permian Basin	2,782.9			1,389.5			1,393.4
Haynesville/Cotton Valley	4,290.5			2,046.7			2,243.8
Other Southern	11.5			6.5			5.0
Total production	11,724.6			13,090.3			(1,365.7		)

Total equivalent prices (per Boe)
Average field-level equivalent price	$	36.04		$	29.43		$	6.61
Commodity derivative impact	(3.70		)	(1.24		)	(2.46		)
Net realized equivalent price	$	32.34		$	28.19		$	4.15

Oil and Condensate Volumes and Prices



	Three Months Ended March 31,
	2018			2017			Change
Oil and condensate production volumes (Mbbl)
Northern Region
Williston Basin	2,612.2			3,336.7			(724.5		)
Pinedale	—			143.0			(143.0		)
Uinta Basin	151.7			166.1			(14.4		)
Other Northern	37.8			26.9			10.9
Southern Region
Permian Basin	2,159.1			1,001.7			1,157.4
Haynesville/Cotton Valley	5.8			7.2			(1.4		)
Other Southern	7.4			1.1			6.3
Total production	4,974.0			4,682.7			291.3
Average field-level oil prices (per bbl)
Northern Region	$	60.93		$	46.58		$	14.35
Southern Region	$	59.82		$	50.14		$	9.68

Average field-level price	$	60.45		$	47.35		$	13.10
Commodity derivative impact	(8.91		)	(0.43		)	(8.48		)
Net realized price	$	51.54		$	46.92		$	4.62

Oil and condensate revenues increased $79.0 million, or 36%, in the first quarter of 2018 compared to the first quarter of 2017, due to higher average field-level prices and higher oil and condensate production volumes. Average field-level oil prices increased 28% in the first quarter of 2018 compared to the first quarter of 2017 primarily driven by an increase in average NYMEX-WTI oil prices for the comparable periods combined with narrowing differentials predominantly in the Williston Basin. The 6% increase in production volumes was driven by increases in the Permian Basin due to increased drilling and completion activity. This increase in production was partially offset by decreased drilling activity in the Williston Basin and a decrease in production in Pinedale as a result of the Pinedale Divestiture, which closed in September 2017.

Gas Volumes and Prices



	Three Months Ended March 31,
	2018		2017			Change
Gas production volumes (Bcf)
Northern Region
Williston Basin	3.4		4.0			(0.6		)
Pinedale	—		18.5			(18.5		)
Uinta Basin	3.7		4.6			(0.9		)
Other Northern	0.4		1.8			(1.4		)
Southern Region
Permian Basin	1.9		1.2			0.7
Haynesville/Cotton Valley	25.7		12.2			13.5
Other Southern	—		—			—
Total production	35.1		42.3			(7.2		)
Average field-level gas prices (per Mcf)
Northern Region	$	2.79	$	3.22		$	(0.43	)
Southern Region	$	2.94	$	3.09		$	(0.15	)

Average field-level price	$	2.91	$	3.18		$	(0.27	)
Commodity derivative impact	0.03		(0.34		)	0.37
Net realized price	$	2.94	$	2.84		$	0.10

Gas revenues decreased $32.5 million, or 24%, in the first quarter of 2018 compared to the first quarter of 2017, due to lower gas production volumes and lower average field-level prices. Production volumes decreased primarily due to the Pinedale Divestiture and divestitures in Other Northern. These production decreases were partially offset by an increase in production in the first quarter of 2018 in Haynesville/Cotton Valley due to a continued refracturing program and the initiation of a drilling program. Average field-level gas prices decreased 8% in the first quarter of 2018 compared to the first quarter of 2017, primarily driven by a decrease in average NYMEX-HH gas prices for the comparable periods.

NGL Volumes and Prices



	Three Months Ended March 31,
	2018		2017		Change
NGL production volumes (Mbbl)
Northern Region
Williston Basin	551.4		823.2		(271.8		)
Pinedale	—		292.5		(292.5		)
Uinta Basin	36.3		41.4		(5.1		)
Other Northern	3.3		4.3		(1.0		)
Southern Region
Permian Basin	312.9		187.8		125.1
Haynesville/Cotton Valley	0.1		6.0		(5.9		)
Other Southern	0.4		0.2		0.2
Total production	904.4		1,355.4		(451.0		)
Average field-level NGL prices (per bbl)
Northern Region	$	22.58	$	22.13	$	0.45
Southern Region	$	20.89	$	16.78	$	4.11

Average field-level price	$	21.99	$	21.36	$	0.63
Commodity derivative impact	—		—		—
Net realized price	$	21.99	$	21.36	$	0.63

NGL production volumes and revenues represent the sale of liquids derived from the processing of QEP's natural gas production. NGL revenues decreased $9.2 million, or 32%, during the first quarter of 2018 compared to the first quarter of 2017, due to lower NGL production volumes, partially offset by higher average field-level prices. The 33% decrease in NGL production volumes was primarily driven by production decreases in Pinedale due to the Pinedale Divestiture and production decreases in the Williston Basin due to decreased drilling activity. These decreases were partially offset by an increase in production in the Permian Basin due to increased drilling and completion activity. The overall decrease in production volumes was partially offset by a 3% increase in NGL prices during the first quarter of 2018 compared to the first quarter of 2017, primarily driven by an increase in propane, ethane and other NGL component prices.

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 March 31,
	2018			2017			Change
	(in millions)
Purchased oil and gas sales	$	14.1		$	30.9		$	(16.8	)
Purchased oil and gas expense	(15.5		)	(29.4		)	13.9
Realized gains (losses) on gas storage derivative contracts	0.2			(0.2		)	0.4
Resale margin	$	(1.2	)	$	1.3		$	(2.5	)

Purchased oil and gas sales and expense decreased during the first quarter of 2018 compared to first quarter of 2017, due to lower resale volumes, as a result of increased production in areas where the Company has oil and gas transportation commitments.

Operating Expenses

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



	Three Months Ended March 31,
	2018		2017		Change
	(in millions)
Lease operating expense	$	72.5	$	69.2	$	3.3
Adjusted transportation and processing costs⁽¹⁾	46.7		70.2		(23.5		)
Production and property taxes	28.9		29.1		(0.2		)
Total production costs	$	148.1	$	168.5	$	(20.4	)
	(per Boe)
Lease operating expense	$	6.18	$	5.29	$	0.89
Adjusted transportation and processing costs⁽¹⁾	3.98		5.36		(1.38		)
Production and property taxes	2.47		2.23		0.24
Total production costs	$	12.63	$	12.88	$	(0.25	)

____________________________

⁽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 March 31,
	2018			2017⁽¹⁾		Change
	(in millions)
Adjusted transportation and processing costs	$	46.7		$	70.2	$	(23.5	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	(12.7		)	—		(12.7		)
Transportation and processing costs, as presented	$	34.0		$	70.2	$	(36.2	)
	(per Boe)
Adjusted transportation and processing costs	$	3.98		$	5.36	$	(1.38	)
Transportation and processing costs deducted from oil and condensate, gas and NGL sales	(1.08		)	—		(1.08		)
Transportation and processing costs, as presented	$	2.90		$	5.36	$	(2.46	)

____________________________


⁽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.

Lease operating expense (LOE). QEP's LOE increased $3.3 million, or 5%, in the first quarter of 2018 compared to the first quarter of 2017, primarily driven by an increases in the Permian and Williston basins. The Permian Basin increase relates to the 2017 Permian Basin Acquisition and costs associated with converting wells to gas lift. These increases were partially offset by the Pinedale Divestiture and Other Northern divestitures of properties.

During the first quarter of 2018, lease operating expense increased $0.89 per Boe, or 17%, compared with the first quarter of 2017, due to the loss of lower LOE production in Pinedale as a result of the Pinedale Divestiture. Excluding the Pinedale Divestiture, LOE per Boe was down 2% primarily due to a decrease in our Permian Basin. The Permian Basin LOE per Boe decreased due to lower cost production from the recent horizontal well completions partially offset by higher cost production on the low volume vertical wells acquired in the 2017 Permian Basin Acquisition.

Adjusted transportation and processing costs. Adjusted transportation and processing costs decreased $23.5 million, or 33%, during the first quarter of 2018 compared to the first quarter of 2017. The decrease in expense was primarily attributable to decreases in Pinedale related to the Pinedale Divestiture. The decrease in Pinedale was partially offset by increased expenses in Haynesville/Cotton Valley and the Permian Basin due to increased production volumes in the first quarter of 2018 compared to the first quarter of 2017.

During the first quarter of 2018, adjusted transportation and processing costs decreased $1.38 per Boe, or 26%, compared to the first quarter of 2017, due to the Pinedale Divestiture, which had higher transportation and processing costs per Boe. Excluding the Pinedale Divestiture, transportation and processing costs per Boe were down 28% due to a decrease in Haynesville/Cotton Valley during the first quarter of 2018 compared to the first quarter of 2017. The rate per Boe decreased in Haynesville/Cotton Valley due to increased production that increased utilization of the Company's firm transportation commitments on interstate pipelines.

General and administrative (G&A) expense. During the first quarter of 2018, G&A expense increased $26.5 million, or 79%, compared to the first quarter of 2017. During the first quarter of 2018, QEP incurred $7.9 million in termination benefits and retention compensation comprised of $3.4 million of severance, $2.8 million of accelerated share-based compensation and $1.7 million related to the retention program 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 $4.9 million increase in share-based compensation and changes in the mark-to-market value of the Deferred Compensation Wrap Plan, a $3.6 million increase in outside services, a $3.0 million increase in labor, benefits and employee expenses and a $0.9 million increase in legal expenses.

Production and property taxes. In most states in which QEP operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production and property taxes decreased $0.2 million, or 1%, in the first quarter of 2018 compared to the first quarter of 2017, primarily due to the Pinedale Divestiture partially offset by increased field-level revenue in the Permian Basin and increased production in Haynesville/Cotton Valley.

During the first quarter of 2018, production and property taxes increased $0.24 per Boe, or 11%, compared to the first quarter of 2017, primarily due to an increase in average field-level equivalent prices in the Permian Basin and increased production in Haynesville/Cotton Valley as a result of a successful refracturing program and a higher tax rate in that area. These increases were partially offset by the Pinedale Divestiture.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $4.7 million in the first quarter of 2018 compared to the first quarter of 2017, primarily due to increased production and a higher DD&A rate in Haynesville/Cotton Valley and increased production in the Permian Basin, partially offset by lower DD&A due to the Pinedale Divestiture in the third quarter of 2017.

Impairment expense. During the first quarter of 2018, QEP recorded impairment charges of $0.7 million, which were primarily related to the impairment of proved properties related to a divestiture in the Other Northern area and expiring leaseholds on unproved properties. During the first quarter of 2017, QEP recorded impairment charges of $0.1 million which was related to expiring leaseholds on unproved properties.

Net gain (loss) from asset sales. During the first quarter of 2018, QEP recognized a gain on the sale of assets of $3.5 million, primarily related to the divestiture of properties outside our main operating areas in the Williston Basin and Other Northern area.

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 first quarter of 2018, losses on commodity derivative contracts were $53.2 million, of which $43.2 million were realized losses and $10.0 million were unrealized losses. During the first quarter of 2017, gains on commodity derivative contracts were $160.9 million, of which $177.3 million were unrealized gains and $16.4 million were realized losses.

Interest expense. Interest expense increased $1.2 million, or 4%, during the first quarter of 2018 compared to the first quarter of 2017. The increase during the first 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.

Income tax (provision) benefit. Income tax benefit increased $59.5 million during the first quarter of 2018 compared to the first quarter of 2017. The increase in benefit was the result of a net loss during the first quarter of 2018 compared to net income during the first quarter of 2017 and a lower combined effective federal and state income tax rate of 20.6% during the first quarter of 2018 compared to a rate of 37.2% during the first 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.

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. The Company expects that these sources of cash will be sufficient to fund its operations and capital expenditures during the next 12 months and the foreseeable future.

QEP also periodically accesses debt and equity markets and sells properties. In 2018, QEP plans to market it assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and, if successful, use the proceeds to fund on-going operations, reduce debt, repurchase shares and for general corporate purposes.

The Company estimates, that as of March 31, 2018, it could incur additional indebtedness of approximately $315.0 million and be in compliance with the covenants contained in its revolving credit facility. To the extent actual operating results, realized commodity prices or uses of cash differ from the Company's assumptions, QEP's 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 March 31, 2018 and 2017, QEP was in compliance with the covenants under the credit agreement.

During the three months ended March 31, 2018, QEP's weighted-average interest rate on borrowings from its credit facility was 3.75%. As of March 31, 2018, QEP had $385.0 million of borrowings outstanding and $1.0 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 April 20, 2018, QEP had $455.0 million of borrowings outstanding, had $1.0 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.

Senior Notes

The Company's senior notes outstanding as of March 31, 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:



	Three Months Ended March 31,
	2018			2017		Change
	(in millions)
Net income (loss)	$	(53.6	)	$	76.9	$	(130.5	)
Non-cash adjustments to net income (loss)	202.2			67.3		134.9
Changes in operating assets and liabilities	11.8			5.7		6.1
Net cash provided by (used in) operating activities	$	160.4		$	149.9	$	10.5

Net cash provided by operating activities was $160.4 million during the first three months of 2018, which included $53.6 million of net loss, $202.2 million of non-cash adjustments to the net loss and $11.8 million in changes in operating assets and liabilities. Non-cash adjustments to the net loss primarily included DD&A expense of $196.5 million, $11.2 million of share-based compensation expense and unrealized losses on derivative contracts of $10.0 million, partially offset by $14.1 million of deferred income taxes and a net gain on asset sales of $3.5 million. The increase in changes in operating assets and liabilities primarily resulted from a decrease in accounts receivable of $11.6 million, an increase in interest payable of $7.4 million and a decrease in prepayments of $1.3 million, partially offset by a decrease in accounts payable and accrued expenses of $10.4 million.

Net cash provided by operating activities was $149.9 million during the first three months of 2017, which included $76.9 million of net income, $67.3 million of non-cash adjustments to net income and a $5.7 million increase in operating assets and liabilities. Non-cash adjustments to net income primarily included DD&A expense of $191.8 million and $45.6 million of deferred income taxes, partially offset by unrealized gains on derivative contracts of $177.3 million. The increase in changes in operating assets and liabilities primarily resulted from a decrease in accounts receivable of $19.5 million, partially offset by a decrease in accounts payable and accrued expenses of $10.8 million and a decrease in the ARO liability of $0.9 million.

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:



	Three Months Ended March 31,
	2018			2017			Change
	(in millions)
Property acquisitions⁽¹⁾	$	36.2		$	68.2		$	(32.0	)
Property, plant and equipment capital expenditures	418.8			214.3			204.5
Total accrued capital expenditures	455.0			282.5			172.5
Change in accruals and other non-cash adjustments	(48.1		)	(37.0		)	(11.1		)
Total cash capital expenditures	$	406.9		$	245.5		$	161.4

____________________________


⁽¹⁾	Excludes acquisition deposits held in escrow of $0.2 million for the three months ended March 31, 2018.

In the first three months of 2018, on an accrual basis, the Company invested $418.8 million on property, plant and equipment capital expenditures (which excludes property acquisitions), an increase of $204.5 million compared to the first three months of 2017. In the first three months of 2018, QEP's significant capital expenditures included $253.8 million in the Permian Basin (including midstream infrastructure of $10.9 million, primarily related to fresh water supply, produced water gathering, salt water disposal and oil and gas gathering), $88.0 million in the Williston Basin, $72.0 million in Haynesville/Cotton Valley (including midstream infrastructure of $7.0 million, primarily related to gas gathering) and $4.3 million in the Uinta Basin. In addition, in the first three months of 2018, QEP acquired various oil and gas properties, primarily proved and unproved leasehold acreage in the Permian Basin related to the 2017 Permian Basin Acquisition, for an aggregate purchase price of $36.2 million.

In the first three months of 2017, on an accrual basis, the Company invested $214.3 million on property, plant and equipment capital expenditures (which excludes property acquisitions), including $108.1 million in the Permian Basin, $67.3 million in the Williston Basin, $28.1 million in Haynesville/Cotton Valley and $5.1 million in Pinedale. In addition, during the first three months of 2017, QEP acquired various oil and gas properties, primarily proved and unproved leaseholds and additional service acreage primarily in the Permian Basin, for an aggregate purchase price of $68.2 million.

The mid-point of our 2018 forecasted capital expenditures (excluding property acquisitions) is $1,120.0 million. QEP intends to fund capital expenditures (excluding property acquisitions) with cash flow from operating activities, cash on hand and borrowings under the credit facility. The aggregate levels of capital expenditures for 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 months of 2018, net cash provided by financing activities was $214.3 million compared to net cash used in financing activities of $9.5 million in the first three months of 2017. During the first three months of 2018, QEP had borrowings under from the credit facility of $1,068.5 million and repayments on its credit facility of $772.5 million. In addition, QEP used $52.8 million of cash to repurchase common stock under the Company's share repurchase program and had treasury stock repurchases of $4.7 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 $24.2 million. During the first three months of 2017, QEP had treasury stock repurchases of $6.4 million and a decrease in checks outstanding in excess of cash balances of $3.1 million.

As of March 31, 2018, long-term debt consisted of $2,458.1 million, of which $2,099.3 million is senior notes, $385.0 million outstanding on the credit facility and $26.2 million of net original issue discount and unamortized debt issuance costs.

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 606, effective January 1, 2018.

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 and collars. The volume of commodity derivative instruments utilized by the Company may vary from year to year based on QEP's forecasted production. The Company's current derivative instruments do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of March 31, 2018, QEP held commodity price derivative contracts totaling 22.2 million barrels of oil and 128.1 million MMBtu of gas.

The following tables present QEP's volumes and average prices for its derivative positions as of April 20, 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 March 31, 2018.



Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2018 (April through December)	NYMEX WTI	12.7	$	52.48
2019	NYMEX WTI	9.5	$	52.66
Gas sales		(MMBtu)	($/MMBtu)
2018 (May through December)	NYMEX HH	71.7	$	3.00
2018 (July through December)	NYMEX HH	1.8	$	3.01
2019	NYMEX HH	43.8	$	2.86



Production Commodity Derivative Basis Swaps
Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2018 (April through December)	NYMEX WTI	Argus WTI Midland	5.5	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.9	$	(0.71	)
2019	NYMEX WTI	Argus WTI Midland	4.7	$	(0.77	)
Gas sales			(MMBtu)	($/MMBtu)
2018 (May through December)	NYMEX HH	IFNPCR	4.9	$	(0.16	)

Changes in the fair value of derivative contracts from December 31, 2017 to March 31, 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	43.2
Change in oil and gas prices on futures markets	50.5
Contracts added	(103.8		)
Net fair value of oil and gas derivative contracts outstanding at March 31, 2018	$	(142.0	)

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:



	March 31, 2018
	(in millions)
Net fair value – asset (liability)	$	(142.0	)
Fair value if market prices of oil, gas and basis differentials decline by 10%	$	(127.7	)
Fair value if market prices of oil, gas and basis differentials increase by 10%	$	(156.1	)

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $14.1 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $14.3 million as of March 31, 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 March 31, 2018, the Company had $385.0 million of borrowings outstanding under its revolving credit facility. If interest rates were to increase or decrease 10% during the three months ended March 31, 2018, at our average level of borrowing for those same periods, the Company's interest expense would increase or decrease by $0.2 million for the three months ended March 31, 2018, or less than 1% of total interest expense.

The remaining $2,099.3 million of the Company's debt is senior notes with fixed interest rates; therefore, it is not affected by interest rate movements. For additional information regarding the Company's debt instruments, refer to Note 9 – Debt, in Item I of Part I of this Quarterly Report on Form 10-Q.

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:


•	focus on returns-focused growth and superior execution and strategies to achieve these objectives;


•	our Strategic Initiatives to transition to a pure-play Permian Basin company;


•	plans to grow oil and condensate production;


•	drilling and completion plans and strategies;


•	including anticipated benefits of our tank-style completion methodology;


•	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;


•	expectations and assumptions regarding impact of oil, gas and NGL prices;


•	future development costs and funding for such costs;


•	factors affecting our decision to modify our development plans;


•	volatility of oil, gas and NGL prices and factors impacting such prices;


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


•	the usefulness of non-GAAP financial measures;


•	our inventory of drilling locations;


•	aggregate purchase price and source of funding for, and the timing of the closing of, acquisitions of additional oil and gas interests in the Permian Basin pursuant to offers made in the fourth quarter of 2017;


•	evaluation of potential acquisitions and divestiture opportunities;


•	plans to market our assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley;


•	our balance sheet and liquidity position allowing us to grow oil production, provide financial flexibility, withstand commodity price volatility and fund our development projects, operations, capital expenditures and Strategic Initiatives;


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


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


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


•	focus on maintaining a sufficient liquidity position to ensure financial flexibility;


•	potential for asset impairments and factors impacting impairment amounts;


•	plans to recover or reject ethane from produced natural gas;


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


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


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


•	outcome and impact of various claims;


•	estimated amount of potential impairment of proved and unproved property, primarily in the Williston and Uinta basins;


•	delays in completion of wells, well shut-ins and volatility to operating results caused by multi-well pad drilling;


•	predictability and success of our drilling operations;


•	plans and ability to pursue acquisition opportunities;


•	oil exports from and imports to the U.S.;


•	sufficiency of our liquidity position to ensure financial flexibility and fund our operations and capital expenditures;


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


•	factors adversely affecting our liquidity;


•	changes in recorded goodwill;


•	redemption of senior notes;


•	factors impacting our ability to borrow and the interest rates offered;


•	loss contingencies;


•	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 costs related to share-based compensation grants;


•	expected contributions to our employee benefit plans;


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


•	use of proceeds from divestiture of assets.

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


•	the risk factors discussed in Item 1A of Part I of the 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;


•	the risks and liabilities associated with acquired assets;


•	asset impairments;


•	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, 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


•	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 March 31, 2018. Based on such evaluation, such officers have concluded that, as of March 31, 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 SEC'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 March 31, 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 Annual Report on 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 Annual Report on Form 10-K for the year ended December 31, 2017. Below are material changes to such risk factors that have occurred during the three months ended March 31, 2018.

QEP may be unable to successfully execute certain aspects of its announced Strategic Initiatives. 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. 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.

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 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 Venting and Flaring 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 2016 Venting and Flaring Rule is the subject of active litigation in the U.S. District Court for the District of Wyoming. In December 2017, the BLM published a rule to delay the January 2018 compliance deadlines and suspend the obligation to comply with certain provisions that had required compliance in January 2017, until January 2019 (2017 Delay Rule). Certain states and environmental nongovernmental organizations (ENGOs) filed litigation in the U.S. District Court for the Northern District of California challenging the 2017 Delay Rule, and the court preliminarily enjoined the 2017 Delay Rule on February 22, 2018, requiring operators to immediately comply with the 2016 Venting and Flaring Rule. These 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. On April 4, 2018, the U.S. Court for the District of Wyoming stayed certain compliance obligations required by the 2016 Venting and Flaring while the BLM completes a rulemaking process in which it may revise the 2016 Venting and Flaring Rule.

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.

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

In February 2018, the Board of Directors of QEP authorized the repurchase of 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⁾⁽²⁾	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)
January 1, 2018 - January 31, 2018	3,869	$	10.38	—	$	—
February 1, 2018 - February 28, 2018	—	$	—	—	$	—
March 1, 2018 - March 31, 2018	6,106,918	$	9.40	5,621,540	$	1,197.2
Total	6,110,787			5,621,540

____________________________


⁽¹⁾	During the three months ended March 31, 2018, QEP purchased 489,247 shares from employees in connection with the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants.

⁽²⁾

During the three months ended March 31, 2018, QEP repurchased and retired 5,621,540 shares under the February 2018 $1.25 billion Repurchase Program at a weighted average price of $9.37 per share, excluding commission of $0.02 per share, for $52.8 million. Shares are as of the settlement date. Subsequent to March 31, 2018, the Company settled and retired the purchase of 592,310 shares at a weighted average price of $9.37, excluding commission of $0.02 per share, for $5.6 million, associated with trades that had been made prior to the end of the quarter.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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 17, 2017 (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 18, 2017).
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.

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)

April 25, 2018	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer

April 25, 2018	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

Document and Entity Information	3 Months Ended
Document and Entity Information	Mar. 31, 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	237,708,346
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018


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


(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.


(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.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
REVENUES
Oil and condensate, gas and NGL sales	$ 409.8	$ 385.2
Other revenue	5.0	4.0
Purchased oil and gas sales	14.1	30.9
Total Revenues	428.9	420.1
OPERATING EXPENSES
Purchased oil and gas expense	15.5	29.4
Lease operating expense	72.5	69.2
Transportation and processing costs	34.0	70.2
Gathering and other expense	2.8	1.5
General and administrative	60.1	33.6
Production and property taxes	28.9	29.1
Depreciation, depletion and amortization	196.5	191.8
Exploration expenses	0.0	0.4
Impairment	0.7	0.1
Total Operating Expenses	411.0	425.3
Net gain (loss) from asset sales	3.5	0.0
OPERATING INCOME (LOSS)	21.4	(5.2)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(53.2)	160.9
Interest and other income (expense)	(0.7)	0.6
Interest expense	(35.0)	(33.8)
INCOME (LOSS) BEFORE INCOME TAXES	(67.5)	122.5
Income tax (provision) benefit	13.9	(45.6)
Net income (loss)	$ (53.6)	$ 76.9
Earnings (loss) per common share
Basic	$ 0	$ 0.32
Diluted	$ 0	$ 0.32
Weighted-average common shares outstanding
Used in basic calculation	240.9	240.2
Used in diluted calculation	240.9	240.3
Dividends per common share	$ 0	$ 0.00

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Postretirement medical plan changes, income tax expense	$ 0.0	$ (1.0)
Pension and other postretirement plans adjustments:
Amortization of prior service cost, income tax expense	0.0	(0.1)
Amortization of net actuarial loss, income tax expense	$ (0.1)	$ (0.1)

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 0.0	$ 0.0
Accounts receivable, net	130.2	142.1
Income tax receivable	4.7	4.9
Fair value of derivative contracts	3.2	3.4
Hydrocarbon inventories, at lower of average cost or net realizable value	2.1	3.6
Prepaid expenses	9.4	10.7
Other current assets	0.2	0.7
Total Current Assets	149.8	165.4
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	12,676.1	12,470.9
Unproved properties	1,073.7	1,095.8
Gathering and other	383.4	319.7
Materials and supplies	38.4	37.8
Total Property, Plant and Equipment	14,171.6	13,924.2
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,660.8	6,642.9
Gathering and other	130.6	124.3
Total Accumulated Depreciation, Depletion and Amortization	6,791.4	6,767.2
Net Property, Plant and Equipment	7,380.2	7,157.0
Fair value of derivative contracts	4.5	0.1
Other noncurrent assets	74.1	72.3
TOTAL ASSETS	7,608.6	7,394.8
Current Liabilities
Checks outstanding in excess of cash balances	19.8	44.0
Accounts payable	400.9	364.6
Production and property taxes	31.9	31.6
Interest payable	33.4	26.0
Fair value of derivative contracts	116.9	103.6
Other current liabilities	10.1	7.5
Total Current Liabilities	613.0	577.3
Long-term debt	2,458.1	2,160.8
Deferred income taxes	504.0	518.0
Asset retirement obligations	200.4	206.6
Fair value of derivative contracts	32.8	31.8
Other long-term liabilities	103.6	102.4
Commitments and contingencies (Note 10)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 240.3 million and 243.0 million shares issued, respectively	2.4	2.4
Treasury stock – 2.6 million and 2.0 million shares, respectively	(39.5)	(34.2)
Additional paid-in capital	1,408.0	1,398.2
Retained earnings	2,336.3	2,442.6
Accumulated other comprehensive income (loss)	(10.5)	(11.1)
Total Common Shareholders' Equity	3,696.7	3,797.9
TOTAL LIABILITIES AND EQUITY	$ 7,608.6	$ 7,394.8

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares shares in Millions	Mar. 31, 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)	240.3	243.0
Treasury stock (in shares)	2.6	2.0

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
OPERATING ACTIVITIES
Net income (loss)	$ (53.6)	$ 76.9
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	196.5	191.8
Deferred income taxes (benefit)	(14.1)	45.6
Impairment	0.7	0.1
Share-based compensation	11.2	6.0
Amortization of debt issuance costs and discounts	1.3	1.5
Bargain purchase gain from acquisition	0.0	0.4
Net gain (loss) from asset sales	(3.5)	0.0
Unrealized (gains) losses on marketable securities	0.1	(0.8)
Unrealized (gains) losses on derivative contracts	10.0	(177.3)
Changes in operating assets and liabilities	11.8	5.7
Net Cash Provided by (Used in) Operating Activities	160.4	149.9
INVESTING ACTIVITIES
Property acquisitions	(36.2)	(68.2)
Property, plant and equipment, including exploratory well expense	(370.7)	(177.3)
Proceeds from disposition of assets	33.3	0.2
Net Cash Provided by (Used in) Investing Activities	(373.6)	(245.3)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(24.2)	(3.1)
Proceeds from credit facility	1,068.5	0.0
Repayments of credit facility	(772.5)	0.0
Common stock repurchased and retired	(52.8)	0.0
Treasury stock repurchases	(4.7)	(6.4)
Net Cash Provided by (Used in) Financing Activities	214.3	(9.5)
Change in cash, cash equivalents and restricted cash	1.1	(104.9)
Beginning cash, cash equivalents and restricted cash(1)	23.4	465.4
Ending cash, cash equivalents and restricted cash(1)	24.5	360.5
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	26.0	32.3
Cash paid for income taxes, net	0.0	0.0
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$ 48.1	$ 37.0

Acquisitions & Divestitures	3 Months Ended
Acquisitions & Divestitures	Mar. 31, 2018
Business Combinations [Abstract]
Acquisitions & Divestitures [Text Block]	Acquisitions During the three months ended March 31, 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 $36.2 million, subject to customary purchase price adjustments. Of the $36.2 million, $35.7 million was related to acquisitions from various persons who 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 three months ended March 31, 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 $68.2 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired in 2017. 2018 Strategic Initiatives 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 a part of this process, in February 2018, the Company engaged advisors to assist with the divestitures of its Williston Basin and Uinta Basin assets and has provided data for potential buyers in April 2018. The assets will be considered held for sale once it is deemed unlikely that there will be any significant changes to QEP's divestiture plan, which QEP believes will be upon the execution of purchase and sale agreements. Pinedale Divestiture In September 2017, QEP sold its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to additional post-closing purchase price adjustments. For the three months ended March 31, 2018, QEP recorded a pre-tax gain on sale of $1.0 million, due to post-closing purchase price adjustments, which were recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations. For the three months ended March 31, 2017, QEP had net income before income taxes related to the divested Pinedale properties of $28.0 million. 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 March 31, 2018, the liability associated with estimated future payments for this commitment was $27.3 million, of which $22.9 million is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses" and $4.4 million is reported on the Condensed Consolidated Balance Sheets within "Other long-term liabilities". Other Divestitures During the three months ended March 31, 2018, QEP received proceeds of $33.3 million and recorded a pre-tax gain on sale of $2.5 million, primarily related to the divestiture of properties outside our main operating areas in the Williston Basin and Other Northern area. The gains and losses were recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations.

Restructuring Costs	3 Months Ended
Restructuring Costs	Mar. 31, 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 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. During the first quarter of 2018, the Company incurred but has not yet paid $6.2 million of costs associated with these termination benefits, including $3.4 million of severance and $2.8 million of accelerated share-based compensation, recorded in "Accounts payable and accrued expenses" and "General and administrative" expense in the Condensed Consolidated Financial Statements. Due to the nature of the Strategic Initiatives and uncertain factors such as 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. In connection with the Strategic Initiatives, QEP also approved an employee retention program and recognized $1.7 million of expense during the three months ended March 31, 2018 and recorded these costs in "Accounts payable and accrued expenses" and "General and administrative" expense in the Condensed Consolidated Financial Statements. QEP expects to incur an additional $18.3 million of expense in 2018 and $5.0 million in 2019 related to the retention program.

Commitment and Contingencies	3 Months Ended
Commitment and Contingencies	Mar. 31, 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.

Acquisitions & Divestitures Acquisitions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Business Acquisition [Line Items]
Bargain purchase gain from acquisition	$ 0.0	$ 0.4
Payments to acquire oil and gas property	36.2	68.2
Goodwill		$ 5.3
2017 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property	$ 35.7

Acquisitions & Divestitures Pinedale Divestiture (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 33.3	$ 0.2
Income (loss) before income taxes	(67.5)	122.5
Pinedale Divestiture [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	718.2
Net gain (loss) from asset sales	1.0
Income (loss) before income taxes		$ 28.0
Minimum volume commitment	45.0
Pinedale Divestiture [Member] \| Short-term [Member]
Divestitures [Line Items]
Minimum volume commitment remaining	22.9
Pinedale Divestiture [Member] \| Long-term [Member]
Divestitures [Line Items]
Minimum volume commitment remaining	4.4
Pinedale Divestiture [Member] \| Total [Member]
Divestitures [Line Items]
Minimum volume commitment remaining	$ 27.3

Earnings Per Share Components of Basic and Diluted Shares Used In EPS Calculation (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share [Abstract]
Anti-dilutive shares	0.0	0.1
Weighted-average basic common shares outstanding	240.9	240.2
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	0.0	0.1
Average diluted common shares outstanding	240.9	240.3

Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - Estimate of Fair Value Measurement [Member] - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
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	19.8	44.0
Long-term debt, fair value	$ 2,456.7	$ 2,256.2

Fair Value Measurements Narrative (Details) $ in Millions	3 Months Ended
Fair Value Measurements Narrative (Details) $ in Millions	Mar. 31, 2018 USD ($)
Proved Property [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Oil and Gas Properties	$ 0.5

Derivative Contracts (Narrative) (Details)	3 Months Ended
Derivative Contracts (Narrative) (Details)	Mar. 31, 2018
Derivative [Line Items]
Maximum Forecasted Production Covered By Derivatives	100.00%
Minimum [Member]
Derivative [Line Items]
Expected Annual Production Covered By Derivatives	50.00%
Maximum [Member]
Derivative [Line Items]
Expected Annual Production Covered By Derivatives	75.00%

Derivative Contracts Schedule Of Commodity Derivative Contracts (Details) MMBTU in Millions	3 Months Ended
	Mar. 31, 2018 USD ($) MMBTU $ / MMBTU
Gas Swaps [Member] \| Year 2018 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	82.5
Average Swap Price per Unit \| $	$ 2.99
Gas Swaps [Member] \| Year 2018 (July through December) [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	1.8
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 Swaps [Member] \| Year 2018 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	12.7
Average Swap Price per Unit \| $	$ 52.48
Oil Swaps [Member] \| Year 2019 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	9.5
Average Swap Price per Unit \| $	$ 52.66
Oil Basis Swaps [Member] \| Year 2018 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	5.5
Weighted-Average Differential \| $ / MMBTU	(1.06)
Oil Basis Swaps [Member] \| Year 2018 (July through December) [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	0.9
Weighted-Average Differential \| $ / MMBTU	(0.71)
Oil Basis Swaps [Member] \| Year 2019 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	4.7
Weighted-Average Differential \| $ / MMBTU	(0.77)
Gas Basis Swaps [Member] \| Year 2018 [Member] \| NYMEX HH LESS IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	5.5
Weighted-Average Differential \| $ / MMBTU	(0.16)

Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Inputs, Level 2 [Member] - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	$ 24.4	$ 22.9
Derivative Liability, Fair Value, Gross	166.4	154.8
Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	16.3	20.6
Derivative Liability, Fair Value, Gross	130.0	120.8
Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	8.1	2.3
Derivative Liability, Fair Value, Gross	36.4	34.0
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	24.4	22.9
Derivative Liability, Fair Value, Gross	166.4	154.8
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member] \| Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	16.3	20.6
Derivative Liability, Fair Value, Gross	130.0	120.8
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member] \| Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	8.1	2.3
Derivative Liability, Fair Value, Gross	$ 36.4	$ 34.0

Restructuring Costs Narrative (Details) $ in Millions	3 Months Ended
Restructuring Costs Narrative (Details) $ in Millions	Mar. 31, 2018 USD ($)
Restructuring Cost and Reserve [Line Items]
Special Termination Benefits	$ 6.2
Severance Costs	3.4
Accelerated Share Based Compensation	2.8
Employee Retention Bonus Cost	1.7
Year 2018 [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	18.3
Year 2019 [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	$ 5.0

Debt (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
Debt (Narrative) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt Maturity Period	5 years
Long-term Debt, Weighted Average Interest Rate	3.75%
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	$ 385.0	$ 89.0
Maturity date of long-term debt	Sep. 01, 2022
Borrowing capacity	$ 1,250.0
Letters of credit outstanding	1.0	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

Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Less unamortized discount	$ (26.2)	$ (27.5)
Long-term debt	2,458.1	2,160.8
Total long-term debt outstanding	2,458.1	2,160.8
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	385.0	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